June 28, 2007

Mr. Gerardo C. Rios

Chief, Permits Office

United States Environmental Protection Agency

Region IX

75 Hawthorne Street

San Francisco, CA 94105-3901

Dear Mr. Rios:

This letter amends the revised Prevention of Significant Deterioration
(PSD) application submitted to your office on December 11, 2006 for the
Big West of California, LLC Bakersfield Refinery Clean Fuels Project
(CFP). There are several amendments to be made to the application,
specifically:

-   The refinery has committed to meeting a fuel gas sulfur content
    limit of 40 ppmv total sulfur (as H~2~S) on a 4-hour average basis;

-   Basic information is presented about the additional equipment that
    will be necessary to achieve this fuel gas sulfur level;

-   The location of the existing Mild Hydrocracker and its two heaters
    14-H1 and 14-H2 was incorrectly modeled;

-   Additional supporting information is presented regarding the cost
    effectiveness of installing selective catalytic reduction (SCR) on
    the two CFP heaters that are less than 50 MMBtu/hr (VGO Feed Heater,
    47 MMBtu/hr; and VGO-HDS Fractionator Feed Heater, 35 MMBtu/hr);

-   An analysis of the proposed NSPS Subpart Ja and how it affects the
    project combustion units and FCCU, which indicates that a short-term
    NOx emissions limit will be required for the FCCU, additional CEMS
    or parametric monitoring will be required for PM emissions from the
    FCCU, and additional NOx CEMS monitoring will be required for the
    VGO-HDS heaters; *and*

-   Additional clarifications on the design and operation of the ground
    flare that will serve CFP units.

Each of these amendments and additional ground flare data are described
in detail below.

***Fuel Gas Sulfur Limit***

As you are aware, Big West has worked extensively with our process
design engineers to achieve a fuel gas sulfur limit lower than 100 ppmv.
As presented in the July 12, 2006 letter from J. Scott Lewis of Linde
BOC Process Plants LLC (provided as an attachment to an email dated July
24, 2006 from Ev Ashworth), the contractor for the amine treatment
system was only willing to guarantee that 50 ppmv H~2~S could be
achieved. However, as the design has progressed, we were able to develop
detailed fuel gas balance scenarios to ascertain the expected fuel gas
sulfur content in normal and "worst-case" operating situations. Big West
now anticipates that with the addition of a caustic scrubber to remove
the potentially high level of sulfur in the fuel gas from Area 3 that
may, in some circumstances, be introduced into the Area 4 fuel gas
system, Big West can meet a limit of 40 ppmv total sulfur (as H~2~S)
averaged over a 4-hour period at all times.

This modification will not adversely affect the PSD permit application.
Modeling will not be performed again, as the current modeling is
conservative in its inclusion of 100 ppmv sulfur in the combusted fuel
gas. To meet the 40 ppmv limit, the facility will need to treat fuel gas
supplied to Area 2 from the Area 3 Delayed Coker Gas Amine Treater, to
reduce non-H~2~S sulfur compounds in the total fuel gas burned in Areas
2 and 4. The new treatment unit will use caustic to extract these sulfur
compounds; the sulfur compounds will be converted to disulfides and
returned to a hydrotreater for conversion to H~2~S.

The addition of this caustic scrubbing unit does not directly affect the
PSD permit application, as the only emissions from the unit will be
volatile organic compounds (VOC), which is not within the scope of the
PSD permit. The refinery will submit a revised application for a Permit
to Construct with the San Joaquin Valley Air Pollution Control District
to support construction of the revised Area 4 fuel gas treatment unit.

A revised Table 5-3, that reflects the lower SO~2~ emissions resulting
from combustion of fuel gas subject to a 40 ppmv sulfur content limit,
is presented below.

**Table 5-3: Big West Clean Fuels Project Source Emission Rates****^a^**

+----------------------+--------+--------+--------+--------+--------+
| Source               | Model  | NO~x~  | SO     | CO     | PM~10~ |
|                      | ID     |        | ~2~^b^ |        |        |
| ID                   |        | (g/s)  |        | (g/s)  | (g/s)  |
|                      |        |        | (g/s)  |        |        |
+======================+========+========+========+========+========+
| VGO Feed Heater (47  | vgohtr | 0.1438 | ~~0.0  | 0.2189 | 0.0441 |
| MMbtu/hr)            |        |        | 833~~\ |        |        |
|                      |        |        | [0     |        |        |
|                      |        |        | .0333] |        |        |
|                      |        |        | {.unde |        |        |
|                      |        |        | rline} |        |        |
+----------------------+--------+--------+--------+--------+--------+
| VGO HDS Fractionator | vg     | 0.1071 | ~~0.0  | 0.1630 | 0.0329 |
| Feed Heater (35      | ofrhtr |        | 620~~\ |        |        |
| MMBtu/hr)            |        |        | [0     |        |        |
|                      |        |        | .0248] |        |        |
|                      |        |        | {.unde |        |        |
|                      |        |        | rline} |        |        |
+----------------------+--------+--------+--------+--------+--------+
| Hydrogen Plant       | h2     | 0.4904 | ~~1.1  | 0.5971 | 0.6018 |
| Reformer             | reform |        | 364~~\ |        |        |
|                      |        |        | [0     |        |        |
|                      |        |        | .4545] |        |        |
|                      |        |        | {.unde |        |        |
|                      |        |        | rline} |        |        |
+----------------------+--------+--------+--------+--------+--------+
| FCCU Regenerator     | fcc    | 1.0604 | 1.4765 | 1.9046 | 1.1647 |
| (annual) ^c^         | uregen |        |        |        |        |
+----------------------+--------+--------+--------+--------+--------+
| FCCU Regenerator     | fcc    | 2.1208 | 3.6913 | 1      | 1.1647 |
| (1-hr, 3-hr, 8-hr,   | uregen |        |        | 6.1407 |        |
| 24-hr) ^c^           |        |        |        |        |        |
+----------------------+--------+--------+--------+--------+--------+
| Existing MHC Feed    | mh     | 0.3748 | ~~0.1  | 1.4904 | 0.0845 |
| Heaters\             | c14h12 |        | 596~~\ |        |        |
| (14-H1 & 14-H2)      |        |        | [0     |        |        |
|                      |        |        | .0638] |        |        |
|                      |        |        | {.unde |        |        |
|                      |        |        | rline} |        |        |
+----------------------+--------+--------+--------+--------+--------+
| HF Alky Isostripper  | hf     | 0.1645 | ~~0.3  | 0.2003 | 0.2018 |
| Reboiler             | reboil |        | 812~~\ |        |        |
|                      |        |        | [0     |        |        |
|                      |        |        | .1525] |        |        |
|                      |        |        | {.unde |        |        |
|                      |        |        | rline} |        |        |
+----------------------+--------+--------+--------+--------+--------+
| SWAATS Unit          | swaats | 0.0000 | 0.2322 | ~~4    | 0.0000 |
|                      |        |        |        | .3994\ |        |
|                      |        |        |        | ~~[0   |        |
|                      |        |        |        | .3384] |        |
|                      |        |        |        | {.unde |        |
|                      |        |        |        | rline} |        |
+----------------------+--------+--------+--------+--------+--------+
| Ground Flare^d^      | gn     | 0.0279 | ~~0.0  | 0.1519 | 0.0107 |
|                      | dflare |        | 089~~\ |        |        |
|                      |        |        | [0     |        |        |
|                      |        |        | .0057] |        |        |
|                      |        |        | {.unde |        |        |
|                      |        |        | rline} |        |        |
+----------------------+--------+--------+--------+--------+--------+
| Diesel Firewater     | fi     | 0.0222 | 0.0000 | 0.0130 | 0.0007 |
| Pump Engines         | repump |        |        |        |        |
| (annual)             |        |        |        |        |        |
+----------------------+--------+--------+--------+--------+--------+
| Diesel Firewater     | fi     | 0.0809 | 0.0001 | 0.0474 | 0.0027 |
| Pump Engines (24‑hr) | repump |        |        |        |        |
+----------------------+--------+--------+--------+--------+--------+
| Diesel Firewater     | fi     | 0.2428 | 0.0003 | 0.1422 | 0.0082 |
| Pump Engines (8‑hr)  | repump |        |        |        |        |
+----------------------+--------+--------+--------+--------+--------+
| Diesel Firewater     | fi     | 0.6475 | 0.0007 | 0.3792 | 0.0219 |
| Pump Engines (3‑hr)  | repump |        |        |        |        |
+----------------------+--------+--------+--------+--------+--------+
| Diesel Firewater     | fi     | 1.9425 | 0.0022 | 1.1375 | 0.0656 |
| Pump Engines (1‑hr)  | repump |        |        |        |        |
+----------------------+--------+--------+--------+--------+--------+
| Cooling Tower 1      | coolt1 | 0.0000 | 0.0000 | 0.0000 | 0.0303 |
+----------------------+--------+--------+--------+--------+--------+
| Cooling Tower 2      | coolt2 | 0.0000 | 0.0000 | 0.0000 | 0.0303 |
+----------------------+--------+--------+--------+--------+--------+
| ^a^ Strikeout values |        |        |        |        |        |
| are from the         |        |        |        |        |        |
| December 2006        |        |        |        |        |        |
| revised PSD          |        |        |        |        |        |
| application.         |        |        |        |        |        |
|                      |        |        |        |        |        |
| ^b^ Revised sulfur   |        |        |        |        |        |
| emission rates       |        |        |        |        |        |
| reflect combustion   |        |        |        |        |        |
| of refinery fuel gas |        |        |        |        |        |
| at 40 ppmv total     |        |        |        |        |        |
| sulfur, expressed as |        |        |        |        |        |
| H~2~S.               |        |        |        |        |        |
|                      |        |        |        |        |        |
| ^c^ FCCU heater is a |        |        |        |        |        |
| limited-use startup  |        |        |        |        |        |
| heater. FCCU         |        |        |        |        |        |
| regenerator emission |        |        |        |        |        |
| rates are larger     |        |        |        |        |        |
| than those from the  |        |        |        |        |        |
| FCCU startup heater, |        |        |        |        |        |
| so FCCU regenerator  |        |        |        |        |        |
| emissions were used  |        |        |        |        |        |
| in the modeling.     |        |        |        |        |        |
|                      |        |        |        |        |        |
| ^d^ Flare emission   |        |        |        |        |        |
| rates are annual     |        |        |        |        |        |
| averages that        |        |        |        |        |        |
| include process unit |        |        |        |        |        |
| startups and         |        |        |        |        |        |
| shutdowns as well as |        |        |        |        |        |
| continuous pilot     |        |        |        |        |        |
| flaring.             |        |        |        |        |        |
+----------------------+--------+--------+--------+--------+--------+

***Mild Hydrocracker Location***

It recently came to our attention that the location of the existing mild
hydrocracker, which has been included as an affected unit in the PSD air
quality impact analysis modeling for the Clean Fuels Project, was
misrepresented in these dispersion modeling runs. The UTM coordinates
should not have been 311795.2 Easting and 3917118.9 Northing (NAD27) as
presented in Table 5-4 of the December 2006 revised application, but
rather should be approximately 220 m SSE, at 311837.5 Easting and
3916901.5 Northing.

The dispersion modeling to compare maximum project impacts with Class II
significance levels and monitoring significance levels has been
performed again to take this change into account. The affected tables
and figures from the December 2006 revised PSD application are included
below. As noted above, this revised modeling analysis does not reflect
the new and reduced fuel gas total sulfur content limit of 40 ppmv.
However, this conservative approach demonstrates that the revised
location of the Mild Hydrocracker does not result in any exceedances of
relevant EPA PSD Significance Levels. The modeling to determine Air
Quality Related Values (AQRV) impacts on Class I areas has not been
revised, as the effect of a 200 m shift of one emission source would be
imperceptible at the distance of the nearest Class I areas (\~80 km).

![](media/image1.wmf){width="6.495138888888889in"
height="5.720138888888889in"}

Figure 5-2: Big West -- Boundary Receptors and Source Locations

![](media/image2.wmf){width="6.495138888888889in"
height="6.134027777777778in"}

Figure 5-3: Big West Far Grid of Receptors

![](media/image3.wmf){width="6.495833333333334in"
height="3.761111111111111in"}

**Figure 5-5: Maximum Impact Locations with Fine Grid for Maximum 3-hour
SO2 Impact**

**Table 5-9: Maximum Project Impacts Compared with Class II Significance
Levels and Monitoring Significance Levels^a^**

+----------+------------+------------+--------------+-----------------+
| P        | Averaging  | Maximum    | Class II     | Monitoring      |
| ollutant |            | Predicted  | Significance | Significance    |
|          | Period     | Impact     | Level        | Level           |
|          |            |            |              |                 |
|          |            | (µg/m^3^)  | (µg/m^3^)    | (µg/m^3^)       |
+----------+------------+------------+--------------+-----------------+
| NO~2~    | Annual     | ~~0.56^b^\ | 1.0          | 14              |
|          |            | ~~[0.68]{. |              |                 |
|          |            | underline} |              |                 |
+----------+------------+------------+--------------+-----------------+
| SO~2~    | Annual     | ~~0.74~~\  | 1.0          | NA              |
|          |            | [0.83]{.   |              |                 |
|          |            | underline} |              |                 |
+----------+------------+------------+--------------+-----------------+
|          | 3-hour     | ~~10.67~~\ | 25.0         | NA              |
|          |            | [10.71]{.  |              |                 |
|          |            | underline} |              |                 |
+----------+------------+------------+--------------+-----------------+
|          | 24-hour    | ~~3.18\    | 5.0          | 13              |
|          |            | ~~[3.37]{. |              |                 |
|          |            | underline} |              |                 |
+----------+------------+------------+--------------+-----------------+
| CO       | 1-hour     | ~~181.31\  | 2,000        | NA              |
|          |            | ~~         |              |                 |
|          |            | [183.42]{. |              |                 |
|          |            | underline} |              |                 |
+----------+------------+------------+--------------+-----------------+
|          | 8-hour     | ~~44.08~~\ | 500          | 575             |
|          |            | [31.38]{.  |              |                 |
|          |            | underline} |              |                 |
+----------+------------+------------+--------------+-----------------+
| Notes:   |            |            |              |                 |
|          |            |            |              |                 |
| ^a^      |            |            |              |                 |
| S        |            |            |              |                 |
| trikeout |            |            |              |                 |
| values   |            |            |              |                 |
| are from |            |            |              |                 |
| the      |            |            |              |                 |
| December |            |            |              |                 |
| 2006     |            |            |              |                 |
| revised  |            |            |              |                 |
| PSD      |            |            |              |                 |
| appl     |            |            |              |                 |
| ication. |            |            |              |                 |
|          |            |            |              |                 |
| ^b^ EPA  |            |            |              |                 |
| default  |            |            |              |                 |
| Ambient  |            |            |              |                 |
| Ratio    |            |            |              |                 |
| Method   |            |            |              |                 |
| factor   |            |            |              |                 |
| of 0.75  |            |            |              |                 |
| applied. |            |            |              |                 |
|          |            |            |              |                 |
| NA = Not |            |            |              |                 |
| applic   |            |            |              |                 |
| able/not |            |            |              |                 |
| defined  |            |            |              |                 |
+----------+------------+------------+--------------+-----------------+

***Cost Effectiveness of SCR on VGO-HDS Heaters***

The BACT analysis presented in section 4.2.1 of the December 2006
revised PSD application concluded that BACT for NOx for refinery
combustion units less than 50 MMBtu/hr is the installation of low NOx
burners to achieve a NOx emission limit of 20 ppmv @ 3% O~2~. This
conclusion was reached with the following reasoning:

-   The most stringent limit found to be achieved in practice or
    required by a state implementation plan (SIP) was 25 ppmv @ 3% O~2~.

-   The lowest vendor guarantee that the refinery was able to secure for
    state-of-the-art low NOx burners on a refinery heater of this size
    is 20 ppmv @ 3% O~2~.

-   While the addition of SCR would be technically feasible and could
    achieve lower NOx emissions, this is not achieved in practice on a
    small refinery heater and is not considered cost effective; the cost
    effectiveness, calculated at \$13,766 and \$12,779 per ton of NOx
    control for the smaller and larger heaters, respectively, was far
    above the SJVAPCD's cost effectiveness threshold for NOx control.

You and your staff have indicated that EPA may not agree with the cost
effectiveness thresholds as established by SJVAPCD and requested a more
complete accounting of costs associated with the installation of SCR.
Because the design of the project has progressed since the cost
estimates were initially prepared over a year ago, and detailed cost
estimates have been obtained for the other CFP heaters, a more complete
cost estimate can now be provided. As we have explained to your staff, a
more detailed cost analysis was not provided in the December 2006
revised PSD application because the estimated cost-effectiveness
exceeded the SJVAPCD BACT cost-effectiveness thresholds. We note that
the addition of SCR units on the VGO-HDS heaters this late in the
project design would significantly increase these costs -- unit
redesign/placement, re-engineering, cancellation charges for parts
already ordered, etc. -- *none* of these schedule- and redesign-related
costs have been included. Only incremental costs between installation of
low NOx burners alone and installation of low NOx burners and SCR have
been included in our revised cost-effectiveness analysis.

Revised Tables C-4 are attached, which provide the new cost estimates
and cost effectiveness calculations. As before, guidance from the EPA
OAQPS Cost Manual, 6^th^ Edition, Chapter 2 regarding cost estimates for
SCR was followed, except where more specific data were available. Cost
effectiveness estimates for the smaller and larger heaters were \$45,170
and \$39,450 per ton, respectively.

In summary, there are no existing refinery heaters or boilers \<50
MMBtu/hr that are permitted to achieve NOx emission rates lower than
proposed here, the proposed NOx emission limits for the VGO heaters are
more stringent than any applicable SIP or proposed NSPS Subpart Ja
requirements, and the cost effectiveness for SCR control is
significantly more expensive than the BACT cost effectiveness thresholds
required for refinery units or similar sources in California or
elsewhere in the United States (under EPA, South Coast, Bay Area or San
Joaquin Valley air district guidelines). We therefore conclude that SCR
controls as applied to the VGO-HDS heaters are not representative of the
lowest achievable NOx emission rate.

***Proposed NSPS Subpart Ja***

On May 17, 2007, EPA proposed amendments to the New Source Performance
Standards for Petroleum Refineries (Subpart Ja and proposed
modifications to Subpart J, see 72 FR 27178, 5/17/2007). NSPS
requirements are effective based on the date of proposal; therefore,
affected facilities in the Clean Fuels Project will have to comply with
these requirements. We note that the proposed rule is subject to review
and comment, and may be modified by EPA in light of these comments.
Nevertheless, as demonstrated in the table below, the affected units
under CFP can comply with Subpart Ja requirements with the following
changes to the proposed project:

  --------------- ------------------------------- -----------------------
  **Unit**        **Proposed NSPS Ja              **CFP Controls/Design**
                  Requirement**                   

  FCCU            PM: 0.5 lb/1,000 lb coke        Same
                  burn-off                        

                  PM Monitoring: Method 5         Proposed continuous
                  performance test; PM CEMS or    opacity monitoring;
                  control device operating        will incorporate Ja
                  parameter monitoring            monitoring requirements
                                                  (PM CEMS or parameter
                                                  monitoring)

                  NOx: 80 ppmv (dry, 0% O~2~ )    More stringent: 40 ppmv
                  7-day rolling average           (dry, 0% O~2~ ) daily
                                                  average; 20 ppmv (dry,
                                                  0% O~2~ ) 365-day
                                                  rolling average

                  NOx Monitoring: CEMS            Same

                  SO~2~: 50 ppmv (dry, 0% O~2~ )  More stringent: 50 ppmv
                  7-day rolling average; 25 ppmv  (dry, 0% O~2~) daily
                  (dry, 0% O~2~ ) 365-day rolling average; 20 ppmv (dry,
                  average                         0% O~2~ ) 365-day
                                                  rolling average

  Claus Sulfur    Provides new SO~2~ and H~2~S    Not applicable to
  Recovery Plant  emissions limits                SWAATS unit

  Process Heater  NOx: 80 ppmv (dry, 0% O~2~ )    More stringent (\<20
  and Other Fuel  24-hour rolling average         ppmv @ 3% O~2~ 15
  Gas Combustion                                  minute average for
  Device                                          CEMS)

                  NOx Monitoring: CEMS            Proposed periodic
                                                  sampling on VGO-HDS
                                                  units to verify
                                                  compliance; will
                                                  install CEMS

                  SO~2~: 20 ppmv (dry, 0% O~2~ )  More stringent: 40 ppmv
                  3-hour rolling average -- or    total sulfur limit,
                  fuel gas limit of 160 ppmv      expressed as H~2~S on a
                  H~2~S 3-hour rolling average; 8 4-hour average
                  ppmv (dry, 0% O~2~ ) 365-day    
                  rolling average -- or fuel gas  
                  limit of 60 ppmv H~2~S 365-day  
                  rolling average                 
  --------------- ------------------------------- -----------------------

As summarized above, the current BACT emission limits for the CFP units
are equal to or more stringent than the proposed Subpart Ja
requirements; however, a new short-term NOx standard will be
incorporated to address the proposed Ja standard for new FCCUs. Further,
additional monitoring will be required to meet the proposed Subpart Ja
monitoring requirements; specifically, installation of NOx CEMS for the
VGO-HDS heaters and installation of a PM CEMS or parametric monitoring
of PM emissions from the FCCU.

***Other Issues***

Separately, in recent email correspondence, Ms. Kathleen Stewart raised
several issues regarding the ground flare, for which our responses are
provided below:

-   The flare is designed to handle only process upset gases, taken to
    include gases released during startup, shutdown and malfunctions; it
    therefore is not designed to comply with Subpart J or proposed
    Subpart Ja. Furthermore, it will not be permitted to handle releases
    subject to Subpart J or Ja under its federally enforceable operating
    permit;

-   The minimum heat content of gases that will vent to the flare during
    process upset conditions, startups and shutdowns will be 300
    Btu/scf. We do not anticipate any instance where the heat content of
    process upset gases will lower than 300 Btu/scf;

-   No pressure relief devices will vent directly to the flare;

-   The presence of a pilot flame on the ground flare will be monitored
    with thermocouples, which will record temperature, and hence, the
    presence of a pilot flame;

-   The flow of gases released to the ground flare will be monitored
    with a GE Sensing ultrasonic flow meter (product brochure and
    technical data are attached). Please note that this unit does not
    require daily calibrations; Big West will calibrate the unit
    consistent with manufacturer's recommendations; flow accuracy and
    repeatability data are provided in the brochure;

-   The heat content and sulfur content of gases released to the flare
    during process upset conditions will be monitored by a sampling
    system that will consist of evacuated cylinders, which will sample
    gases during a release. We are working with vendors to define the
    specifications for this sampling system, which we understand is used
    by other facilities in California and required under the Motiva
    Consent Decree to measure heat content and sulfur concentrations in
    gases that are released to a flare. The sample gas obtained from the
    automated sampling system will then be analyzed for heat content
    (ASTM Method D2382-88; D3588-91 or D4891-89) and sulfur content (EPA
    Method 15/16 GC-FPD or equivalent); *and*

-   Finally, we wish to confirm that the sulfur content of the torch oil
    used in the startup of the FCCU will be verified through testing.

A CD of the modeling input and output files will be sent to you under
separate cover; copies will be provided directly to Ms. Carol Bohnenkamp
as well. Please contact Mr. Everard Ashworth of Ashworth Leininger Group
(805.370.1469) to discuss any concerns or questions raised by this
letter. Thank you again for your continued assistance on this important
project. Thank you again for your continued assistance on this important
project.

Very truly yours,

Eugene Cotten

Vice President-Refining

Enclosure

cc: Carol Bohnenkamp, USEPA

Kathleen Steward, USEPA

> Vince Memmott, P.E., Flying J Inc.\
> Bill Chadick, HSE Director, Big West\
> Everard Ashworth, ALG\
> Richard Karrs, SJVAPCD\
> Leonard Scandura, SJVAPCD
>
> Perry Fontana, QEP, URS
>
> Mike McCorison, US Forest Service

Table C-4: BACT Annual Cost Analysis -- Refinery Combustion Units \<50
MMBtu/hr

> ![](media/image5.wmf){width="5.678472222222222in"
> height="9.427083333333334in"}

Table C-4: BACT Annual Cost Analysis -- Refinery Combustion Units \<50
MMBtu/hr (cont.)

> ![](media/image6.wmf){width="5.678472222222222in"
> height="9.427083333333334in"}