NATURAL RESOURCES DEFENSE COUNCIL ENVIRONMENTAL LAW AND POLICY CENTER

ALLIANCE FOR THE GREAT LAKES ENVIRONMENT ILLINOIS

ENVIRONMENTAL INTEGRITY PROJECT HOOSIER CHAPTER OF THE SIERRA CLUB

LEGAL ENVIRONMENTAL AID FOUNDATION SAVE THE DUNES COUNCIL

March 24, 2008 Madhurima D. Moulik IDEM, Office of Air Quality 100 North Senate Avenue MC 61-53, Room 1003 Indianapolis, Indiana 46204-2251 mmoulik@idem.in.gov

Re: Significant Source Modification No.: 089-25484-00453 and Significant Permit Modification No.: 089-25488-00453

Dear Ms. Moulik: Please accept these comments concerning the above-captioned draft permits, issued to BP Products North America, Inc. for expansion of its Whiting Refinery (the Permits), on behalf of the Natural Resources Defense Council (NRDC), the Environmental Law and Policy Center (ELPC), the Alliance for the Great Lakes, Environment Illinois, Environmental Integrity Project (EIP), Legal Environmental Aid Foundation, Save the Dunes Council, Hoosier Chapter of the Sierra Club (Commenters). We are deeply concerned with both the substance of the draft Permits and the process by which public comment concerning them is being solicited. Substantively, the Permits are riddled with critical omissions that result in far less stringent control measures than are required by the Clean Air Act (CAA, or the Act). The draft source modification permit – unlike the initial permit application that BP Products North America (BP) withdrew in the wake of last summer’s water permit controversy – claims a decrease in emissions across the board, thus not triggering the stringent pollution control requirements of CAA New Source Review (NSR). However, this purported decrease is grounded in a significantly flawed analysis, and depends on permit conditions that are not enforceable as a practical matter. Among other things, the analysis outright fails to count

Madhurima D. Moulik March 24, 2008 Page 2 the enormous pollutant emissions that are almost certain to result from use of the three new flares that BP is constructing in connection with the Canadian Extra Heavy Crude Oil (CXHO) refinery expansion project (the Project), emissions from increases in releases to existing flares, and emissions from depressurizing the new coker. Moreover, the Permits fail to address at all the large increase in greenhouse gas emissions that will result from the Project, which the CAA requires be evaluated and controlled pursuant to NSR – particularly in light of the U.S. Supreme Court’s recent decision in Massachusetts v. EPA, 127 S.Ct. 1438 (2007). The draft Title V permit, in turn, fails to include a schedule of compliance to address the violations identified in the Notice of Violation (NOV) sent to BP by the United States Environmental Protection Agency (USEPA) in November 2007, in violation of the CAA provisions mandating that such a schedule be included whenever the permittee is in violation of any applicable requirement. Finally, the Permits and supporting materials fail to provide adequate information to determine whether the emission calculations adequately accounted for the higher levels of pollutants in tar sands crude oil. Given time, we could undoubtedly identify many more significant problems with these Permits. Unfortunately, however, we have not been given time. NRDC and other organizations have submitted multiple requests for an extension of time to review the subject Permits and underlying documents, explaining why the public needs at least 60 days following receipt of all relevant documents to meaningfully evaluate the Permits (Exhibit 1). The response of the Indiana Department of Environmental Management (“IDEM”) was a paltry extension of the deadline by two weeks (Exhibit 2); and even this limited extension merely corrected the unlawfully short timeframe established by the initial notice, which afforded less than the required 30 days between the notice and the comment period. See 326 Ind. Admin. Code 2-7-17(c)(1)(C). Thirty days is the minimum comment period required under Indiana law, 326 IAC 2-1.1-6(a)(4), applicable across the board to the simplest and most uncontroversial permits, and the vastly complicated and controversial Permits at issue here unquestionably require far longer to review.1 It is, moreover, entirely inappropriate to close the comment period before all relevant documents have even been produced to the public in response to Open Records Act Requests – which, as discussed below, is the case here.

As explained in our extension request, these Permits – collectively thousands of pages long – are spectacularly complex, even by ordinary air permitting standards. The Project involves the modification of 57 different emissions sources, and the use of new feedstock. Many other projects from years past and future are being used to offset Project emissions. The netting baselines used are a "representative" two year period of past years, with a different period used for each pollutant. Quantifying these periods and 1 We also note, in this regard, that USEPA has previously identified a willingness to grant comment period extensions (not merely to correct violations of law) as a strength of Indiana’s New Source Review and Title V programs, but that willingness is strangely absent here, despite the obvious need for more time. See USEPA Indiana Title V Program Review, June 30, 2005, at 5, Appendix A at 12-13 (relevant excerpts attached as Exhibit 3); USEPA Indiana New Source Review Program Review, August, 2004, at 4 (relevant excerpts attached as Exhibit 4).

Madhurima D. Moulik March 24, 2008 Page 3

calculating the potential to emit in the future for each component of the expansion, are together an enormous project requiring in-depth technical understanding to validate that large reductions claimed are actually real and legally available as offsets. A Consent Decree based on past violations mandates emission reductions that may be used only in part to offset the new project, based on a complex formula. The USEPA NOV is directly relevant to many aspects of these Permits. Overall, the Permits involve a large number of pollutant changes – including both criteria pollutants and hundreds of toxics, leaving aside greenhouse gases – that are affected by the new Project and the offsetting projects.

Moreover, although a request (from the Illinois Attorney General, with whom

Commenters are collaborating) for the documents in IDEM’s files associated with the Project Permits was submitted in September 2007, IDEM did not actually begin responding to this request until February 2008, and has not yet even completed its response. On February 8, IDEM produced 6,410 pages of documents containing extensive and complex technical information concerning the permit evaluation process. On February 22, February 27, March 12, and March 19, IDEM produced many thousands of pages of additional documents. See cover letters from IDEM attached as Exhibit 5. The March 12 shipment alone – received March 13, the day before the back-to-back public meeting and hearing – was a full banker’s box containing at least 2,000 pages; and the March 19 shipment – received March 20, one business day before the comment deadline2 – was another half banker’s box. The cover letter to the March 19 shipment indicates that yet more documents will be forthcoming.

These documents are both mountainous in number – totaling many thousands of

pages – and essential to a thorough understanding of these Permits, as they may pertain directly to the netting analysis, Title V schedule of compliance requirements, and other matters. What is more, IDEM has acknowledged that not even all of the relevant documents have yet been made available to us. As noted in NRDC’s February 21 request for an extension of time, simply reviewing all of the documents in the initial February 8 shipment, if one were to spend 5 minutes on each page, would require more than 500 hours.3 The time frame allotted for public comment simply does not allow for this review. Lacking the hundreds of hours necessary to read through the documents in the few weeks available, we have been able to review only a small fraction of the documents provided, and have been compelled to devote our limited resources to crafting comments addressing the most superficially obvious deficiencies in the Permits.

Accordingly, the comments set forth herein reflect only what we have been able

to read, assimilate and analyze during the exceedingly short window of time for public comment we have been allotted. We reserve the right to supplement these comments as necessary in the future based on the more thorough review that only additional time will

2 IDEM has informed us that its offices are closed March 21, 2008. 3 In addition, NRDC has a pending FOIA request to USEPA for documents associated with the NOV issued to BP in connection with the Whiting facility. Although some documents were produced on March 5, USEPA informed NRDC that it would not be able to comply with the request in its entirety until March 18, less than a week before the comment deadline. Commenters therefore reserve the right to submit additional information after the comment deadline based on the response received to this request as well.

Madhurima D. Moulik March 24, 2008 Page 4 make possible; and on any additional relevant documents that may be produced in the future in response to Open Records Act requests.

We are disappointed that IDEM and BP have not taken the steps necessary to

avoid a repeat of last summer’s debacle concerning the Whiting refinery Clean Water Act permit. Once again, we are confronting woefully inadequate permits coupled with inadequate public information. But history does not have to repeat itself. We request that IDEM withdraw the draft Permits from consideration, declare BP’s application incomplete, and demand sufficient information to rectify the serious deficiencies that we are bringing to light in these comments.

I. The Analysis Concluding that the Project will Result in No Net Emissions

Increases, such that NSR is Not Triggered, is Deeply Flawed In its original air emissions permit application filed earlier, BP identified a significant increase in carbon monoxide (CO) emissions that would trigger NSR permitting requirements, so as to require that emissions be controlled with the Best Available Control Technology (BACT). However, in October, 2007, BP withdrew that initial application and substituted a new application containing netting calculations claiming an overall decrease in all pollutant emissions (allegedly as a result of additional equipment shutdowns and other factors). Thus, since the new application’s net emissions came in below the CAA significance levels according to BP’s analysis, the CAA requirement for installation of BACT or Lowest Achievable Emission Rate (LAER) purportedly did not apply to any pollutant. Unfortunately, the netting calculations contained in the new Permits are deeply flawed. A number of these flaws are described in detail in the extensive analysis performed by refinery expert Julia May, whom NRDC retained to review the draft Permits to evaluate compliance with the CAA and other matters.4 Her report (without the exhibits) is attached as Exhibit 6.5 Once these errors are corrected, the project will almost certainly trigger full NSR review for all regulated NSR pollutants. Our comments will not address the full range of LAER and BACT possibilities for the multiple sources at the facility, but will be limited to LAER and BACT for flares, a major source of unaccounted-for emissions (see Section II. below), while leaving the remainder to BP to address in its revised application. We similarly reserve comment on air quality modeling until BP has submitted its assessment in the revised application. A. The Netting Analysis Failed to Account for Use of Flares

The primary and overwhelming problem identified by Ms. May in her analysis is the failure to factor in any emissions associated with actual use of the three new flares

4 Phyllis Fox, Ph.D, retained by ELPC, and Lisa Sumi, retained by NRDC, also contributed significantly to the preparation of this document. 5 The exhibits to Ms. May’s comments are attached to the version of those comments submitted separately under an NRDC cover letter dated March 24, 2008, and are incorporated into this comment by reference.

Madhurima D. Moulik March 24, 2008 Page 5 that BP proposes to construct in connection with the Project. As explained in her report, refinery flares have consistently proven to be an enormous source of air pollution emissions. At refineries in the Bay Area, where great attention has been paid to the problem of flaring emissions, sulfur dioxide (SOx) emissions at refineries studied frequently exceeded 10,000 pounds, and were as high as 70,000 pounds, in a single day. Similarly, emissions of volatile organic compounds (VOCs) from flaring frequently exceeded thousands of pounds per day, and were recorded as high as 22,000 pounds per day. Annually, flaring events meant SOx emissions as high as 3,000 tons and VOC emissions over 1,800 tons. These levels of emissions – recorded from refineries with far fewer flares than the 8 current and 3 proposed new flares at the Whiting refinery – would by themselves far exceed the NSR significance thresholds, so as to trigger BACT and LAER requirements for multiple regulated NSR pollutants.

Commenter EIP has also studied “start-up, shut-down, and malfunction” (SSM) emissions (i.e., flaring), issuing a report in 2004 documenting releases from large petrochemical plants in some states.6 Their review of industry-filed reports showed that for some facilities, releases from SSM events were actually higher than total annual “routine” emissions reported to either EPA’s Toxics Release Inventory (TRI) or state emission inventories for the entire facility for the entire year.7 EIP found that more than half of the 37 facilities studied had SSM emissions of at least one pollutant that were 25% or more of their total reported annual emissions of that pollutant. For ten of the facilities, upset emissions of at least one pollutant actually exceeded the annual emissions that each facility reported to the state for that pollutant. SSM emissions of carbon monoxide (CO) from Exxon Mobil’s Baton Rouge facility were almost three times its reported annual CO emissions.8 More recent examples of SSM emissions include releases of hazardous air pollutants (HAPs) reported in 2006 by the Premcor Refining Group Inc.’s “Valero” oil refinery in Port Arthur, Texas; Motiva Enterprises’ Port Arthur Refinery; and Total Petrochemicals’ Port Arthur Refinery. Specifically, the Premcor refinery released nearly 4 tons of HAPs during one single “air emissions event”; the Motiva refinery released

6 See “Gaming the System – How Off-the-Books Industrial Upset Emissions Cheat the Public Out of Clean Air” (EIP, August 2004), available at http://www.environmentalintegrity.org/pubs/EIP_upsets_report_FULL.pdf (hereinafter “Gaming the System”). 7 In addition, studies have shown that wind and other factors can reduce flare combustion efficiencies, which means that, although refineries typically estimate flare efficiency at 98 – 99%, more pollution is actually being released to the environment instead of being destroyed during combustion. See, e.g., “Reducing Flare Emissions from Chemical Plants and Refineries – An Analysis of Industrial Flares’ Contribution to the Gulf Coast Region’s Air Pollution Problem,” Industry Professionals for Clean Air (“IPCA”), May 23, 2005, available at http://www.ipcahouston.org/files/IPCA_Flare_Report2005.pdf; and Robert E. Levy, Lucy Randel, Meg Healy and Don Weaver, “Reducing Emissions from Flares – Paper # 61,” Industry Professionals for Clean Air (“IPCA”), April 24, 2006, available at http://www.ipcahouston.org/files/IPCA_Flare_AWMA2006.pdf. 8 Increased CO emissions indicate incomplete flare combustion, and therefore increased emissions of hazardous air pollutants (HAPs).

Madhurima D. Moulik March 24, 2008 Page 6 nearly 35 tons of HAPs in a single upset event; and the Total refinery released over 47 tons of HAPs in a single “air emissions event.” The referenced event reports from the Premcor, Motiva, and Total refineries are attached as Exhibits 7, 8, and 9 respectively. 9

Yet in the netting analysis, BP and IDEM simply did not count emissions from the three new flares at all. The only flare emissions it factored into the netting calculation were the miniscule amounts attributable to pilot gas and purge gas – which are the emissions when the flare is off. As explained by Ms. May, that makes as much sense as measuring fuel use in one’s home as the amount burned by the furnace pilot light. IDEM thus is credulously accepting BP’s dubious contention that it is constructing its 3 giant new flares with the intention of never using them. 10 In addition, as pointed out by Ms. May, the netting analysis fails to account for increased use of existing flares that will result from the Project, which is expressly designed to make use of them in specified circumstances. The assumption that no emissions can be expected to occur from use of the refinery flares is particularly incredible given BP Whiting’s numerous past flare-related violations in connection with the existing flares. These violations are documented in both compliance reports for the facility submitted to IDEM and in the USEPA NOV, and are described in greater detail in Ms. May’s report. For example, as documented in Ms. May’s report, deviation reports show that BP repeatedly exceeded the H2S 159 parts per million (ppm) 3-hour limit, meaning that too much H2S was burned in the flare. EPA limits H2S burned in the flare because when burned, H2S turns into harmful sulfur oxide emissions to the atmosphere. Clearly, the facility’s eight existing flares are not only very much in use at present, but in violation of applicable CAA requirements; and flaring at the facility is virtually certain to increase as a result of the Project. Moreover, H2S emissions during flaring events would increase relative to baseline flaring as the refinery will be processing higher sulfur Canadian tar sands crude oils. Additionally, as documented in Ms. May’s comments, the Permits expressly anticipate use of the flares in numerous places. Failure to account for flaring emissions is a direct violation of CAA regulations and Indiana’s State Implementation Plan, including the provisions requiring that emissions from startup, shutdown, and malfunction events – the circumstances under which flares are appropriately used – be factored into netting calculations. See 40 CFR 52.21(b)(41)(ii)(b)(“projected actual emissions” for PSD purposes “[s]hall include…emissions associated with startups, shutdowns, and malfunctions”); 326 Ind. Admin. Code. 2-2-1(rr)(2)(A)(ii) (same); 326 IAC 2-3-1(mm)(2)(A)(ii) (nonattainment

9 These “air emission event reports” can also be found at http://www.tceq.state.tx.us/compliance/field_ops/eer/index.html. 10 The USEPA, in its recently proposed New Source Performance Standards (NSPS) for Petroleum Refineries (72 Fed. Reg. 27178 (May 14, 2007)), candidly acknowledges that “many refineries … routinely use flares as an emission control device under normal operating conditions.” 72 Fed. Reg. at 27195. Even if BP only uses its flares in “emergency” situations, it is absurd to assume that such situations will never arise.

Madhurima D. Moulik March 24, 2008 Page 7 NSR). BP cannot simply omit these emissions from the netting calculations under the vague claim that “the CXHO project will improve overall reliability at the refinery and is anticipated to reduce emissions from startup, shutdown, and malfunction events” (Project Application at 3-17). Rather, it must quantify flaring emissions – including those from startup, shutdown and malfunction – in the flares’ potential to emit and clearly commit to creditable decreases in flaring emissions, i.e., decreases that, among other things, are enforceable as a practical matter and have approximately the same qualitative significance for public health and welfare as that attributed to the increase from the particular change. 326 IAC 2-2-1(jj)(6)(B) and (C) (PSD creditable decreases); 326 IAC 2-3-1(dd)(6)(B) and (C) (nonattainment creditable decreases). For example, creditable decreases for flaring cannot be spread out over long time periods where increased emissions from flaring would occur in a single day, as the decreases would fail to protect short-term air quality. We note, in any event, that even if it were true that overall reliability will improve, the change in crude slate would still increase emissions of at least SO2, PM10, PM2.5 and perhaps of other pollutants. Based on Ms. May’s evaluation, the project will exceed significance levels for all regulated NSR pollutants once flaring emissions are properly added.

B. The Netting Analysis Failed to Account for Other Emissions Sources As discussed above, the exceedingly brief timeframe for review provided by IDEM precludes a thorough review of the netting analysis conducted in support of the Permits. Thus, it is simply not possible to present here a comprehensive listing of all problems and deficiencies in such analysis. Nonetheless, the limited review that has been possible in the brief time afforded us reveals multiple emissions sources in addition to flares that were not factored into the netting calculation. Specifically, the analysis fails to consider (1) venting of uncontrolled pressure relief devices (PRDs), which can release up to 100 tons of VOCs at once; (2) uncontrolled cargos of petroleum products loaded onto marine vessels, which can emit many tons of pollutants per day; (3) residual emissions from vessel depressurization, after a portion of the contents of process vessels have been sent to refinery recovery systems; (4) increased coking, which is virtually certain to increase emissions of particulate matter, SOx, VOCs, heavy metals, and other pollutants; (5) wastewater ponds and their systems, which have significant air emissions that may be increased as a result of the Project; (6) coke drum depressurization, which emits large amounts of PM, PM10, and VOCs; and (7) fugitive emissions of reduced sulfur compounds. Some of these are discussed in Ms. May’s comments, and others are discussed further below. All of these additional types of emissions must be included in the netting calculation. A permit may not issue based on this incomplete analysis, and BP’s application should be determined incomplete until the company provides the information necessary to correct the netting calculations.

Madhurima D. Moulik March 24, 2008 Page 8

a. Coke Drum Depressurization Emissions Omitted

In the coker, vacuum residuum is heated in three 208 MMBtu/hr feed heaters to 900 to 940 F and fed into six coke drums. The residuum remains in the coke drums under a pressure of 30 to 60 psig for about 12 hours.11 The lighter materials boil off and are separated into byproducts. The coke drums fill up with solid coke. At the end of the 12 hours, the drums are stripped with steam to remove remaining hydrocarbons, cooled with water, and depressurized. Ap. p. 2-2. Typically, when the coke drum pressure drops below about 5 psig, the line from the coke drum to the coker blowdown section is closed and the coke drum vent line to atmosphere is opened, venting steam and reducing the drum pressure.

The South Coast Air Quality Management District (“SCAQMD”) has measured

depressurization emissions from all refineries within its jurisdiction and is proposing to initiate a rulemaking to control these emissions.12 These emissions are viewed as considerable.13 See, for example, the test report from Chevron’s El Segundo Refinery.14 This test report measured 13.75 lb of total PM and 11.16 lb of VOCs per depressurization event. The increase in the number of such events that would occur per day at BP Whiting was not reported in the Application. However, the Application indicates that the Project would increase coke production from 1,638 ton/day to 6,000 ton/day. TSD, p. 4. Assuming 1,000 ton per drum, the Project would increase the number of depressurization events by over four per day. Thus, depressurization venting alone would increase total PM emissions by at least 10 ton/yr and VOC emissions by 8 ton/yr.

Actual emissions are likely much higher. The Test Report summary table notes:

"All mass emissions results are biased low; See Test Critique." Test Report, p. 3. The Test Critique explains that "the reported emissions reflect an inherent low bias and potentially a large low bias... As such, the emissions should be considered as greater than reported. Furthermore...the emissions are at least that which was reported." Test Report, p. 12.

b. Coke Drum VOC And PM10 Decoking Emissions Omitted After the coke drums are depressurized, the tops and bottoms of the drums are

removed, water is drained from the coke, and high-pressure water drilling is used to break up and remove coke from the drums. The Application did not disclose that there were 11 The actual residence time is not disclosed in the Application. This is a typical estimate. 12 Telephone communication with Bob Sanford, May 11, 2006. 13 E-mail chain, Sanford to various parties, March 22, 2006. Aarni say to Sanford: “the magnitude of the emissions surprised me as well.” And Sanford replies to Aarni: “The Magnitude of the PM and VOC emissions during coke drum depressurization caught me by surprise.” 14 South Coast Air Quality Management District, Volatile Organic Compound (VOC), Carbon Monoxide, and Particulate Matter (PM) Emissions from a Coke Drum Steam Vent, Source Test Report 03-194, Conducted at Chevron/Texaco Refinery, El Segundo, CA, January 23, 2003

Madhurima D. Moulik March 24, 2008 Page 9 emissions from this process nor include them in the netting calculations that we can discern.

The depressurization Test Report discussed above explains that the coke drums

continue to emit after they have been depressurized: After the blow down period [which was tested], the top drum head is removed and continues to remain open for a period of time longer than the vent period to allow further cooling. After cooling, the coke is cut from the drum. It was observed that emissions occurred during these events similar to the blow down event, as indicated by a visible steam and an emissions plume comparable in appearance and odor to those that were tested during venting. These emissions were not tested nor included in the Results section of this report. Based on observation of these plumes, these emissions may be significant or possibly more significant than those that were tested.

Test Report, p. 13 (highlighting in original). Thus, PM10 and VOC emissions from further cooling and decoking could be roughly comparable to those from depressurization. Making the corrections discussed above, further cooling and decoking could double or more the depressurization emissions.

c. Fugitive Sulfur Emissions Omitted

Hydrogen sulfide (H2S) and reduced sulfur compounds, including H2S, are PSD

pollutants. Fugitive sources, such as leaks from valves, connectors, flanges, pumps, compressors, and tanks are typically major sources of reduced sulfur compounds including H2S at refineries. The Project will substantially increase the amount of reduced sulfur compounds formed in all existing processing units because the Project is designed to change the crude slate to process high sulfur Canadian tar sands. Further, reduced sulfur compounds including H2S will be emitted from fugitive components in the new units. The Application did not include reduced sulfur including H2S emissions from leaks from fugitive sources.

The coking process, for example, produces high concentrations of H2S and other

reduced sulfur compounds. The coke drum vapors are about 5% H2S by weight.15 The depressurization, cooling, and decoking operations discussed above also emit H2S and other reduced sulfur compounds. These compounds would also be emitted in high concentrations from all fugitive components in the Coker, including valves, connectors, and pumps. The Application did not disclose that the coke drums would emit H2S.

15 Tesoro Petroleum, Material Safety Data Sheet, Coke Drum Vapors, February 18, 2005; South Coast Air Quality Management District, Mobil Oil Corporation, Torrance Refinery, Reformulated Gasoline (RFG) Project, Environmental Impact Report, Risk of Upset, August 1993, Table 5.

Madhurima D. Moulik March 24, 2008 Page 10

C. The Netting Analysis Inappropriately Used Emission Factors to Calculate Baseline Emissions

BP relied on emission factors to calculate baseline emissions for purposes of

netting. See, e.g., Permit Application Sections 3.2.1.1 (VOCs from new heaters), 3.2.1.4 (Particulate Matter from new heaters), 3.2.1.6 (lead from new heaters), 3.2.1.7 (mercury from new heaters), 3.2.1.8 (beryllium from new heaters), 3.2.2 (AP-42 factors used for VOC, NOX, SO2, PM/PM10/PM2.5, CO, and lead from sulfur recovery unit), 3.2.3.2 (Particulate Matter from cooling towers), 3.2.4.1 (fugitive emissions from material handling), and 3.3.1.1 (baseline actual emissions for existing units calculated from, among other things, AP-42 emission factors) and generally Appendix C. This reliance on emission factors in calculating baseline emissions, such as those contained in U.S. EPA’s AP-42, is improper. In particular, we note that many of the USEPA emission factors that were relied on had a quality rating of D, which is below average.

Increases and decreases used to determine the “net emissions increase” for any regulated NSR pollutant must be calculated using “baseline actual emissions.” 326 IAC 2-2-1(jj)(1)(B) (PSD) (emphasis added); 326 IAC 2-3-1(dd)(1)(B) (nonattainment NSR). For an existing refinery, baseline actual emissions means “the average rate, in tons per year, at which the emissions unit actually emitted the pollutant during any consecutive twenty-four (24) month period” during a preceding ten year period. 326 IAC 2-2-1(e)(2); 326 IAC 2-3-1(d)(1). Baseline actual emissions thus must be based on actual testing data from the unit or a similar unit, i.e., a unit’s actual operating hours, production rates, and types of material processed, stored or combusted during the selected period. In other words, actual emissions must be based on measurement or other concrete, source-specific evidence, and not on industry-wide average emission factors.

Indeed, the introduction to AP-42 indicates that the resource’s emission factors should not be used as a first course for purposes of calculating baseline actual emissions. See AP-42, “Introduction” (1995) (“Data from source-specific emission tests or continuous emission monitors are usually preferred for estimating a source’s emissions because those data provide the best representation of the tested source’s emissions.”) As AP-42 states,

Emission factors in AP-42 are neither EPA-recommended emission limits (e. g., best available control technology or BACT, or lowest achievable emission rate or LAER) nor standards (e. g., National Emission Standard for Hazardous Air Pollutants or NESHAP, or New Source Performance Standards or NSPS). Use of these factors as source-specific permit limits and/or as emission regulation compliance determinations is not recommended by EPA. Because emission factors essentially represent an average of a range of emission rates, approximately half of the subject sources will have emission rates greater than the emission factor and the other half will have emission rates less than the factor… source-specific tests or continuous emission monitors can determine the actual pollutant contribution from an existing source better than can emission factors…To

Madhurima D. Moulik March 24, 2008 Page 11

provide the best estimate of longer-term (e. g., yearly or typical day) emissions, these conditions should be representative of the source’s routine operations.

AP-42, “Uses of Emissions Factors” (1995).

BP therefore must recalculate its emissions using actual data from the facility.

II. The Permits Do Not Include Proper BACT/LAER Limits For Flares and other Sources

Indiana Administrative Code requires that the air pollution control board and the department safeguard the air resource through the prevention, abatement, and control of air pollution by “all practical and economically feasible methods.” IC-13-17-1. These Permits fall woefully short of this mandate. Once BP corrects the netting calculations, it is almost a certainty that the Project will trigger full NSR for all regulated NSR pollutants. The Project therefore will be subject to BACT and LAER requirements, as well as requirements for air quality modeling.16 As noted above, providing comments on BACT or LAER for every aspect of the facility in the absence of such an analysis from BP or IDEM is beyond the scope of these comments, as is conducting an air quality assessment where none has been done. We instead focus primarily on BACT/LAER for flaring, one of the most egregious sources of pollutants from the expansion that can be controlled through readily available measures, and briefly summarize other BACT/LAER deficiencies. A. Flaring BACT/LAER The specific measures that BP and IDEM have failed to implement concerning flare minimization performance are available for other refineries that have actually implemented the type of stringent measures required as BACT and LAER. The Bay Area refineries where enormous flare emissions cited in Ms. May’s report were recorded have succeeded in achieving large and quantifiable reductions in flare emissions through readily available measures to prevent flaring. These measures include both structural improvements such as additional compressor capacity; other flare prevention measures to be established in an enforceable flare minimization plan, including work practices that reduce the frequency of flaring events; and heightened monitoring and observation requirements essential to the efficacy of flare prevention measures.17

16 As discussed in Section III of these comments, Indiana law additionally prohibits the issuance of a permit that is not “protective of public health.” See 326 IAC 2-1.1-5. This prohibition is independent of the requirement that permits ensure compliance with ambient air quality standards, PSD increments, and all other applicable air pollution control rules. Id. Thus, to the extent application of BACT and LAER controls are insufficient to protect public health, additional more stringent measures must be imposed. 17 Effective observation and monitoring requirements are in additionally necessary to ensure the enforceability of any flare minimization measures that may be imposed. USEPA New Source Review

Madhurima D. Moulik March 24, 2008 Page 12 In particular, the Tesoro-Avon refinery was able to drastically reduce its flare emissions through imposition of such readily-available measures. Similarly, the Shell refinery in Martinez, California has significantly reduced flaring and maintained lower flaring levels through implementation of such measures. In 2004, following implementation of those measures, Shell Martinez had no flaring events with SOx emissions greater than 1,000 lbs, and only one event with flaring emissions more than 500 lbs. Shell also had no flaring events with VOC emissions greater than 300 lbs. Shell’s low flaring emissions included emergency flaring. In later years, Shell reduced flaring even further. The flare control measures implemented at Shell Martinez – in conjunction with the Bay Area Air Quality Management District (BAAQMD) and other similar regulations requiring those measures – should, at minimum, be considered as BACT or LAER for reduction of flare emissions. Moreover, IDEM must either establish numeric BACT or LAER limits for flares, or must present a numeric evaluation of emissions reductions expected to be achieved through work practices. In In re Indeck-Elwood, LLC, PSD Appeal 03-04 (September 27, 2006), the USEPA Environmental Appeals Board (EAB) reiterated the principle that upset events are not only subject to BACT analysis, but that numeric BACT limits must be imposed, unless the permitting authority specifically sets forth the emission reductions expected to be achieved by the work practices approach, including “a comparative analysis of the emission reductions expected from the approach [the permitting agency] adopted and the reductions expected from the application of numeric limits.” Id. at 31. Although the Permits contain a number of provisions that concern flaring, it contains no actual limits of any kind on the frequency with which flares may be used, or on flaring emissions. These omissions are in violation of the BACT and LAER requirements. Moreover, these omissions also fail to limit the potential to emit to the assumed zero emissions assumed in the netting analysis. Finally, we note that failure to identify BACT and LAER flare control measures is particularly problematic in light of the fact, as documented in the USEPA NOV, that BP is in violation of its CAA requirement to install even minimally necessary monitoring equipment as required by CAA New Source Performance Standards (NSPS). See NOV (Ex. 12) at 10-12. The Permits must be revised to require both a schedule of compliance addressing the NSPS violations (as discussed below), and to implement the necessary BACT and LAER controls that are required above and beyond these basic NSPS requirements.

Workshop Manual (“NSR Manual”) at B.56. USEPA itself has acknowledged: “In the absence of effective monitoring, emissions limits can, in effect, be little more than paper requirements. Without meaningful monitoring data, the public, government agencies and facility officials are unable to fully assess a facility’s compliance with the Clean Air Act.” Initial Brief of Respondent United States Environmental Protection Agency, Appalachian Power Co. v. EPA, No. 98- 1512 (D.C. Cir., Oct. 25, 1999) quoted at 71 Fed. Reg. 75422, 75425 (Dec. 15, 2006).

Madhurima D. Moulik March 24, 2008 Page 13 B. Other BACT/LAER Issues The draft Permit fails to require all practical and economically feasible control methods for virtually all new emission units and modifications of existing emission units. These include the following:

• SCR should be used on all combustion sources with a firing rate of 50 MMBtu/hr or more, designed to remove 90% of the NOx;

• SCR should be used on FCUs regenerator gases, designed to remove 90% of the NOx;

• Oxidation catalysts should be used on all combustion sources with a firing rate of 50 MMBtu/hr or more, designed to remove at least 90% of the CO and 50% of the VOC;

• Pall filters should be used on the FCU regenerator gases, designed to remove 99.99% of the PM;

• A scrubber should be used on the FCU regenerator gases, designed to remove >95% of the SO2;

• Fuel sulfur content should be limited to no more than 20 ppmv total sulfur, expressed as H2S on a 4-hour average, achievable using Sulfatreat and other sulfur removal technologies;

• Cooling towers should be equipped with drift eliminators, designed with a 0.0005% drift rate;

• A wet electrostatic precipitator should be used to control sulfuric acid mist emissions from the sulfur recovery units;

• Leakless components should be used where available;

• Tanks should be vented to a vapor recovery system designed to remove >99% of the hydrocarbon vapors.

III. BP and IDEM Failed to Account for Increased Greenhouse Gases from the

Project and to Conduct GHG BACT Analyses as Required by the CAA

As documented by Ms. May in her attached report, the Project will result in a very large increase in emission of greenhouse gases, most notably CO2, in part because of the processing of heavy crude oil extracted from the Canadian tar sands. Tar sands, with their long carbon chains, require more energy to refine than conventional crude oil. BP declined to conduct any greenhouse gas (GHG) emission analysis in its application for the Project. However, as noted in the report, the company has publicly admitted that post-project emissions of GHGs will be 5.8 million tons annually, including an increase in carbon dioxide of 1.5 to 2 million tons per year from the expansion alone. Via the Project, the Whiting facility is effectively moving to a much more energy-intensive process to create the same product.

Madhurima D. Moulik March 24, 2008 Page 14

BP must at a minimum meet CAA requirements to assess the quantity of GHGs

from the expansion and conduct BACT analysis for all refinery GHG sources. As discussed below, the expected increase in GHG emissions is greater than the PSD significance threshold, which is any emissions of each GHG. IDEM nonetheless failed to include BACT limits on increases in any of the GHGs expected from the expansion. Indeed, the Permits contain no GHG reduction commitments at all. This failure is in violation of the CAA, even more so following this year’s U.S. Supreme Court ruling in Massachusetts v. EPA, 127 S.Ct. 1438, 1460 (2007), holding that CO2 and other greenhouse gases are “pollutants” under the CAA. The draft Permits must be revised to include such limits. In addition, under state law, GHG emissions that will occur after application of BACT must be offset to protect the public health.

We find BP’s failure to comply with these requirements, and to implement measures that will curtail GHG emissions from the Project, particularly unfortunate in light of the Company’s pronouncements concerning not only the importance of limiting GHG emissions that cause global warming, but also (as discussed below) the availability of measures by which to do so at its refineries.

The Permits may not issue without BACT limits and offsets for GHGs, and IDEM must declare BP’s application incomplete until sufficient information to conduct BACT and offset analyses concerning GHGs is provided. BP must provide this information not only to comply with the requirements of the CAA, but to fulfill its public commitment to GHG emission reduction.

A. The US Supreme Court has Held that CO2 is a CAA “Pollutant”

On April 2, 2007, the United States Supreme Court issued its landmark ruling in Massachusetts v. EPA, overturning USEPA’s long-held position that GHGs are not CAA “pollutants.” 127 S.Ct. at 1460. Because USEPA believed that Congress did not intend it to regulate substances that contribute to climate change, the agency maintained that carbon dioxide is not an “air pollutant” within the meaning of the provision. The Court found that the statutory text forecloses USEPA's reading. The Act's sweeping definition of “air pollutant” includes “any air pollution agent or combination of such agents, including any physical, chemical ... substance or matter which is emitted into or otherwise enters the ambient air....” 42 U.S.C. § 7602(g) (emphasis added). On its face, the definition embraces all airborne compounds of whatever stripe, and underscores that intent through the repeated use of the word “any.” Carbon dioxide is without a doubt a “physical [and] chemical ... substance which is emitted into ... the ambient air.” The statute is unambiguous. In ruling that carbon dioxide is a pollutant, and therefore “subject to regulation under the Act,” the Court also made clear the obligation for permitting agencies to include carbon dioxide and other GHG emission limits in PSD permits. 40 C.F.R. § 52.21(b)(50)(iv).

Madhurima D. Moulik March 24, 2008 Page 15

B. The CAA PSD Provisions Require BACT For Each Pollutant “Subject to Regulation”

The Clean Air Act prohibits the construction of a new major stationary source of

air pollutants except in accordance with a PSD construction permit. 42 U.S.C. § 7475(a); 40 C.F.R. § 52.21(a)(2)(iii). A PSD permit must include a BACT limit “for each pollutant subject to regulation under [the CAA]” for which emissions exceed specified significance levels. 42 U.S.C. §§ 7475(a), 7479; 40 C.F.R. §§ 52.21(b)(1), (b)(2), (b)(12), (b)(50), (j)(2). BACT is further required “for each regulated NSR pollutant that [a source] would have the potential to emit in significant amounts.” 40 C.F.R. § 52.21(j)(1). For any regulated NSR pollutant that is not listed in the table at 40 C.F.R. § 52.21(b)(23)(i), a significant rate is “any net emission increase.” 40 C.F.R. § 52.21(b)(23)(ii) (emphasis added).

Section 52.21(b)(50), in turn, defines “Regulated NSR pollutant” as:

(i) Any pollutant for which a national ambient air quality standard has been promulgated and any constituents or precursors for such pollutants identified by the Administrator (e.g., volatile organic compounds are precursors for ozone);

(ii) Any pollutant that is subject to any standard promulgated under Section 111 of the Act;

(iii) Any Class I or Class II substance subject to a standard promulgated under or established by title VI of the Act; or

(iv) Any pollutant that otherwise is subject to regulation under the Act; except that any or all hazardous air pollutants either listed in section 112 of the Act or added to the list pursuant to section 112(b)(2) of the Act, which have not been delisted pursuant to section 112(b)(3) of the Act, are not regulated NSR pollutants unless the listed hazardous air pollutant is also regulated as a constituent or precursor of a general pollutant listed under section 108 of the Act.

40 C.F.R. § 52.21(b)(50). See 326 Ind.Admin.Code 2-2-1(uu). The regulatory definition of BACT similarly applies to all air pollutants “subject to regulation” under the Act:

Best available control technology means an emissions limitation (including a visible emission standard) based on the maximum degree of reduction for each pollutant subject to regulation under Act which would be emitted from any proposed major stationary source or major modification which the Administrator, on a case-by-case basis, taking into account energy, environmental, and economic impacts and other costs, determines is achievable for such source or modification through application of production processes or available methods, systems, and techniques, including fuel cleaning or treatment or innovative fuel combustion techniques for control of such pollutant.

Madhurima D. Moulik March 24, 2008 Page 16

40 C.F.R. § 52.21(b)(12) (emphasis added); see also 42 U.S.C. 7479(3). In short, a PSD permit must include a BACT limit for each pollutant subject to regulation.

C. The Significance Level for Carbon Dioxide and Other GHGs is Any Amount Above Zero

The significance level triggering PSD applicability for a regulated NSR pollutant,

other than the 15 listed in 40 C.F.R. § 52.21(b)(23)(i), is any net increase. 40 C.F.R. § 52.21(b)(23)(ii). CO2 is not among the 15 pollutants listed in 40 C.F.R. § 52.21(b)(23)(i), nor does the list include other GHGs. Therefore, because CO2 and other GHGs are regulated NSR pollutants, as shown below, any increase in emissions is significant and requires a BACT limit. 42 U.S.C. §§ 7475(a)(1), (4), 7479(3); 40 C.F.R. §§ 52.21(j)(2), 52.21(b)(23)(ii). The Project will have the potential to significantly increase emissions of CO2 - clearly meeting the requirement for “any” emission rate increase – and to increase other GHGs, also meeting the “any” emission increase bar. .

D. Carbon Dioxide is a Pollutant That is “Subject to Regulation” Under the CAA

As discussed above, CO2 is a “pollutant,” as that term is used in the CAA and the PSD regulations. Massachusetts v. EPA, 127 S.Ct. at 1460 (emphasis in original). Additionally, the term “subject to regulation,” as that term is used in the Act and the PSD regulations, means not only pollutants that are currently regulated, but pollutants for which EPA and the states possess but have not exercised authority to impose requirements. Notably, CO2 meets either test – it is currently regulated and is potentially regulated even further under the Act.

1. CO2 is Currently Regulated Under the CAA Acid Rain Provisions Even if the term “subject to regulation” in the Act and 40 C.F.R. § 52.21(b)(50)

were limited to pollutants that are currently regulated under an existing Clean Air Act provision, a BACT limit for carbon dioxide is required. CO2 is currently regulated under the Clean Air Act’s acid rain provisions.

Section 821 of the CAA Amendments of 1990 directed EPA to promulgate

regulations to require specified sources to monitor CO2 emissions and report monitoring data to EPA. 42 U.S.C. § 7651k. In 1993, USEPA promulgated such regulations, which are set forth at 40 C.F.R. Part 75. The regulations generally require monitoring of CO2 emissions through the installation, certification, operation and maintenance of a continuous emission monitoring system or an alternative method (40 C.F.R. §§ 75.1(b), 75.10(a)(3)); preparation and maintenance of a monitoring plan (40 C.F.R. § 75.33); maintenance of certain records (40 C.F.R. § 75.57); and reporting of certain information to EPA, including electronic quarterly reports of CO2 emissions data (40 C.F.R. §§ 75.60 – 64). Section 75.5 prohibits operation of an affected source in the absence of compliance with the substantive requirements of Part 75, and provides that a violation of any requirement of Part 75 is a violation of the CAA. 40 C.F.R. § 75.5; see also Buckley v.

Madhurima D. Moulik March 24, 2008 Page 17 Valeo, 424 U.S. 1, 66-67 (1976) (finding record keeping and reporting requirements to be regulation, albeit permissible regulation, of political speech). Thus, CO2 is already regulated under the Act as part of the Acid Rain provisions.

2. CO2 is Subject to Further Regulation Under the CAA.

Moreover, a current limit on CO2 is unnecessary for it to be “subject to”

regulation under the CAA. “Subject to” means “capable of being regulated” and not “currently regulated.” USEPA itself has recognized the general principle that “[t]echnically, a pollutant is considered regulated once it is subject to regulation under the CAA. A pollutant need not be specifically regulated by a section 111 or 112 standard to be considered regulated. (See 61 FR 38250, 38309, July 23, 1996.)” 40 C.F.R. Part 70, 66 Fed. Reg. 59161, 59163 (Nov. 27, 2001) (Change to Definition of Major Source) 66 Fed. Reg. 59161 (Nov. 27, 2001) (emphasis added).18 Also, USEPA has previously interpreted the phrase “subject to” in the context of the Resource Conservation and Recovery Act (RCRA) and Clean Water Act as meaning “should” be regulated, as opposed to currently regulated:

RCRA section 1004(27) excludes from the definition of solid waste “solid or dissolved materials in … industrial discharges which are point sources subject to permits under [section 402 of the Clean Water Act].” For the purposes of the RCRA program, EPA has consistently interpreted the language “point sources subject to permits under [section 402 of the Clean Water Act]” to mean point sources that should have a NPDES permit in place, whether in fact they do or not. Under EPA’s interpretation of the “subject to” language, a facility that should, but does not, have the proper NPDES permit is in violation of the CWA, not RCRA.

Memo from Michael Shapiro and Lisa Friedman (OGC) to Waste Management Division Directors, Interpretation of Industrial Wastewater Discharge Exclusion from the Definition of Solid Waste at 2, (Feb. 17, 1995) (emphasis added).

Under both Sections 111 and 202, CO2 can be regulated and, indeed, should be regulated. Section 202 of the CAA requires USEPA to set standards applicable to emissions of “any air pollutant” from motor vehicles, and Section 111 requires USEPA to establish standards of performance for emissions of “air pollutants” from new stationary sources, where air pollution “may reasonably be anticipated to endanger public health or welfare.”19 42 U.S.C. § 7411(b)(1)(A); 42 U.S.C. § 7521(a)(1).20 18 Indeed, this principle only makes sense. For example, section 112(b) of the Act specifically lists more than 180 chemicals to be regulated as hazardous air pollutants from stationary sources under section 112. However, whether or not EPA ever adopts any stationary source rule with actual emission limitations for an individual chemical, all of these chemicals are “subject to regulation” under the Act (they are however expressly excluded from NSR/PSD). In the wake of the Supreme Court’s recent decision, CO2 must similarly be understood as “subject to regulation.” 19 Without a doubt, emission of GHGs such as CO2 are a threat to public health and welfare nationwide, including and especially in Indiana. See section III.G of this comment. See also George L. King et al., “Confronting Climate Change in the Great Lakes Region,” Union of Concerned Scientists 2003 (available

Madhurima D. Moulik March 24, 2008 Page 18

USEPA’s failure, thus far, to establish specific emission limits for CO2 under these two programs is not determinative of whether these GHGs are “subject to regulation.” However, it is notable that this failure to establish emission limits is the subject of pending legal actions against the agency. For example, USEPA’s failure to establish CO2 emission limits for stationary sources under Section 111 is pending before the United States Court of Appeals for the District of Columbia. State of New York, et al. v. EPA, No. 06-1322.

Additionally, on May 14, 2007, President Bush issued an Executive Order

confirming the Supreme Court’s ruling that USEPA can regulate greenhouse gases, including CO2, from motor vehicles, nonroad vehicles and nonroad engines under the Clean Air Act.21 The Executive Order directs USEPA to coordinate with other federal agencies in undertaking such regulatory action. The President’s action indicates the Chief Executive is also of the opinion that carbon dioxide is subject to regulation under the Clean Air Act.

at http://www.ucsusa.org/greatlakes/glchallengereport.html) and Indiana State Summary (available at http://www.ucsusa.org/assets/documents/global_warming/ucssummaryINfinal.pdf) (both incorporated by reference). According to these reports, among other things, water levels in Indiana are expected to decline in both inland lakes and Lake Michigan as a result of climate change, as more moisture evaporates due to warmer temperatures and less ice cover. Moreover, reduced summer water levels are likely to diminish the recharge of groundwater and cause small streams to dry up – thereby increasing the pressure to extract more water from the Great Lakes. The duration of summer stratification of lakes will increase, adding to the risk of oxygen depletion and formation of deep-water “dead zones” for fish and other organisms. 20 In other contexts USEPA has specifically acknowledged that the impact of methane on global warming is an important consideration for potential new sources. See Letter from EPA Region 8 to Charles Richmond, Forest Supervisor Gunnison National Forest (June 1, 2007) (attached as Exhibit 11). This letter relates to an Environmental Impact Statement regarding a proposal to drill 168 methane drainage wells at the West Elk Mine in Gunnison County, Colorado. In this letter, the Deputy Regional Administrator explains:

The draft EIS does not present information on the amount of methane that is expected to be released from the proposed action . . . As indicated on EPA’s website, methane is a greenhouse gas that remains in the atmosphere for approximately 9-15 years and is over 20 time more effective in trapping heat in the atmosphere than carbon dioxide (CO2) over a 100-year period. Methane’s relatively short atmospheric lifetime, coupled with its potency as a greenhouse gas, makes it a candidate for mitigation global warming over the near-term (i.e., next 25 years or so). . . . Given the project’s release of significant quantities of methane, there is an important economic and environmental opportunity here to capture and utilize the methane resource. . . . [W]e recommend that the final EIS analyze measure for capturing all or part of the methane to be vented from the mine. . . . Methane capture and reuse is a reasonable alternative to the proposal of venting the methane to the atmosphere, and thus, we recommend that it be analyzed. . . . EPA believes that the information in the DEIS is insufficient and the missing information and analyses are substantial issues which must be resolved and disclosed in the Final Environmental Impact Statement.

21 See http://www.whitehouse.gov/news/releases/2007/05/20070514-2.html (last accessed March 20, 2008).

Madhurima D. Moulik March 24, 2008 Page 19

3. Other GHGs Such as Methane and Nitrous Oxide Are Also Subject to Regulation

The Massachusetts v. EPA decision was not limited to carbon dioxide, but

recognized that all greenhouse gases are “air pollutants” under the CAA. 127 S. Ct. at 1460 (“On its face, the definition [of air pollutant] embraces all airborne compounds of whatever stripe, and underscores that intent through the repeated use of the word "any." Carbon dioxide, methane, nitrous oxide, and hydrofluorocarbons are without a doubt ‘physical [and] chemical . . . substance[s] which [are] emitted into . . . the ambient air.’ The statute is unambiguous.”) Thus, for the same reasons as put forth above with regards to carbon dioxide, III.D.2, all greenhouse gases are subject to regulation.

E. BP Must Account for GHGs Emissions and the Permits Must Include Appropriate BACT Limits for GHGs

As CO2 is currently regulated under both the acid rain provisions of the CAA and

the Indiana SIP, it is a pollutant “subject to regulation” under the CAA. Additionally, because GHGs can and should be regulated under one or more additional Clean Air Act programs, including section 111 and 202, because they “may reasonably be anticipated to endanger public health or welfare,” they are “subject to regulation” under the Act. 42 U.S.C. §§ 7411(b)(1)(A), 7521(a)(1). Accordingly, the Permits for the Project should have included emissions estimations and BACT limits for all GHGs that the project will emit in “any” amount. IDEM thus should withdraw the draft Permits, require BP to submit the required supporting analyses, and establish appropriate BACT limits in the Permits.

F. Measures Are Readily Available To Control GHGs at the Whiting Refinery

Refinery companies themselves, including BP, have recognized that GHGs can be reduced at refineries. These reductions are available in particular through flare minimization which, as discussed above, is eminently achievable using available technology. A BP official made the following statement at Stanford University more than ten years ago:22

Our carbon dioxide emissions result from burning hydrocarbon fuels to produce heat and power, from flaring feed and product gases, and directly from the process of separation or transformation.

Now we want to go further.

We have to continue to improve the efficiency with which we use energy. . . .

We have already taken some steps in the right direction.

In Norway, for example, we've reduced flaring to less than 20% of 1991 levels, primarily as a result of very simple, low cost measures.

The operation there is now close to the technical minimum flare rate which is dictated by safety considerations.

22 Climate Change Speech, John Browne, Group Chief Executive, British Petroleum (BP America), Stanford University, 19 May 1997, available at http://dieoff.org/page106.htm.

Madhurima D. Moulik March 24, 2008 Page 20

Our experience in Norway is being transferred elsewhere - starting with fields in the UK sector of the North Sea and that should produce further progressive reductions in emissions. Our goal is to eliminate flaring except in emergencies.

According to the Climate Registry, a private non-profit organization originally formed by the State of California that serves as a voluntary GHG registry, flares account for approximately 3 percent of GHG emissions from a refinery. See Exhibit 13 (“Petroleum Refining Protocol Discussion Paper”). Still, three percent of 2 million tons per year means approximately 60,000 tons per year of GHGs, not an insignificant number.

The main sources of GHGs from refineries are stationary combustion, FCCU catalyst regeneration, and hydrogen process vent. Id. Numerous opportunities exist for reduction of GHGs from these and other sources. A useful starting point are the GHG mitigation measures from the Final Environmental Impact Report for the Chevron Energy and Hydrogen Renewal Project in Richmond, California (attached as Exhibit 14).23 A list of measures relevant to the Whiting Refinery is as follows:

• Engage energy efficiency engineers to conduct a thorough audit of fuel, electricity and natural gas use at the Refinery to identify potential energy savings and energy efficiency improvements, and implement those feasible measures identified.

• Replace stationary, non-emergency diesel internal combustion engines. • Retrofit or replace old process heaters to use new high efficiency burners, oxyfuel

(use of oxygen instead of air), advanced controls, and/or more heat recovery • Add/improve heat exchangers. • Replace existing CoGens with higher-efficiency units, or add CoGen units. • Replace stationary, non-emergency internal combustion engines with high

efficiency electric motors. Implement process efficiencies (e.g., control fouling in crude unit preheater train).

• Initiate carbon sequestration, capture and export. • any reduction measures recommended by the state agency for refineries.

To the extent that these measures have not or are not being conducted at the refinery or as a part of the expansion project, they should be considered in the required BACT analyses for GHGs, along with any other identified control options. Such audits, retrofits and equipment installations can provide much-needed jobs to the Indiana economy.

G. The Permit May Not Be Issued Unless GHG Emissions Are Limited Sufficiently to Protect Public Health

Indiana law prohibits the issuance of a permit that is not “protective of public health.” See 326 IAC 2-1.1-5. This prohibition is independent of the requirement that permits ensure compliance with ambient air quality standards, PSD increments, and all other applicable air pollution control rules.

23 The attachment provides an excerpt from the Response to Comments dated January 2008. The full FEIR documents are available at www.ci.richmond.ca.us/index.asp?NID=832

Madhurima D. Moulik March 24, 2008 Page 21

Given the relative difficulty in controlling GHGs from refineries due to the many and dispersed sources of GHGs, the Whiting refinery is likely to result in a significant volume of GHG emissions even after imposition of BACT. The public health threat associated with these climate change-causing GHGs is well documented. Regional concerns from global warming are presented in the U.S. Global Change Research Program’s report entitled Climate Change Impacts on the United States: The Potential Consequences of Climate Variability and Change (National Assessment).24 The report was authored by scientists from the U.S. Geological Survey, USDA Forest Service, and numerous universities across the nation. According to the report, the Midwest is likely to face grave problems in terms of water quantity and quality due to drought and increasing heavy precipitation events, as well as dangerous increases in temperature and increases in respiratory disease due to increased pollution accompanying high temperatures.25

Thus, since GHG emissions and the ensuing global warming effects clearly pose a

threat to the public’s health, both in Indiana and the rest of the country, the Permits must require whatever additional measures are necessary to mitigate that threat. 26 ELPC will be submitting additional comments concerning such measures.

IV. IDEM Failed to Conduct BACT Analysis for Increased PM2.5 Emissions From

the Project as Required by the CAA

The Permits impermissibly substitute regulation of PM10 for PM2.5.27 This surrogate approach not only violates the letter of the law, but fails to guarantee that increases in particulate matter from the project will be offset by qualitatively equal or less harmful reductions, in violation of state and federal “netting” regulations.

A. The Permits Must Directly Apply Nonattainment NSR Regulations to PM2.5

The proposed Whiting Refinery expansion will be located in an air quality control region designated nonattainment for ozone and fine particulate matter (PM2.5). 70 Fed.

24 National Assessment Synthesis Team (2001), available at http://globalchange.gov/pubs/nast_2000.html 25 See id., D. Eastering and T. Karl, Chapter 6, “Potential Consequences of Climates Variability and Change for the Midwestern United States,” pages 174 to 177 (“Water Resources” and “Great Lakes Water Diversion”), 182, and 186. 26 It is possible that these additional measures could include a component of GHG offsets, provided the offsets were appropriately crafted to address the Project’s anticipated lifetime GHG emissions. We note, in this regard, that even offsets of the increased GHGs directly associated with the proposed refinery expansion would not fully mitigate the overall global warming impact of the proposed Whiting refinery expansion. Extraction of the CXHO feedstock generates substantially more GHG emissions than extraction of conventional oil, as well as diminishing the boreal forest carbon sink. 26 See Woynillowicz, Dan. “Oil Sands Fever: The Environmental Implications of Canada’s Oil Sands Rush,” The Pembina Institute, November 2005, p. 19. 27 Technical Support Document (TSD) at 3 (“OAQ is following the U.S. EPA’s guidance to regulate PM10 emissions as a surrogate for PM2.5 emissions pursuant to the requirements of Emission Offset, 326 IAC 2-3.”)

Madhurima D. Moulik March 24, 2008 Page 22 Reg. 944 (Jan. 5, 2005).28 As the result of a formal rulemaking by USEPA, this designation determines the applicable NSR program unless and until USEPA redesignates the area or the designation is overturned by a court of law. See 326 IAC 2-3-2(a) (nonattainment NSR); 326 IAC 2-2-2(b) (PSD); 326 IAC 2-3-2(a) (emissions offset regulations apply to a major modification constructed in an area designated “as of the date of submittal of a complete application,” as nonattainment “for a pollutant for which the stationary source or modification is major”); 40 C.F.R. 81.300 (revision procedure for designations). Thus, the Permits must comply with the nonattainment NSR rules for PM2.5.

As USEPA notes, fine particles are believed to pose the “largest health risks,” due to their ability to lodge deeply in the lungs.29 PM2.5 is associated with aggravation of respiratory and cardiovascular disease, lung disease, asthma attacks, cardiovascular problems such as heart attack and arrhythmia, and even premature death.30 Children and the elderly are particularly susceptible to the negative impacts of PM2.5, the former because their immune and respiratory systems are still developing and the latter because their systems are weak and compromised. For these reasons, it is crucial that the Permits contain the appropriate and mandated direct limits on PM2.5. However, nowhere did BP or IDEM actually apply the nonattainment NSR requirements to the proposed project’s PM2.5 emissions. They instead treated PM2.5 as if it were PM10, then used the nonattainment NSR regulations for PM10 to address PM2.5: “OAQ is following the U.S. EPA’s guidance to regulate PM10 emissions as a surrogate for PM2.5 emissions pursuant to the requirements of Emission Offset, 326 IAC 2-3.” TSD at p. 3 of 32. This use of PM10 as a surrogate for PM2.5 violates federal and state law. BP must resubmit its permit application with a direct assessment of PM2.5, including application of nonattainment NSR requirements to the project’s PM2.5 emissions, and IDEM must reissue the Permits with appropriate direct limits on PM2.5.

B. Use of PM10 As a Surrogate for PM2.5 Violates Indiana and Federal Law Using PM10 as if it were PM2.5 violates federal and state law. The Clean Air Act contains specific requirements regarding areas whose air quality violates the National Ambient Air Quality Standards, or NAAQS.31 USEPA since 1997 has distinguished PM2.5 from PM10, most importantly by setting different NAAQS for each.32 Both the federal and Indiana NSR program treat PM2.5 and PM10 separately in terms of attainment designations in relation to these separate standards. Thus, the proposed Whiting Refinery will be located in an area designated as “attainment” for PM10 and nonattainment for PM2.5. 28 Commenters note that the nonattainment designation Federal Register notice is incorrectly cited in the TSD as 70 FR 943. 29 USEPA, “PM2.5 NAAQS Implementation,” available at www.epa.gov/ttnnaaqs/pm/pm25_index.html. 30 Id. 31 42 U.S.C. §§ 7501-7515. 32 62 Fed. Reg. 38652 (Jul. 18, 1997); 40 C.F.R. 50.6 (NAAQS for PM10); 40 C.F.R. 50.13 (NAAQS for PM2.5).

Madhurima D. Moulik March 24, 2008 Page 23 USEPA has expressly recognized that fine particles, or those less than 2.5 micrometers in diameter, are “very different” from coarse particles (from 2.5 to 10 micrometers) in terms of sources, characteristics, and potential health effects.33 These differences mean that states will have to “evaluate different sources for controls, to consider controls of one or more precursors in addition to direct PM emissions, and to adopt different control strategies” in order to implement the PM2.5 NAAQS compared to the PM10 NAAQS.34 Grounding these needs is the engineering reality that controls designed for capture of PM10 (consisting primarily of filterable particles) do not effectively capture PM2.5 (made up in large part of condensable particles). Indiana law prohibits IDEM from issuing a permit unless the permit is protective of the public health and will not cause or contribute to a violation of the NAAQS. 326 IAC 2-1.1-5(a)(1) and (4). In addition, the Indiana nonattainment offset provisions apply to a source that emits a “significant emissions increase” and “significant net emissions increase” of a “regulated NSR pollutant.” 326 IAC 2-3-2(c)(1). A “regulated NSR pollutant,” in turn, includes “any pollutant for which a national ambient air quality standard has been promulgated.” As stated above, USEPA has issued separate NAAQS for PM2.5 and PM10 based on the differences between them. BP and IDEM therefore must determine directly whether the project will result in a significant emissions increase and significant net emissions increase of PM2.5 to ensure protection of the public health and compliance with the NAAQS.

C. Under Indiana Law, a Significant Emissions Increase and Significant Net Emissions Increase in PM2.5 Triggers Nonattainment NSR

The agency must apply the regulation as written, which requires offsets where the source will result in a “significant emissions increase” and “significant net emissions increase.” 326 IAC 2-3-2(c)(1) (emphasis added). The lack of a numeric significance level for PM2.5 in the Indiana regulations does not absolve IDEM from determining directly whether the project will result in a significant emissions increase and significant net emissions increase. Rather, these numeric significance levels only apply to the pollutants listed at 326 IAC 2-3-1(qq) (“significant” in reference to a net emissions increase “to emit any of the following pollutants” (emphasis added)). If a numeric significance level were a prerequisite to determining whether a pollutant triggers offset requirements, the Indiana regulations would limit “significant” for all regulated NSR pollutants to the numeric list at 326 IAC 2-3-1(qq). The regulations instead state that this list only determines whether a significant emissions increase will occur for “a regulated NSR pollutant.” 326 IAC 2-3-1(rr) (emphasis added). Thus, a gap 33 USEPA, Fact Sheet: National Air Quality Standards for Fine Particles: Guidance for Designating Areas (Jul. 17, 1997); see also USEPA, Clean Air Fine Particle Implementation Rule (“Final PM2.5 Implementation Rule”), 72 Fed. Reg. 20586, 20599 (Apr. 25, 2007) (“PM2.5 also differs from PM10 in terms of atmospheric dispersion characteristics, chemical composition, and contribution from regional transport.”) 34 Final PM2.5 Implementation Rule, 72 Fed. Reg. 20586, 20589 (Apr. 25, 2007).

Madhurima D. Moulik March 24, 2008 Page 24 exists in the numeric significance levels – but not in the triggering provision itself. The triggering provision instead continues to require that BP and IDEM determine whether the project will result in a “significant emissions increase” and “significant net emissions increase” of PM2.5 to ensure protection of the PM2.5 NAAQS, due to the differences between PM2.5 and PM10 described above. No such determination of significance has occurred for PM2.5 from the Whiting Refinery, and thus the Permits cannot issue.

D. IDEM Cannot Rely on Guidance That Is In Conflict with Statutory and Regulatory Requirements, and is No Longer Technically Justified

IDEM based its decision to pretend that the expansion project’s PM2.5 emissions were PM10 on “U.S. EPA’s guidance to regulated PM10 emissions as a surrogate for PM2.5 emissions pursuant to the requirements of Emission Offset, 326 IAC 2-3.” TSD at 3 of 32. The TSD does not provide any additional explanation identifying this guidance or justification for the agency’s reliance on it. Therefore, these comments will address reliance on USEPA guidance in terms of the “Seitz Memo”35 and “Page Memo”36 of which Commenters are aware. Reliance on these documents, or any similar guidance, is improper and invalidates BP’s and IDEM’s so-called analysis of PM2.5. Reliance is improper for three primary reasons, as follows. First, IDEM cannot rely on USEPA guidance that does not have the force of law where, as here, that guidance is in conflict with statutory and regulatory requirements.37 As discussed above, federal and state law require BP and IDEM to analyze directly and directly ensure compliance with the PM2.5 NAAQS. The Seitz Memo clearly states that it does not bind states, local governments and the public as a matter of law. Second, USEPA’s recommended use of PM10 as a surrogate for PM2.5 expired by its own terms when USEPA published the final PM2.5 implementation rule in September 2007. The 1997 Seitz Memo provided interim guidance for implementing the new PM2.5 NAAQS. This now nearly ten-year-old memo stated that sources could use the PM10 surrogacy approach to meet NSR requirements until certain difficulties were resolved, most notably with respect to monitoring, emissions estimation, and air quality modeling. The more recent, but still dated for the purposes of the BP project, Page Memo reaffirmed the surrogacy approach specifically for nonattainment NSR. The Page Memo noted that U.S. EPA recommended using PM10 as a surrogate for PM2.5 “until [U.S. EPA] promulgate[s] the PM2.5 implementation rule.” Not more than six months later, USEPA published a proposed PM2.5 implementation rule. The proposed rule made clear that the surrogacy approach would expire when the proposed rule was finalized: 35 Memorandum of John S. Seitz, U.S. EPA, “Interim Implementation of New Source Review Requirements for PM2.5” (Oct. 23, 1997). 36 Memorandum of Stephen D. Page, “Implementation of New Source Review Requirements in PM-2.5 Nonattainment Areas” (Apr. 5, 2005). 37 See, e.g., Appalachian Power Co. v. E.P.A., 208 F.3d 1015, 1020 (D.C. Cir. 2000).

Madhurima D. Moulik March 24, 2008 Page 25

Once this PM2.5 implementation rule is finalized, States will have the necessary tools to implement a major NSR program for PM2.5. States will no longer be permitted to implement a nonattainment major NSR program for PM10 as a surrogate for the PM2.5 nonattainment major NSR program.

- - - - Under the Title V regulations, major sources have an obligation to include in their Title V permit applications all emissions for which the source is major and all emissions of regulated air pollutants. The definition of regulated air pollutant in 40 C.F.R. 70.2 includes any pollutant for which a NAAQS has been promulgated, which would include both PM10 and PM2.5. To date, some permitted entities have been using PM10 emissions as a surrogate for PM2.5 emissions. Upon promulgation of this rule, EPA will no longer accept the use of PM10 as a surrogate for PM2.5.38

BP and IDEM therefore had nearly two years notice that the surrogate approach was about to expire, well in advance of BP’s submission of its applications. Most notably, the company and agency had notice prior to the application version serving as the basis for the present Permits, submitted in the fall of 2007 many months after promulgation of the final PM2.5 rule. The April 2007 final rule clearly affirms USEPA’s rejection of the surrogacy approach: “the EPA will no longer accept the use of PM10 emissions information as a surrogate for PM2.5 emissions information given that both pollutants are regulated by a National Ambient Air Quality Standard and therefore are considered regulated air pollutants.”39 Reliance on guidance that USEPA itself has abandoned is in direct conflict with the NSR requirements. Third, technical difficulties in directly implementing the PM2.5 NAAQS that grounded the interim guidance back in 199740 have been resolved. USEPA itself noted in the preamble to the November 2005 Proposed PM2.5 Implementation Rule that these technical concerns have been resolved: “As discussed in this preamble, those difficulties have been resolved in most respects, and where they have not been, the proposal contains appropriate provisions to account for it.”41 USEPA also has included the PM2.5 algorithms in the AERMOD air quality computer modeling program, the recommended model for short distance air quality assessment, thus formally resolving the Seitz’ Memo’s concerns about PM2.5 modeling capabilities.42 Experts in other cases likewise

38 USEPA, Proposed Rule to Implement the Fine Particle National Ambient Air Quality Standards (“Proposed PM2.5 Implementation Rule”), 70 Fed. Reg. 65984, at 66043 and 66058 (Nov. 1, 2005) (emphasis added). 39 U.S. EPA, Final PM2.5 Implementation Rule, 72 Fed. Reg. 20586, 20660; see also id. at 20659-60 (listing circumstances necessitating the quantification of PM2.5 emissions). 40 See Seitz Memo at par. 1. 41 Proposed Rule To Implement the Fine Particle National Ambient Air Quality Standards, 70 Fed. Reg. 65984, 66043 (Nov. 1, 2005) (emphasis added). 42 See Revision to the Guideline on Air Quality Models: Adoption of a Preferred General Purpose (Flat

Madhurima D. Moulik March 24, 2008 Page 26 have demonstrated that the technical concerns behind the surrogacy approach have been resolved.43

E. The Permits Cannot Rely on Reductions in Less Harmful PM10 in Order to “Net Out” of Nonattainment NSR for PM2.5

Using PM10 as a surrogate for PM2.5 means that some increases in PM2.5 are likely to be offset by decreases in PM10. Such substitution of decreases in less harmful pollution for more harmful increases violates the federal and state nonattainment NSR “netting” provisions. BP and IDEM must instead only offset PM10 increases with PM10 decreases and PM2.5 increases with PM2.5 decreases. Direct offset of PM10 and PM2.5 with in-kind reductions will meet the requirement that the refinery not offset more harmful emission increases with less harmful emission decreases. Otherwise, the netting calculations for particulate matter are in error. In order to be creditable for netting purposes in a nonattainment area, a reduction in emissions at an existing unit must have “approximately the same qualitative significance for public health and welfare as that attributed to the increase from the particular change.” 326 IAC 2-3-1(dd)(3)(B)(v)(DD). This provision mirrors and must be at least as stringent as the parallel federal requirement, 40 C.F.R. § 51.166(b)(3)(vi)(c) (qualitative public health significance); see 40 C.F.R. 51.155(a)(7)(iv) (state implementation plan PSD provisions must be “more stringent than or at least as stringent in all respects” as the corresponding federal provision), whose purpose is to prevent proposed units from netting reductions in less harmful emissions against increases in more harmful emissions. 45 Fed Reg 52676 at Lexis p. 41 (1980).44 Thus, under both federal and Indiana law, a creditable reduction in emissions must be approximately as harmful, or less harmful, to public health and welfare than a proposed increase. As described above, USEPA has found that the health effects associated with PM2.5 differ significantly from those linked to PM10, and that PM2.5 poses the largest health risks. A ton of PM10 therefore is not qualitatively the same as a ton of PM2.5 regarding impacts on public health. Using PM10 as a surrogate for PM2.5 in the nonattainment netting calculations means that neither BP nor IDEM can show that increases in very harmful PM2.5 will be sufficiently mitigated by creditable decreases with respect to health. A search of the permit documents shows that IDEM nowhere made the required determination that any of the claimed decreases met the qualitative public health significance criteria, let alone that decreases solely in PM10 from the

and Complex Terrain) Dispersion Model and Other Revisions; Final Rule, 70 Fed. Reg. 68218, 68253 (Nov. 9, 2005) (adopting AERMOD as the “preferred model”) 43 See, e.g., Expert Report of Hal Taylor, “Feasibility of Conducting PM 2.5 BACT Analysis for the Highwood Generation Station,” submitted on behalf of Appellants, Montana Environmental Information Center and Citizens for Clean Energy, at 5-6, In the Matter of: Southern Montana Electric Generation and Transmission Cooperative – Highwood Generating Station, Air Quality Permit No. 3423 (Sept. 2007). 44 “By this provision, EPA seeks mainly to prevent an increase in emissions with considerable health and welfare significance from escaping review merely because of a contemporaneous decrease in less harmful emissions.” 45 Fed Reg 52676 at Lexis p. 41 (1980)

Madhurima D. Moulik March 24, 2008 Page 27

project are of the same qualitative public health significance as the increases in PM10 and PM2.5 taken separately. The netting determinations for particulate matter in general and PM2.5 in particular therefore are unsupported, and the Permits cannot issue. IV. BP and IDEM Have Provided Insufficient Information to Determine Whether

the Emissions Calculations Adequately Account for Higher Levels of Pollutants in Tar Sands Crude Oil

Crude oil extracted from Canadian tar sands, although still insufficiently studied in many respects, has been shown to contain higher levels of sulfur, nitrogen, harmful metals and other pollutants than conventional crude, and in some cases than other types of heavy crude. The application lacks any chemical composition data for the crudes that are currently processed and those that will be processed, preventing any meaningful of review of the impact of the change in crude slate on emissions. There is no way to tell from the information submitted by BP to IDEM whether BP took this fact into account in calculating its emissions. This is a critical omission, because factoring in this higher level of pollutants, to the extent that has not been done, could result in increased emissions that would trigger NSR requirements, including of hydrogen sulfide, reduced sulfur compounds, sulfuric acid mist, sulfur dioxide, lead, mercury, and beryllium, among others.. More generally, it is critical from a public health standpoint that the pollutant impact of refining tar sands crude be fully understood and appropriately controlled. As noted above, permits in Indiana must be “protective of public health,” independently from ensuring compliance with ambient air quality standards, PSD increments, and all other applicable air pollution control rules. 326 IAC 2-1.1-5. The permit thus must be based on a full accounting of these pollutants. Mercury is a potent neurotoxin. In addition, the U.S. EPA has determined that nickel refinery dust and nickel subsulfide are human carcinogens.45 According to one tar sands company, “The bitumen in the Canadian oil sands contains vanadium, nickel, and other metals in significantly larger quantities than occur in most other oils.”46 Nickel, vanadium and other metals occur in such high concentrations that companies are considering metals recovery from waste products.47

Concerning mercury, the most recent study on mercury in crude in Canada includes data for one bitumen blend coming out of Alberta (Hollebone and Yang,

45 See Agency for Toxic Substances and Disease Registry, “ToxFAQs for Nickel,” available at http://www.atsdr.cdc.gov/tfacts15.html#bookmark05 46 Rettger, P., Arnold, J., Brandenburg, B. and Felch, C. 2006. “THE LONG LAKE INTEGRATED UPGRADING PROJECT: STATUS REPORT and DISCUSSION OF SOOT PROCESSING.” GASIFICATION TECHNOLOGIES,” October 1 - 4, 2006. Washington, D.C., available at http://www.gasification.org/Docs/2006_Papers/29RETT-Paper.pdf 47 Rettger, P. et al. 2006. p. 6. See also GE Energy. Alma Rodarte. GTC 2006. Meeting the Challenges of Oil Sands.http://www.gasification.org/Docs/2006_Papers/31RODA.pdf

Madhurima D. Moulik March 24, 2008 Page 28 2007).48 Compared to conventional crudes from Canada, the bitumen blend had a higher mercury content (range 5.0 – 10.7 parts per billion (ppb)). The synthetic crude (i.e., upgraded bitumen) oil samples from Alberta had mercury generally in the range of 0.1 – 2.4 ppb, with one sample having a much higher mercury concentration than even the bitumen (43.6 ppb). For the most part, conventional crudes had concentrations below 2 ppb. Concerning nickel and vanadium, the table below includes information on nickel and vanadium content of various western Canadian crude oils. The figures below are approximate values – the concentrations of the metals vary through time, because there is variation in metal content within the tar sands deposits. The values below are averages of data published by Crudemonitor.ca (a data compilation concerning Canadian crude).49

10 As seen from the data in Table 1, bitumen blends, in general, have slightly higher nickel and vanadium contents than conventional Canadian heavy crudes, and significantly higher nickel and vanadium than conventional light and synthetic crudes. Globally, as seen in Table 2, compared to many heavy crudes Canadian bitumen blends have high nickel and vanadium contents.

48 Hollebone, B.P. and Yang, C.X. October 2007. Mercury in Crude Oil Refined in Canada. (Environment Canada) 49 Crudemonitor.ca. December 2007 Heavy Crude Report, available at http://www.crudemonitor.ca/archives/monthly/DecemberHeavy2007.pdf December Light Crude Report, available at http://www.crudemonitor.ca/archives/monthly/DecemberLight2007.pdf

Madhurima D. Moulik March 24, 2008 Page 29

It is entirely possible that tar sands crude contains elevated levels of other metals as well. Assay data that would shed light on the matter is not currently publicly available to our knowledge. Notwithstanding the above data indicating that metals content in tar sands crude may be significantly higher than levels in other types of crude, there is no information in the record indicating the basis for BP’s and IDEM’s emission assumptions. More to the point, there is no way to tell whether they used emission factors that are more appropriate to other types of crude containing lower metals content. The “Alternate Emission Factor” form submitted by BP makes reference to “site specific engineering estimate” and a published paper concerning lead and beryllium, but does not provide supporting documentation:

Madhurima D. Moulik March 24, 2008 Page 30

These higher metal concentrations will end up deposited on the coke and emitted when the coke is consumed or deposited on the FCU catalyst. In particular, it is likely that Fluid Catalytic Cracking Unit (FCU) emissions from catalyst regeneration create a link between the level of metals in tar sands crude and the level of emissions, since the amount of metals deposited on the catalyst (during coke formation) is related to the heavy metals in the feedstock.50 If more metal is present in the coke, there will presumably be

50 Jones, D. S. J. and Pujadó, Peter R. 2006. Handbook of Petroleum Processing, available at

Madhurima D. Moulik March 24, 2008 Page 31 more metals released when the coke is burned off the catalyst during regeneration; and also more metals in the coke byproduct, which will be released when the coke is burned as a fuel.. Yet neither BP’s application nor the Permits contain sufficient information as to how this link was quantified, if at all. Specifically with respect to mercury, BP’s emissions factor for mercury from its FCUs is based on “engineering estimates,” which are not provided in the Alternative Emissions Factor Request form set forth above. While emissions from the FCUs are correlated with the mercury content of the expected crude feedstock (i.e., tar sands bitumen), it is impossible to confirm that, and assess its significance for the Project’s emissions, unless we can get the technical documentation for this engineering estimate from BP. We note in addition that when USEPA promulgated its National Emission Standards for Hazardous Air Pollutants for Petroleum Refineries, mercury from CCU catalyst regeneration vents was not included in the rule. After conducting a review of available data and technology, EPA concluded, “There are a number of emerging technologies (such as activated carbon injection) but none have been show to be applicable to CCU catalyst regeneration vents. Therefore, the MACT floor for Hg is determined to be no control for both new and existing units.”51 In other words, the mercury that is burned off during catalyst regeneration is being emitted uncontrolled. In the absence of MACT controls for these sources, IDEM should, at minimum, require that mercury emissions from catalyst regeneration vents be monitored using DIAL or other appropriate technology.52 Additionally, as a general matter, it is not ascertainable from the record whether BP and IDEM considered that the more intensive processing required for refining of tar sands crude may increase pollutant generation regardless of feedstock pollutant content. http://books.google.com/books?id=D6pb1Yn0vYoC&printsec=frontcover&dq=Handbook+of+Petroleum+Proce ssing&ei=CB3PR9HCC5q6tgPZ9fSkBQ&sig=eEXrFItiOf13KZ0gUGvywJfdBjU “Processing heavier feeds poses challenges to the normal FCC design due to the higher coke laydown on the catalyst during the cracking reactions. . . heavy metals that lay down on the catalyst surface promote dehydrogenation and lead to extra coke and hydrogen. Nickel, vanadium and iron are the main contaminates though occasionally copper, zinc and lead have been known to cause problems.” (p. 258) 51 “National Emission Standards for Hazardous Air Pollutants for Source Categories; National Emission Standards for Hazardous Air Pollutants From Petroleum Refineries—Catalytic Cracking (Fluid and Other) Units, Catalytic Reforming Units, and Sulfur Plant Units; Proposed Rule.” 63 FR 48890, 48901 (September 11, 1998). See Mercury In Petroleum And Natural Gas: Estimation Of Emissions From Production, Processing, And Combustion. EPA/600/R-01/066. at 47, available at http://www.epa.gov/nrmrl/pubs/600r01066/600r01066.pdf (last accessed March 19, 2008). 52 See Faris, G.W.; Sunesson, A.; Edner, H. ; Svanberg, S. Atmospheric atomic mercury monitoring using differential absorption lidar techniques. March 1, 1989. Appl. Opt.; Vol/Issue: 28:5. ("Three-dimensional mapping of atmospheric atomic mercury has been performed with lidar techniques, to our knowledge, for the first time. Industrial pollution monitoring, as well as measurements of background concentrations, is reported. High-efficiency frequency doubling of narrowband pulsed dye laser radiation was employed to generate intense radiation at the mercury UV resonance line. Field measurements were supplemented with extensive laboratory investigations of absorption cross sections and interfering lines of molecular oxygen.")

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In fact, in a study performed by Communities for a Better Environment, it was determined that selenium discharge to San Francisco Bay increased more than the selenium content of refiners’ crude slates because of this more intensive processing.53

Finally, we note that, along similar lines, the Permits use an emission factor for SO2 that underestimates the level of sulfur in the tar sands crude. Sulfur in crude is converted into H2S and other reduced sulfur compounds, like mercaptans, during processing. Thus, H2S and reduced sulfurs compounds will be emitted in higher amounts when the refinery processes tar sands crude, mostly from fugitive sources like tanks, valves, flanges, etc and the sulfur recovery plant. The permits do not adequately account for these additional sources of pollution.

A permit cannot issue based on faulty or incomplete emissions calculations. Thus, IDEM should make a finding that the permit application is incomplete in the absence of data supporting BP’s emission factors and assumptions regarding the relationship between the tar sands crude feedstock and Project emissions, and should make findings based upon such full information. Anything short of this outcome deprives the public of critical information concerning harmful emissions and Permits that meet the CAA’s requirements V. IDEM Failed to Require and Include a Schedule of Compliance for the Violations

Identified in the NOV Issued to BP in Connection with the Whiting Refinery

On November 29, 2007, USEPA Region 5 issued to BP an NOV documenting extensive violations of CAA requirements at the Whiting facility. The NOV is attached as Exhibit 12. Specifically, the NOV set forth detailed allegations concerning (i) a major modification to the facility’s fluidized catalytic cracking unit designated as FCU 500 and to the UIU Flare at the facility, without compliance with NSR and NSPS requirements; (iii) violation of SO2 and reduced sulfur compound emission and monitoring limits at the sulfur recovery plant, and (iv) failure to conduct required performance testing and submit the results of the HCl emissions from Ultraformers 3 and 4 as required by the Refinery MACT II. The NOV further documented the health impacts of these violations, which include, among other things, respiratory illness, heart disease, lung damage, and premature death. In addition, as documented in Ms. May’s report, deviation reports concerning flaring submitted to IDEM indicate repeated violations of current flare emissions limitations. Specifically, BP repeatedly exceeded the H2S 159 parts per million (ppm) 3-hour limit, meaning that too much H2S was burned in the flare. EPA limits H2S burned in the flare because when burned, H2S turns into harmful sulfur oxide emissions to the atmosphere.

53 Communities for a Better Environment (CBE) April 2007 Flaring Prevention Measures. http://gcm.live.radicaldesigns.org/downloads/Embargoed%20Report%202_1.pdf 23 R. Bertrand and J. Siegell. “Emission of Trace Compounds from Catalytic Cracking Regenerators.” Environmental Progress (Vol 21, No 3). Oct. 2002. Pp. 163-167.

Madhurima D. Moulik March 24, 2008 Page 33 Under Title V of the CAA and associated regulations, IDEM was required to mandate submission of a schedule of compliance addressing these violations, and to include it in the Project Title V permit modification. CAA § 503(b)(1) requires that permit applicants “submit with the permit application a compliance plan describing how the source will comply with all applicable requirements under this chapter” (emphasis added). 40 CFR 70.5(c)(8)(iii)(C), promulgated pursuant to this provision, states that a permit application must include the following:

A schedule of compliance for sources that are not in compliance with all applicable requirements at the time of permit issuance. Such a schedule shall include a schedule of remedial measures, including an enforceable sequence of actions with milestones, leading to compliance with any applicable requirements for which the source will be in noncompliance at the time of permit issuance. This compliance schedule shall resemble and be at least as stringent as that contained in any judicial consent decree or administrative order to which the source is subject.

(emphasis added). In New York Public Interest Research Group v. Johnson, 427 F.3d 172 (2nd Cir. 2005) the court made clear that, where non-compliance has been demonstrated, agencies are obligated under the CAA to require a schedule of compliance in a Title V permit regardless of whether there has been an adjudicated determination of liability. The court found that an NOV – like the NOV issued to BP in November – was sufficient evidence of violations to require a schedule of compliance.54 BP failed to submit the required schedule of compliance; and consequently, the Title V permit modification does not include one. IDEM must make a determination that BP’s Title V permit application is incomplete, and require submission of a schedule of compliance to address all violations identified in the USEPA NOV, and the schedule of compliance must be incorporated into the permit. VI. The Permits Are Not Consistent With the Netting Analysis

The Applicant is seeking to net out of new source review by relying on a myriad of assumptions as to baseline, contemporaneous decreases and future potential emissions. However, the Permits do not contain practically enforceable emission restrictions, production and operating conditions, monitoring, and recordkeeping to assure that emissions remain below the significance thresholds. The Permits do not limit all sources to ensure the emissions remain below significance thresholds, as it is required to do by

54 A similar issue, although not directly involving the issuance of an NOV preceding issuance of a Title V permit, is currently pending before the Court of Appeals for the 7th Circuit in Citizens Against Ruining the Environment v. USEPA, Consolidated Nos. 07-3197 07-3198 and 07-3199.

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law.55 The Permits also do not contain limits for all pollutants and sources as set out in the TSD. Finally, some of the limits are not enforceable as a practical matter. A. Emissions Limits Are Missing The Application and TSD claim the facility nets out of NSR review for H2S, reduced sulfur compounds, sulfuric acid mist, beryllium, lead, and mercury. However, the Permits do not contain any limitations on the emission of these substances nor require any testing to demonstrate that the claimed reductions and future potential emissions are achieved. Thus, the claim that the Project nets out of NSR review is a hollow promise, and inconsistent with applicable CAA requirements. B. Testing Is Inadequate

The Permits require NOx CEMS on some combustion sources, but otherwise

require only stack testing every five years for only one representative source from an arbitrary group of alleged similar sources. This is not adequate to assure that the emission reductions and future potential emissions assumed in the netting analysis are achieved in practice.

The claimed emission reductions can only be enforced through appropriate

monitoring, testing and reporting of emissions. An appropriate hierarchy for specifying monitoring to determine compliance is: (1) continuous direct measurement where feasible; (2) initial and periodic direct measurement where continuous monitoring is not feasible; (3) use of indirect monitoring, e.g. surrogate monitoring, where direct monitoring is not feasible; and (4) equipment and work practice standards where direct and indirect monitoring are not feasible. NSR Manual, p l.3. The Permits do not comport with this guidance, and in some instances do not require any testing to demonstrate that the emission limits will be complied with when the source is operating.

First, testing should be required for every fired source, not just one out of the proffered groupings as fired sources, even when superficially identical, can differ from unit to unit as refinery fired sources are not off-the-shelf technology. Hundreds of stack tests of boilers and refinery heaters from across the country demonstrate that emissions are highly variable and depend upon the degree of air preheat, age of the unit, maintenance practices, type of burners, etc. The Permits must be modified to require testing of all emission units, not just one from a grouping.

Second, the infrequent testing does not provide sufficient data to determine if the assumptions used in the netting analysis are realized. Further, it is not adequate to allow IDEM, U.S. EPA or the public to ensure compliance with the Permit limits. It is feasible to directly and continuously monitor CO, VOC, and NOx emissions from all heaters,

55 This issue is addressed as it pertains specifically to flare emissions in section II of this comment. As discussed there, BP claims that enhanced reliability will limit flaring events, but the draft Permits contain no actual requirements limiting the number of such events.

Madhurima D. Moulik March 24, 2008 Page 35 boilers, and other fired sources. The draft Permits only require continuous emission monitors for NOx from some fired sources. It is also feasible to conduct more frequent stack tests. Annual or more frequent testing is feasible, is commonly required for similar facilities, and should be required here. Finally, annual fugitive emission inventories for PM/PM10 and VOCs are required elsewhere and should be required here. Thus, the draft Permits should be modified to require more frequent direct emission testing.

Conclusion

For the foregoing reasons, we respectfully request that the draft Permits not be issued in their current form. Very truly yours,

______________________________ Ann Alexander Senior Attorney, Midwest Program Natural Resources Defense Council 101 North Wacker Drive, Suite 609 Chicago, Illinois 60601 312-780-7427

_______________________________ Meleah Geertsma Staff attorney and public health specialist

Environmental Law and Policy Center 35 East Wacker Drive, Suite 1300 Chicago, IL 60601 (312) 795-3713