oregon title v operating permit review report report/permit no.: 05-2520 application number: 21882...

Review Report/Permit No.: 05-2520

Application number: 21882 & 22942

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Revised 2/22/08

OREGON DEPARTMENT OF ENVIRONMENTAL QUALITY

OREGON TITLE V OPERATING PERMIT

REVIEW REPORT

Northwest Region

2020 SW 4th

Avenue, #400

Portland, OR 97201-4987

Telephone (503) 229-5263

Source Information:

SIC 4911

NAICS 221112

OAR 340-216-0020, Table 1

Source Categories (Part and code)

Part B, 25.

Part C., 4.

Part C., 5.

Compliance and Emissions Monitoring Requirements:

Unassigned emissions NA

Emission credits NA

Compliance schedule NA

Source test [date(s)] See permit

conditions

COMS NA

CEMS Yes

Ambient monitoring N/A

Reporting Requirements

Annual report (due date) February 15

Emission fee report (due date) February 15

SACC (due date) July 30

Quarterly report (due dates)

Monthly report (due dates) NA

Excess emissions report Yes

Other reports (Acid Rain) Yes

Air Programs



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NSPS (list subparts) GG, Db, Dc

NESHAP (list subparts) NA

CAM NA

Regional Haze (RH) Yes

Synthetic Minor (SM) NA

Part 68 Risk Management NA

CFC NA

RACT NA

TACT NA

Title V Yes

ACDP (SIP) NA

Major HAP source NA

Federal major source Yes

NSR NA

PSD NA

Acid Rain Yes

Clean Air Mercury Rule (CAMR) NA

TABLE OF CONTENTS

LIST OF ABBREVIATIONS……………………..……………………………………………..…………………….2

PERMITTEE IDENTIFICATION………………………………………………………………………….………….4

PERMIT INFORMATION/CHANGES……………………………………………………………………………….4

FACILITY DESCRIPTION……………………………………………………………………………….………….12

EMISSION UNIT AND POLLUTION CONTROL DEVICE IDENTIFICATION…………………………………13

EMISSION LIMITS AND STANDARDS, TESTING, MONITORING, AND RECORDKEEPING ....................... 15 PLANT SITE EMISSION LIMITS……………………………………………………………...……………………24

HAZARDOUS AIR POLLUTANTS .......................................................................................................................... 27 GENERAL BACKGROUND INFORMATION ......................................................................................................... 28 COMPLIANCE HISTORY ......................................................................................................................................... 28 SOURCE TEST RESULTS ......................................................................................................................................... 29

PUBLIC NOTICE……………………………………...……………………………………………………………..31

EMISSIONS DETAIL SHEETS ................................................................................................................................. 31



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LIST OF ABBREVIATIONS USED IN THIS REVIEW REPORT

ACDP Air Contaminant Discharge Permit

Act Federal Clean Air Act

AQMA Air Quality Mangement Area

ASTM American Society of Testing and

Materials

BACT Best Available Control Technology

BART Best Available Retrofit Technology

Btu British thermal unit

CEMS continuous emissions monitoring

system

CFR Code of Federal Regulations

CH4 Methane

CMS continuous monitoring system

CO Carbon Monoxide

CPMS Continuous parameter monitoring

system

CRGNSA Columbia River Gorge National

Scenic Area

CTG combustion turbine generator

DAHS Data Acquisition and Handling

System

DEQ Department of Environmental

Quality

DLN dry low NOX

dscf Dry standard cubic feet

EF Emission factor

EFSC Energy Facility Siting Council

EPA US Environmental Protection

Agency

EU Emissions Unit

FCAA Federal Clean Air Act

FLAG Federal Land Managers’ Air

Quality Related Values Work

Group

FLM Federal Land Managers

FSA Fuel sampling and analysis

gr/dscf Grain per dry standard cubic feet (1

pound = 7000 grains)

HAP Hazardous Air Pollutant as defined

by OAR 340-244-0040

HCFC Halogenated Chlorofluorocarbons

HRSG Heat recovery steam generator

H2SO4 Sulfuric Acid (mist)

ID Identification number

I&M Inspection and maintenance

LHV Lower heating value

LSD Low sulfur diesel fuel oil

Mgals 1000 gallons

MMbtu Million btus (106 btus)

MW Megawatt

NA Not applicable

NAAQS National Ambient Air Quality

Standards

NCASI National Council for Air and

Stream Improvement, Inc.

NG Natural Gas

NOx Nitrogen oxides

NP National Park

NSPS New Source Performance Standard

NSR New Source Review

O2 Oxygen

OAR Oregon Administrative Rules

ODEQ Oregon Department of

Environmental Quality

ORS Oregon Revised Statutes

ORIS Office of Regulatory Information

Systems

O&M Operation and maintenance

Pb Lead

PCD Pollution Control Device

PM Particulate matter

PM10 Particulate matter less than 10

microns in size

ppm Parts per million

ppmvd Parts per million by volume, dry

PSEL Plant Site Emission Limit

PSD Prevention of Significant

Deterioration

psia pounds per square inch, actual

QA/QC quality assurance/quality control

RATA Relative Accuracy Test Audit

RBLC RACT, BACT, LAER Clearing

House

RMP Risk Management Plan

S Sulfur content of fuel oil, %

SCR selective catalytic reduction

SERP Source emissions reduction plan

SIP State Implementation Plan

SO2 Sulfur dioxide

ST Source test

TRAACS Tracking, Reporting and

Administration of Air Contaminant

Sources (DEQ internal database)

ULSD Ultra low sulfur diesel fuel oil

USFS United States Forest Service

VE Visible emissions

VMT Vehicle miles traveled

VOC Volatile organic compounds

Year Any 12 consecutive calendar month

period



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Page 4 of 50

PERMITTEE IDENTIFICATION

1. Portland General Electric Company (PGE) owns and operates two electrical power generation facilities (the

Beaver Plant and the Port Westward Plant) located near Clatskanie, Oregon. The two plants are contiguous

and are considered a single source by Department rules. Therefore both facilities are operating under one

Title V Permit, No. 05-2520. The plant is located on an 852-acre site in Columbia County. The property is

leased from the Port of St. Helens. PGE is sub-leasing 49 acres of the 852 acre site to the Cascade Grain

Ethanol Manufacturing Facility, which has been issued Standard Air Contaminant Discharge Permit No. 05-

0006 by the Department. The ethanol plant is between the two power plants, located at 81200 Kallunki

Road, and it produces approximately 120 million gallons of ethanol per year.

PERMIT INFORMATION/CHANGES

2. The following permit actions are included in this Review Report and Permit issuance:

2.a. Title V Permit Renewal Oregon Title V Operating Permit No. 05-2520 was issued by the

Department on September 5, 2002, and scheduled to expire on July 01, 2007. The renewal

application was submitted on June 23, 2006, assigned application number 21882, and was solely

for the Beaver plant, as the Port Westward plant was under construction (Construction ACDP 05-

0008). The Port Westward plant began commercial operation in Spring 2007, and was appended

to the Beaver Title V Operating Permit through Significant Permit Modification No. 21802 (as

described below in item 4), which was issued on May 31, 2007. This renewal permit is being

issued to incorporate the renewal for both plants under one Title V permit. The existing permit is

in effect until this renewal is issued.

2.b. Significant Permit Modification No. 22942 This modification was submitted on April 3, 2008, and

revised on May 23, 2008, in accordance with OAR 340-218-0180(1). This modification includes

operational limitations to the six combined cycle turbines at the Beaver plant (Emission Unit

GTEU6), which are Best Available Retrofit Technology (BART) -eligible emission units, to

ensure that emissions are maintained at a level where the plant will have insignificant impacts on

visibility in fourteen applicable Federal Class I areas and the Columbia River Gorge Scenic Area,

(although not a Class I area, it was included for informational purposes only). Further detailed

discussion on the Regional Haze Plan, PGE’s and the Department’s Visibility Protection Strategy,

and BART are found below in item 18. These operational changes have resulted in significant

decreases of the Plant Site Emission Limits (PSELs) for PM, PM10, SO2, NOx, and VOCs due to a

limit on fuel oil quantity and sulfur concentration, with all future shipments of fuel oil limited to

Ultra Low Sulfur Diesel (15 ppm). The CO PSEL is increased due to a correction in the emission

factor; this increase and the required air quality analysis are discussed in detail below in item 19.

The modification/renewal also includes an update of various emission factors based upon EPA AP-

42 and/or site-specific source test results, and consolidation of permit conditions for both power

plants, as many conditions were redundant.

3. In accordance with OAR 340-218-0120(1)(f), this review report is intended to provide the legal and factual

basis for the draft permit conditions. In most cases, the legal basis for a permit condition is included in the

permit by citing the applicable regulation. In addition, the factual basis for the requirement may be the

same as the legal basis. However, when the regulation is not specific and only provides general

requirements, this review report is used to provide a more thorough explanation of the factual basis for the

draft permit conditions.

4. The following changes and/or permit modifications have been made at the facility during the last permit

term:

Table 1.

Date Issued Permit Revision or Notification Brief Explanation

03/08/2005 Minor Permit Modification

Addendum No. 1

This permit action applies to PTEU1 only. This change

incorporated changes to the NSPS, Subpart GG and clarified



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Page 5 of 50

Date Issued Permit Revision or Notification Brief Explanation

Application No. 21164 testing requirements for this turbine for NOx emissions.

02/03/2006 Minor Permit Modification

Addendum No. 2

Application No. 21618

This change included a voluntary reduction of the PSEL for

SO2 from 6431 tpy to 1077 tpy due to the voluntary use of

0.05% sulfur fuel oil in the Beaver Plant turbines, GTEU6

from a regulatory fuel oil sulfur limit of 0.3%. [OAR 340-

228-0110(1)]

06/23/2006 Title V Permit Renewal


Renewal package was submitted with regards to the Beaver

plant only, as it was submitted prior to Addendum No. 3,

below. However, this renewal permit contains several

changes, most of which are consolidation and the resulting

reformatting of permit condition, as described in detail in

Item No. 5, below.

05/31/2007 Significant Permit Modification

Addendum No. 3


This permit action merged the Standard ACDP for the

construction of the Port Westward Plant into the Title V

Permit for the Beaver Plant, so both plants are under one

operating permit. The signification modification was on

Public Notice from April 11, 2007 through May 16, 2007.

No comments were received, nor was a public hearing held.

With renewal Significant Permit Modification

Addendum No. 4


The permit action incorporates operational limits for the

Beaver gas turbines (GTEU6) as part of the Visibility

Protection Strategy for the Department’s implementation of

the Regional Haze Rule. The PSELs are significantly reduced

for PM, PM10, SO2, NOx and VOCs, and increased for CO.

Emission factors are also updated.

5. The following is a list of condition-by-condition changes between the previous permit and the proposed

permit:

Table 2.

New Permit

Condition

Number

Old Permit

Condition

Number(s) Description of change Reason for change

Cover page Cover page Added Acid Rain Program

Information.

Applicable program for Port Westward turbine.

1 1 & 67 Removed construction

statement from previous

condition 67.

Port Westward Facility construction complete.

The permit was revised to consolidate those

conditions common to both facilities; as a

consequence, 32 conditions were

deleted/consolidated from the renewal permit.

2 2, 3 & 68 Consolidated conditions,

updated condition numbers

and rules

State enforceable conditions numbers changed and

SIP approved rules updated.

3 4 & 69 Consolidated the Beaver and

Port Westward Plants’

equipment into one table and

clarified Facility wide

emission units. Renamed

aggregate insignificant

emission unit from AIEU2 to

AIEU1.

The permit was revised to consolidate those

conditions common to both facilities.

4 5 & 70 Reasonable precaution

options expanded for fugitive

Listed rule elements in condition.



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Page 6 of 50

New Permit

Condition

Number

Old Permit

Condition


emission controls

5 6 & 71 Consolidated applicable

emission units

Permit revision and consolidation

6

7 Corrected applicable

reference, deleted the ash

limitation and added the

requirement that future

shipments of distillate fuel oil

be ULSD

Minor Permit Modification No. 21164 requested

fuel sulfur voluntary reductions to 0.05%. Under

Significant Permit Modification No. 22942, PGE

elected to take federally enforceable permit limits

to satisfy the requirements of 40 CFR Part

51.308(e)(1) for the BART-eligible emission units,

and this resulted in the commitment to use ULSD

fuel oil (< 15 ppm S) with a fuel oil quantity limit.

A complete discussion of this Visibility Protection

Strategy issue is included in item 18 of this review

report. Ash requirements were removed as

distillate oil has negligible ash content.

7 8 Added applicable monitoring

rule reference, modified the

sulfur limit to 0.0015% to

reflect the requirement for

ULSD, and deleted ash

limitation and ash testing

requirement

Condition had no rule reference. PGE has

requested the use of ULSD to ensure the Beaver

Turbines (GTEU6) do not cause or contribute to

visibility impairment as part of the Visibility

Protection Strategy. Added annual analysis

requirements for sulfur content. Ash requirements

were removed as distillate oil has negligible ash

content.

-- 9 Condition deleted Rule was rescinded

-- 10 Condition deleted Rule was rescinded

8 11 & 74 Added the provision that the

Department must verify that

the deposition exists.

Change in language to clarify requirement

9 12 & 75 Changed language from

“odorous matter” to “air

contaminants”

Change in language to better clarify requirement

10 13 & 76 Clarified documentation

detail

Change in language to better clarify requirement

11 14 & 72 No change NA


13 16 No change NA


emission units


15 24 Deleted emission unit GTEU6

from condition.

Removed the turbines from this requirement, as

they are not defined in the Division 208 rules as

“fuel burning equipment” per OAR 340-208-

0010(4).

16 26 No change NA


emission units


18 19 No change NA

19 20, 23 & 78 Consolidated applicable

emission units


-- 22 Deleted condition Deleted condition as the turbines are not defined in

the Division 208 rules as “fuel burning equipment”



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Page 7 of 50

New Permit

Condition

Number

Old Permit

Condition


per OAR 340-208-0010(4).

20 25 Removed reference to natural

gas combustion

Clarified requirement as cited rule only applies to

combustion of fuel oil.

-- 79 Deleted condition Rule citation incorrect – not applicable to natural

gas combustion, which is the only fuel PWEU1

and PWABEU1 are permitted to combust.

21 21 Added provisions for testing

auxiliary boiler (ABEU1) on

oil.

Clarified testing requirements for ABEU1.

22 -- New condition added for

daily fuel oil combustion limit

for Beaver turbines (GTEU6)

See item 18, below for a full discussion of the

Department’s Visibility Protection Strategy as part

of the Regional Haze Program, 40

CFR51.308(e)(1).

23 -- New condition added to

monitor and record

requirements of condition 22

See item 18, below for a full discussion of the

Department’s Visibility Protection Strategy as part

of the Regional Haze Program, 40

CFR51.308(e)(1).

24 -- Added testing condition for

Beaver turbines for

formaldehyde

Condition added in response to comments. See

Appendix A and B for complete discussion.

-- 48 Deleted Condition pertaining

to previous fuel oil

combustion limit in the

Beaver turbines (GTEU6)

The previous quantity limit of fuel oil for all 6

turbines was developed from 1982 air dispersion

modeling. These emission units (GTEU6) cannot

physically burn distillate oil at these levels to

exceed the 1982 modeled emission rates. In

addition, the recent voluntary fuel oil quantity

limits presented in Condition 22 govern, as the

modeling completed for the Visibility Protection

Strategy replaces the results from 1982, in any

case. The previous permit states: “Condition 48

cannot be changed without revisiting the 1982 air

quality model.” This modeling was revisited as

explained in detail in items 17, 18 and 19 of this

review report.

25 28 & 96 Deleted initial construction

and startup notifications for

PTEU1 PWEU1 and

PWABEU1, as applicable, as

these notifications were

completed as required

Clarified applicable NSPS General Provision

Notifications and Recordkeeping requirements.

26 102 Added PTEU1 fuel usage Complete record of NSPS equipment fuel usage

27 -- Added condition Added applicable NSPS general provision

condition

28 -- Added condition Added applicable NSPS general provision

condition

29 53 & 91 Combined PSD sources and

conditions


30 27 Updated condition numbers Permit consolidation and restructuring



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Page 8 of 50

New Permit

Condition

Number

Old Permit

Condition


31 29 No change NA

32 30 No change NA

-- 31 & 97 Deleted conditions All initial performance tests for applicable NSPS

sources (i.e. PTEU1, PWEU1 and PWABEU1)

have been completed as required. Conditions no

longer necessary

-- 32 Deleted condition Initial NOx testing on PTEU1 has been completed.

Annual evaluation to be combined with NOx CEM

Rata (Condition 67.a.)

33 35 No change NA

34 36 & 101 Deleted language regarding

previous Departmental

submission detail

Copy of tariff sheet to be maintained on-site

regardless of submittal status to Department

35 49 No change NA

36 50 No change NA

37 51 No change NA

38 52 Added monitoring reference

condition

Expanded applicable monitoring conditions

39 -- Added condition Clarify NSPS applicability and resulting

conditions for PWEU1

40 93 Modified permit condition

references

Clarify monitoring, reporting and testing

requirements for PWEU1.

41 92 Modified permit condition

references


42 81 No change NA

43 82 No change NA

44 94 No change NA

45 83 No change NA

46 84 No change NA

47 85 No change NA

48 86 No change NA

49 87 No change NA

50 88 No change NA

51 --- Added new condition PWEU1 is subject to the Acid Rain provisions

from 40 CFR Part 75.

52 103 Expanded condition language Added rule references, and provision to use

commercial billing meter in lieu of facility gas

meter calibration and maintenance.

53 -- Added new condition PWEU1 is subject to the Acid Rain provisions

from 40 CFR Part 75, and this condition details

the requirements of the CEM systems for the Acid

Rain Program, including CO2.

54 -- Added testing condition for

PW turbine for formaldehyde

Condition added in response to comments. See

Appendix A and B for complete discussion.

55 95 No change NA

56 89 No change NA

57 90 No change NA

58 37, 38, 39,

104, 105 &

106

No change – other than

consolidation

Condition consolidation



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Page 9 of 50

New Permit

Condition

Number

Old Permit

Condition


-- 40 Deleted Condition The Storage and Handling of Petroleum Products

section in OAR 340-208-0560 was redundant with

existing New Source Performance Standards

(NSPS) and vapor control requirements in OAR

340-242-0520, and the rules were recently deleted.

59 43 & 108 PSEL modifications See PSEL discussion below in items 39 through 43

– corrected/updated emission factors and fuel

usage, resulting in PSEL changes per pollutant

60 41 Annual emission limit

modifications

See discussion below in items 39 through 43 -

corrected/updated emission factors and fuel usage,

resulting in emission changes per pollutant

61 42 & 107 Annual emission limit

modifications

See discussion below in items 39 through 43 -

corrected/updated emission factors and fuel usage,

resulting in emission changes per pollutant

62 44.a., 44.c.,

44. d., 109.a.,

109.c. &

109.d.

Consolidated process

parameter recordkeeping and

emission factors. Removed

calculation sections and

testing sections to separate

conditions

Permit revision, consolidation and clarification –

added fuel usage recordkeeping for duct burners,

updated emission factors with correct and/or better

information or testing,.

63 44.b. &

109.b.

Separated emission factor

calculation PSEL compliance

requirement into one

condition. Removed K3

factor for fugitive road

emissions, which will be part

of aggregate insignificant

amount of PM/PM10.

Permit revision, consolidation and clarification

64 45.a., 45.b. &

110

Separated NOx CEM PSEL

compliance requirement into

one condition.


65 45.c. & 110 Separated CO CEM PSEL

compliance requirement into

one condition.


66 46 Added applicable emission

units

Clarified SO2 emission calculation on fuel oil for

emission units GTEU6 and ABEU1 (only units

allowed to burn oil), and added provision to

calculate PWEU1 SO2 emissions per Acid Rain

Program requirements.

67 -- New condition from template

revision for fee payment

based upon actual or

permitted emissions.

Condition added to template and permit to clarify

which pollutants from which emission units are

assessed fees for actual vs. permitted emissions.

68.a. 44.e. No change Although recent testing completed on September

13 & 14, 2007 indicated highest VOC number of

3.2 lbs/mmcf natural gas, one more round of

testing is warranted to confirm much lower

emissions (previous permit EF was 25.2

lbs/mmcf). This permit renewal includes a

reduction of the EF to the recent test average of 6

runs plus 2 standard deviations.



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Page 10 of 50

New Permit

Condition

Number

Old Permit

Condition


68.b. -- New condition adding CO

emission factor verification

testing for GTEU6

combusting fuel oil over a

specific fuel consumption

rate.

A new EF for CO on fuel oil was calculated from

AP-42, which is higher than the previous EF,

which was not explained. The higher EF increases

the CO PSEL, requiring an ambient air quality

analysis for this pollutant. The 97,000 Mgals of

fuel combustion is 75% of the amount of oil that

would result in the emissions of the previous CO

PSEL contribution for this emission unit. (i.e.

[97,000 Mgals oil/yr * 10.6 lbs CO/Mgals

oil]/2000 lbs/ton = 514 tons CO. The previous

PSEL contribution for this emission unit on oil

was 686 tons.

68.c 109.e. Modified condition to remove

reference to initial

performance testing, which

was completed on June 6 & 7,

2007.

Testing completed on June 6 & 7, 2007 indicated

highest VOC number of 0.042 lbs/mmcf natural

gas. The emission factor used in the permit is 2.2

lbs/mmcf, so after one more cycle of testing, this

may be deleted, as results may verify that the

actual emissions are orders of magnitude lower

than the AP-42 emission factor.

-- 109.f. Deleted condition PGE supplied representative test results on

October 1, 2003, and the Department waved the

emission factor verification testing for PM/PM10

for PWEU1 on October 6, 2003. PM emissions

are not expected to be significant due to natural

gas combustion in any case.

68.d 109.g. Added appropriate test

method to conditions

Initial testing indicated interference from ammonia

from the SCR system. Added industry standard

test method be used for evaluation.

69.a. 32 & 111 Consolidated NOx testing

requirement

To demonstrate compliance with the NOx NSPS

limit for PTEU1, PGE can opt to either conduct an

annual source test, or use the RATA method

reference runs as per 40 CFR 60.335(b)(7).

69.b. 98 & 111 Consolidated NOx testing

requirement

To demonstrate compliance with the NOx NSPS

limit for PWEU1, PGE can opt to either conduct

an annual source test, or use the RATA method

reference runs as per 40 CFR 60.335(b)(7).

69.c. -- Added requirement for

QA/QC on NOx CEM for

GTEU6

Although there is no NOx limit, other than the

annual PSEL, for these turbines, GTEU6, the

permittee utilizes the CEM for compliance

purposes, so this condition is added to include

necessary QA/QC verification on the system.

70 33 & 99 Updated language Clarification of submittal terms

71 34, 47, 63,

100 & 112

Consolidation of general

testing requirements

Clarification and consolidation of testing

requirements.

72 -- Added condition from permit

template

General Monitoring conditions were not in permit,

and are necessary requirements per OAR 340-218-

0050.


template

General Monitoring conditions were not in permit,


0050 and 340-218-0080.

74 -- Added condition from permit General Monitoring conditions were not in permit,



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Page 11 of 50

New Permit

Condition

Number

Old Permit

Condition


template and are necessary requirements per OAR 340-218-

0050.



template

General Recordkeeping conditions were not in

permit, and are necessary requirements per OAR

340-214-0110, and Title V requirements.


template

General Recordkeeping conditions were not in

permit, and are necessary requirements per OAR

340-214-0110, and Title V requirements.

78 56 & 115 Added reference to previous

Title V Permit

Facility is under the Title V program, and records

required by that program must be retained for at

least five (5) years, as well as any previous ACDP

recordkeeping requirements.

79 55 & 114 Added pertinent conditions to

each record requirement

Consolidation of conditions for each emission

unit, and referenced specific condition numbers for

each record required.

80 61 Added provision in 78.a. and

modified language to reflect

revision to Department Rules

OAR 340-214-0300 through

0360.

The Department recently adopted rule revisions to

the excess emission reporting requirements found

in Division 214.

81 62 Prompt reporting changed

from 7 days to 15 days to be

consistent with excess

emission reporting.

Consistency among reporting period for excess

emissions and permit deviations is matched to 15

days.

82 64 No change NA

83 65 No change NA



template

General Reporting conditions were not in permit,


0080, and Title V requirements.


template

General Reporting conditions were not in permit,


0080, and Title V requirements.

87 57 &116 Changed quantity of report

copies to be submitted

Quantity reduced from 4 to 3 copies of reports.

88 58 & 117 No change – other than

consolidation


89 59 & 118 Consolidation of

requirements, and updated

condition references

Clarification of requirements

90 60 & 119 No change –other than

consolidation


91 121 No change NA

92 122 No change NA

General

Conditions

G1 – G28

General

Conditions

G1 – G28

No change NA

Attachment 1 Attachment 1 Rule revision list updated New revision date of March 24, 2003 from

previous permit revision date of October 14, 1999.



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Page 12 of 50

New Permit

Condition

Number

Old Permit

Condition


Acid Rain

Permit

Application

Acid Rain

Permit

Application

No change NA

FACILITY DESCRIPTION

6. Beaver Plant

The Beaver plant, located at 80997 Kallunki Road, is a 558 MW electrical power generation facility. The

facility is composed of 6 combined cycle combustion turbines (GTEU6), a steam generator, a Cleaver

Brooks Watertube Boiler (Model DL-52), and one Alstom Model GT 10B natural gas fired simple cycle 24

MW turbine (PTEU1). The original 6 combustion turbines (GTEU6) were installed in 1974 as simple cycle

turbines. Heat Recovery Steam Generators for each turbine were added in 1977 to convert the plant to

combined cycle operation, which necessitated the need for an auxiliary boiler (ABEU1) for start-up, also

added in 1977. The Alstom peaking turbine (PTEU1) was installed in 2001.

The plant was originally built to operate on crude oil, bunker "C" oil (#6), residual oil, and distillate oil

(#2). In 1980, the combustion turbines were modified to permit operation with natural gas. This

modification did not trigger NSR/BACT because there was a reduction in emissions resulting from the

change. The six combined cycle combustion turbines and associated auxiliary boiler primarily combust

natural gas, but can also burn distillate oil. The peaking turbine (PTEU1) is permitted for natural gas only.

7. Port Westward

The Port Westward plant, located at 81566 Kallunki Road, is a 415 MW electrical power generation

facility, which was permitted for construction and initial operation under Standard Air Contaminant

Discharge Permit (ACDP), No. 05-0008, which was issued to PGE on January 16, 2002. The facility is

composed of a single G Class Mitsubishi natural gas fired combined cycle turbine with duct burners

(PWEU1) and a 91 MM Btu/hr natural gas fired auxiliary boiler (PWABEU1). The Port Westward Plant

began commercial operation in June 2007. This Title V Permit includes an Acid Rain Permit and

supporting acid rain application for Port Westward pursuant to Federal Rules 40 CFR 72.6.

The Standard ACDP for the Port Westward plant included a Prevention of Significant Deterioration (PSD)

permit. The PSD permit was originally issued on January 16, 2002, and subsequently modified on August

27, 2003, and May 12, 2005. The August 27, 2003, modification involved a Departmental approval of the

extension of the construction authorization until January 1, 2005. The Port Westward Plant commenced

construction on September 3, 2004. The May 12, 2005, modification involved expanding the permit to

construct and operate a natural gas fired auxiliary boiler (PWABEU1). This type boiler was not required

under the original permit which allowed construction of two F-Class combustion turbines with an electric

boiler. On December 17, 2003, the Department approved PGE’s request to construct one G-Class turbine

in lieu of the two F-Class turbines originally requested. Any changes to conditions in the PSD permit

require revisiting the PSD action.

8. Permit-wide/Facility-wide areas:

In addition to the turbine and boiler facilities, the plant(s) also contain the following areas/equipment:

Buildings for Administration, Engineering and Training.

A Maintenance Building.

A Demineralizer Building for processing river water into potable water and demineralized water

for NOX control and boiler feed water.

A mechanical draft cooling tower and associated circulating water system building.

A tank farm for storing distillate oil (two of the tanks are leased to Cascade Grain and used to store

denatured ethanol)



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Page 13 of 50

A natural gas supply station, which includes a natural gas heater (NATCO Indirect Pipeline Heater

Model D-92743). This unit was installed by Northwest Natural Gas Co. in 1993.

Distillate oil unloading facilities capable of receiving oil by railcar, truck or barge/ship. The

barge/ship unloading system is presently isolated for spill control.

An intake structure for supplying river water for cooling, fire protection and making potable and

demineralized water.

Settling and holding ponds for water returned to the river.

Unpaved roads

EMISSIONS UNIT AND POLLUTION CONTROL DEVICE IDENTIFICATION

9. Emission Units

Existing air emission sources at the facility are described below. Table 3, which follows this source

description, summarizes the identification numbers.

Beaver Plant

9.a. Emission Unit ID GTEU6: Six (6) General Electric Combustion Turbines (Model 7001-B). The

emission control system includes water injection for NOx control and limits on fuel sulfur content

and quantity (0.05% maximum sulfur by weight), with future shipments of oil limited to 0.0015%

sulfur. The operating scenario for the facility is based on these six turbines operating at maximum

capacity through the year on either distillate oil or natural gas fuel. These turbines are equipped

with CEMs for NOx and O2. PGE refers to these units as Units 1 – 6.

9.b. Emission Unit ID ABEU1: One (1) Cleaver-Brooks 50.525 mmbtu/hr Boiler (Model DL-52), Unit

No. WL-2005. It was put into service in 1977 when the turbines were upgraded from simple cycle

to combined cycle. This boiler is used for combustion turbines start-up and is not run while the

turbine(s) is(are) in normal operating mode.

9.c. Emission Unit ID PTEU1: One (1) Alstom Model GT 10B, 24MW simple cycle turbine with

water injection, dry low NOX combustion and a CO catalyst, fired on natural gas only. This

turbine is equipped with CEMS for NOx, CO and O2. PGE refers to this unit as Unit 8.

Port Westward

9.d. Emission Unit ID PWEU1: One (1) Mitsubishi Class G Combustion Turbine, natural gas fired,

dry low NOx burners with steam cooled combustors. A Deltak Heat Recovery Steam Generator

operates as a combined cycle configuration with the combustion turbine and the steam turbine.

The HRSG system includes a 198 mmbtu/hr Forney duct burner in the stack. Emissions are

controlled by a Deltak SCR system (ammonia injection and catalyst) for NOx control and a CO

reduction catalyst. This turbine is equipped with CEMS for NOx, CO and O2.

9.e. Emission Unit PWABEU1: One (1) Babcock & Wilcox 91mmbtu/hr auxiliary boiler, D-type

water tube, natural gas fired. The boiler is designed to deliver 69,800 lbs/hr gross, (59,690 lbs/hr

net) of superheated steam; however normal maximum steaming rate is 45,000 lbs/hr. This boiler is

used for combustion turbine start-up and is not run while the turbine is in normal operating mode.

Permit/Facility-wide

9.f. Emission Unit ID AEIU1: Aggregate insignificant emissions, which includes the paved roads

fugitive emissions.

9.g. Emission Unit ID UREU1: Unpaved Roads (fugitive emissions) is based on the facility’s fleet

vehicles driving on the unpaved roads on the plant site.

10. The emissions units regulated by this permit are the following [OAR 340-218-0040(3)]:



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Table 3.

Emissions Unit EU ID Pollution Control

Device/Practice

PCD ID

BEAVER PLANT

Six combined cycle combustion turbines for electric

power generation

(natural gas or distillate fuel oil fired)

GTEU6 Water injection GTCD6

Auxiliary Boiler (natural gas or distillate fuel oil fired) ABEU1 None NA

Peaking turbine

(Natural gas fired)

PTEU1 Dry Low NOX, Water

Injection,

PTCD1

Oxidation Catalyst for CO PTCD2

PORT WESTWARD PLANT

Combined cycle combustion turbine for electric power

generation with duct firing

(natural gas fired)

PWEU1 SCR for NOx control

CO catalyst for CO and

VOC control

PWCD1

Auxiliary Boiler (for combustion turbine startup – natural

gas fired)

PWABEU1 Low-NOX burners for NOX

control

NA

FACILITY-WIDE

Unpaved roads UREU1 None NA

Aggregate insignificant activities including paved roads

and natural gas pipeline heater

AIEU1 None NA

11. Categorically insignificant activities include the following:

Constituents of a chemical mixture present at less than 1% by weight of any chemical or compound

regulated under OAR Chapter 340, Divisions 200 through 268, excluding Divisions 248 and 262, or less

than 0.1% by weight of any carcinogen listed in the U.S. Department of Health and Human Service's

Annual Report on Carcinogens when usage of the chemical mixture is less than 100,000 pounds/year

Evaporative and tail pipe emissions from on-site motor vehicle operation

Distillate oil, kerosene, and gasoline fuel burning equipment rated at less than or equal to 0.4 million Btu/hr

Natural gas and propane burning equipment rated at less than or equal to 2.0 million Btu/hr

Office activities

Food service activities

Janitorial activities

Personal care activities

Groundskeeping activities including, but not limited to building painting and road and parking lot

maintenance

On-site recreation facilities

Instrument calibration

Maintenance and repair shop

Automotive repair shops or storage garages

Air cooling or ventilating equipment not designed to remove air contaminants generated by or released from

associated equipment

Refrigeration systems with less than 50 pounds of charge of ozone depleting substances regulated under

Title VI, including pressure tanks used in refrigeration systems but excluding any combustion equipment

associated with such systems

Bench scale laboratory equipment and laboratory equipment used exclusively for chemical and physical



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analysis, including associated vacuum producing devices but excluding research and development facilities

Temporary construction activities

Warehouse activities

Accidental fires

Air vents from air compressors

Air purification systems

Continuous emissions monitoring vent lines

Demineralized water tanks

Pre-treatment of municipal water, including use of deionized water purification systems

Electrical charging stations

Instrument air dryers and distribution

Process raw water filtration systems

Pharmaceutical packaging

Routine maintenance, repair, and replacement such as anticipated activities most often associated with and

performed during regularly scheduled equipment outages to maintain a plant and its equipment in good

operating condition, including but not limited to steam cleaning, abrasive use, and woodworking

Electric motors

Storage tanks, reservoirs, transfer and lubricating equipment used for ASTM grade distillate or residual

fuels, lubricants, and hydraulic fluids

On-site storage tanks not subject to any New Source Performance Standards (NSPS), including

underground storage tanks (UST), storing gasoline or diesel used exclusively for fueling of the facility's

fleet of vehicles

Natural gas, propane, and liquefied petroleum gas (LPG) storage tanks and transfer equipment

Pressurized tanks containing gaseous compounds

Emissions from wastewater discharges to publicly owned treatment works (POTW) provided the source is

authorized to discharge to the POTW, not including on-site wastewater treatment and/or holding facilities

Storm water settling basins

Fire suppression and training

Hazardous air pollutant emissions of fugitive dust from paved and unpaved roads except for those sources

that have processes or activities that contribute to the deposition and entrainment of hazardous air pollutants

from surface soils

Health, safety, and emergency response activities

Emergency generators and pumps used only during loss of primary equipment or utility service due to

circumstances beyond the reasonable control of the owner or operator, or to address a power emergency as

determined by the Department

Non-contact steam vents and leaks and safety and relief valves for boiler steam distribution systems

Non-contact steam condensate flash tanks

Non-contact steam vents on condensate receivers, deaerators and similar equipment

Boiler blowdown tanks

Industrial cooling towers that do not use chromium-based water treatment chemicals

Ash piles maintained in a wetted condition and associated handling systems and activities

Oil/water separators in effluent treatment systems

Combustion source flame safety purging on startup

EMISSION LIMITS AND STANDARDS, TESTING, MONITORING, AND RECORDKEEPING

Facility wide Emission Limits and Standards

Table 4.

Applicable Requirement Pollutant/

Parameter

Limit/Standard Monitoring

Method

340-208-0210(2) Fugitives Minimize VE periodic



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monitoring

February 2006 Minor Permit Modification No. 216181,

May 2008 Significant Permit Modification No. 229422,

40CFR51.308(e)(1) and 340-228-0110

Fuel sulfur 0.05% S1 with

quantity limits

Future shipments:

0.0015% S2

FSA or

recordkeeping

340-208-0450 PM > 250 No fallout NA

340-208-0300 Odors No nuisance Recordkeeping

340-206-0050 SERP Emission

reductions

Recordkeeping

40 CFR Part 68 Risk

management

Risk management

plan NA

1 PGE voluntarily took a reduction in sulfur content in the fuel oil, from 0.3%, which is the requirement

found in OAR 340-228-0110(1) to 0.05%. This change resulted in a SO2 PSEL reduction of 5358

tons/year. 2 PGE voluntarily limited all future shipments of fuel oil to ULSD, with a sulfur content of 0.0015% as part

of the Visibility Protection Strategy under the Regional Haze Program. This change resulted in an

additional 522 tons/year of SO2 PSEL reduction.

Emission Unit Specific Emission Limits and Standards

Table 5.

BEAVER PLANT

Emissions

Unit(s)

Applicable

Requirement

Pollutant/

Parameter


Method

GTEU6 340-208-0110(2)

and (3)

Visible emissions 20% opacity, 3 min. in 60

min.

VE periodic

monitoring

340-226-

0210(1)(b)

PM 0.1 gr/dscf ST periodic

monitoring, VE

periodic

monitoring, or

Fuel

recordkeeping

40 CFR

51.308(e)(1)

Visibility 0.5 deciviews (24-hour

basis)

Fuel quantity

limitations

ABEU1 340-208-0110(2)

and (3)


min.

VE periodic

monitoring

340-208-0610(2) Smoke spot #2 VE periodic

monitoring

340-228-

0210(1)(b)

PM 0.1 gr/dscf @ 50% excess

air

ST periodic

monitoring, VE

periodic

monitoring, or

Fuel

recordkeeping



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Page 17 of 50

340-208-0610(1) PM 0.21 lb/106 Btu heat input ST periodic

monitoring, VE

periodic

monitoring, or

Fuel

recordkeeping

PTEU1 340-208-0110(2)

and (3)


min.

VE periodic

monitoring

340-226-

0210(1)(b)

PM 0.1 gr/dscf ST periodic

monitoring, VE

periodic

monitoring, or

Fuel

recordkeeping

NSPS

340-238-

0060(3)(mm)

40 CFR Part 60

Subpart GG

NOx emission concentration See formulas in condition Stack Testing

and CEM

Fuel use and sulfur content Pipeline quality natural gas

and 0.8% sulfur by weight

Fuel Sampling

and

Recordkeeping

BACT

(340-224-0070)

NOX 17 ppmvd @ 15% O2, 8-hr.

rolling average

CEMS

CO 5 ppm @ 15% O2, 8-hr.

rolling average

CEMS

VOC 4.73 pounds/hour, 8-hr

rolling average as CH4

Recordkeeping

PM/PM10, SO2 Pipe line quality NG Fuel

recordkeeping

PM10, CO, NOX, SO2, and VOC PSD Event Log,

recordkeeping

and CEMs

PORT WESTWARD PLANT

Emissions

Unit(s)

Applicable Requirement Pollutant/

Parameter


Method

PWEU1 340-208-0110(2) and (3) Visible

emissions

20% opacity, 3

min. in 60 min.

Fuel

recordkeeping

340-226-0210(1)(b) PM 0.1 gr/dscf Fuel

recordkeeping

OAR 340-208-0300 Nuisance 8 ppmvd

ammonia

slippage

Source test

BACT 340-224-0070(1) NOX 2.5 ppm at

15% O2

CEMS

CO 4.9 ppm at

15% O2

CEMS

VOC 7.74

pounds/hour

Recordkeeping

PM/PM10,

SO2

Pipe line

quality NG

Fuel

recordkeeping



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Page 18 of 50

Startup

and

shutdown

Startup and

shutdown

procedures

Event log

PM10,

CO, NOX,

SO2, and

VOC

PSD Event Log,

recordkeeping

and CEMs

340-238-0060(3)(mm)

40 CFR Part 60.333(b)

Fuel use

and sulfur

content

Pipeline

quality natural

gas and

0.8% sulfur by

weight

Fuel Sampling

and

Recordkeeping

40 CFR Part 60.332(a)(1) NOX 111 ppm NOx

at 15% O2

ST

40 CFR Part 60.44b(a)(4)(i) NOX 0.20

lb/MMBtu/hr,

30-day rolling

ave.

CEMS

PWABEU1 340-208-0110(2) and (3) Visible

emissions

20% opacity, 3

min. in 60 min.

Fuel

recordkeeping

340-226-0210(1)(b) PM 0.1 gr/dscf Fuel

recordkeeping

BACT 340-224-0070(1) NOX Low NOX

burner, 4.55

lb/hr

Hours of

operation and

source test

BACT 340-224-0070(1) CO,

VOC,

PM/PM10,

SO2

Pipe line

quality NG

Fuel

Recordkeeping

NSPS 40CFR60.48.c Operation Hours Recordkeeping

PERMIT/FACILITY – WIDE

UREU1 340-208-0110(2) and (3) Visible

emissions

20% opacity, 3

min. in 60 min.

VE periodic

monitoring

340-208-0600 Visible

emissions

20% opacity,

30 seconds in

60 min.

VE periodic

monitoring

AIEU1 340-208-0110(2) and (3) Visible

emissions

20% opacity, 3

min. in 60 min.

NA

340-208-0600 Visible

emissions

20% opacity;

30 seconds in

60 min.

NA

340-226-0210(1)(b) PM 0.1 gr/dscf NA

Emission Units GTEU6 – Units 1 -6 Beaver Plant

12. The applicable limits and standards for these turbines are the opacity (20%) and PM (0.1 gr/dscf ) standards

from the DEQ rules, and the fuel oil limits in sulfur content and corresponding quantity as part of PGE’s

and the Department’s Visibility Protection Strategy under the Regional Haze Rule, which is discussed in

detail in item 18, below. There are no applicable NSPS for these turbines, however the permittee utilizes



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water injection to control NOx and a CEMs to measure NOx. These turbines are not required to meet any

specific standards other than the PSEL, nor are these turbines subject to the Compliance Assurance

Monitoring Requirements (Part 64). CAM is defined under 40 CFR, Part 64 incorporated into Oregon’s

rules as OAR 340-212-0200 through 340-212-0280. These rules require compliance assurance monitoring

for emissions units with add-on control devices that would have uncontrolled potential emissions greater

than 100 tons per year if the control device were not in place. The rules are pollutant specific and only

apply to those pollutants that are regulated by emissions standards or limits promulgated before November

1992, excluding the Plant Site Emissions Limit (PSEL). Because these turbines are not subject to any

emission standards or limits promulgated before Nov 1992 other than the opacity and PM limits, discussed

above, and the equipment does not have any add-on control equipment for particulate emissions, CAM does

not apply to these turbines. The water injection would not be considered CAM applicable equipment, as

there are no applicable NOx standards or limits for these turbines.

Monitoring Requirements

13. The permittee must monitor visible emissions using modified EPA Method 9 if the turbines are combusting

oil for longer than 30 minutes. The permit includes a reduction in frequency if the results are consistently

less than 20% opacity. If the turbines are combusting natural gas, no visible emissions or particulate matter

monitoring is required, as it is highly unlikely that these standards could be violated on this fuel.

Testing Requirements

14. The permittee must test for particulate matter for these turbines if they are operated on fuel oil more than

438 hours per year for any one turbine or 2,628 hours per year for the combined turbines.

15. The permittee must conduct a Relative Accuracy Audit (RAA) on the NOx CEM at least once per permit

term, or within three months of any 12-month period if they are collectively operated greater than 28,000

hours, which is the amount of hours that would result in approximately 50% of the NOx component of the

PSEL for these turbines if operated on natural gas.1

16. The permittee must conduct a source test for formaldehyde on two of the Beaver turbines while operating

on natural gas within the first year of permit issuance. Note: This item was added in response to

comments on 12/23/2008. See Appendices for discussion.

Special Requirements/Issues

17. The previous permit contained a condition (48) that limited fuel oil combustion in GTEU6 in order to

maintain consistency with the worst case emission rates used in the 1982 air quality modeling. The limit

was to combust no more than 47,706 gallons of fuel oil per hour for all six turbines. This limitation was

based on the modeled NOX emission rate of 1680 pounds per hour, and modeled SO2 emission rate of 1585

pounds per hour. These emission units (GTEU6) cannot physically burn distillate oil at these levels. In

addition, the recent voluntary fuel oil quantity limits presented in Permit Condition 23 govern, as the

modeling completed for the Visibility Protection Strategy under the Regional Haze – BART Regulations

replaces the results from 1982, in any case. The previous permit states: “Condition 48 cannot be changed

without revisiting the 1982 air quality model.” This modeling was revisited as explained in detail in item 18

of this review report, and therefore this condition is deleted in this permit action.

18. Regional Haze-BART - The original six Beaver turbines (GTEU6) were identified as a BART-eligible

source, as they were installed between August 1962 and August 1977, are within one of the 26 specifically

listed source categories, and have the potential to emit 250 tons or more of visibility-impairing pollutants,

namely NOx, PM10 and SO2. BART is required for any BART-eligible source which emits any air pollutant

1 GTEU6 emissions approximately 125 lbs NOx per hour. NOx PSEL component on gas = 3552 tons/yr.

3552*2000*0.5 = 3,552,000 lbs NOx/yr. 3552000/125 = 28,416 hours.



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Page 20 of 50

which may reasonable be anticipated to cause or contribute to any impairment of visibility in Class I areas.

Alternatively, federally enforceable permit limits may be established to ensure visibility impacts are below

the 0.5 deciviews threshold. A modeling study using the highest emission rates between 2003 through 2005

indicated that the Beaver turbine emissions resulted in significant visibility impairment upon six of the

fourteen Class I areas evaluated, plus impairment in the Columbia River Gorge Scenic Area, (although not a

Class I area, it was included for informational purposes only). The modeled emissions were from February

25, 2003, which represent the maximum 24-hour average actual emissions between 2003 and 2005, and

occurred while combusting distillate oil in all six turbines.

The significant permit modification No. 22942, submitted in May, 2008, requested fuel oil quantity limits

for these turbines based upon the sulfur content of the fuel oil combusted, as well as the requirement that all

future shipments of oil contain no more than 0.0015% sulfur (i.e. ULSD). The regression analysis equation

presented in Condition 22 determines a daily fuel oil quantity limit that is tied to the sulfur content of the

fuel so as to not exceed the significance threshold of 0.5 deciviews for visibility impairment. The federally

enforceable permit limits identified in permit conditions 22 and 23 satisfy section 40 CFR 51.308(e)(1) of

the Regional Haze Rule, and are consistent with Appendix Y to 40 CFR Part 51 – Guidelines for BART

Determinations Under the Regional Haze Rule. The Department has determined that these permit limits

will prevent the BART-eligible emission units (i.e. GTEU6) at the PGE Beaver plant from causing or

contributing to any impairment over the visibility threshold of 0.5 deciviews, in any mandatory Class I

Federal Area. As a result, PGE Beaver is not subject to BART for those BART-eligible emission units.

19. CO PSEL and emission factor increase - This permit action increases the PSEL for CO, as shown in

Table 13 in item 43. This increase is a result of an emission factor correction only, as the previous permit

CO emission factor for the Beaver turbines on oil was 2.664 lbs/Mgals. The reference for this was cited as

EPA AP-42 Table 1.3-5, which is an incorrect citation for both equipment type and pollutant and is not the

source of the actual emission factor number, in any case. The correct reference for this type of equipment

and pollutant is EPA AP-42 Table 3.1-1, which lists an emission factor of 7.6E-02 lbs/mmbtu for distillate

oil-fired turbines with water-steam injection; using an oil heating value of 139,000 btu/gal, this would equal

10.6 lbs/Mgal. The PSEL detail sheets have been updated to reflect this change. Because the increase is a

correction only, and not a result of an equipment modification or new construction, NSR (i.e. BACT)

requirements are not triggered, but the Department requires an air quality analysis be conducted per OAR

340-225-0050. Based on the Department’s 1986 analysis of the PGE Beaver's ambient impacts results,

which was re-reviewed by both the Department and PGE in the May 2008 significant permit modification

No. 22942, the ambient air quality standard for CO is not exceeded when the facility emits 537.5 lbs/hr of

this pollutant. Emission estimates for this permit renewal indicate maximum CO emissions are significantly

less than the modeled 1986 values. No physical or operational changes have taken place on the facility's

turbines since the 1986 analysis. The 1986 air quality analysis successfully demonstrated that the existing

CO emissions will not result in any ambient air quality violation within the Class II areas potentially

influenced by the PGE Beaver facility. In addition, there is no PSD increment for CO, so the NAAQS is the

only standard that is applicable for this pollutant.

Emission Unit ABEU1 – Beaver Plant Auxiliary Boiler

20. The only applicable limits and standards for this boiler are the opacity (20% and smoke spot #2) and PM

(0.1 gr/dscf and 0.21 lbs/mmbtu when combusting oil only) standards from the DEQ rules. There are no

applicable NSPS for this boiler, it is not required to meet any specific standards other than the PSEL, and it

is not subject to the CAM Requirements (Part 64), because emissions from this unit are less than 100 ton/yr

for any pollutant uncontrolled and this unit does not have any control devices.


21. The permittee must monitor visible emissions using modified EPA Method 9 if the boiler is combusting oil

for longer than 30 minutes. The permit includes a reduction in frequency if the results are consistently less

than 20% opacity. If the boiler is combusting natural gas, no visible emissions or particulate matter

monitoring is required, as it is highly unlikely that these standards could be violated on this fuel.



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22. The permittee must test for particulate matter for this boiler if it is operated on fuel oil more than 100 hours

per year.

Emission Unit PTEU1 – Unit 8 Beaver Plant

NSPS Subpart GG

23. Emission unit PTEU1 is subject to NSPS Subpart GG, Standards of Performance for Stationary Gas

Turbines, 40CFR 60.330 through 60.335. Specifically, this turbine is subject to the NOx limit in 60.332(a),

which is calculated to be 101 ppm. In any case, the BACT NOx limit is considerably lower, as discussed in

item 24, and compliance with the BACT limit guarantees compliance with the NSPS limit. NOx emissions

must be measured with a CEM per 60.334(a), and the annual RATA for this system can be used for the

NOx performance testing, as allowed in 60.335(b)(7), or the permittee can conduct a performance test

utilizing one of the listed reference methods per 60.335(a). The permittee must also only use pipeline

quality natural gas in this turbine to demonstrate compliance with the sulfur limits in 60.333(b), and

60.334(h)(3)(i).

BACT Requirements

24. Best Available Control Technology (BACT) analysis for PTEU1 is required by OAR 340-224-0070(1). A

detailed BACT analysis is included in the Review Report for Application No. 018229, but Table 6 has a

BACT summary:

Table 6.

Pollutant BACT

NOX The permittee must not cause or allow the emissions of nitrogen oxides (NOX)

from emission unit PTEU1 in excess of 17 ppmvd corrected to 15% oxygen,

based on an 8-hour rolling average. Nitrogen oxides must be controlled by the

use of Dry Low NOX combustion (DLN), water injection, and good combustion

practices. Nitrogen oxides must be measured by CEMS. Water injection is not

required during startup and shutdown, however the BACT NOX limit is

applicable to startup and shutdown events.

CO The permittee must not cause or allow the emissions of carbon monoxide from

emission unit PTEU1 in excess of 5 ppmvd, corrected to 15% oxygen based on

an 8-hour rolling average. Carbon monoxide must be controlled by catalytic

oxidation, and good combustion practices. Carbon monoxide must be measured

by CEMS. The BACT CO limit is applicable to startup and shutdown events.

VOC The permittee must not cause or allow the emissions of volatile organic

compounds (VOCs) from emission unit PTEU1 in excess of 4.73 pounds per

hour as methane, CH4, based on an 8 hour rolling average. VOC emissions must

be controlled by good combustion practices. The BACT VOC limit is

applicable to startup and shutdown events.

PM/PM10 and SO2 The permittee must control emissions of PM/PM10 and SO2 by limiting fuel use

in emission unit PTEU1 to pipe line quality natural gas.


25. The permittee must monitor NOx and CO utilizing CEMs for these pollutants, and must monitor fuel usage

and maintain a tariff sheet on-site indicating the use of pipeline quality natural gas.




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26. The permittee must conduct a Relative Accuracy Test Audit (RATA) annually on the NOx and CO CEM

systems as part of the CEMS quality assurance program and for NSPS requirements (NOx CEM only).

Emission Unit PWEU1 – Port Westward Turbine and Duct Burners

NSPS Subpart GG - Turbine

27. Emission unit PWEU1 is subject to NSPS Subpart GG, Standards of Performance for Stationary Gas

Turbines, 40CFR 60.330 through 60.335. Specifically, this turbine is subject to the NOx limit in 60.332(a),

which is calculated to be 111 ppm. In any case, the BACT NOx limit is considerably lower, as discussed in

item 29, and compliance with the BACT limit guarantees compliance with the NSPS limit. NOx emissions

must be measured with a CEM per 60.334(a), and the annual RATA for this system can be used for the

NOx performance testing, as allowed in 60.335(b)(7), or the permittee can conduct a performance test

utilizing one of the listed reference methods per 60.335(a). The permittee must also only use pipeline

quality natural gas in this turbine to demonstrate compliance with the sulfur limits in 60.333(b), and

60.334(h)(3)(i).

NSPS Subpart Db – Duct Burner

28. The 198 mmbtu/hr Deltak duct burner portion of Emission unit PWEU1 is subject to NSPS Subpart Db,

Standards of Performance for Industrial-Commercial-Institutional Steam Generating Units, 40CFR 60.40b

through 60.49b. Specifically, this unit only combusts natural gas, so the SO2 and PM limits are not

applicable (60.42b and 60.43b). The NOx limit from 60.44b(a)(4)(i), is applicable and is 0.2 lbs

NOx/mmbtu heat input, determined on a 30-day rolling average per 60.44b(i).

BACT Requirements

29. Best Available Control Technology (BACT) analysis for PWEU1 is required by OAR 340-224-0070(1). A

detailed BACT analysis is included in the Review Report for Standard ACDP 05-0008, the Port Westward

permit for construction, Application No. 018688, but Table 7 has a BACT summary:

Table 7.

Pollutant BACT


from emission unit PWEU1 in excess of 2.5 ppmvd corrected to 15% oxygen,

based on a 3-hour rolling average. Nitrogen oxides must be controlled by the

use of Dry Low NOX combustion (DLN), selective catalytic reduction (SCR),

and good combustion practices. Nitrogen oxides must be measured by CEMS.

CO The permittee must not cause or allow the emissions of carbon monoxide from

emission unit PWEU1 in excess of 4.9 ppmvd, corrected to 15% oxygen based

on a 3-hour rolling average. Carbon monoxide must be controlled by catalytic

oxidation, and good combustion practices. Carbon monoxide must be measured

by CEMS.

VOC The permittee must not cause or allow the emissions of volatile organic

compounds (VOCs) from emission unit PTEU1 in excess of 7.74 pounds per

hour as methane, CH4, based on an 3 hour rolling average. VOC emissions must

be controlled by good combustion practices.

PM/PM10 The permittee must control emissions of PM/PM10 by limiting fuel use in

emission unit PWEU1 to pipe line quality natural gas.

SO2 and H2SO4 The permittee must control emissions of SO2 and H2SO4 by limiting fuel use in

emission unit PWEU1 to pipe line quality natural gas.

Minimization of

emissions during

Specific start-up and shutdown events must be followed, as indicated in the

permit condition 48. These requirements are programmed into the startup and



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startup and shutdown shutdown sequences at the facility.

Ammonia Slip Limits to 8 ppmv (is this a BACT requirement or nuisance driven???)

Acid Rain Permit

30. The Port Westward Turbine is an affected source under Title IV of the Clean Air Act, so it is subject to the

Acid Rain rules in 40 CFR Part 72 through 78. The Acid Rain permit is included as an attachment to the

permit and includes its own statement of basis. The Acid Rain permit was effective beginning on August 1,

2006 and has a 5 year permit term.


31. The permittee must monitor NOx and CO utilizing CEMs for these pollutants, and must monitor fuel usage

and maintain a tariff sheet on-site indicating the use of pipeline quality natural gas.


32. The permittee must conduct a Relative Accuracy Test Audit (RATA) annually on the NOx and CO CEMs as

part of the CEMS quality assurance program and for NSPS requirements (NOx CEM only ).

33. The permittee must conduct a source test for formaldehyde on the PW turbine within the first year of permit

issuance. Note: This item was added in response to comments on 12/23/2008. See Appendices for

discussion.

Emission Unit PWABEU1 – Port Westward Auxiliary Boiler

NSPS Subpart Dc

34. Emission unit PWABEU1 is subject to NSPS Subpart Dc, Standards of Performance for Small Industrial-

Commercial-Institutional Steam Generating Units, 40CFR 60.40c through 60.48c. Specifically, this unit

only combusts natural gas, so the SO2 and PM limits are not applicable (60.42c and 60.43c). The amount of

natural gas combusted and hours of operation must be monitored on a daily basis per 60.48c(g) and kept for

two years, per 60.48c(i).

BACT Requirements

35. Best Available Control Technology (BACT) analysis for PWABEU1 is required by OAR 340-224-0070(1).

A detailed BACT analysis is included in the Review Report for Application No.20606, Addendum No. 2 to

the Standard ACDP No. 05-0008 for the Port Westward construction, but Table 8 has a BACT summary:

Table 8.

Pollutant BACT


from emission unit PWABEU1 in excess of 4.55 lbs/hr. Nitrogen oxides must

be controlled by the use of Low NOX burners.

CO, PM, PM10, SO2,

and VOC

The permittee must control emissions of CO, PM, PM10, SO2 and VOC by

limiting fuel use in emission unit PTEU1 to pipe line quality natural gas and

good combustion practices.

Insignificant activities

36. As identified earlier in this Review Report, this facility has insignificant emissions units (IEUs) that include

categorically insignificant activities and aggregate insignificant emissions, as defined in OAR 340-200-



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0020. For the most part, the standards that apply to IEUs are for opacity (20% limit) and particulate matter

(0.1 gr/dscf limit). The Department does not consider it likely that IEUs could exceed an applicable

emissions limit or standard because IEUs are generally equipment or activities that do not have any

emission controls (e.g., small natural gas fired space heaters) and do not typically have visible emissions.

Since there are no controls, no visible emissions, and the emissions are less than one ton per year, the

Department does not believe that monitoring, recordkeeping, or reporting is necessary for assuring

compliance with the standards.

PLANT SITE EMISSION LIMITS

Baseline Emission Rate

37. This facility operated in the baseline year 1977. The reported hours of operation, fuel use, and production

were as follows:

37.a. The maximum plant operation was 688 hours during 1977. The total operating hours for all 6

turbines in 1977 was 2105 hours and 168 hours for the auxiliary boiler.

37.b. The total annual distillate oil consumption during this baseline period was 10,359,804 gal for the

turbines and 61,992 gal for the auxiliary boiler.

37.c. The maximum fuel usage rate during 1977 was 31,493 gal/hr for the turbines and 369 gal/hr for the

auxiliary boiler.

37.d. The maximum hourly production rate in the baseline year was 519 Mw/hour and the annual

production was 120,104 Mw-hr.

38. Emissions in tons per year for the baseline year 1977 were as follows:

Table 9.

Emissions device PM/PM10 CO NOx SO2 VOC Pb

Combustion turbines (GTEU6) 25.9 13.8 182.3 217.8 3.5 0.1

Auxiliary boiler (ABEU1) 0.1 0.2 0.6 1.3 0.01 0.001

Unpaved roads (UREU1) 2.1 NA NA NA NA NA

Aggregate insignificant (AIEU2) 1.0 1 1 1 1 0.06

Total 29 15 184 220 4.5 0.16

NA means that the pollutant is either not emitted or the emissions are less than 0.1 ton/yr.

PSEL DISCUSSION:

Based on a plant history which includes emission increases due to expanded use of equipment existing in the baseline

year and the installation of new equipment with emissions above the Significant Emission Rates (SERs), the permit

contains two sets of equipment-specific limits (ESL), as well as the overall PSEL.

39. The ESL for the emissions from equipment that existed in the baseline year is as follows:

Table 10.

Emissions Unit Pollutant Annual Emission Limit for Equipment Existing in

the Baseline Year (ton/yr)

GTEU6, ABEU1, AIEU22, and

UREU13 (Beaver Plant Equipment)

PM/PM10 140

CO 1008

2 AIEU2 is renamed to AIEU1 in this permit renewal, as it is unclear why it was labeled “2” instead of “1”.

3 UREU1, Unpaved Roads is for the entire permitted facilities, Beaver and Port Westward plants, not only the

Beaver plant.



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Emissions Unit Pollutant Annual Emission Limit for Equipment Existing in

the Baseline Year (ton/yr)

NOx 3553

SO2 559

VOC 87

40. The ESL for the emissions from new and modified equipment (Beaver Plant: PTEU1; Port Westward Plant:

PWEU1 and PWABEU1) is as follows:

Table 11.

Emissions Unit Pollutant Annual Emission Limit for New and Modified

Equipment (ton/yr)

PTEU1 (Beaver Plant),

PWEU1 and PWABEU1

(Port Westward Plant)

PM/PM10 99

CO 96

NOx 223

SO2 36

VOC 32

41. The permit-wide PSEL for all emissions units, including insignificant activities, is as follows for any 12

consecutive calendar month period:

Table 12.

Emissions Unit Pollutant Permit-Wide PSEL (ton/yr)

Permit-wide:

Beaver Plant – GTEU6, ABEU1

Port Westward Plant - PWEU1, PWABEU1

Facility-wide – AIEU1 and UREU1

PM/PM10 241

CO 1104

NOx 3776

SO2 595

VOC 118

Note: the previous permit has Pb listed as a PSEL pollutant, but the assigned PSEL amount was listed in all three

PSEL tables as “N/A”; therefore it was removed as a listed pollutant.

42. Netting Basis/ Three PSEL Discussion

In the permitting past for these facilities, PGE increased their PSEL due to use of equipment that existed during the

baseline year and also increased their PSEL due to use of new and modified equipment. This resulted in some

special situations which impacted/impact PSELs, netting basis, and major/minor New Source Review applicability.

The original PGE facility (Beaver) was constructed and began operation as a peaking power plant in 1977.

However, the rate of operation was very low which resulted in a low baseline and subsequent netting basis. Several

years later in 1986 PGE requested an increase in their PSELs to allow “increased use of existing capacity”.

Increased use of existing capacity does not involve construction or modification of the facility, it simply means

operating the facility for more time or at higher rates than it was operated during the baseline period. PSEL

increases for increased use of existing capacity do not trigger NSR/PSD, and do not change the netting basis. PGE

conducted an air quality analysis demonstrating no adverse impact and were granted the requested PSEL increases in

accordance with the PSEL rule.

Of particular concern is the fact that PSEL increases for increased use of existing capacity may only be used for the

specific equipment that the increase was granted for; in other words, they cannot be used for netting of other

equipment. Further, because such increases are tied to specific equipment, these increases become invalid if and

when that equipment is permanently shut down.



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In early 2001, PGE installed a 24MW peaking turbine (PTEU1) and modified their permit to include operational

limits to keep new and modified equipment emissions to less than the SERs. Later in 2002 PGE applied for a

Standard/Construction ACDP for construction and operation of a new large turbine (PWEU1). The permit was

issued on January 16, 2002. With the addition of the proposed turbine, new and modified equipment emissions

exceeded the SERs triggering PSD for all new and modified equipment (PTEU1, PWEU1, and PWABEU1). PGE

satisfied PSD requirements including BACT for PTEU1, PWEU1, and PWABEU1. When a source satisfies

NSR/PSD, their netting basis is increased by the amount equal to the emission increases granted in the NSR/PSD

action.

As a result of this sequence of events and emissions increases, the overall facility’s PSELs are equal to the Beaver

plant baseline emissions rate, plus the PSEL increases for increased use of existing capacity at the Beaver plant, plus

the emissions increases granted through NSR/PSD for the Port Westward facility. However, the netting basis is

equal only to the Beaver plant baseline emissions rate, plus the emissions increases granted theough NSR/PSD for

the Port Westward facility (i.e. the netting basis does not include the PSEL increases for increased use of existing

capacity at the Beaver plant). To ensure that all emissions increases are associated with the right equipment, and in

particular to ensure that the emissions increases due to increased use of existing capacity can only be used by the

baseline equipment at the Beaver plant, the Department will establish overall facility PSELs, plus two conditions

with unit-specific limits, one for the Beaver plant, and one for the Port Westward plant. See PSEL detail sheets for

baseline emission rates, netting basis emission rates and Plant Site Emission Rates from 1977 to present.

43. Provided below is a summary of the baseline emissions rate, netting basis, and plant site emission limits.

Table 13.

Pollutant

Baseline

Emission

Rate

(tons/yr)

Plant Wide Netting Basis

Plant Site Emission Limit (PSEL)

Previous

PSEL

(tons/yr)

Proposed

PSEL

(tons/yr)

PSEL

Change

(tons/yr)

Previous

(tons/yr)

Proposed

(tons/yr)

PM 29 119 119 857 241 - 616

PM10 29 119 119 857 241 - 616

CO 15 112 112 784 1104 + 320

NOx 184 407 407 5605 3776 - 1829

SO2 220 264 264 1117 595 - 522

VOC 4.5 60 60 564 118 - 446

43.a. The baseline emission rate is the actual emissions during 1977. The baseline emission rate is now

frozen, as this is the first permit renewal after 07/01/2002, in accordance with OAR 340-200-

0010(71)(a).

43.b. The netting basis is the combined baseline equipment (i.e. GTEU6, ABEU1, AIEU1 and UREU1)

and “new” equipment (i.e. PTEU1, PWEU1 and PWABEU1) netting basis. Care must be taken

for future modifications and permit actions to determine changes to netting basis based upon which

equipment is modified.

43.c. The PSEL for all pollutants except CO have decreased substantially. The emissions decreases are

due primarily to fuel oil quantity limits taken on the Beaver turbines (GTEU6) for the Visibility

Protection Strategy as part of the Regional Haze Program as explained in item 18. The previous

fuel oil limit was 305,760 Mgals/yr, and this has been reduced to 189,999 Mgals/yr for ULSD fuel

oil, and 159,354 Mgals/yr for LSD fuel oil in accordance with the regression analysis equation

presented in permit condition 22. These quantity and sulfur content limitations on fuel oil

combustion will maintain visibility protection, and reduce the PSEL for PM, PM10, NOx, SO2 and

VOC. The CO PSEL was increased solely due to an emission factor correction, which is

explained in detail in item 19. Many of the emission factors have been updated and/or corrected

from recent source-specific testing or EPA AP-42 data. See the PSEL detail sheets for additional

information.



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HAZARDOUS AIR POLLUTANTS

44. The revised and updated HAP table is presented below. The HAP emission factors and fuel quantity basis

are presented in the PSEL detail sheets for each emission unit on each fuel type, and have been updated

based upon EPA AP-42 and recent fuel oil analysis for metal HAPs, done by Columbia Analytical on April

17, 2008. This fuel oil HAP analysis is included in the May, 2008, Significant Permit Modification No.

22942. This HAP analysis was calculated on the Potential to Emit (PTE) fuel amounts as specified in Table

15, although the fuel oil for GTEU6 is limited below this PTE amount in accordance with the Visibility

Protection Strategy requirements.

Table 14.

HAP Annual HAP Emissions (tons/yr) Total HAP

Emissions

(tons/yr) GTEU6

FO

GTEU6

NG

ABEU1

FO

ABEU1

NG

PTEU1 PWEU1 PWABEU1

1,1,1-

Trichloroethane -- --

9.82E-

05 -- -- -- -- 0.00E+00

1,3-Butadiene 2.09E-01 9.10E-03 -- -- 5.94E-

04 5.88E-03 -- 2.15E-01

Acetaldehyde -- 8.47E-01 -- -- 5.53E-

02 5.47E-01 -- 1.45E+00

Acrolein -- 1.36E-01 -- -- 8.84E-

03 8.75E-02 -- 2.32E-01

Antimony -- -- -- -- -- -- -- 0.00E+00

Arsenic 3.34E-01 -- 1.46E-

03

1.22E-

05 -- -- 6.50E-06 3.34E-01

Benzene 7.17E-01 2.54E-01 8.91E-

05

1.28E-

04

1.66E-

02 1.64E-01 6.83E-05 8.98E-01

Beryllium 1.34E-02 -- 5.86E-

05

7.31E-

07 -- -- 3.90E-07 1.34E-02

Cadmium 1.34E-02 -- 5.86E-

05

6.70E-

05 -- -- 3.58E-05 1.34E-02

Chromium 6.68E-01 -- 2.93E-

03

8.53E-

05 -- -- 4.55E-05 6.69E-01

Cobalt -- -- -- 5.12E-

06 -- -- 2.73E-06 2.73E-06

Ethylbenzene -- 6.78E-01 2.65E-

05 --

4.42E-

02 4.37E-01 -- 1.16E+00

Fluoranthene -- -- 2.01E-

06 -- -- -- -- 0.00E+00

Formaldehyde 3.65E+0

0 6.55E-02

1.45E-

01

4.57E-

03

4.27E-

03 4.23E-02 2.44E-03 3.70E+00

Hexane -- -- -- 1.10E-

01 -- -- 5.85E-02 5.85E-02

Lead 1.21E+0

0 --

5.30E-

03

3.05E-

05 -- -- 1.63E-05 1.21E+00

Manganese 3.34E-02 -- 1.46E-

04

2.31E-

05 -- -- 1.24E-05 3.34E-02

Mercury 1.34E-02 -- 5.86E-

05

1.58E-

05 -- -- 8.45E-06 1.34E-02

Naphthalene 4.56E-01 2.75E-02 4.70E-

04

3.71E-

05

1.80E-

03 1.78E-02 1.98E-05 4.76E-01

Nickel 1.34E-01 -- 5.86E- 1.28E- -- -- 6.83E-05 1.34E-01



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HAP Annual HAP Emissions (tons/yr) Total HAP

Emissions

(tons/yr) GTEU6

FO

GTEU6

NG

ABEU1

FO

ABEU1

NG

PTEU1 PWEU1 PWABEU1

04 04

PAH/POM 5.21E-01 4.66E-02 1.37E-

03

7.85E-

05

3.04E-

03 3.01E-02 4.19E-05 5.55E-01

Propylene

Oxide -- 6.14E-01 -- --

4.01E-

02 3.96E-01 -- 1.05E+00

Selenium 6.68E-01 -- 2.93E-

03

1.46E-

06 -- -- 7.80E-07 6.68E-01

Toluene -- 2.75E+0

0

2.58E-

03

2.07E-

04

1.80E-

01

1.78E+0

0 1.11E-04 4.71E+00

Xylenes -- 1.36E+0

0

4.54E-

05 --

8.84E-

02 8.75E-01 -- 2.32E+00

TOTAL HAPs 8.19 6.76 0.16 0.11 0.44 4.36 0.06 13.05

Table 15. – Note: This table was updated in response to comments on 12/23/2008. See Appendices for

discussion.

Emission Unit/Equipment Fuel Annual Rates

GTEU6 Fuel oil 189,999 Mgals

Natural gas 40,366 mmcf

ABEU1 Fuel oil 833 Mgals

Natural gas 122 mmcf

PTEU1 Natural gas 2,634 mmcf

PWEU1 Natural gas 26,061 mmcf

PWABEU1 Natural gas 65 mmcf

Hours of operation --- 8760

GENERAL BACKGROUND INFORMATION

45. The facility is located along the Columbia River in an area that is in attainment with all ambient air quality

standards. The facility is approximately 40 miles downriver from the Portland Air Quality Management

Area

46. The facility is located within 300 kilometers (186.4 miles) of twelve Class I air quality protection areas.

47. A Land Use Compatibility Statement signed by Columbia County on October 7, 1991 granted approval.

48. Other permits issued or required by the Department include a Water Quality NPDES Permit No. 101209

and a Water Quality WPCF Permit No. 102626.

49. The facility is registered as a Small Quantity Hazardous Waste Generator and is regulated by DEQ’s

Hazardous Waste program.

COMPLIANCE HISTORY

50. The previous Title V Permit 05-2520 was issued on September 5, 2002 and was solely for the Beaver Plant.

The Port Westward ACDP was amended to the Title V Operating Permit on May 31, 2007. Since

September 5, 2002 to present, PGE has received one Notice on Noncompliance No. NWR AQ-02-0075 on

October 15, 2002. This NON was regarding an emission factor verification test that was not conducted in a

timely manner. The violation was satisfactorily resolved and a discussion of the detailed issue and

resolution are in the permit file.



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Page 29 of 50

51. The Beaver Plant was inspected on July 30, 2003 and March 15, 2005 and found to be in compliance; both

the Beaver Plant and the Port Westward Plant were inspected on September 28, 2007 and found to be in

compliance.

SOURCE TEST RESULTS

52. Provided below is a summary of emission tests performed on the Beaver Plant Combustion Turbines,

GTEU6, during the last permit term:

Table 16. Source Test Results based upon Relative Accuracy Audit (RAA) – September 10-14, 2007

Parameter/

Pollutant

Parameter Turbine

1 2 3 4 5 6

O2 Avg. RM (Reference Method)

value, %

15.38 15.47 15.35 15.37 15.36 15.44

RAA results: % 2.7 1.0 0.3 0.1 0.59 1.2

Status pass pass pass pass pass pass

NOx (as NO2) Avg. RM value, ppmv @ 15% O2 45.56 48.23 46.89 43.56 43.88 42.41

RAA results: % 1.8 9.7 7.8 3.6 3.9 2.1


NOx (as NO2) Avg. RM value, lbs/hr 125.9 141.6 136.1 128.4 127.1 125.5

RAA results: % 4.4 11.7 7.9 2.7 1.66 0.4


Table 17. VOC emission Factor Verification testing

September 13 & 14, 2007

Parameter/Pollutant Turbine 2 Turbine 3 Permit EF

VOC concentration, ppmv-C 3 1 N/A

Lbs/hr as C 2.0 0.51 N/A

Lbs C/mmcf natural gas 2.9 0.72 25.2

Lbs C/mmbtu 0.0027 0.0009 0.024

Natural gas usage, mmcf/hr 0.69 0.71 N/A

Results for each turbine are average of 3 test runs.

53. Provided below is a summary of emission tests performed on the Beaver Plant Peaking Turbine, PTEU1,

during the last permit term:

Table 18. Source Test Results based upon Relative Accuracy

Test Audit (RATA) – September 11, 2007

Parameter/Pollutant Parameter Result

O2 Avg. RM value, % 14.83

RATA results, % 0.2

Status Pass

CO, ppmv Avg. RM value, ppmv @ 15% O2 0.5

RATA results, % (PS4A) 0.81

Status Pass

CO, lbs/hr Avg. RM value, lbs/hr 0.31


Status Pass

NOx, ppmv Avg. RM value, ppmv @ 15% O2 15.12

RATA results, % 5.1

Status Pass

NOx, lbs/hr Avg. RM value, lbs/hr 15.14



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RATA results, % 2.9

Status pass

54. Provided below is a summary of emissions tests performed on the Port Westward Plant Auxiliary Boiler,

PWABEU1, during the last permit term:

Table 19. NOx compliance/emission factor verification testing – May 24, 2007

Parameter/Pollutant Result/Permit Limit

NOx, ppmv 35

NOx, lbs/hr (as NO2) 3.2

NOx, lbs/hr Permit Limit (BACT limit) 4.55

Natural gas usage, ft3 /hr 57,732

Steaming Rate, Mlbs steam/hr 41.4

Results are average of 3 test runs.

55. Provided below is a summary of emissions tests performed on the Port Westward Plant Combustion

Turbine, PWEU1, during the last permit term:

Table 20. Source Test Results based on Relative Accuracy Test

Audit (RATA) – June 6 & 7, 2007


O2 Avg. RM value, % 13.16

RATA results, % 0.2

Status pass

CO, ppmv Avg. RM value, ppmv @ 15% O2 -0.25


Status pass

NOx, ppmv Avg. RM value, ppmv @ 15% O2 2.1

RATA results, % (AS) 3.6

Status pass

NOx, lbs/mmbtu Avg. RM value, lbs/mmbtu 0.0076

RATA results, % 7.3

Status pass

Results reported are best 9 runs. Source Test Report includes all 12 runs.

Table 21. NOx, VOC and NH3 compliance/emission factor verification testing – June 6, 2007

Pollutant/Parameter Result/Permit Limit

NOx NOx, ppmv @ 15%O2 2.1

NOx, ppmv @ 15% O2 permit limit

(BACT limit/NSPS limit)

2.5/111

NOx, lbs/hr 19.1

NOx, lbs/mmbtu 0.0076

NOx, lbs/mmbtu NSPS limit (30-day average) 0.2

VOC ppmv-CH4 0.02

lbs-CH4/hr 0.058

lbs-CH4/hr, permit limit (BACT) 7.74

lbs/mmcf 0.023

lbs/mmcf, permit EF 3.24

Ammonia (NH3) ppmv 6.9

ppmv, permit limit (ammonia slip) 8

lbs/hr 18.0



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Pollutant/Parameter Result/Permit Limit

lbs/mmbtu 0.0072

Process parameters Natural Gas flow, combustion turbine 2513.1 mcf/hr

Net load (minus plant usage) 389.7 MW

Heat input 2598.9 mmbtu/hr

Ammonia injection 800.4 lbs/hr

Results are average of 3 test runs for VOC and ammonia. The NOx compliance runs consist

of 2 RA runs per compliance run.

PUBLIC NOTICE

This permit was put on public notice from October 17, 2008 until 5pm, November 25, 2008. The

Department held a public hearing at Clatskanie High School on November 18, 2008. The Informational

Meeting started at 6:30 with the Hearing following, Comments were received and are included in Appendix

A. The Department’s Response to Comments is included in Appendices B and C. The proposed permit,

including changes as a result of the comments, will then be sent to EPA for a 45 day review period. The

Department may request and EPA may agree to an expedited review of 5 days if there were no substantive

or adverse comments during the comment period. In any event, the public will have 105 days (45 day EPA

review period plus 60 days) from the date the proposed permit is sent to EPA to appeal the permit with

EPA. The permit will be issued following EPA’s review.

EMISSIONS DETAIL SHEETS

See attached Excel Spreadsheets.

APPENDIX A – Comments

APPENDIX B – Departmental Response to Comments

APPENDIX C – Modeling Scenario Summary

APPENDIX A – Comments

Received from Caroline Skinner via e-mail on November 19, 2008:

To: Catherine Blaine 11-19-08

DEQ Permit Co-ordinator

2020 SW 4th Avenue Ste 400

Portland, OR 97201

[email protected]

From: Caroline Skinner

2420 NW Quimby St #14


mailto:[email protected]



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Page 32 of 50

(503)248-9719

[email protected]

Greetings,

Thank you for giving me an opportunity to comment on the PGE Beaver natural gas power plant permit. I live in

northwest Portland but also am half-owner of a home at 462 S Third St in St Helens, OR in Columbia County. I

spend every weekend there. We already have a burden of air pollution from several large local sources including the

Boise plant, Coast Chemical (now called Dyno Nobel) and the Armstrong plant. Air quality is frequently poor in St

Helens.

Also, as a PGE customer, as well as person concerned about air quality, I feel qualified to share my concerns about

this situation. I am not a scientist or lawyer. As a lay person, it’s not easy to fully understand the issues before me on

this permit, but I do know someone needs to stand up and remind DEQ of the importance of air quality and the right

of every person to have clean air to breathe. While industry and energy generation are important, they must not come

at the cost of harm to human health.

I have recently joined the board of Rachel’s Friends Breast Cancer Coalition. Our group’s goal is prevention of

breast cancer, and other cancers, through reducing human exposure to environmental toxins. Pollutants of concern

from the old PGE Beaver plant include NOX, SOX, carbon monoxide (colorless, odorless and deadly),

formaldehyde, benzene, acrolein and organic HAPS and particulates.

I believe that PGE got away with too much for too long at its coal-fired plant in Boardman. It was only under

pressure from the community that PGE has started to install what it needs to operate more cleanly there. I know the

Beaver plant is not a coal plant, but the principle seems to be the same. I hope DEQ won’t let the Beaver plant be

another Boardman. I hope DEQ will use it’s regulatory and analytical powers to make sure the Beaver plant operates

in the public interest by running as clean as possible.

Do not avoid Best Available Retrofit Technology, or BART, by using operational limits. I find these are hard to

monitor and enforce. Beaver is an old and outdated power plant. If PGE wants it to operate full-time, they need to

outfit it to meet current standards. PGE sees fit to give an $11 million dollar retirement bonus to its parting executive

Peggy Fowler. As far as I’m concerned, that’s $10 million dollars that could be applied to BART for Beaver and

we’d all be far better off.

Focus on visibility improvements. We’re part of the Columbia Gorge ecosystem, which is overburdened with

regioinal haze from pollution.

Do not mix low sulphur fuel with ultra-low sulphur fuel as it may foul the equipment. Northwest Environmental

Defense Center, or NEDC, may address concerns about this. I want to underscore that NEDC speaks for me on this

point, as well as the entire permit application.

The public cares about clean air and is paying attention to what is in our air. A recent tire reprocessing facility

(ReKlaim) proposed for St Helens was defeated due to overwhelming community opposition. In Goble, a little girl

named Victoria developed leukemia and moved away for treatment. After moving, she went into spontaneous

remission before treatment was started. In Longview, three kids on the same soccer team developed three different

types of blood disorders. The odds of this happening are quite low; it raises legitimate questions about environmental

causes. It was newsworthy and covered in The Oregonian. All this goes to show that the air quality in this part of our

state already has major problems without even more coming from the Beaver plant.

I have concerns about HAP calculations used for minor source status. This concern is also being addressed in greater

detail by NEDC.

Finally, two to three tons per year is a lot of pollution. Please protect human health by promoting the cleanest

possible operation at the PGE Beaver plant in Clatskanie, OR. Thank you.



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--Caroline Skinner

Received from Howard Blumenthal via e-mail on November 23, 2008:

to: Catherine Blaine 11-23-08 Oregon DEQ re: PGE Port Westard/ Beaver power plant permit from: Howard Blumenthal 462 S Third St St Helens, OR 97051 503+366+1613 [email protected] Greetings, I am writing to comment on the PGE Beaver natural gas-fired power plant in Clatskanie, OR. As a resident of St Helens in Columbia County, Oregon, our weather pattern is from the west during the summer time. We hate to see more air pollution that would come our way during that time of the year. We already have Boise, which bothers us when we have south/southwest winds. We look forward to clean air during the summer when winds are coming from the west windows are open to cool the house. We hate to any increase on any permit that would allow dumping more pollutants into our airshed. We understand that the Beaver plant is operating with older pollution-control equipment that does not meet today's standards. If this plant (Beaver) will increase operations up to full-time, it must improve its air pollution management. We already have a lot of other sources of air pollution on the Washington side of the river. We don't have access to the full story about what these other plants in Washington are or what they emit, but we are in a shared ecosystem. We dot't want it to become worse that it already is. As a for-profit energy provider, PGE must prioritize its spending to include updating the old Beaver plant. I get my electric power from Columbia River PUD and use 100% wind power. (I am very happy with our local power provider.) I am not even a customer of PGE but will have to live with the effects of its power generating plants here in my area. I am not happy about the large ($11 million) bonus PGE is giving to its retiring executive Peggy Fowler. I hope to have PGE take care of the plant to run as clean as possible. Thank you.--Howard Blumenthal Received from Andrea Boris on behalf of Oregon Physicians for Social Responsibility via e-mail on November

24, 2008:

From: [email protected] [mailto:[email protected]] On Behalf Of Alexandra Boris Sent: Monday, November 24, 2008 4:40 PM To: BLAINE Catherine Subject: Public Comment Submission Regarding the Permit for Beaver/Port Westward Power Plants

November 24, 2008



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To: Ms. Catherine Blaine

DEQ Permit Coordinator

2020 SW 4th Avenue Ste 400

Portland, OR 97201

[email protected]

From: Alexandra Boris

Environmental Health Intern

Oregon Physicians for Social Responsibility

812 SW Washington St., Ste. 1050

Portland, OR 97205

[email protected]

Subject: Public Comment Submission Regarding the Proposed Renewal of a Title V Operating Permit Portland

General Electric Beaver/Port Westward Power Plants.

Dear Ms. Blaine,

As a citizen as well as an intern doing research on environmental health, it is extremely important to me that the

permit for the P.G.E. electric energy facilities near Clatskanie, Oregon to be carefully designed to strictly prioritize

the health of all those who live in the vicinity of the plant. Oregon Physicians for Social Responsibility is just one

example of an organization through which many dedicated individuals spend countless hours promoting practices

which decrease the incidence of preventable injury and disease. There are many that will be of significant expense to

us, and others which only take the time and efforts of involved individuals to make the proper decisions and

planning. In my mind, however, there is no price to be put on our lives. Particularly in the current economic

situation, it is essential to internalize as much as possible any quantifiable future costs such as those incurred due to

health care, absence from school or work, or damage to the environment. The current permit draft does not do this

with regard to several apparent issues.

The emission limits for monitored pollutants must be enforceable. It is not acceptable to only put on paper the

stricter control of chemicals such as PM, SO2, NOx and VOCs. In writing the current permit, the D.E.Q. has the

opportunity to significantly decrease emissions of these pollutants. The current draft does not propose to do so with

certainty. By strengthening the Plant Site Emission Limit, these facilities will theoretically be releasing smaller

amounts of these gases and particles. In practice, however, the actual decrease can only be ascertained by applying

the Best Available Retrofit Technology requirements; the pre-existing enforceable tools reduce emissions.

There are many risks for human and environmental health created by pollutants in our air. The effects include

respiratory illnesses which cause discomfort, but can also be deadly. Research has indicated that smog is associated

with increased incidence in cardiovascular disease.[i] The health implications of particulate matter are particularly

scary: a study done using World Health Organization data calculated that, "an increase in PM2.5 of only 1µg/m3

would lead to a loss of 27,500 years of life over a 15 year period." [ii] There are many more considerable threats to

health which have been associated.

Unlike the aforementioned substances, Hazardous Air Pollutants are classified as such because they have been

declared toxic by the agencies which monitor them. In order to prevent specified levels of human harm, there are

benchmarks here in Oregon mandating the regional control of these substances. While the current figures would

classify these two facilities as minor sources of these pollutants, verifying the reported HAP emissions values is

essential to ensure that residents are not unnecessarily harmed by such substances. This permit renewal process

presents the ideal time to do so, and taking this action could potentially prevent first and foremost a great deal of

harm, as well as time and energy spent in dealing with resulting illnesses.

mailto:[email protected]

[email protected]



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As citizens of the Northwest and members of this society who have taken the responsibility to ensure the health of

the public and environment here in Oregon, please weigh carefully the factors in this permit renewal. It is possible

to, without a doubt, prevent future harm by:

Writing this permit to prioritize health;

Planning for direct enforcement of any new standards set; and

Verifying all reported values so that the new permit is also accurate and precise.

Please take the steps mentioned here as well as those outlined by all other concerned people and organizations to

improve this draft and keep Oregon a safe place to live.

Thank you,

Alexandra Boris, Environmental Health Intern, Oregon Physicians for Social Responsibility

[i] Northwest Environmental Defense Center (2008) PGE Boardman. Retrieved October, 2008 from

http://www.lclark.edu/org/nedc/pge.html

[ii] Thompson, J. & Anthony, H. (June, 2008) The Health Effects of Waste Incinerators: 4th Report of the British

Society for Ecological Medicine. Retrieved October, 2008 from http://www.ecomed.org.uk/pub_waste.php

Received from Lyndsey Bechtel and Johannes Epke on behalf of Northwest Environmental Defense Center

via e-mail on November 24, 2008:

April 8, 2011

Catherine Blaine, NWR Permit coordinator

Department of Environmental Quality

2020 SW 4th Ave Ste 400


Re: Public Comment Submission Regarding the Proposed Renewal of a Title V Operating Permit Portland General

Electric Beaver/Port Westward Power Plants.

Northwest Environmental Defense Center (NEDC) respectfully submits the following comments

for the Proposed Title V Operating Permit Renewal for Portland General Electric Beaver/Port Westward Power

Plants. NEDC’s mission is to preserve and protect the environment and natural resources of the Pacific Northwest.

NEDC’s membership includes individuals who visit, recreate near or live in the vicinity of the Beaver and Port

Westward power plants and their pollution. NEDC requests a response to comments, as well as notification when

the permit renewal is approved.

Introduction

DEQ is proposing to allow PGE Beaver/Port Westward to avoid triggering “best available retrofit

technology” (BART) requirements by imposing several operational limits on the plants. These limits are supposed to

ensure that the plants will emit fewer pollutants that hinder visibility, in accordance with the DEQ’s Regional Haze

Program. If DEQ determines that the plants will reduce emissions to therefore meet the visibility threshold of .5

deciviews, DEQ will not require the plants to install controls to meet BART limits.

http://www.lclark.edu/org/nedc/pge.html

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NEDC believes that the conditions in the proposed permit renewal will not achieve the desired

visibility results. Furthermore, the method to measure visibility is subjective and there is no way to tell if the new

limits are making a difference in terms of surrounding visibility. The plants have also not adequately demonstrated

that they are not a major source of Hazardous Air Pollutant (HAP) emissions. Finally, NEDC questions DEQ’s

decision not to subject the the main turbines in the Beaver plant to certain air contamination limits.

The Changes to the Proposed Permit are not Adequate BART Limits and Might not Achieve the Desired

Visibility Improvements

In order to circumvent BART requirements, the plants’ renewal permit contemplates lowering the

“plant site emission limit” (PSEL). DEQ assumes that the stricter PSEL will be achieved by introducing ultra low

sulfur fuel to the diesel fuel-burning turbines in the Beaver plant. The permit renewal allows the Beaver plant to mix

the remaining low sulfur fuel oil (500 ppm) with the new ultra low sulfur fuel oil (15ppm). By burning the ultra low

sulfur fuel, the turbines will emit less PM, SO2, NOx and VOCs, allowing for increased visibility in nearby Class 1

areas. These PSELs are supposed to bring the plant below the .5 deciview threshold for visibility.

"Permitting Out" of BART

DEQ plans to allow this source, otherwise “subject to” BART, to “permit out” of the technology

based control requirements by revising the operating permit to include PSELs under a threshold determined by

modeling. The modeling will demonstrate the emissions level under which the facility could operate without making

a “significant contribution” to visibility impairment. DEQ finds authority for this approach under the definition of

“potential to emit” in the BART guidance, which is borrowed from 40 C.F.R. § 51.301. Under this formulation, the

potential to emit of a source is calculated based on its capacity to emit a pollutant taking into account its physical and

operational design. 70 Fed. Reg. at 39112. This definition allows the state to take into consideration “federally

enforceable” emission limits in calculating potential to emit. Id. This is a concept borrowed from “synthetic minor”

permitting, which allows otherwise major sources to avoid applicable requirements through permit limits. DEQ has

historically relied on PSELs to demonstrate that sources remain under these major source thresholds. However,

DEQ's practice does not comply with the requirements of the Clean Air Act, and should not be extended in its

current form to the regional haze rule.

PSELs are annual plantwide caps on pollution in total tons per year, and they are not federally

enforceable. A limit is federally enforceable if it is contained in a permit that is federally enforceable and if it is

enforceable as a practical matter. See U.S. v. Louisiana-Pacific Corp., 682 F. Supp. 1122 (D.C. Colo. 1988).

PSELs must thus be practically enforceable. Practical enforceability means a source must be able to show

continuous compliance with each limitation or requirement.4 EPA has repeatedly concluded that “in accordance with

the 1989 potential to emit policy, when an emission limit is taken to restrict potential to emit, some type of

continuous monitoring of compliance with that emission limit is required.”5 In addition, EPA has concluded that

“[i]n order for emission limitations to be Federally enforceable from the practical stand point, they must be short

term and specific so as to enable the Agency to determine compliance at any time.”6 The EPA has also explained

that to appropriately limit potential to emit, permits “must contain a production or operational limitation in addition

to the emission limitation in cases where the emission limitation does not reflect the maximum emissions of the

source operating at full design capacity without pollution control equipment.”7

4 Memorandum from Terrell F. Hunt, Associate Enforcement Counsel, OECA, and John Seitz,

Director, OAQPS, to EPA Regional Offices, Re: Guidance on Limiting Potential to Emit in New

Source Permitting, June 13, 1989. 5 Memorandum John B. Rasnic, Director Stationary Source Compliance Division, to David Kee,

Director Air and Radiation Division, Re: Policy Determination on Limiting Potential to Emit for

Koch Refining Company’s Clean Fuels Project, March 13, 1992. 6 Memorandum from John S. Seitz to Air Management Division directors, Re: Clarification of

New Source Review Policy on Averaging Times for Production Limitations, April 8, 1987. 7 A BART eligible source is one of the 26 source types that has the potential to emit 250 tons per year of a

visibility impairing pollutant and entered service between 1962 and 1977.



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PSELs are not practically enforceable because they are not short term limits on production or

operation, and compliance with PSELs can only be determined on an annual basis. In addition, permits issued by

DEQ often fail to specify sufficient testing, monitoring, recordkeeping and reporting to enable DEQ to verify

compliance with the annual caps. In many cases, DEQ does not require any testing to demonstrate compliance with

PSELs in “synthetic minor” permits. Any permits issued to “permit out” BART sources must meet certain minimum

requirements to effectively limit the source’s potential emissions. These include: (1) emissions limits and

operational and production standards that assure compliance with all applicable requirements; (2) sufficient testing,

monitoring, reporting and record keeping requirements to assure compliance with the terms and conditions of the

permit; and (3) federal enforceability by the U.S. EPA and citizens under the Clean Air Act. DEQ’s past permitting

actions in the “synthetic minor” context do not demonstrate DEQ’s ability or willingness to impose sufficient

conditions to satisfy these three criteria in future permits.

Visibility Impacts and Reasonable Progress

In addition to concerns regarding the enforceability of the PSEL and legitimacy of "permitting out"

of BART generally, the new requirements might not improve visibility in practice. The main turbine in the Port

Westward plant only burns natural gas. The main turbines in the Beaver plant can burn both natural gas and diesel

fuel, according to Item 9 of the Review Report. However, item 6 in the Review Report mentions that the Beaver

plant turbines primarily combust natural gas. Thus, there is a possibility that diesel fuel is rarely used. The new

sulfur limits imposed are only for diesel fuel. Although the new diesel fuel use could result in less visibility-

impairing pollutants, there will be no results if the new diesel oil is rarely used. Because Oregon must make

"reasonable progress" to increase visibility, DEQ should require facilities subject to BART to make actual and

certain decreases in visibility-impairing pollutants.

Furthermore, there is no requirement in the new permit for the number of hours or amount of diesel

fuel the Beaver turbines are required to burn. Thus, changing the type of diesel fuel without a mandate to use diesel

fuel is nonsensical and might not result in changes significant enough to improve visibility. NEDC questions if the

figures in table 15 in the Review Report are enforceable fuel input limits.

Second, the method of mixing the fuels might not achieve the desired visibility improvement. The

difference between the ultra low sulfur fuel (15 ppm) and the low sulfur fuel (500 ppm) is drastic. By mixing the low

and ultra low sulfur fuels, the average ppm of the mixture can result in pollutant emissions higher than expected.

New permit condition number 6 will eliminate old ash requirements, reasoning that the new ultra low fuel use will

result in a negligible ash content. However, if the low and ultra low sulfur fuels are mixed, the average ppm could

result in more ash content than expected. Eliminating the as requirement assumes that the Beaver plant will resort to

the ultra low fuel immediately, which is not the case.

Finally, the method of measuring visibility is too subjective. A deciview is the smallest amount of

change in visibility that the eye can pick up. More haze in the air results in a higher deciview. Because a deciview is

hard to quantify, it can easily be measured in favor of industry. It is too easy to find that slight operational changes

in the plants’ permit effectively improved area visibility. Depending on arbitrary measurements is not an effective

way to ensure that operational changes will actually improve visibility.

In conclusion, the facts that the turbines rarely run on diesel fuel and there is no requirement for

amount of diesel fuel that needs to be burned, demonstrates that the operational limits imposed might not be

sufficient to improve visibility. Also by mixing the fuels, the average ppm of the mixture might be higher than

expected resulting in more emissions. Finally the method for measuring the success of the operational limits is not

objective. For these reasons the plants should be required to install control technology to meet BART limits.

Installing BART is the honest way to ensure that the surrounding air quality will improve.

PGE Has Not Adequately Demonstrated That The Plants Are Not A Major Source of HAP

DEQ has not demonstrated in the Review Report that this facility is not a major source of HAPs.

Table 14 in the Review Report lists DEQs estimate as to the plants’ total potential HAP emissions per year. NEDC

believe that DEQ underestimates the plants’ PTE HAPs, and that the facility is a major source of HAPs.

A “major source” is “any stationary source or group of stationary sources within a contiguous area

and under common control that emits or has the potential to emit” 10 TPY or more of any single HAP or 25 tpy or

more of HAPs in the aggregate. 42 U.S.C. § 7412; OAR 340-244-0030(26). Potential to emit must reflect the



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maximum capacity of the source to emit HAPs under its physical and operational design, including fugitive

emissions. 40 C.F.R. § 63.2. Oregon defines potential to emit as the “maximum capacity of a stationary source to

emit any air pollutant under its physical or operational design.” OAR 340-244-0030(31).

Usually PTE calculations are based on emission rates when the plant is operating at 100% load.

The idea behind testing emissions when the plant is at 100% is that many emissions are at their highest when the

plant runs at maximum capacity. However, this is not the case for all HAPs. Some organic HAPs are a product of

incomplete combustion, meaning that they escape at higher rates when the plant is running at lower loads. For

natural gas combustion, according to AP-42 Emission Factor Background Documentation For Stationary Gas

Turbines,8 formaldehyde, acrolein, benzene, naphthalene, and PAH emissions are higher when the turbines run at “all

loads” as opposed to high (80%-100%) loads. This is because they are HAPs that are emitted due to incomplete

combustion. All five of these HAPS are emitted at the Beaver/Port Westward plants. NEDC would like more

information as to how the PTE for each of these pollutants was determined. The Review Report states that the PTE

figures in Table 14 are based on the material input and productions rates in Table 15. Are the fuel input rates in

Table 15 of the Review Report enforceable?

The PTE Formaldehyde, according to Review Report Table 14 is 3.70 TPY. NEDC finds this

figure questionable. For GTEU6, using the “high-load” AP-42 factor for natural gas combustion turbines and the

natural gas use from Review Report Table 15, instead of the 0.0655 TPY provided by DEQ, we arrive at 14.62 TPY.

Using the “all-loads” factor provided in the AP-42 background document, we arrive at 64.23 TPY of formaldehyde.

Though NEDC encourages use of source specific testing in lieu of AP-42 emission factors, the

source testing must be done as to be representative of actual operating conditions at the facility. If the source tests

upon which the formaldehyde PTE estimates were based were done at near maximum operating capacity, they are

not representative of actual operating conditions. Even if the facility does not operate at less than maximum load for

extended periods, frequent startup and shutdown results in considerable incomplete combustion and resulting

emissions.

Though the facility has a PSEL for CO, there are no short term CO limits on the GTEU6

emissions, and therefore no limit on incomplete combustion. Because this facility has, remarkably, avoided NSR for

several decades, there is inadequate control technology and insufficient permit limitations to conclude that the

facility is not a major source of HAP under the physical and operational design.

DEQ Should Find that the Main Turbines in the Beaver Plant fall under the definition of “Fuel Burning

Equipment.”

Condition 15 of the new permit no longer subjects the main turbine in the Beaver plant, GTEU6, to

air contaminant emission limits. The reasoning is that the GTEU6 is not considered “fuel burning equipment.”

Oregon Administrative Rule, 340-208-0010 (4) defines fuel burning equipment as “a boiler or process heater that

burns a solid, liquid, or gaseous fuel, the principal purpose of which is to produce heat or power by indirect heat

transfer.” This definition includes external combustion units, effectively excluding internal equipment. Internal

combustion units emit air contaminants just like external combustion units, thus should be included in the definition

of fuel burning equipment and subject to air contaminant emission limits of new condition 15.

Conclusion

NEDC believes that the Beaver/Port Westward Plants should be required to install control

technology to meet the BART limits. The facility must also make a compelling showing that is it not a major emitter

of HAPs, or must be required to meet all applicable NESHAP or MACT standards. Finally, NEDC does not think

that the main turbines should be able to resist air contamination requirements because they are not defined as “fuel

burning equipment.”

Thank you in advance for your help with these issues and concerns. We appreciate how hard you all work on these

8 http://www.epa.gov/ttn/chief/ap42/ch03/bgdocs/b03s01.pdf



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permits, and especially how hard you work to help us to understand them better.

Lyndsey Bechtel Johannes Epke

NEDC Air Project Volunteer NEDC Air Project Coordinator

[email protected]

(202) 230-6036



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APPENDIX B – Department Response to Comments

Comment Grouping/ Individual Comment Department Response Commenter

Best Available Retrofit Technology (BART) Requirements

Do not avoid Best Available Retrofit Technology, or BART, by using operational limits. I find these are hard to monitor and enforce. Beaver is an old and outdated power plant. If PGE wants it to operate full-time, they need to outfit it to meet current standards.

Under the Environmental Protection Agency’s (EPA’s) Regional Haze program as implemented by DEQ, certain facilities, including the PGE Beaver plant, were required to model their visibility impacts based on their maximum actual emissions during the years 2003, 2004 and 2005. If visibility impacts exceeded 0.5 deciviews, they were required to either submit a full BART analysis and (possibly) to install control equipment, or accept a Federally Enforceable Permit Limit (FEPL) that would require reduced emissions in order to model under the visibility threshold. Either approach is allowed under federal and Oregon regulations and is acceptable to DEQ and the EPA. In fact, the BART evaluation does not guarantee emission reductions, as it is possible it may conclude no controls are feasible (for technical or economic reasons). In the case of the PGE Beaver plant, PGE chose to accept limits (the FEPL) that would prevent them from exceeding the visibility impact threshold. The FEPL ensures no impact over 0.5 deciview, must be quantifiable and enforceable, and must be in effect by the time the regional haze SIP is submitted to EPA; however it will be effective and enforceable upon issuance of the permit.

A

We understand that the Beaver plant is operating with older pollution-control equipment that does not meet today’s standards. If this plant (Beaver) will increase operations up to full-time, it must improve its air pollution management. PGE must prioritize its spending to include updating the old Beaver plant…. I hope to have PGE take care of the plant to run it as cleanly as possible.

B

In practice, however, the actual decrease can only be ascertained by applying the Best Available Retrofit Technology requirements; the pre-existing enforceable tools reduce emissions.

C

DEQ is proposing to allow PGE Beaver/Port Westward to avoid triggering “best available retrofit technology” (BART) requirements by imposing several operational limits on the plants. These limits are supposed to ensure that the plants will emit fewer pollutants that hinder visibility, in accordance with the DEQ’s Regional Haze Program. If DEQ determines that the plants will reduce emissions to therefore meet the visibility threshold of 0.5 deciviews, DEQ will not require the plants to install controls to meet BART limits. In order to circumvent BART requirements, the plants’ renewal permit contemplates lowering the “plant site emission limit” (PSEL). PGE should be required to install control technology to

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meet the BART limits. Any permits issued to “permit out” of BART must include (1) emissions limits and operational and production standards that assure compliance with all applicable requirements; (2) sufficient testing, monitoring, reporting and record keeping requirements to assure compliance with the terms and conditions of the permit; and (3) federal enforceability by EPA and citizens under the Clean Air Act.

PSEL limits for Visibility Protection

Focus on visibility improvements. We’re part of the Columbia Gorge ecosystem, which is overburdened with regional haze from pollution.

The Commenters appear to believe that the Department is relying upon the PSELs to limit the visibility impact from the Beaver plant, but that is not the case. It is the FEPL in the permit that controls emissions through a 24-hour (i.e. short term) maximum fuel oil usage limit coupled with a maximum fuel sulfur content limit. These daily limits are shown in proposed permit conditions 6, 7, 22 and 23, and were established so that maximum visibility impacts will not exceed 0.5 deciviews at the 98

th percentile. These daily fuel

oil usage limits in the FEPL have the secondary effect of significant reductions in the PSELs for NOx, PM10, SO2 and VOCs; however, the reduced PSELs are not themselves the visibility protection limits.

A

DEQ assumes that the stricter PSEL will be achieved by introducing ultra low sulfur fuel to the diesel fuel-burning turbines in the Beaver plant. ….These PSELs are supposed to bring the plant below the 0.5 deciview threshold for visibility.

D

PSELs not enforceable

The emission limits for monitored pollutants must be enforceable….DEQ has the opportunity to significantly decrease emissions of these pollutants. The current draft does not propose to do so with certainty. By strengthening the Plant Site Emission Limit, these facilities will theoretically be releasing smaller amounts of these gases and particles.

The Department considers the daily fuel oil and sulfur content limits (referred to as FEPLs) to be both federally and practically enforceable. The limits are federally enforceable because the permits and the FEPLs will be referenced in the Department’s Regional Haze State Implementation Plan and will be enforceable by EPA. The permit itself will be reviewed by EPA, and will be enforceable upon approval and issuance. The limits are practically enforceable because the fuel oil usage and sulfur content must be monitored and recorded daily. The PSEL is a rolling 12-month limit, so compliance can be determined every month. That meets the EPA

C

PSELs are annual plantwide caps on emissions and are not federally enforceable. A limit is federally enforceable and if is enforceable as a practical matter. Practical enforceability means a source must be able to show continuous compliance with each limit or requirement. PSELs are not practically enforceable because they are

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not short term limits on production or operation, and compliance with PSELs can only be determined on an annual basis.

requirements for a PTE limit, and has been approved by EPA for limiting PTE for Title V and other programs.

Fuel oil concerns Do not mix low sulphur fuel with ultra-low sulphur fuel as it may foul the equipment.

The amount of sulfur dioxide emitted by burning diesel fuel is a function of the amount of fuel burned and the sulfur content of the fuel. PGE currently has a large inventory of low-sulfur diesel fuel and the permit requires that all future fuel oil purchases be ultra low-sulfur diesel. Over time, as diesel fuel is purchased and blended with the existing inventory, the sulfur content of the blended fuel in inventory will decrease. The proposed fuel usage limits take the sulfur content into account. As the blended sulfur content of the fuel in inventory decreases over time, the maximum amount of diesel that PGE may burn in the Beaver turbines is allowed to increase, depending on the sulfur content. Ultimately, PGE will only use ultra low-sulfur diesel. Until that time, there are no anticipated equipment problems with using blended fuel oil. Commenters note that the Beaver turbines can burn both natural gas and diesel fuel, and are concerned that DEQ has established emission limits only for fuel oil. Fuel limits for natural gas are not necessary since the visibility impacts resulting from natural gas use fall significantly below the 0.5 dv visibility limit even at a maximum operating rate. Daily limits have been set on the maximum amount of diesel fuel and the sulfur content of the fuel because at maximum operation with diesel fuel, the visibility impact would exceed 0.5 dv.

A

The Beaver turbines can burn both natural gas and diesel fuel. Although the use of low and ultra-low sulfur diesel fuel could result in less visibility-impairing pollutant emissions, there will be no results if the new fuel is rarely used. There is no requirement in the new permit for the number of hours or amount of diesel fuel the Beaver turbines are required to burn. The method of mixing the fuels might not achieve the desired visibility improvement.

D

Visibility Measurement

A deciview is hard to quantify and depending on an arbitrary measurement is not an effective way to ensure that operational changes will actually improve visibility.

For this and other BART eligible facilities, DEQ used a computer model and three years of representative meteorology to determine worse-case visibility impacts in wilderness areas across Oregon, Washington, and Idaho. The Department cannot rely upon actual measurement of visibility degradation, as this would not be practical. In cases where the computer model indicated visibility impacts

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over the visibility impact threshold, the source either had to do a full BART analysis or accept a limit or limits that would control emissions and bring visibility impacts down to less than the threshold. If a source chose to accept a limit or limits, the resulting maximum visibility impacts under the limit(s) was (were) also verified by computer modeling. The computer model and its application by DEQ follows guidance from EPA and the Federal Land Managers (FLM), and conforms to BART modeling throughout the U.S. Appendix C includes a modeling scenario summary for both permitted fuels using actual emissions for the BART determination analysis, along with modeling scenarios with the fuel oil limits demonstrating the results below the 0.5 dv threshold.

Major Hazardous Air Pollutant (HAP) Status

I have concerns about HAP calculations used for minor source status.

Commenters have indicated that PGE has not adequately demonstrated that the Beaver and Port Westward plants are not a major source of HAP. The Department has updated the HAP table with recent (April 17, 2008) metals testing results, available source test data and EPA AP-42 emission factor estimates. Upon further review of this comment, the Department is correcting Table 15 in the current Review Report. This table reports the fuel values used to calculate the Potential to Emit HAP emissions from all emission units, with the exception of the Beaver turbines. The table erroneously indicates the previous permitted fuel oil amount of 305,760 Mgals/yr, which is also the physical maximum quantity the turbines could possibly combust (based upon a heat input rating of 809 mmbtu/hr per turbine). This quantity will be changed to an annual limit of 189,999 Mgals/yr, which is based upon the new ULSD fuel oil daily limit of 521,000 gallons per day. This limit is federally and practically enforceable, and limits the facilities’ potential to emit. The formaldehyde emission factor (3.2E-03 lbs/mmcf) used for natural gas is from a source test on similar turbines at

A

While the current figures would classify these two facilities as minor sources of these pollutants, verifying the reported HAP emissions values is essential to ensure that residents are not unnecessarily harmed by such substances.

C

PGE has not adequately demonstrated that the plants are not a major source of HAP. Turbines operating at part load can have significantly higher HAP emissions than turbines operating at part load because of incomplete combustion at part load operation. PGE’s HAP testing was all done at full load and therefore may significantly underestimate the HAP potential to emit. In addition, there are no short term limits on CO and therefore no limit on incomplete combustion. The Review Report states that the PTE figures in Table 14 are based on the material input and productions [sic] rates in Table 15. Are the fuel input rates in Table 15 of the Review Report enforceable?

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the PGE Coyote Springs facility, and were conducted at full load. This resulted in the 0.0655 Tons per Year formaldehyde for the Beaver turbines on natural gas. The Department agrees that the combustion efficiency of gas turbines declines at part load operation and that HAP emissions may also increase as a result of lower combustion efficiency. However the Department also wants to indicate that turbines are typically operated at high loads to achieve maximum thermal efficiency, greater fuel efficiency and peak combustor zone flame temperatures, thereby minimizing the amount of CO and HAP emissions. Operating turbines at partial load is an inefficient use of fuel and equipment. Notwithstanding, the Department has added two conditions (24 and 54) requiring PGE to conduct formaldehyde testing of the turbines (Beaver and Port Westward) while operating the turbines at partial and full load. This testing must be completed within the first year of the permit issuance. The Department will add the condition(s) as follows: 56. The permittee shall conduct an emission factor

verification test in accordance with the Department’s Source Sampling Manual for formaldehyde on emission units GTEU6 and PWEU1 using EPA Method 316 or EPA Proposed Method 323. Testing shall be conducted on two of the Beaver turbines (GTEU6) while operating on natural gas and on the Port Westward turbine (PWEU1). Tests shall be performed at 70 and 100 percent of peak load or at minimum and peak load capacity in the normal operating range of the turbine(s). Three tests runs on each turbine at each load shall be performed. Each test shall be of sufficient duration so that the mass of formaldehyde collected is above the method detection limit. This testing must be completed



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during the first year of the permit issuance. During each test run, the permittee shall record the following information:

56.a.i. Date, time, emissions unit and

monitoring point identification; 56.a.ii. Pollutant emission results in ppmvd,

ppmvd@ 15% O2, lbs/hr, and lbs/mmbtu

56.a.iii. Turbine Load in % of full load and MW generated;

56.a.iv. Turbine parameters; 56.a.v. Heat input, mmbtu/hour; 56.a.vi. O2, % by volume; and 56.a.vii. CO2, % by volume

Protective of Public Health

Please protect human health by promoting the cleanest possible operation at the PGE Beaver plant in Clatskanie, OR.

Near-field modeling of criteria pollutants from Beaver and Port Westward demonstrates that the emissions are either less than the Significant Emission Rate, or that modeled concentrations are less than the applicable National Ambient Air Quality Standard (NAAQS). EPA established a NAAQS for each criteria pollutant to be protective of human health; the Significant Emission Rate is a rate below which a NAAQS will not be exceeded. In addition, as discussed above, the facilities are not a major source of HAPs. Since Beaver and Port Westward’s limits fall below these limits, the Department believes the emission limits for the facilities are consistent with a level considered protective of human health.

A

The permit for the PGE facility should be designed to strictly prioritize the health of all those who live in the vicinity of the plant. The current permit does not do this with regard to several apparent issues…. There are many risks for human and environmental health created by pollutants in our air.

C

Beaver Turbine Condition Changes and Fuel Burning Equipment Definition

The ash content requirement in condition 6 should not have been eliminated.

The ash content limit in condition 6 was not based upon a regulation, nor was it established to ensure compliance with any other limits, such as particulate matter emission limits and therefore the Department removed the limit.

D

Condition 15 of the new permit no longer subjects the main turbine in the Beaver plant, GTEU6, to air contaminant emission limits. DEQ should find that the main turbines at the Beaver plant fall under the

Condition 15 limits the opacity from “fuel burning equipment” to smoke spot 2 (which is the original, rather archaic definition of 20% opacity). The Beaver turbines (GTEU6) are still required to comply with the 20% opacity

D



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definition of “Fuel burning equipment”.

limitation under condition 14, with both fuels specified and the correct rule citation as OAR 340-208-0110(2). The requirement listed in condition 15 applies only to the auxiliary boiler at the Beaver plant. The relevant definition is found in OAR Chapter 340, Division 228, which reads: "Fuel burning equipment" means equipment, other than internal combustion engines, the principal purpose of which is to produce heat or power by indirect heat transfer.” This is essentially the definition of a boiler. Gas turbines, like those at the Beaver plant, do not produce power by indirect heat transfer and therefore do not meet this definition.

Commenters: A - Caroline Skinner, Citizen – November 19, 2008 B - Howard Blumenthal , Citizen– November 23, 2008 C - Alexandra Boris, Environmental Health Intern, Oregon Physicians for Social Responsibility – November 24, 2008 D - Lyndsey Bechtel, NEDC Air Project Volunteer and Johannes Epke, NEDC Air Project Coordinator, Northwest Environmental Defense Center –

November24,2008



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Appendix C

PGE Beaver BART Exemption Modeling Analysis

and

Significant Permit Modification Visibility Modeling Analysis

Summary

General Beaver Information

6 turbines – each maximum heat input of 809.3 mmbtu/hr; total maximum of 4856 mmbtu/hr.

The maximum combusted natural gas is therefore 4.63 mmcf/hr, and the annual amount PTE is 40,551 mmcf/yr (@ 1049 btu/cf heating value). (Permit value 40,366)

The maximum combusted oil is therefore 34.93 Mgals/hr, and the annual amount PTE is 306,033 Mgal/yr (@ 139,000 btu/gal). (Previous permit value 305,760)

BART Exemption Modeling Analysis

Oil Scenario9 - resulted in the following impacts:

Class I Areas 22nd

High of 3 years 8th

High of 1

year

Exempt?

Alpine Lakes 0.487 0.609 No

Diamond Peak 0.222 0.239 Yes

Glacier Park 0.285 0.339 Yes

Goat Rocks 0.532 0.598 No

Mt. Adams 0.496 0.544 No

Mt. Hood 0.699 0.699 No

Mt. Jefferson 0.411 0.436 Yes

Mt. Rainier 0.802 0.931 No

Mt. Washington 0.322 0.347 Yes

North Cascades 0.231 0.296 Yes

Olympic NP 0.838 0.866 No

Three Sisters 0.320 0.417 Yes

Additional Areas

Columbia Gorge

0.767

0.852

No

Highest Day – February 25, 2003 – all 6 turbines operating on distillate oil.

Modeled emissions:

SO2 emissions: 122.8 lbs/hr – based upon the 2/25/03 combustion rate and a sulfur content of 0.041% from fuel

analysis on 1/21/03. Assumes a heating value of 138,800 btu/gal and density of 7.1 lbs/gal.

Back calculating the heat input from this rate:

EF = 7.1 lbs/gal * 0.041/100 * 2 * 1000 = 5.8 lbs SO2/Mgals oil

[122.8 lbs SO2/hr] / [gal/0.0058 lbs SO2] * 138,800 btu/gal * 1/1E6

Heat input based upon SO2 emissions = 2939 mmbtu/hr

NOx emissions: 777.6 lbs/hr – based upon the CEMS from this date.

Back calculating the heat input from this rate assuming EF in permit at time of analysis:

EF = 35 lbs NOx/Mgals oil

[777.6 lbs NOx/hr] * Mgals/35 lbs NOx * 138,800 btu/gal * 1/1E3

Heat input based upon NOx emissions = 3083.7 mmbtu/hr

PM10 emissions: 105.5 lbs/hr – based upon 2/25/03 combustion rate and PM EF of 5 lbs/Mgal oil.

9 As described in the July 2 or 5, 2007 memo to Phil Allen re: “Protocol for Alternative BART Exemption Modeling

Analysis Portland General Electric, Beaver Generating Plant, Clatskanie, OR”



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[105.5 lbs/hr]* [Mgals/5 lbs PM10] * 138,800 btu/gal * 1/1E3

Heat input based upon PM10 emissions = 2928.7 mmbtu/hr

Ave of heating values = [2939 + 3084 + 2929]/3 = 2984 mmbtu/hr = 21.5 Mgal/hr or 516 Mgal/day

Natural Gas Scenario10

– resulted in the following impacts:

Class I Areas 22nd

High of 3 years 8th

High of 1

year

Exempt?

Alpine Lakes 0.225 0.330 Yes



Goat Rocks 0.226 0.263 Yes

Mt. Adams 0.211 0.214 Yes

Mt. Hood 0.293 0.298 Yes


Mt. Rainier 0.338 0.386 Yes



Olympic NP 0.330 0.375 Yes


Additional Areas

Columbia Gorge 0.302 0.318

Yes

Natural gas usage on highest day resulted in all areas, all conditions below 0.5 deciviews impact, therefore this fuel

dropped out of analysis.

Highest day – July 30, 2003

SO2 emissions: 8.8 lbs/hr – based upon the 7/30/03 combustion rate and a sulfur content of 0.003% from fuel

testing in 1994. Assumes a heating value of 1049 btu/cf and density of 0.044 lbs/cf.

Back calculating the heat input from this emission rate:

EF = 0.044 lbs/cf * 0.003/100 * 2 * 1000000 cf/mmcf = 2.64 lbs SO2/mmcf

[8.8 lbs SO2/hr] / [mmcf/2.64 lbs SO2] * 1049 btu/cf = 3496.7 mmbtu/hr

Heat input based upon SO2 emissions = 3496.7 mmbtu/hr



EF = 164 lbs NOx/mmcf

[601.3 lbs NOx/hr] * mmcf/164 lbs NOx * 1049 btu/cf = 3846.1 mmbtu/hr


PM10 emissions: 8.5 lbs/hr – based upon 7/30/03 combustion rate and PM EF of 2.5 lbs/mmcf.


[8.5 lbs/hr]* [mmcf/2.5 lbs PM10] * 1049 btu/cf = 3566.6 mmbtu/hr


Ave of heating values = [3496.7+ 3846.1 +3566.6]/3 = 3636.5 mmbtu/hr = 3.5 mmcf/hr or 83.2mmcf/day


10

As described in the July 2 or 5, 2007 memo to Phil Allen re: “Protocol for Alternative BART Exemption

Modeling Analysis Portland General Electric, Beaver Generating Plant, Clatskanie, OR”



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For the ULSD oil11

, modeled emissions equal:

SO2 = 4.6 lbs/hr

PM10 = 12.8 lbs/hr

NOx = 763.5 lbs/hr

Resulted in the following impacts:

Class I Areas 22nd

High of 3 years 8th

High of 1

year

Exempt?






Mt. Hood 0.354 0.363 Yes







Additional Areas

Columbia Gorge

0.357

0.377

Yes

SO2 emissions: 4.6 lbs/hr – based upon 90% of the 2/25/03 combustion rate and a sulfur content of 0.0015 %.

Assumes a heating value of 138,800 btu/gal and density of 7.05 lbs/gal.



[4.6 lbs SO2/hr] * [1000 gal/0.21 lbs SO2] * 138,800 btu/gal /1E6







PM10 emissions: 12.8 lbs/hr – based upon 90% 2/25/03 combustion rate and PM EF of 0.58 lbs/Mgal oil.

[12.8 lbs/hr]* [Mgals/0.58 lbs PM10] * 138,800 btu/gal * 1/1E3


Ave of heating values = [3040.4 + 3027.8 + 3063.2]/3 = 3043.8 mmbtu/hr = 21.9 Mgal/hr or 526 Mgal/day

For the LSD oil12

, modeled emissions equal:

SO2 emissions @ 0.05% S = 127.4 lbs/hr

11

As described in the April 3, 2008, memo to Patty Jacobs, DEQ from Eri Ottersburg, SLR, on behalf of Portland

General Electric (PGE) re: “Significant Modification to Title V Operating Permit for BART Portland

General Electric - Beaver Generating Plant, Clatskanie, OR”

12

As described in the May 23, 2008, memo to Patty Jacobs, DEQ from Ray Hendricks, Portland General Electric

(PGE) re: “Significant Modification to Title V Operating Permit for BART Portland General Electric -

Beaver Generating Plant, Clatskanie, OR”



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SO2 emissions @ 0.041% S = 105.6 lbs/hr (actual values of fuel oil S at Beaver – value not used)

PM10 emissions = 23.66 lbs/hr

NOx emissions = 637 lbs/hr


Class I Areas 22nd

High of 3 years 8th

High of 1

year

Exempt?






Mt. Hood 0.365 0.369 Yes







Additional Areas

Columbia Gorge

0.377

0.380

Yes

The equation presented in The Title V Permit 05-2520 Condition 22 allows PGE to blend the remaining LSD with

new ULSD while maintaining all conditions that would consistently remain under 0.5 deciviews. PGE is required to

only purchase ULSD from the date of permit issuance, and the reported sulfur content of the remaining oil as

recently analyzed is 0.041% S. As the fuel is replaced and blended with the 15 ppm S oil, the sulfur content will be

decreased incrementally. This equation is as follows:

Fuel oil combustion quantity (Mgal/day) = - 173,111 * S + 523.14

where S = sulfur content of the fuel oil (%, by weight).

Example, if sulfur content in the fuel is 0.0015 percent,

then S = 0.000015, (i.e. 0.0015/100).

LSD oil (500 ppm) amount :

-173,111 * 0.0005 + 523.14 = 436.6 Mgals/day or 18.2 Mgal/hr (24-hr. average).

Existing oil (410 ppm) amount:


ULSD oil (15 ppm) amount :


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Best Available Retrofit Technology (BART) Requirements

Do not avoid Best Available Retrofit Technology, or BART, by using operational limits. I find these are hard to monitor and enforce. Beaver is an old and outdated power plant. If PGE wants it to operate full-time, they need to outfit it to meet current standards.

Under the Environmental Protection Agency’s (EPA’s) Regional Haze program as implemented by DEQ, certain facilities, including the PGE Beaver plant, were required to model their visibility impacts based on their maximum actual emissions during the years 2003, 2004 and 2005. If visibility impacts exceeded 0.5 deciviews, they were required to either submit a full BART analysis and (possibly) to install control equipment, or accept a Federally Enforceable Permit Limit (FEPL) that would require reduced emissions in order to model under the visibility threshold. Either approach is allowed under federal and Oregon regulations and is acceptable to DEQ and the EPA. In fact, the BART evaluation does not guarantee emission reductions, as it is possible it may conclude no controls are feasible (for technical or economic reasons). In the case of the PGE Beaver plant, PGE chose to accept limits (the FEPL) that would prevent them from exceeding the visibility impact threshold. The FEPL ensures no impact over 0.5 deciview, must be quantifiable and enforceable, and must be in effect by the time the regional haze SIP is submitted to EPA; however it will be effective and enforceable upon issuance of the permit.

A

We understand that the Beaver plant is operating with older pollution-control equipment that does not meet today’s standards. If this plant (Beaver) will increase operations up to full-time, it must improve its air pollution management. PGE must prioritize its spending to include updating the old Beaver plant…. I hope to have PGE take care of the plant to run it as cleanly as possible.

B

In practice, however, the actual decrease can only be ascertained by applying the Best Available Retrofit Technology requirements; the pre-existing enforceable tools reduce emissions.

C

DEQ is proposing to allow PGE Beaver/Port Westward to avoid triggering “best available retrofit technology” (BART) requirements by imposing several operational limits on the plants. These limits are supposed to ensure that the plants will emit fewer pollutants that hinder visibility, in accordance with the DEQ’s Regional Haze Program. If DEQ determines that the plants will reduce emissions to therefore meet the visibility threshold of 0.5 deciviews, DEQ will not require the plants to install controls to meet BART limits. In order to circumvent BART requirements, the

D

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plants’ renewal permit contemplates lowering the “plant site emission limit” (PSEL). PGE should be required to install control technology to meet the BART limits. Any permits issued to “permit out” of BART must include (1) emissions limits and operational and production standards that assure compliance with all applicable requirements; (2) sufficient testing, monitoring, reporting and record keeping requirements to assure compliance with the terms and conditions of the permit; and (3) federal enforceability by EPA and citizens under the Clean Air Act.

PSEL limits for Visibility Protection

Focus on visibility improvements. We’re part of the Columbia Gorge ecosystem, which is overburdened with regional haze from pollution.

The Commenters appear to believe that the Department is relying upon the PSELs to limit the visibility impact from the Beaver plant, but that is not the case. It is the FEPL in the permit that controls emissions through a 24-hour (i.e. short term) maximum fuel oil usage limit coupled with a maximum fuel sulfur content limit. These daily limits are shown in proposed permit conditions 6, 7, 22 and 23, and were established so that maximum visibility impacts will not exceed 0.5 deciviews at the 98th percentile. These daily fuel oil usage limits in the FEPL have the secondary effect of significant reductions in the PSELs for NOx, PM10, SO2 and VOCs; however, the reduced PSELs are not themselves the visibility protection limits.

A

DEQ assumes that the stricter PSEL will be achieved by introducing ultra low sulfur fuel to the diesel fuel-burning turbines in the Beaver plant. ….These PSELs are supposed to bring the plant below the 0.5 deciview threshold for visibility.

D

PSELs not enforceable

The emission limits for monitored pollutants must be enforceable….DEQ has the opportunity to

The Department considers the daily fuel oil and sulfur content limits (referred to as FEPLs) to be both

C

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significantly decrease emissions of these pollutants. The current draft does not propose to do so with certainty. By strengthening the Plant Site Emission Limit, these facilities will theoretically be releasing smaller amounts of these gases and particles.

federally and practically enforceable. The limits are federally enforceable because the permits and the FEPLs will be referenced in the Department’s Regional Haze State Implementation Plan and will be enforceable by EPA. The permit itself will be reviewed by EPA, and will be enforceable upon approval and issuance. The limits are practically enforceable because the fuel oil usage and sulfur content must be monitored and recorded daily. The PSEL is a rolling 12-month limit, so compliance can be determined every month. That meets the EPA requirements for a PTE limit, and has been approved by EPA for limiting PTE for Title V and other programs.

PSELs are annual plantwide caps on emissions and are not federally enforceable. A limit is federally enforceable and if is enforceable as a practical matter. Practical enforceability means a source must be able to show continuous compliance with each limit or requirement. PSELs are not practically enforceable because they are not short term limits on production or operation, and compliance with PSELs can only be determined on an annual basis.

D

Fuel oil concerns Do not mix low sulphur fuel with ultra-low sulphur fuel as it may foul the equipment.

The amount of sulfur dioxide emitted by burning diesel fuel is a function of the amount of fuel burned and the sulfur content of the fuel. PGE currently has a large inventory of low-sulfur diesel fuel and the permit requires that all future fuel oil purchases be ultra low-sulfur diesel. Over time, as diesel fuel is purchased and blended with the existing inventory, the sulfur content of the blended fuel in inventory will decrease. The proposed fuel usage limits take the sulfur content into account. As the blended sulfur content of the fuel in inventory decreases over time, the maximum amount of diesel that PGE may burn in the Beaver turbines is allowed to increase, depending on the sulfur content. Ultimately, PGE will only use ultra low-sulfur diesel. Until that time, there are no anticipated equipment problems with using blended fuel oil. Commenters note that the Beaver turbines can burn

A

The Beaver turbines can burn both natural gas and diesel fuel. Although the use of low and ultra-low sulfur diesel fuel could result in less visibility-impairing pollutant emissions, there will be no results if the new fuel is rarely used. There is no requirement in the new permit for the number of hours or amount of diesel fuel the Beaver turbines are required to burn. The method of mixing the fuels might not achieve the desired visibility improvement.

D

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both natural gas and diesel fuel, and are concerned that DEQ has established emission limits only for fuel oil. Fuel limits for natural gas are not necessary since the visibility impacts resulting from natural gas use fall significantly below the 0.5 dv visibility limit even at a maximum operating rate. Daily limits have been set on the maximum amount of diesel fuel and the sulfur content of the fuel because at maximum operation with diesel fuel, the visibility impact would exceed 0.5 dv.

Visibility Measurement

A deciview is hard to quantify and depending on an arbitrary measurement is not an effective way to ensure that operational changes will actually improve visibility.

For this and other BART eligible facilities, DEQ used a computer model and three years of representative meteorology to determine worse-case visibility impacts in wilderness areas across Oregon, Washington, and Idaho. The Department cannot rely upon actual measurement of visibility degradation, as this would not be practical. In cases where the computer model indicated visibility impacts over the visibility impact threshold, the source either had to do a full BART analysis or accept a limit or limits that would control emissions and bring visibility impacts down to less than the threshold. If a source chose to accept a limit or limits, the resulting maximum visibility impacts under the limit(s) was (were) also verified by computer modeling. The computer model and its application by DEQ follows guidance from EPA and the Federal Land Managers (FLM), and conforms to BART modeling throughout the U.S. Appendix C includes a modeling scenario summary for both permitted fuels using actual emissions for the BART determination analysis, along with modeling scenarios with the fuel oil limits demonstrating the

D

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results below the 0.5 dv threshold.

Major Hazardous Air Pollutant (HAP) Status

I have concerns about HAP calculations used for minor source status.

Commenters have indicated that PGE has not adequately demonstrated that the Beaver and Port Westward plants are not a major source of HAP. The Department has updated the HAP table with recent (April 17, 2008) metals testing results, available source test data and EPA AP-42 emission factor estimates. Upon further review of this comment, the Department is correcting Table 15 in the current Review Report. This table reports the fuel values used to calculate the Potential to Emit HAP emissions from all emission units, with the exception of the Beaver turbines. The table erroneously indicates the previous permitted fuel oil amount of 305,760 Mgals/yr, which is also the physical maximum quantity the turbines could possibly combust (based upon a heat input rating of 809 mmbtu/hr per turbine). This quantity will be changed to an annual limit of 189,999 Mgals/yr, which is based upon the new ULSD fuel oil daily limit of 521,000 gallons per day. This limit is federally and practically enforceable, and limits the facilities’ potential to emit. The formaldehyde emission factor (3.2E-03 lbs/mmcf) used for natural gas is from a source test on similar turbines at the PGE Coyote Springs facility, and were conducted at full load. This resulted in the 0.0655 Tons per Year formaldehyde for the Beaver turbines on natural gas. The Department agrees that the combustion efficiency

A

While the current figures would classify these two facilities as minor sources of these pollutants, verifying the reported HAP emissions values is essential to ensure that residents are not unnecessarily harmed by such substances.

C

PGE has not adequately demonstrated that the plants are not a major source of HAP. Turbines operating at part load can have significantly higher HAP emissions than turbines operating at part load because of incomplete combustion at part load operation. PGE’s HAP testing was all done at full load and therefore may significantly underestimate the HAP potential to emit. In addition, there are no short term limits on CO and therefore no limit on incomplete combustion. The Review Report states that the PTE figures in Table 14 are based on the material input and productions [sic] rates in Table 15. Are the fuel input rates in Table 15 of the Review Report enforceable?

D

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of gas turbines declines at part load operation and that HAP emissions may also increase as a result of lower combustion efficiency. However the Department also wants to indicate that turbines are typically operated at high loads to achieve maximum thermal efficiency, greater fuel efficiency and peak combustor zone flame temperatures, thereby minimizing the amount of CO and HAP emissions. Operating turbines at partial load is an inefficient use of fuel and equipment. Notwithstanding, the Department has added two conditions (24 and 54) requiring PGE to conduct formaldehyde testing of the turbines (Beaver and Port Westward) while operating the turbines at partial and full load. This testing must be completed within the first year of the permit issuance. The Department will add the condition(s) as follows: 1. The permittee shall conduct an emission

factor verification test in accordance with the Department’s Source Sampling Manual for formaldehyde on emission units GTEU6 and PWEU1 using EPA Method 316 or EPA Proposed Method 323. Testing shall be conducted on two of the Beaver turbines (GTEU6) while operating on natural gas and on the Port Westward turbine (PWEU1). Tests shall be performed at 70 and 100 percent of peak load or at minimum and peak load capacity in the normal operating range of the turbine(s). Three tests runs on each turbine at each load shall be performed. Each test shall

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be of sufficient duration so that the mass of formaldehyde collected is above the method detection limit. This testing must be completed during the first year of the permit issuance. During each test run, the permittee shall record the following information:

1.a.i. Date, time, emissions unit and

monitoring point identification; 1.a.ii. Pollutant emission results in

ppmvd, ppmvd@ 15% O2, lbs/hr, and lbs/mmbtu

1.a.iii. Turbine Load in % of full load and MW generated;

1.a.iv. Turbine parameters; 1.a.v. Heat input, mmbtu/hour; 1.a.vi. O2, % by volume; and 1.a.vii. CO2, % by volume

Protective of Public Health

Please protect human health by promoting the cleanest possible operation at the PGE Beaver plant in Clatskanie, OR.

Near-field modeling of criteria pollutants from Beaver and Port Westward demonstrates that the emissions are either less than the Significant Emission Rate, or that modeled concentrations are less than the applicable National Ambient Air Quality Standard (NAAQS). EPA established a NAAQS for each criteria pollutant to be protective of human health; the Significant Emission Rate is a rate below which a NAAQS will not be exceeded. In addition, as discussed above, the facilities are not a major source of HAPs. Since Beaver and Port Westward’s limits fall below these limits, the Department believes the emission limits for the facilities are consistent with a level considered protective of human health.

A

The permit for the PGE facility should be designed to strictly prioritize the health of all those who live in the vicinity of the plant. The current permit does not do this with regard to several apparent issues…. There are many risks for human and environmental health created by pollutants in our air.

C

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Beaver Turbine Condition Changes and Fuel Burning Equipment Definition

The ash content requirement in condition 6 should not have been eliminated.

The ash content limit in condition 6 was not based upon a regulation, nor was it established to ensure compliance with any other limits, such as particulate matter emission limits and therefore the Department removed the limit.

D

Condition 15 of the new permit no longer subjects the main turbine in the Beaver plant, GTEU6, to air contaminant emission limits. DEQ should find that the main turbines at the Beaver plant fall under the definition of “Fuel burning equipment”.

Condition 15 limits the opacity from “fuel burning equipment” to smoke spot 2 (which is the original, rather archaic definition of 20% opacity). The Beaver turbines (GTEU6) are still required to comply with the 20% opacity limitation under condition 14, with both fuels specified and the correct rule citation as OAR 340-208-0110(2). The requirement listed in condition 15 applies only to the auxiliary boiler at the Beaver plant. The relevant definition is found in OAR Chapter 340, Division 228, which reads: "Fuel burning equipment" means equipment, other than internal combustion engines, the principal purpose of which is to produce heat or power by indirect heat transfer.” This is essentially the definition of a boiler. Gas turbines, like those at the Beaver plant, do not produce power by indirect heat transfer and therefore do not meet this definition.

D

Commenters:

A - Caroline Skinner, Citizen – November 19, 2008

B - Howard Blumenthal , Citizen– November 23, 2008

C - Alexandra Boris, Environmental Health Intern, Oregon Physicians for Social Responsibility – November 24, 2008 D - Lyndsey Bechtel, NEDC Air Project Volunteer and Johannes Epke, NEDC Air Project Coordinator, Northwest Environmental Defense

Center – November 24, 2008

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Appendix C

PGE Beaver BART Exemption Modeling Analysis

and


Summary

General Beaver Information

6 turbines – each maximum heat input of 809.3 mmbtu/hr; total maximum of 4856 mmbtu/hr.

The maximum combusted natural gas is therefore 4.63 mmcf/hr, and the annual amount PTE is 40,551 mmcf/yr (@ 1049 btu/cf heating value). (Permit value 40,366)

The maximum combusted oil is therefore 34.93 Mgals/hr, and the annual amount PTE is 306,033 Mgal/yr (@ 139,000 btu/gal). (Previous permit value 305,760)

BART Exemption Modeling Analysis

Oil Scenario1 - resulted in the following impacts:

Class I Areas 22nd High of 3 years 8th High of 1 year Exempt?

Alpine Lakes 0.487 0.609 No



Goat Rocks 0.532 0.598 No

Mt. Adams 0.496 0.544 No

Mt. Hood 0.699 0.699 No


Mt. Rainier 0.802 0.931 No



Olympic NP 0.838 0.866 No


Additional Areas

Columbia Gorge

0.767

0.852

No

Highest Day – February 25, 2003 – all 6 turbines operating on distillate oil.

Modeled emissions:

SO2 emissions: 122.8 lbs/hr – based upon the 2/25/03 combustion rate and a sulfur content of 0.041%

from fuel analysis on 1/21/03. Assumes a heating value of 138,800 btu/gal and density of 7.1 lbs/gal.



[122.8 lbs SO2/hr] / [gal/0.0058 lbs SO2] * 138,800 btu/gal * 1/1E6

Heat input based upon SO2 emissions = 2939 mmbtu/hr

1 As described in the July 2 or 5, 2007 memo to Phil Allen re: “Protocol for Alternative BART Exemption


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PM10 emissions: 105.5 lbs/hr – based upon 2/25/03 combustion rate and PM EF of 5 lbs/Mgal oil.

[105.5 lbs/hr]* [Mgals/5 lbs PM10] * 138,800 btu/gal * 1/1E3


Ave of heating values = [2939 + 3084 + 2929]/3 = 2984 mmbtu/hr = 21.5 Mgal/hr or 516 Mgal/day

Natural Gas Scenario2 – resulted in the following impacts:







Mt. Hood 0.293 0.298 Yes







Additional Areas

Columbia Gorge 0.302 0.318

Yes

Natural gas usage on highest day resulted in all areas, all conditions below 0.5 deciviews impact,

therefore this fuel dropped out of analysis.

Highest day – July 30, 2003

SO2 emissions: 8.8 lbs/hr – based upon the 7/30/03 combustion rate and a sulfur content of 0.003%

from fuel testing in 1994. Assumes a heating value of 1049 btu/cf and density of 0.044 lbs/cf.


EF = 0.044 lbs/cf * 0.003/100 * 2 * 1000000 cf/mmcf = 2.64 lbs SO2/mmcf

2 As described in the July 2 or 5, 2007 memo to Phil Allen re: “Protocol for Alternative BART Exemption


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[8.8 lbs SO2/hr] / [mmcf/2.64 lbs SO2] * 1049 btu/cf = 3496.7 mmbtu/hr




EF = 164 lbs NOx/mmcf

[601.3 lbs NOx/hr] * mmcf/164 lbs NOx * 1049 btu/cf = 3846.1 mmbtu/hr


PM10 emissions: 8.5 lbs/hr – based upon 7/30/03 combustion rate and PM EF of 2.5 lbs/mmcf.


[8.5 lbs/hr]* [mmcf/2.5 lbs PM10] * 1049 btu/cf = 3566.6 mmbtu/hr


Ave of heating values = [3496.7+ 3846.1 +3566.6]/3 = 3636.5 mmbtu/hr = 3.5 mmcf/hr or

83.2mmcf/day


For the ULSD oil3, modeled emissions equal:

SO2 = 4.6 lbs/hr

PM10 = 12.8 lbs/hr

NOx = 763.5 lbs/hr








Mt. Hood 0.354 0.363 Yes







Additional Areas

3 As described in the April 3, 2008, memo to Patty Jacobs, DEQ from Eri Ottersburg, SLR, on behalf of Portland

General Electric (PGE) re: “Significant Modification to Title V Operating Permit for BART Portland General

Electric - Beaver Generating Plant, Clatskanie, OR”

of 13


Columbia Gorge 0.357 0.377 Yes

SO2 emissions: 4.6 lbs/hr – based upon 90% of the 2/25/03 combustion rate and a sulfur content of

0.0015 %. Assumes a heating value of 138,800 btu/gal and density of 7.05 lbs/gal.



[4.6 lbs SO2/hr] * [1000 gal/0.21 lbs SO2] * 138,800 btu/gal /1E6







PM10 emissions: 12.8 lbs/hr – based upon 90% 2/25/03 combustion rate and PM EF of 0.58 lbs/Mgal oil.

[12.8 lbs/hr]* [Mgals/0.58 lbs PM10] * 138,800 btu/gal * 1/1E3


Ave of heating values = [3040.4 + 3027.8 + 3063.2]/3 = 3043.8 mmbtu/hr = 21.9 Mgal/hr or 526

Mgal/day

For the LSD oil4, modeled emissions equal:

SO2 emissions @ 0.05% S = 127.4 lbs/hr

SO2 emissions @ 0.041% S = 105.6 lbs/hr (actual values of fuel oil S at Beaver – value not used)

PM10 emissions = 23.66 lbs/hr

NOx emissions = 637 lbs/hr








Mt. Hood 0.365 0.369 Yes

4 As described in the May 23, 2008, memo to Patty Jacobs, DEQ from Ray Hendricks, Portland General Electric

(PGE) re: “Significant Modification to Title V Operating Permit for BART Portland General Electric - Beaver

Generating Plant, Clatskanie, OR”

of 13








Additional Areas

Columbia Gorge

0.377

0.380

Yes

The equation presented in The Title V Permit 05-2520 Condition 22 allows PGE to blend the remaining

LSD with new ULSD while maintaining all conditions that would consistently remain under 0.5 deciviews.

PGE is required to only purchase ULSD from the date of permit issuance, and the reported sulfur content

of the remaining oil as recently analyzed is 0.041% S. As the fuel is replaced and blended with the 15

ppm S oil, the sulfur content will be decreased incrementally. This equation is as follows:

Fuel oil combustion quantity (Mgal/day) = - 173,111 * S + 523.14

where S = sulfur content of the fuel oil (%, by weight).

Example, if sulfur content in the fuel is 0.0015 percent,

then S = 0.000015, (i.e. 0.0015/100).

LSD oil (500 ppm) amount :


Existing oil (410 ppm) amount:


ULSD oil (15 ppm) amount :


oregon title v operating permit review report report/permit no.: 05-2520 application number: 21882...

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