4.11-1 4.11 – Air Quality and Noise

4.11 AIR QUALITY AND NOISE 

4.11.1 Air Quality 

4.11.1.1 Waterway for LNG Marine Traffic 

Climate 

The proposed waterway for LNG marine traffic would extend from the territorial seas boundary, 

12 nautical miles from shore, up the Coos Bay navigation channel to the proposed LNG terminal. 

The proposed waterway is within the Oregon Coast climate region. The climate of the Project 

area is characterized by wet winters, relatively dry summers, and mild temperatures year round. 

Terrain features include the coastal plain, which extends from less than a mile to a few tens of 

miles in width, numerous coastal valleys, and the Coast Range, whose peaks range from 2,000 to 

5,500 feet above sea level (ASL). 

The heaviest precipitation in this zone occurs mainly during the winter months when moist air 

masses move off the Pacific Ocean onto land. Normal annual precipitation at the Southwest 

Oregon Regional Airport, just across Coos Bay from the Project site, is approximately 65 inches, 

with normal annual snowfall of approximately one inch. The highest monthly precipitation 

values occur during the months of November, December, and January. 

The mean maximum temperature is approximately 60 °F, the mean minimum temperature is 

approximately 46 °F, and the mean temperature is approximately 53 °F. Temperatures of 90 °F

or higher occur less than once per year, on average, and freezing temperatures are infrequent, 

with killing frosts being even less frequent. The area around the airport averages approximately 

303 days (growing season) between the last occurrence (in spring) and the first occurrence (in 

fall) of 28 °F temperatures. 

Strong winds occur occasionally, usually in advance of winter storms. These winds can exceed 

hurricane force, and have been known to cause significant damage to structures and vegetation. 

Such events, however, are typically short-lived, and last less than one day. Partly cloudy skies 

are prevalent during the summer. Winter skies are likely to be cloudy. As a result of the 

persistent cloudiness, total solar radiation is lower in this zone. 

Ambient Air Quality Standards 

The proposed waterway for LNG marine traffic would pass through Oregon’s state territorial 

boundaries. Ambient air quality standards for Oregon, as well as federal ambient air quality 

standards, are discussed below. 

National Ambient Air Quality Standards (NAAQS) and Prevention of Significant 

Deterioration (PSD)

The EPA has established National Ambient Air Quality Standards (NAAQS) for seven 

pollutants: sulfur dioxide (SO2), carbon monoxide (CO), nitrogen dioxide (NO2), ozone, 

particulate matter less than 10 microns in diameter (PM10), particulate matter less than 2.5 

microns in diameter (PM2.5), and lead. These pollutants are referred to as “criteria pollutants” 

because EPA is required to periodically identify air quality criteria which reflect the latest 
4.11-2 4.11 – Air Quality and Noise

scientific knowledge (including knowledge regarding the effects on children, asthmatics, and the 

elderly), and revise the NAAQS accordingly. The CAA requires EPA to set both primary 

NAAQS (which are necessary to protect human health, allowing an adequate margin of safety) 

and secondary NAAQS (necessary to protect the public welfare from any known or anticipated 

adverse effects; this includes effects on wildlife and vegetation.). All areas of the United States 

are classified as being “attainment,” “unclassified,” or “nonattainment” with respect to these 

standards. Although emissions of other air pollutants (including reduced sulfur compounds and 

various carcinogens) are regulated, there are no NAAQS for these pollutants. 

EPA’s NAAQS regulations also state that NAAQS “shall not be considered in any manner to 

allow significant deterioration of existing air quality in any portion of any state or Indian 

country.” To address concerns that air quality in attainment or unclassified areas not deteriorate 

up to the point where NAAQS are set, the CAA includes requirements for purposes of preserving 

existing clean air resources; specifically, for particulate matter and SO2, Section 163(b) of the 

CAA identifies the maximum increments above baseline concentrations by which air quality is 

allowed to deteriorate, and EPA regulations identify additional requirements for NO2 and PM10. 

(EPA proposed PM2.5 increments in the September 21, 2007 Federal Register, but has not yet 

promulgated a final rule.) 

PSD baseline concentrations are determined based on historical information regarding large 

stationary sources or modifications—i.e., those classified as “major” with respect to PSD 

permitting regulations. For particulate matter and SO2, the baseline date is defined as the earliest 

date that a complete PSD permit application was submitted after August 7, 1977; for NO2, the 

baseline date is defined as the earliest date that a complete PSD permit application was submitted 

after February 8, 1988. Although baseline concentrations have not been identified for the areas 

influenced by this project, ODEQ’s Air Quality Data Summaries shows that historically, PM10

concentrations have been decreasing substantially since the 1980s, and that therefore it is 

possible that baseline concentrations will be substantially higher than current background 

concentrations. 

PSD increments depend on whether the affected area is designated as Class I or Class II. The 

nearest Class I areas to the site of the proposed LNG terminal are: 

• Crater Lake National Park (Oregon), at a distance of 165 km 

• Redwood National Park (California), 177 km 

• Kalmiopsis Wilderness Area (Oregon), 110 km 

• Diamond Peak Wilderness Area (Oregon), 164 km 

• Three Sisters Wilderness Area (Oregon), 184 km 

• Mountain Lakes Wilderness Area (Oregon), 185 km 

All other nearby areas are designated as Class II. Estimates of background concentrations for the 

project area are listed in table 4.11.1.1-1, along with the NAAQS and PSD increments. 

Background concentrations were determined for three calendar years (2003 to 2005) from sites 

in Seattle, Washington (SO2), the Eugene area (CO, ozone, and PM10), Portland (NO2 and lead), 

and Lane County (PM2.5); those listed in table 4.11.1.1-1 are for the worst-case year of these 3 

years. 
4.11-3 4.11 – Air Quality and Noise

TABLE 4.11.1.1-1 

Ambient Air Quality, National Ambient Air Quality Standards and PSD Increments

Air Pollutant 

Averaging 

Period 

Background 

Level 

Primary 

Standard 

Secondary 

Standard 

Background 

as Fraction 

of Primary 

NAAQS 

PSD 

Increments 

Class I areas 

PSD 

Increments 

Class II 

areas 

3-Hour a/ 32 NA 1,300 NA 25 512 

24-Hour a/ 19 365 NA 0.10 5 91 

SO2 (μg/m3) 

Annual b/ 6 80 NA 0.13 2 20 

CO (μg/m 1-Hour a/ 6,785 40,000 NA 0.17 NA NA 3) 

8-Hour a/ 3,910 10,000 NA 0.39 NA NA 

NO2 (μg/m3) Annual b/ 18 100 100 0.26 2.5 25 

Ozone (ppm) 1-Hour c/,d/ NA c/ 0.12 0.12 NA NA NA 

8-Hour e/ 0.072 0.075 0.075 0.96 NA NA 

PM10 (μg/m 24-Hour d/ 38 150 150 0.27 8 30 3) 

Annual b/,f/ 14 50 50 0.32 4 17 

PM2.5 (μg/m 24-Hour g/ 18 35 35 0.51 NA h/ NA h/ 3) 

Annual b/ 7 15.0 15.0 0.47 NA h/ NA h/

Lead (μg/m3) Calendar 

Quarter 

0.012 1.5 1.5 0.01 NA NA 

a/ This standard is not to be exceeded more than once per calendar year. 

b/ The annual average concentration. 

c/ The 1-hour ozone standard was revoked effective June 15, 2005 for all areas in Oregon as per 70 FR 44477 (August 3, 2005) 

and therefore a background level was not calculated. 

d/ The standard is met when the expected number of exceedances per year (determined as per 40 CFR 50) is less than one. 

e/ Standards and data are three-year averages of the 4th highest daily maximum 8-hour concentrations; the 8-hour ozone standard 

shown is effective on May 27, 2008. 

f/ The historical annual PM10 standard was revoked, effective December 18, 2006. 

g/ The standard applies to the 98th percentile 24-hour concentration. 

h/ PSD increments for PM2.5 were proposed by EPA on September 21, 2007, but have not yet been finalized. 

μg/m3

 = micrograms per cubic meter 

State Ambient Air Quality Standards

For most criteria pollutants, Oregon Ambient Air Quality Standards (OAAQS) and PSD 

increments are the same as federal NAAQS and PSD increments. However, Oregon has set 

more stringent standards for SO2 for the 24-hour and annual averaging periods. The Oregon SO2

standards (in ppm) and equivalent concentrations in μg/m3

 are shown in table 4.11.1.1-2. 

TABLE 4.11.1.1-2 

Oregon SO2 Ambient Air Quality Standards

Oregon Standards 

Averaging Period ppm Equivalent μg/m3

3-Hour a/ 0.50 1,300 

24-Hour a/ 0.10 260 

Annual b/ 0.020 52 

a/ Not to be exceeded more than once per calendar year. 

b/ The annual average concentration. 
4.11-4 4.11 – Air Quality and Noise

Existing Air Quality 

The proposed waterway for LNG marine traffic runs through Coos County, which is currently 

designated as attainment or unclassifiable for all NAAQS. 

Air Quality Control Regions 

Air Quality Control Regions (AQCR) were established by the EPA and local agencies, in 

accordance with section 107 of the CAA, as a means to implement the CAA and comply with the 

NAAQS through State Implementation Plans. The AQCRs are intra- and interstate regions such 

as large metropolitan areas where the improvement of the air quality in one portion of the AQCR 

often requires emission reductions throughout the AQCR. Coos County is part of the Southwest 

Oregon Intrastate AQCR (defined by 40 CFR 81.221). 

Regulatory Requirements for Air Quality 

The entire LNG marine transit route is an attainment area and therefore not subject to a General 

Conformity determination under 40 CFR 93, Subpart B. During transit, LNG carriers are mobile 

sources and thus are not subject to permitting under the CAA. While moored/docked and 

unloading, different interpretations exist with respect to whether vessel emissions are subject to 

stationary source permitting requirements under the CAA or not. ODEQ has determined that 

emissions from LNG carriers that are directly associated with terminal activities (including, but 

not limited to, emissions attributable to providing power for the ship-board LNG transfer system 

and fugitive emissions from ship-board LNG piping and pumping systems) are part of the 

stationary source’s emissions. 

Federal and International Air Quality Requirements

Mobile Source Regulations 

Annex VI of MARPOL 73/78 – IMO Regulations for the Prevention of Air Pollution from 

Ships (Annex VI of MARPOL 73/78) regulate the maximum sulfur content of marine fuel oil to 

be no more than 4.5 percent (by weight), and also require that equipment placed in service since 

January 1, 2000 meet international emissions standards. Specifically, these standards restrict 

NOx from large non-emergency marine diesels (i.e., those with ratings of over 130 kW) and CO 

and PM emissions from shipboard incinerators. Recent amendments that have been approved by 

the IMO’s Marine Environment Protection Committee (MEPC) include a reduction in the 

maximum fuel sulfur content to 3.5 percent (wt) effective January 1, 2012, then progressively to 

0.50 percent (wt) effective January 1, 2020, subject to a feasibility review to be completed no 

later than 2018; and progressive reductions in NOx emission limits for marine engines. 

On July 21, 2008, President Bush signed into law the Maritime Pollution Protection Act of 2008, 

which implements the MARPOL Annex VI provisions for all ships in a port, shipyard, offshore 

terminal, or U.S. internal waters; and all ships bound for, or departing from, a port, shipyard, 

offshore terminal, or the internal waters of the United States. 

The United States EPA along with Canadian Officials has applied to the IMO on March 27, 2009 

to designate an Emission Control Area (ECA) under Annex VI. The ECA in the application 

would affect all ships within 200 miles from the coastline of the contiguous United States, most 

of the Hawaiian islands and the southern portion of the Alaskan coast. Currently, this is just a 
4.11-5 4.11 – Air Quality and Noise

proposal to the IMO, should a majority of the signatories of the IMO agree, the regulations 

would be anticipated to be approved in 2010 and in effect some time in 2012. 

ECAs have an accelerated schedule for restriction of sulfur fuels and restrictions on NOx 

emissions from the engines. In an ECA, the sulfur content of fuel oil shall not exceed the 

following limits: 1.5 percent prior to July 1, 2010, 1 percent after July 1, 2010; and 0.1 percent 

after January 1, 2015. If the ECA is effective in 2012, LNG tankers would be required to burn 

fuels with a maximum sulfur content of 1 percent from the date the rule comes into force until 

January 1, 2015, at which time LNG tankers would be required to burn fuel with a maximum 

sulfur content of 0.1 percent. This accelerated schedule would significantly reduce the SO2 and 

PM emissions (EPA-420-F-09-015, March 2009) from LNG tankers. 

Similarly, the ECA required more stringent NOx emission controls for ships built after 2016 

within an ECA. Should the IMO approve the ECA application and the rule go into effect, the 

EPA estimates that ships subject to the NOx emission controls within the ECA would have a 

dramatic reduction in NOx emissions and subsequent ozone formation from LNG tankers. In 

addition, EPA has promulgated emission standards for NOx from large non-emergency marine 

diesels, which are substantially similar to those in the Annex VI standards (see below). 

40 CFR 94, Final Rule, Control of Emissions from Marine Compression-Ignition Engines – 

All marine diesels larger than 37 kW that have been manufactured in the United States since 

January 1, 2004 are required to meet federal emissions standards identified in 40 CFR 94. 

Although most engines on existing LNG carriers were not manufactured in the United States, 

some of the newer engines installed on tugs and other local support vessels may have been 

subject to these regulations. 

40 CFR 80, Final Rule, EPA Regulations on Fuels – Any fuel oil sold in the United States that 

is used in or intended for use in marine diesel engines is subject to federal regulations (40 CFR 

80, Subpart I). The cetane index must be at least 40, or else the aromatic content must be no 

more than 35 percent by volume. Non-road, locomotive, and marine (NRLM) diesel sold in the 

United States must have a sulfur content no greater than 500 ppm (.05 percent) sulfur by weight. 

For locomotive and marine (LM) diesel, the sulfur content restriction drops to 15 ppm on June 1, 

2012. (Small refiners and entities with sufficient documentation of hardship may have 

alternative compliance provisions.) However, there is currently no requirement that LNG 

carriers be fueled in the United States. 

Air Quality Impacts and Mitigation 

Air quality impacts are a function of both the quantity of pollutants emitted and the dispersion of 

those pollutants in the ambient air (which is in turn influenced by stack temperatures, exhaust 

flowrates, and other variables). In the waterway, sources of emissions would include the 

transoceanic LNG carriers and the local tugboats escorting them as they enter the waterway. 

(Emissions from Coast Guard vessels and aircraft are not included here, because the details of 

their activities are security-related and confidential.) 

The primary emissions sources in the waterway would be those associated with fuel combustion 

in the marine vessels. As described in section 2.1.1.4, small quantities of LNG BOG would be 

generated during operation of LNG carriers, but these gases are burned in the ships’ propulsion 

systems. BOG consists essentially entirely of methane, and sometimes nitrogen. No odorant 
4.11-6 4.11 – Air Quality and Noise

(e.g., reduced sulfur compounds) has been added to the LNG; what little sulfur may be present in 

the LNG would not volatize and be present in the BOG; and even if it did, it would likely be 

oxidized into SO2 during combustion. Vessels have the capability to burn both BOG and oil. 

The duration of LNG carrier transit times in the waterway (i.e., prior to berthing and subsequent 

to deberthing) is summarized in table 4.11.1.1-3. Jordan Cove estimated that three tugs would be 

needed to assist the LNG carriers in the waterway, and that these would require approximately 1 

hour of dispatch time and 1.5 hours of time escorting the LNG carriers. 

TABLE 4.11.1.1-3 

LNG Carrier Transit Time Summary 

Activity 

Distance(naut

ical miles) Speed (knots) 

Duration 

(minutes) 

Inbound Transit to Berth 

 “K” Buoy through the Entrance Range 2.3 10/8 21 

 Entrance Range and Turn 0.5 10/8 5 

 Inside Range 0.6 6 7 

 Coos Bay Range 1.6 6 13 

 Empire Range 1.3 6 11 

 Lower Jarvis Range 0.8 6-4 8 

 Jarvis Turn 0.5 4 8 

 Upper Jarvis Range & Turn in LNG Berth 0.4 4 17 

Outbound Transit from Berth 

 Exit Turn from LNG Berth & Upper Jarvis Range 0.4 4 17 

 Jarvis Turn 0.5 4 8 

 Lower Jarvis Range 0.8 4-6 8 

 Empire Range 1.3 6 11 

 Coos Bay Range 1.6 6 13 

 Inside Range 0.6 6 7 

 Turn and Entrance Range 0.5 8/10 5 

 Entrance Range to “K” Buoy 2,3 8/10 21 

Contingency (weather, high slack tide) N/A N/A 150 

TOTAL 16 N/A 330 

Past estimates of hourly emissions in the waterway are summarized in table 4.11.1.1-4. For SO2, 

these estimates are based on very conservative assumptions regarding fuel sulfur content, given 

(a) the previously mentioned capability of LNG carriers to fire BOG instead of oil, and (b) the 

fact that domestic diesel fuel provided to the tugs would be required to have a much lower sulfur 

content in 2012 (0.0015 percent sulfur by weight, or less). 
4.11-7 4.11 – Air Quality and Noise

TABLE 4.11.1.1-4 

Estimates of Hourly Emissions from Vessels in Waterway a/

PM SO2 NOx CO VOC CO2 CH4 N2O

LNG carriers b/, c/ (ST) 17.1 584 247 68.2 6.90 37,110 b/ b/

LNG carriers c/, d/ (DFDE) 31.6 684 670 60.8 10.4 37,194 5.36 0.36 

3 Tugs (dispatch) e/ 9.47 119 318 51.5 8.52 22,714 3.16 0.21 

3 Tugs (inbound) f/ 2.96 37.1 148 16.1 2.66 7,098 0.99 0.07 

a/ Estimates are in the process of being revised. Information shown here for criteria pollutants and CO2 from LNG carriers is from 

Jordan Cove Energy’s February 27, 2009 response to FERC comments; other information is from Jordan Cove Energy’s 

December 2007 supplemental responses to FERC comments. 

b/ Figures include emissions associated with both propulsion power and auxiliary power. Propulsion power was conservatively 

assumed to be 16.75 MW; emission factors used for propulsion power were: 0.327 g PM/kWh, 9.53 g SO2/kWh, 1.05 g NOx/kWh, 

1.11 g CO/kWh, 0.00621 g VOC/kWh, 680 g CO2/kWh. Emissions of CH4 and N2O were not estimated; however, based on data 

for stationary boilers are not significant, even after correcting for global warming potential. 

c/ Auxiliary power was conservatively assumed to be 7.56 MW. Emission factors used for auxiliary power were: 0.30 g PM/kWh, 

9.53 g SO2/kWh, 12.5 g NOx/kWh, 1.63 g CO/kWh, 0.40 g VOC/kWh, 720 g CO2/kWh, 1.5 g CH4/gal fuel, 0.1 g N2O/gal fuel 

(10,000 Btu/kWh, 150,000 Btu/gal). 

d/ Figures include emissions associated with both propulsion power and auxiliary power. Propulsion power was conservatively 

assumed to be 16.75 MW; emission factors used for propulsion power were: 0.72 g PM/kWh, 12.3 g SO2/kWh, 12.5 g NOx/kWh, 

0.91 g CO/kWh, 0.10 g VOC/kWh, 682 g CO2/kWh, 1.5 g CH4/gal fuel, 0.1 g N2O/gal fuel (10,000 Btu/kWh, 150,000 Btu/gal). 

e/ Tug emissions during dispatch based on three tugs with power requirements of 6,400 hp (= 4,774 kW) each during dispatch 

and 2,000 hp (= 1,492 kW) each when inbound. Emission factors used were: 0.30 g PM/kWh, 3.76 g SO2/kWh, 15.03 g 

NOx/kWh, 1.63 g CO/kWh, 0.27 g VOC/kWh, 719.59 g CO2/kWh, 0.1 g CH4/kWh, 0.0067 g N2O/kWh. 

f/ Tug emissions while inbound based on three tugs with power requirements of 2,000 hp (= 1,492 kW) each when inbound. 

Emission factors used at this load were: 0.30 g PM/kWh, 3.76 g SO2/kWh, 10.08 g NOx/kWh, 1.63 g CO/kWh, 0.27 g VOC/kWh, 

719.59 g CO2/kWh, 0.1 g CH4/kWh, 0.0067 g N2O/kWh. 

Annual emissions are dependent on several factors, including the number of vessel trips, which 

may in turn be restricted by requirements that emissions associated with unloading at the 

terminal not exceed PSD permit thresholds and that ambient air quality impacts not exceed any 

applicable standards. Table 4.11.1.1-5 illustrates past estimates of annual emissions that were 

based on the expected number of LNG carrier trips (80 trips per year for vessels with 148,000 m3

capacity). 

Jordan Cove has stated that it continues to evaluate emissions from potential hourly and annual 

emissions estimates during operation of its proposed facility, but has not yet filed revised 

estimates. Therefore, we recommend that:

• Jordan Cove should revise its worst-case emissions estimates (both hourly and 

annual) for criteria pollutants, hazardous air pollutants, and GHG in accordance 

with the FERC staff’s March 23, 2009 data request and file these calculations with 

the Secretary for review and approval of the Director of OEP, prior to construction

of the LNG terminal. The revised estimates should incorporate the maximum worst 

case number of trips, to reflect the facility’s maximum sendout design capacity of 

1.0 Bscfd of natural gas. 
4.11-8 4.11 – Air Quality and Noise

TABLE 4.11.1.1-5 

Estimates of Annual Emissions from Vessels in Waterway (Transit)

PM SO2 NOx CO VOC CO2 CH4 N2O 

80 LNG carriers/yr (ST) a/ 2.04 70.0 29.6 8.18 0.82 4,453 b/ b/

116 LNG carriers/yr (ST) a/ 2.98 102 43.0 11.9 1.20 6,457 b/ b/

80 LNG carriers/yr (DFDE) a/ 3.80 82.1 80.4 7.30 1.24 4,463 0.64 0.043 

116 LNG carriers/yr (DFDE) a/ 5.50 119 117 10.6 1.80 6,472 0.93 0.062 

Tugs (for 80 LNG carriers/yr) b/ 1.11 13.9 43.2 6.05 1.00 2,669 0.37 0.025 

Tugs (for 113 LNG carriers/yr) b/ 1.61 20.2 62.7 8.77 1.45 3,870 0.54 0.036 

a/ Estimates are in the process of being revised. Based on hourly emissions shown in Table 4.11.1.1-4 and an estimated 

three hours (180 minutes) of LNG carrier transit time per trip (i.e., contingency factor in Table 4.11.1.1-3 is not included). 

b/ Based on hourly emissions shown in Table 4.11.1.1-4 and an estimated two hours (120 minutes) of time in dispatch mode 

(60 minutes for dispatch to meet LNG carriers and 60 minutes for return after leaving departing LNG carriers) and three hours 

(180 minutes) of time in “inbound” mode (transit time with the LNG carriers – 90 minutes each way). 

Dispersion modeling based on previous emissions estimates was conducted for both waterway 

and terminal emissions to determine the impacts of emissions on ambient air concentrations (at 

the worst-case locations) of PM, SO2, NO2, and CO, and these results are provided in section 

4.11.1.2. We recommend that:

• Jordan Cove should revise its dispersion modeling based on revised estimates of 

worst-case emissions in accordance with the FERC staff’s March 23, 2009 data 

request, and identify mitigation necessary to comply with air quality standards. 

Jordan Cove should file its revised modeling results with the Secretary, for review 

and approval of the Director of OEP, prior to construction of the LNG terminal. 

Emissions of NOx and VOC also contribute to the formation of ambient ozone, although the 

modeling of such formation is considerably more complex and is often not practical and/or 

useful at the project scale (e.g., from the standpoint of model accuracy and/or uncertainties in 

model input data). For marine vessels, NOx emissions are clearly much more significant than 

VOC emissions. For purposes of providing context for NOx emissions shown in table 4.11.1.1-5, 

1996 NOx emissions associated with commercial marine vessels (i.e., 155 bulk carriers, 54 

general cargo ships, and no tugs) in and around Coos Bay (in cruise mode, the reduced speed 

zone, and maneuvering) have been estimated as being approximately 133 tons per year (Environ 

2002). Context for GHG emissions is discussed in section 4.11.1.5. 

4.11.1.2 LNG Terminal 

Climate 

The proposed Jordan Cove LNG terminal would be located in Coos County, Oregon, within the 

Oregon Coast climate region, as described in section 4.11.1.1. The National Weather Service 

maintains a climate station at the Southwest Oregon Regional Airport in Coos County. Climate 

data from this station should be representative of conditions in the area of the proposed terminal. 
4.11-9 4.11 – Air Quality and Noise

Ambient Air Quality Standards 

The federal and Oregon ambient air quality standards applicable to this portion of the Project are 

discussed in section 4.11.1.1. 

Existing Air Quality 

The proposed LNG terminal is located in Coos County. As stated in section 4.11.1.1, this area is 

designated as attainment or unclassifiable for all NAAQS. 

Air Quality Control Regions 

Coos County is part of the Southwest Oregon Intrastate AQCR (defined by 40 CFR 81.221). 

Regulatory Requirements for Air Quality 

Emissions from all phases of construction and operation of the proposed LNG terminal would be 

subject to applicable state and federal air regulations. Air quality regulations affecting LNG 

terminal construction are primarily concerned with reducing emissions associated with 

construction equipment and fugitive dust. Construction would not involve the use of any marine 

vessels or locomotives. Ongoing operations at the constructed LNG terminal would be 

addressed by air quality regulatory programs for stationary sources of air pollution. 

The new stationary air emission sources associated with operating the proposed LNG terminal 

include: 

• one 329-million British thermal units per hour (MMBtu/hr) natural gas-fired combustion 

turbine; 

• two 160,000-m3

 capacity LNG storage tanks; 

• six 126-MMBtu/hr natural gas fired submerged combustion vaporizers (SCVs); 

• one 132-MMBtu/hr natural gas-fired hot oil heater; 

• one 2,000-kW diesel emergency generator; 

• two 150-hp diesel fire pumps; and 

• fugitive emission sources (valves, flanges, and other equipment). 

In addition, on January 17, 2008, ODEQ determined that “emissions from LNG carriers that are 

directly associated with terminal activities are part of the stationary source’s emissions. 

Emissions from the LNG carriers that are directly associated with terminal activities include, but 

are not limited to: emissions attributable to providing power for the ship-board LNG transfer 

system, including pumps used to transfer liquid or vapor LNG to or from the carrier; fugitive 

emissions from ship-board LNG piping and pumping systems; and any other emissions that can 

be directly attributed to terminal activities.” Emissions associated with berthing/deberthing, 

hotelling, and keeping the vessels’ propulsion systems online during onloading are not 

considered part of the stationary source’s emissions. 

In Jordan Cove’s January 23, 2009 responses to FERC comments, it stated that although it “is 

still including the capability to provide shore side power to those LNG ships that are equipped to 

connect to shore side power for the unloading of LNG cargos”, but acknowledge that it may not 

be feasible for all LNG ships to utilize this “cold ironing” capability. 
4.11-10 4.11 – Air Quality and Noise

The proposed terminal air emission sources are regulated at the federal level by the CAA and its 

associated regulations, and at the state level by OAR. Applicable federal and state air quality 

regulations are summarized below. 

Federal Air Quality Requirements

The federal regulations that are potentially applicable to the Project include: 

• Mobile Source Regulations; 

• New Source Performance Standards; 

• New Source Review (NSR), including nonattainment NSR and PSD; 

• Title V Operating Permits; 

• National Emissions Standards for Hazardous Air Pollutants (HAP); 

• Federal Class I Area Protection; 

• General Conformity; and 

• Chemical Accident Prevention. 

Mobile Source Regulations 

Title II of the CAA/40 CFR 86, 89, 90, 1039, and 1048 – EPA has promulgated extensive 

regulations reducing emissions from new on-road vehicles and construction equipment. 

40 CFR 80, Final Rule, EPA Regulations on Fuels – Gasoline or diesel sold in the United 

States is subject to federal regulations (40 CFR 80, Subpart I), and the sulfur content of both was 

recently decreased. Gasoline is required to have a sulfur content of no more than 80 ppm per 

gallon, or more than 30 ppm on average for any given refinery or importer. Non-road (NR) 

diesel sold in the United States must have a sulfur content no greater than 500 ppm (.05 percent) 

sulfur by weight, and the allowable sulfur content will decrease to 15 ppm (0.0015 percent) on 

June 1, 2010. (Small refiners and entities with sufficient documentation of hardship may have 

alternative compliance provisions.) 

Both NR and highway use vehicles and construction equipment used for the Project would be 

required to use the low-sulfur diesel fuels required by EPA regulations. 

New Source Performance Standards 

New Source Performance Standards (NSPS) regulations (40 CFR 60) establish pollutant 

emission limits and monitoring, reporting, and recordkeeping requirements for various emission 

sources based on source type and size. The NSPS apply to new, modified, or reconstructed 

sources. NSPS regulations that are applicable to the Project, or that have the appearance of 

potentially being applicable to the Project, are discussed below. 

The gas-fired combustion turbine located at the LNG terminal would be subject to NSPS Subpart 

KKKK (and is therefore specifically exempted from NSPS Subpart GG for stationary 

combustion turbines, as per 40 CFR 60.4305(b)). It would be required to meet a NOx emission 

standard of 25 ppm by volume, dry basis (ppmvd), corrected to 15 percent oxygen (ppmvd at 15 

percent O2) or approximately 1.2 lb NOx per megawatt-hour generated (lb/MWh). 

Liquid storage tanks that can emit VOCs may be subject to NSPS Subpart Kb, if the vapor 

pressure of the VOC is larger than 3.5 kilopascals (kPa) at the temperature at which they are 
4.11-11 4.11 – Air Quality and Noise

stored. However, the principal constituents of LNG are methane and ethane—both of which are 

exempted from the definition of VOC due to their relatively low atmospheric reactivity (40 CFR 

51.100(s)(1))—and the small amounts of VOC (e.g., propane, butanes, etc.) have a combined 

vapor pressure below 3.5 kPa at the temperature at which they are stored. As a result, Subpart 

Kb does not apply to the LNG tanks. (This applicability determination has also been previously 

made by EPA Region 9 [EPA 2006]). 

NSPS Subpart KKK applies to onshore natural gas processing plants; however, the Project would 

not be a natural gas processing plant; specifically, it would not be engaged in the extraction of 

natural gas liquids from field gas or fractionation of mixed natural gas liquids to natural gas 

products. 

Steam generating units with maximum heat input ratings between 100 MMBtu/hr and 

250 MMBtu/hr can be subject to NSPS Subpart Db, which requires that NOx emissions be 

limited to no more than 0.10 pounds per million Btu of heat input (lb/MMBtu). Both the SCVs 

and the hot oil heater located at the LNG terminal have maximum heat input ratings in this range 

and would meet this standard, although there is some question whether the SCVs are considered 

steam generating units. Specifically, there has been a determination by EPA Region 9 that 

because the SCVs are designed to have direct contact and intermixing of the combustion gases 

and the heat transfer medium, they are not considered steam generating units and therefore not 

subject to NSPS Subpart Db. 

The diesel emergency generator and diesel fire pump engines at the LNG terminal are subject to 

NSPS Subpart IIII. Standards for the emergency generators and fire pump engine differ, and are 

dependent on their rated output: 

• The 2,000-kW emergency generator at the LNG terminal would be required to have been 

manufactured to meet Tier 2 nonroad emissions standards for engines rated above 

560 kW, i.e., the sum of the emissions of non-methane hydrocarbons (NMHC) and NOx

(NMHC+NOx) would need to be at or below 10.5 g/kWh, and emissions of PM would 

need to be at or below 0.54 g/kWh (40 CFR 89.112, Table 2).1

• The two 150-hp diesel fire pumps at the LNG terminal would be required to have been 

manufactured to meet emissions standards for fire pump engines rated between 75 and 

130 kW (100 and 175 hp), i.e., emissions of NMHC+NOx would need to be at or below 

7.8 g/hp-hr, emissions of CO would need to be at or below 3.7 g/hp-hr, and emissions of 

PM would need to be at or below 0.60 g/hp-hr.2

New Source Review 

The federal NSR preconstruction permit program includes two components: Nonattainment 

NSR (NNSR), which applies to “major” stationary sources located in nonattainment areas, and 

PSD, which applies to “major” stationary sources located in attainment or unclassifiable areas. 

Oregon regulations for implementing the federal NSR permitting program (OAR 340, Division 

 

1

 The numerical nonroad emissions standards refer to average emissions rates measured during test cycles across multiple 

operating modes. The standards shown here are the highest possible Family Emissions Limits (FELs) that manufacturers can 

produce; average emissions from each manufacturer’s engine family are subject to more stringent standards. 

2

 More stringent standards apply to fire pump engines starting in model year 2010; however, if the fire pump engines have rated 

speeds of greater than 2,650 rpm, these standards do not need apply until 2013 (40 CFR 60, Subpart IIII, Table 4, footnote 2). 

The numerical Subpart IIII emissions standards refer to average emissions rates measured during test cycles across multiple 

operating modes. 
4.11-12 4.11 – Air Quality and Noise

224) conform with the federal requirements identified in 40 CFR 51.165 and 51.166. Because 

existing air quality is classified as “attainment” or “unclassifiable” for all NAAQS pollutants, 

only PSD regulations are potentially applicable. 

The U.S. Congress recognized that if compliance with ambient air quality standards was the sole 

criteria for air quality, air quality in attainment areas could deteriorate all the way up to the 

standards. In addition, for certain lands (e.g., national parks and wilderness areas), air quality 

was considered a special feature of the area. As a result, Congress identified PSD “increments” 

which identified the maximum allowable deterioration in air quality, and identified different 

increments for “Class I” areas deserving special protection than for other “Class II” areas. The 

PSD increments and the nearest Class I areas are identified in the discussion of ambient air 

quality in section 4.11.1. 

PSD preconstruction permits are needed by stationary sources where the total potential emissions 

from a group of emissions sources located in a contiguous area, under common control, and with 

the same industrial grouping are “major.” (EPA has historically not interpreted pipelines alone 

as constituting a “contiguous area” between sources that they connect; therefore, the LNG 

terminal is evaluated separately from the compressor station with regard to the “major source” 

classification.) For PSD, a “major” source is one with potential emissions (excluding fugitive 

emissions) of any regulated NSR pollutant over 250 tons per year (TPY), except that for certain 

sources, including “fossil fuel-fired steam electric plants of more than 250 MMBtu/hr heat 

input,” emissions only need to exceed 100 TPY. 

EPA has previously determined that both combined-cycle turbines and cogeneration plants that 

recover heat are classified as “fossil fuel-fired steam electric plants” (EPA 1993). Heat is being 

recovered from the proposed simple-cycle turbine by the SCV water as described in section 

2.1.3.5, but because there is no heat recovery steam generator, the unit is not considered a “fossil 

fuel-fired steam electric plant.” Therefore, the appropriate PSD threshold would be 250 TPY. 

The proposed terminal would be committing to cap emissions below levels that trigger PSD 

permitting requirements. 

Title V Operating Permit 

Title V of the federal CAA requires that a major source—which in this case is defined as a group 

of emissions sources located in a contiguous area and under common control with the potential 

to emit more than 100 TPY of any regulated air pollutant, 25 TPY of HAPs, or 10 TPY of any 

individual HAP—obtain an operating permit that codifies all air pollution regulatory 

requirements applicable to the facility and provides increased opportunities for citizen 

involvement. Oregon’s Title V regulations (OAR 340, Division 218) conform with federal 

requirements (40 CFR 70). As with the National Emission Standards for Hazardous Air 

Pollutants (NESHAPs) and NSR programs, EPA has historically not interpreted pipelines alone 

as constituting a “contiguous area” between sources that they connect; therefore, the LNG 

terminal is evaluated separately from the compressor station with regard to the “major source” 

classification. Potential emissions of NOx and CO from the LNG terminal exceed 100 TPY and 

therefore the LNG terminal would require a Title V Operating Permit. 

National Emissions Standards for Hazardous Air Pollutants 

Specific types of stationary sources of air pollution can be subject to NESHAPs. HAPs are 

defined in Section 112(b)(1) of the CAA and 40 CFR 63, Subpart C, and include formaldehyde 
4.11-13 4.11 – Air Quality and Noise

(which is often the most prevalent HAP from internal fuel combustion sources). NESHAPs are 

identified in 40 CFR 61 and 40 CFR 63, with standards in the latter chapter being referred to as 

Maximum Achievable Control Technology (MACT) standards; many of the NESHAPs are also 

incorporated by reference into Oregon’s regulations at OAR 340-244-0220. NESHAPs exist for 

the following source types included in this Project: 

• Stationary Combustion Turbines (40 CFR 63, Subpart YYYY; regulation stayed per 

§63.6095(d)); 

• Stationary Reciprocating Internal Combustion Engines (40 CFR 63, Subpart ZZZZ); and 

• Industrial, Commercial, and Institutional Boilers and Process Heaters (40 CFR 63, 

Subpart DDDDD; vacated per June 8, 2007 D.C. Court of Appeal decision). 

The standards for turbines and boilers only apply if emissions sources located in a contiguous 

area and under common control represent a “major source” of HAP, i.e., if they have the 

combined potential to emit 25 TPY of HAPs or 10 TPY of any individual HAP. EPA has 

historically not interpreted pipelines alone as constituting a “contiguous area” between sources 

that they connect; therefore, the LNG terminal is evaluated separately from the compressor 

station with regard to the “major source” classification. The LNG terminal would not be a 

“major source” of HAP, and therefore the NESHAPs for turbines and boilers listed above do not 

apply. The standards for internal combustion engines apply to nonmajor sources of HAP, but 

state that for new sources, compliance with the Subpart IIII New Source Performance Standards 

represents compliance with the MACT requirement [§63.6590(c)]. 

Federal General Conformity 

Project activities in nonattainment areas or maintenance areas can be subject to general 

conformity regulations if there are emissions associated with construction and operation that 

exceed 100 TPY and are not covered by a PSD or NNSR permit; Oregon’s regulations (OAR 

340, Division 350) implement Federal regulations identified in 40 CFR 51, Subpart W. Because 

the LNG terminal would not be located in nonattainment or maintenance areas, general 

conformity requirements would not apply. 

Chemical Accident Prevention Provisions 

LNG facilities are subject to safety regulations developed by the DOT (49 CFR 193) and the 

Department of Homeland Security (33 CFR 127). The EPA’s Chemical Accident Prevention 

Provisions (40 CFR 68, which were developed in accordance with Section 112(r) of the CAA 

and referenced by Oregon regulations at OAR 340-244-0230) can also apply to owners or 

operators of stationary sources producing, processing, handling, or storing toxic or flammable 

substances; however, EPA’s General Counsel has clarified that Section 112(r) and the associated 

regulations do not apply to LNG stored at terminals because the material is either being 

transported or stored incident to transportation (EPA 2003). 

Aside from LNG, which would be stored incident to transportation, the Project would not be 

storing hazardous or flammable substances in excess of any thresholds identified in 40 CFR 68, 

and therefore those regulations do not apply. However, with regard to the storage of any small 
4.11-14 4.11 – Air Quality and Noise

quantities of hazardous substances that are not being transported or stored incident to 

transportation, the 112(r)(1) general duty clause does apply: 

“The owners and operators of stationary sources producing, processing, handling 

or storing [hazardous] substances have a general duty in the same manner and to 

the same extent as section 654, title 29 of the United States Code, to identify 

hazards which may result from [accidental] releases using appropriate hazard 

assessment techniques, to design and maintain a safe facility taking such steps as 

are necessary to prevent releases, and to minimize the consequences of accidental 

releases which do occur.” 

State Air Quality Requirements

In addition to the rules identified above, ODEQ has state-specific air quality requirements. 

Those that would be directly applicable to the Project, and those that have the appearance of 

being potentially applicable, are discussed below. 

Oregon Construction Permit 

Oregon requires that facilities subject to NSPS regulations with emissions greater than 10 TPY 

obtain a Standard Air Contaminant Discharge Permit (ACDP) in accordance with OAR 340-216 

prior to construction. As part of this permit, Plant Site Emission Limits (PSELs) are required to 

be obtained for all regulated pollutants, as per OAR 340-222-0020, and an air quality impact 

analysis must be conducted in accordance with OAR 340-216. 

Jordan Cove is currently recalculating emissions associated with all potential operating 

scenarios; however, table 4.11.1.2-1 compares the potential emissions that have previously been 

identified for the terminal to Oregon’s Significant Emission Rates (SERs). For pollutants with 

emissions greater than the SERs, which in this case include NOx, CO, and PM10 (SERs of 100 

TPY, 100 TPY, and 15 TPY, respectively. PSELs would likely be set equal to the facility-wide 

potential to emit. For pollutants with emissions lower than the SER, the facility would likely be 

assigned a Generic PSEL. OAR 340-216-0066(1)(a) and 340-222-0041(3)(b)(C) require that the 

ACDP application include an analysis of the air quality impact of the proposed source, described 

in more detail later in this section. 

TABLE 4.11.1.2-1 

Oregon Significant Emission Rates and Terminal Potential to Emit

Pollutant Significant Emission Rate (tpy) Terminal Potential to Emit (tpy) 

CO 100 174.4 

NOx 40 248.1 

PM10 15 37.3 

SO2 40 6.7 

VOCs 40 21.3 

To meet these requirements, Jordan Cove submitted an application to the ODEQ in October 2008 

for an ACDP addressing operation of land-based emissions sources at the LNG terminal (Jordan 

Cove Energy 2008). However, Jordan Cove will be recalculating emissions and revising its 

application in the near future. Jordan Cove has stated the revised application will incorporate the 
4.11-15 4.11 – Air Quality and Noise

potential scenarios of vessels unloading under their own power, and emissions from the 

combustion turbine and/or vaporizers may be reduced from the previously submitted values. 

Oregon Title V Permit 

As mentioned previously, the Jordan Cove LNG terminal’s projected potential emissions would 

trigger Oregon Title V permit requirements (OAR 340-218). Jordan Cove would submit a timely 

Title V permit application and would pay applicable Title V operating permit fees (OAR 340-

220). 

Air Quality Impact Analysis 

Oregon regulations require an air quality analysis in accordance with OAR 340-225-0050(1) and 

(2) and OAR 340-225-0060. With respect to the requirement for projects to demonstrate 

compliance with the NAAQS and PSD increments, ODEQ allows projects to show that their own 

impacts are below significant impact levels (SILs). Projects that cannot demonstrate impacts less 

than the SILs must show that (a) modeled impacts from the proposed source and other PSD 

increment-consuming sources are less than PSD increments, and (b) those impacts plus 

background concentrations are less than the NAAQS. 

Oregon Major New Source Review 

As stated previously, Oregon’s Major New Source Review program follows federal 

requirements, which do not apply to the proposed terminal, as described above. 

General Emission Standards 

The proposed LNG terminal would be subject to two provisions from Oregon’s general emission 

standards in OAR 340-226. The first provision requires that sources that are not already subject 

to NSPS requirements (as identified above) or other new source standard and have the potential 

to emit at least 1 TPY of any criteria pollutant must meet requirements for Typically Achievable 

Control Technology (TACT). The TACT requirement therefore applies to the SCVs, if they are 

confirmed to be exempt from the NSPS requirements. If ODEQ determines that the proposed 

SCVs do not meet the TACT requirement, the Department has the authority to make its own 

TACT determination. 

The second applicable provision mandates that “the highest and best practicable treatment and 

control of air contaminant emissions must in every case be provided.” In accordance with OAR 

340-226-0100(2), sources comply with this requirement if they meet all other applicable 

emission standards and requirements in Oregon’s air regulations. Therefore, the Jordan Cove 

facility would be in compliance with the requirement for “highest and best practicable 

treatment.” 

Fuel Burning Equipment and Fuel Sulfur Content 

Under OAR 340-228, ASTM fuel oils used in stationary oil-burning equipment at the LNG 

terminal are required to have sulfur contents of no more than 0.3 percent (wt.) for ASTM Grade 

1 fuel oil and no more than 0.5 percent (wt.) for ASTM Grade 2 fuel oil. PM emissions from all 

fuel combustion sources must not exceed 0.1 grains per standard cubic foot (gr/scf). 
4.11-16 4.11 – Air Quality and Noise

Visible Emission and Nuisance Requirements 

State visible emissions and nuisance abatement regulations are codified in OAR 340-208. Both 

construction and operation phases of the proposed LNG terminal would be subject to visible 

emission limits stated in terms of opacity. In Oregon, the LNG terminal may not emit 

contaminants causing opacity to equal or exceed 20 percent in any period or periods aggregating 

more than 3 minutes in any hour. In addition, no person may create an observable deposition of 

particulate matter on another person’s property (OAR 340-208-540). 

This regulation prohibits nuisances, and requires that reasonable precautions be taken to 

minimize fugitive dust emissions in Special Control Areas (which include areas within 3 miles of 

the corporate limits of any city having a population of 4,000 or more). 

Energy Facility Siting Requirements (Oregon Department of Energy) 

Most large energy facilities in Oregon are under the jurisdiction of the EFSC. The Oregon 

Legislature determines what types of energy facilities require EFSC review. An energy facility 

developer must apply to the EFSC for a site certificate and must supply information about the 

proposed facility and the proposed site. 

In 1997, the Oregon legislature gave the EFSC authority to set carbon dioxide (CO2) emissions 

standards for new energy facilities. Division 24 of the EFSC’s rules, beginning at OAR-345-

024-0500, contains specific standards for base load gas plants, non-base load (peaking) power 

plants, and non-generating energy facilities that emit CO2. The standard for non-generating 

energy facilities is expressed as a rate of emissions per horsepower-hour: 0.504 pounds of 

CO2/hp-hr. CO2 would be formed during the operating of the Jordan Cove LNG terminal as a 

primary product of combustion in the SCVs, emergency generator, and emergency firewater 

pump engine. In 2005, the EFSC had initiated development of additional criteria for LNG 

facilities. 

The EPAct contains a provision that the FERC has exclusive jurisdiction over onshore LNG 

import facilities. As a result, the EFSC has stated that it would not be asserting jurisdiction over 

LNG import terminals. In addition, the ODE stopped all work related to rulemaking for LNG 

facilities. 

Oregon Governor Ted Kulongoski directed state agencies to participate in the FERC’s review of 

any LNG import terminals in Oregon. He designated the ODE as the lead state agency in 

working with the FERC on LNG import terminal safety and security issues. 

In a letter filed July 26, 2006, the ODE submitted comments in response to the NOI. ODE’s 

comments included a request that FERC consider CO2 offsets for the proposed LNG import 

terminal, “to the extent that the proposed project would use technology that produces carbon 

dioxide.” 

On March 31, 2009, Jordan Cove filed its MOU with the State of Oregon. In this MOU Jordan 

Cove commits to mitigation of CO2 emissions from the operation of the proposed LNG terminal 

and associated electric cogeneration facility as specifically detailed in the MOU. In summary, 

Jordan Cove commits to complying with EFSC requirements by offsetting 17 percent of the 

emissions produced using best available technology (BAT). In addition to using the most 

efficient commercially available vaporizer and heater design consistent with BAT, Jordan Cove 

proposes to provide funds sufficient to offset an equivalent 17 percent of the emissions to The 
4.11-17 4.11 – Air Quality and Noise

Climate Trust, an entity meeting the definition of a “qualified organization” as described in ORS 

469.503. 

Air Quality Impacts and Mitigation 

Construction of the terminal is projected to last approximately 36 months, and exhaust and 

evaporative emissions associated with construction of the LNG terminal in each of these years 

are estimated in table 4.11.1.2-2. GHG emissions are estimated in table 4.11.1.2-3. 

TABLE 4.11.1.2-2 

Terminal Construction – Total (Exhaust and Evaporative) Emissions (PM10, SO2, NOx, CO, VOC, and HAP)

Year 

PM10

tpy 

SO2

tpy 

NOx

tpy 

CO 

tpy 

VOC 

tpy 

Total HAP 

tpy 

1 20.9 6.5 39.1 49.7 2.2 0.3 

2 3.2 7.8 57.3 80.3 3.6 0.4 

3 1.1 2.4 19.8 31.9 1.9 0.1 

4 0.8 1.8 14.0 20.7 1.3 - 

TABLE 4.11.1.2-3 

Terminal Construction – Total (Exhaust and Evaporative) Emissions of Greenhouse Gases (CO2, CH4, and N2O)

Year 

CO2

tpy 

CH4

tpy 

N2O 

tpy 

1 3,039 1.1 2.0 

2 11,785 1.1 0.4 

3 3,487 0.3 0.08 

4 1,471 0.07 0.05 

Reliable methodologies do not exist for the accurate quantification of fugitive dust emissions 

from LNG terminal construction. Emissions may result from construction activities such as land 

clearing, grading, excavation, and concrete placement, as well as vehicular traffic on paved and 

unpaved roads. The magnitude of fugitive dust generation is a function of the area of 

construction, silt, and moisture contents of the soil, wind speed, frequency of precipitation, 

amount of vehicle traffic, vehicle types, and paved roadway characteristics. Although emissions 

have not been quantified, fugitive dust emissions will tend to be greater during the drier summer 

months and in areas of fine-textured soils. 

Emissions of SO2 (and the sulfate portion of PM emissions) would be reduced as a result of EPA 

fuel sulfur content standards mentioned previously. For compliance with Oregon’s regulations 

regarding visible emissions and nuisances, reasonable precautions would need to be taken to 

minimize fugitive dust emissions in Special Control Areas (which include areas within 3 miles of 

the corporate limits of any city having a population of 4,000 or more). Such reasonable 

precautions may include, but not be limited to the following: 

• Use, where possible, of water or chemicals for control of dust in the demolition of 

existing buildings or structures, construction operations, the grading of roads or the 

clearing of land;
4.11-18 4.11 – Air Quality and Noise

• Application of asphalt, oil, water, or other suitable chemicals on unpaved roads, materials 

stockpiles, and other surfaces that can create airborne dusts;

• Full or partial enclosure of materials stockpiles in cases where application of oil, water, 

or chemicals are not sufficient to prevent particulate matter from becoming airborne;

• Installation and use of hoods, fans, and fabric filters to enclose and vent the handling of 

dusty materials;

• Adequate containment during sandblasting or other similar operations;

• Covering, at all times when in motion, open-bodied trucks transporting materials likely to 

become airborne; and

• The prompt removal from paved streets of earth or other material that does or may 

become airborne.

Additionally, Jordan Cove has committed to the following practices to minimize fugitive dust 

emissions during general Project construction activities: 

• Take reasonable measures to limit visible density (opacity) of fugitive dust emissions to 

less than or equal to 20 percent; 

• Apply water one or more times per day (or as needed during periods of natural 

precipitation) to all affected unpaved roads, and unpaved haul and access roads; 

• Reduce vehicle speeds on all unpaved roads, and unpaved haul and access roads; 

• If bulk transfer operations are required, spray handling and transfer points with water at 

least 15 minutes before use; 

• Cover all haul truck loads, or maintain at least 6 inches of freeboard space in each cargo 

compartment, ensure that all haul truck cargo compartments are constructed and 

maintained to minimize spillage and loss of materials, and clean or wash each cargo 

compartment at the delivery site after removal of the bulk materials; 

• Use application of water when necessary to active construction areas to minimize fugitive 

dust emissions; 

• Use application of water to open and/or non-vegetated areas to minimize fugitive dust 

emissions; 

• For temporary surfaces during periods of inactivity, restrict vehicular access by means of 

either fencing or signage, and apply water and/or surfactants or crusting agents to 

minimize fugitive dust emissions; and 

• Control occurrence of windblown erosion from dry excavation piles at the proposed LNG 

tract and other dredge disposal areas by: using double-layered silt fencing at the toe of the 

dikes or slopes; inundating the interior faces of the dikes within the Linerboard and Port 

sites with wet material; installing finger dikes, silt fence or similar structures not more 

than 200 feet on the center of each pile in all directions to limit windblown debris 

migration; and pumping water for short-term stabilization prior to hydroseeding. 

Previously identified potential emissions from stationary sources at the LNG terminal are shown 

in table 4.11.1.2-4. The revised ACDP application to be submitted in the future may reflect 

control of emissions from the combustion turbine and/or vaporizers to lower levels. Although 

odorant (reduced sulfur compounds) is added to the LNG, the relative quantities are very small 
4.11-19 4.11 – Air Quality and Noise

TABLE 4.11.1.2-4 

Terminal Operation – Initial Estimates of Potential to Emit from Stationary Sources (PM10, SO2, NOx, CO, VOC, Total HAP)

Source PM10 tpy SO2 tpy NOx tpy CO tpy 

VOC 

tpy Total HAP tpy 

SCVs (5) a/ - 3.5 101.5 73.0 12.0 4.1 

Combustion Turbine (1) 22.3 2.2 118.3 70.0 3.0 1.5 

Hot Oil Heater (1) 14.9 0.9 26.0 31.0 3.1 1.1 

Firewater Pump Engines (2) b/ 0.001 0.001 0.30 0.02 0.01 2.3E-07 

Emergency Generator (1) b/ 0.03 0.2 1.98 0.1 0.04 1.7E-06 

Fugitive Hydrocarbons b/ - - - - 3.2 - 

Vessel-Powered Unloading (80 vessels/yr) c/ 2.58 119.51 107.5 14.1 3.4 a/

Vessel-Powered Unloading (116 vessels/yr) c/ 3.74 173.29 155.8 20.3 5.0 a/

Fugitive Hydrocarbons from LNG Tankers b/ - - - - 0.03 - 

Total d/ 41.0 177.3 < 250 136.0 16.8 a/. 

a/ Estimates are in the process of being recalculated. Criteria pollutant values shown for the SCVs are those submitted in the 

permit application to Oregon DEQ in October 2008 (Jordan Cove Energy, 2008). HAP emissions were not included in this 

submittal and will be calculated in the near future. 

b/ These sources were included in the September 2007 version of Resource Report No. 9 but are not shown in the permit 

application submitted to Oregon DEQ in October 2008. 

c/ The vessel-powered unloading Information is based on Jordan Cove Energy’s February 27, 2009 response to FERC 

comments, which did not include HAP calculations. Estimates are based on 13 hours of unloading per vessel using 7.5 MW of 

auxiliary electrical power, and identified the following emission factors for electrical power: 0.30 g PM/kWh, 13.9 g SO2/kWh, 12.5 

g NOx/kWh, 1.63 g CO/kWh, 0.40 g VOC/kWh. (Note: reported SO2 emissions totals are not consistent with the identified SO2

emission factor.)

d/ Total includes vessel-powered unloading of 116 vessels/year, except that for NOx the total reflects the fact that the Project 

intends to incorporate a restriction in the form of a Federally enforceable limit on potential to emit to maintain the facility as a 

“nonmajor” source relative to PSD regulations. 

(such that odor is only detected near the vicinity of a leak) and odorant is not vented at the 

terminal. Additional emissions associated with the vessels that are not considered to be part of 

the “stationary source” are identified in table 4.11.1.2-5. Potential GHG emissions are estimated 

in table 4.11.1.2-6. We have recommended above under the waterway for LNG traffic that 

Jordan Cove should revise its worst-case emissions estimates for criteria pollutants, HAP, and 

GHGs (see section 4.11.1.1).

TABLE 4.11.1.2-5 

Terminal Operation – Initial Estimates of Potential to Emit from Mobile Sources (PM10, SO2, NOx, CO, VOC, Total HAP) a/

Source PM10 tpy SO2 tpy NOx tpy CO tpy 

VOC 

tpy Total HAP tpy 

LNG carrier berthing emissions b/ 0.61 14.8 17.9 1.52 0.26 b/

Tug berthing emissions (3 tugs) c/ 0.51 6.45 19.6 2.80 0.46 0.009 

LNG carrier hotelling emissions b/ 1.13 32.0 35.7 3.43 0.68 b/

LNG carrier propulsion engine emissions (hot 

standby) during unloading b/ 2.0 34.2 50.7 3.1 0.28 b/

Standby tug emissions during unloading (1 tug) c/ 0.02 0.02 0.95 0.10 0.02 0.0007 

LNG carrier emissions from engine 

warming/towline connection/cast-off/deberthing b/ 0.81 19.7 23.9 2.03 0.35 b/

Tug emissions for towline connection/deberthing 

(3 tugs) c/ 0.53 0.48 20.6 2.89 0.48 0.009

Total d/ 5.61 107.7 169.4 15.9 2.53 b/ 

a/ Estimates are in the process of being revised. Values are based on 116 LNG carrier trips/year and the following operational 

schedule, identified in Jordan Cove Energy’s February 27, 2009 responses to FERC comments and tug parameters identified in 

the September 2007 version of Resource Report No. 9: 1.5 hours for berthing (LNG carrier main engines at 3.35 MW, LNG 

carrier aux engines at 2.583 MW, engines for each tug at 4,000 hp ≈ 3000 kW); 4.5 hours for LNG hotelling prior to unloading 

(LNG carrier main engines on hot standby at 1.675 MW, LNG carrier aux engines at 2.52 MW, one tug standing by with main 

engines off and aux. engine at 27 kW); 13. hours for unloading (LNG carrier main engines on hot standby at 1.675 MW, LNG 

carrier aux engines counted as stationary sources in Table 4.11.1.2-4, one tug standing by with main engines off and aux. engine 
4.11-20 4.11 – Air Quality and Noise

TABLE 4.11.1.2-5 

Terminal Operation – Initial Estimates of Potential to Emit from Mobile Sources (PM10, SO2, NOx, CO, VOC, Total HAP) a/

Source PM10 tpy SO2 tpy NOx tpy CO tpy 

VOC 

tpy Total HAP tpy 

at 27 kW); 2.0 hours to warm LNG carrier propulsion engines/connect towlines/cast-off/deberth (same engine loads as for 

berthing, except that tug engines are at 400 hp = 300 kW for 30 minutes of towline connection and 4000 hp = 3000 kW for 90 

minutes of deberthing). 

b/ Emission factors for LNG carrier main engines are worst-case of the “light load” factors identified in the Project’s February 27, 

2009 response to FERC comments for the two LNG carrier technology types (ST and DFDE): i.e., 0.72 g PM/kWh, 12.3 g 

SO2/kWh, 1.82 g NOx/kWh, 1.11 g CO/kWh, 0.10 g VOC/kWh. Emission factors for aux. engines are the same as those identified 

in footnote c/ to Table 4.11.1.2-4. HAP emissions will be calculated in the future. 

c/ Tug data presented is from the September 2007 version of Resource Report No. 9 (which also includes documentation of 

emission factors) scaled up from 12 hrs standby to 17.5 hrs standby and 80 LNG carrier trips/year to 116 LNG carrier trips/year. 

d/ The vessel-powered unloading Information is based on Jordan Cove Energy’s February 27, 2009 response to FERC 

comments, which did not include HAP calculations. Estimates are based on 13 hours of unloading per vessel using 7.5 MW of 

auxiliary electrical power, with the following emission factors for electrical power: 0.30 g PM/kWh, 13.9 g SO2/kWh, 12.5 g 

NOx/kWh, 1.63 g CO/kWh, 0.40 g VOC/kWh.

TABLE 4.11.1.2-6 

Terminal Operation - Potential to Emit Greenhouse Gases (CO2, CH4, N2O) a/

Source CO2 tpy CH4 tpy N2O tpy 

SCVs (5) 256,868 28.71 0.49 

Combustion Turbine (1) 167,678 18.74 0.32 

Hot Oil Heater (1) 67,275 7.52 0.13 

Firewater Pump Engines (2) 9 0.00 0.00 

Emergency Generator (1) 166 0.01 0.00 

Fugitive Hydrocarbons - - - 

Fugitive Hydrocarbons from LNG Tankers - 0.24 - 

Tugs (for 116 LNG carrier trips/year) a/ 6,751 0.94 0.06 

LNG carriers (116 trips/year) b/ 20,899 c/ c/

Total 519,646 c/ c/

a/ Data are from the Project’s December 2007 response to FERC comments and may be revised. 

b/ Values are currently being recalculated, but values shown are based on Jordan Cove Energy’s February 27, 2009 response 

to FERC comments: CO2 emission factors of 682 g/kWh for main engines (worst-case of data presented for DFDE and steam 

turbine propulsion systems) and 720 g/kWh for auxiliary engines. 

c/ Emissions of CH4 and N2O will be estimated by the Project in the future, but are not expected to significant relative to CO2

emissions. 

The estimated maximum impacts of criteria pollutant emissions from terminal operation—

specifically, impacts from land-based sources and emissions from 80 DFDE LNG carriers (not 

including emissions during unloading) using dispersion modeling and 5 year’s worth of local 

meteorological data. Separate runs were conducted for land-based sources only, and the 

combination of land-based sources with LNG tanker emissions while LNG tankers are in motion. 

Results are summarized in table 4.11.1.2-7 and illustrate compliance with the NAAQS for all 

cases. Project impacts including both land-based sources and LNG carriers would also not cause 

a significant deterioration of air quality (as defined by the PSD increments identified in Section 

163 of the CAA). We have recommended that Jordan Cove should revise its dispersion 

modeling based on revised estimates of worst-case emissions in accordance with FERC’s March 

23, 2009 data request, and identify mitigation necessary to comply with air quality standards (see 

section 4.11.1.1). 
4.11-21 4.11 – Air Quality and Noise

TABLE 4.11.1.2-7 

Maximum Air Quality Impacts from Land-Based Terminal Sources and LNG Tankers

Project Impacts Total Impacts 

Air 

Pollutant 

Averaging 

Period 

Background 

Level 

Land-based 

Sources 

Land-based 

Sources + 

Vessels a/

Land-based 

Sources 

Land-based 

Sources + 

Vessels 

NAAQS or 

OAAQS 

3-Hour 32 2 243 34 275 1,300 

24-Hour 19 25 62 44 81 260 

SO2 (μg/m3) 

Annual 6 6 15 12 21 52 

CO (μg/m 1-Hour 6,785 381 392 7,166 7,177 40,000 3) 

8-Hour 3,910 128 138 4,038 4,048 10,000 

NO2 (μg/m3) Annual 18 12 20 30 38 100 

24-Houra PM10 38 15 16 53 54 150 

(μg/m3

) Annuala

 14 2.7 3 17 17 50 

24-Houra PM2.5 18 15 16 33 34 35 

(μg/m3

) Annuala

 7 2.7 3 10 10 15.0 

μg/m3

 = micrograms per cubic meter 

a/ LNG carrier modeled impacts are based on a vessel fuel sulfur content of 2.7 percent. Short-term modeling will be revised to 

reflect worst-case sulfur content. 

As mentioned previously, “Class I” areas are located at distances of 110 to 200 km, in various 

directions from the proposed terminal site. For most analyses, modeling of impacts at these 

areas was simplified by estimating worst-case impacts at a distance of 50 km from the proposed 

terminal site in any direction. This is conservative; i.e., actual impacts at the Class I areas would 

be less, given that they are more distant than 50 km. Results are shown in table 4.11.1.2-8 and 

demonstrate that Class I PSD increments would easily be met at the Class I areas. Although 

nitrogen deposition at 50 km is shown as being higher than the National Park Service/U.S. Fish 

and Wildlife Service Deposition Analysis Threshold (DAT) for insignificant impacts in western 

Class I areas, impacts at Class I areas are likely to be well below the DAT, given that the actual 

Class I areas are more than twice as far away as the 50 km analysis point. 

TABLE 4.11.1.2-8 

Maximum Air Quality Impacts from Land-Based Terminal Sources and Vessels (While Stationary) at 50 km

Project Impacts 

Air Pollutant 

Averaging 

Period 

Land-based 

Sources 

Land-based 

Sources + 

Vessels 

Class I PSD 

Increment 

3-Hour 0.3 <9.1 25 

24-Hour 0.02 <1.7 5 

SO2 (μg/m3) 

Annual 0.0004 <0.009 2 

NO2 (μg/m3) Annual 0.01 <0.02 2.5 

24-Hour 0.07 <0.09 8 

Annual 0.002 <0.002 4 

 

PM10 (μg/m3) 

 

Air Quality-Related Values (AQRVs) 

Analysis 

Thresholds 

Nitrogen Deposition (kg/ha/yr) <0.016 0.005 

Sulfur Deposition (kg/ha/yr) <0.003 0.005 

Visibility: plume contrast <0.000 0.05 

Visibility: color difference parameter (ΔE) <0.022 2.0 

μg/m3

 = micrograms per cubic meter 
4.11-22 4.11 – Air Quality and Noise

Visibility impacts of emissions from the terminal were estimated at a distance of 110 km (the 

distance of the nearest Class I area, Kalmiopsis) and at closer distances (to represent the visual 

range of an observer located in the Class I area looking into the Class II area). Plume contrast at 

a wavelength of 0.55 μm (green light) was found to be less than 0.001, well below the EPA 

screening criteria of 0.05. The color difference parameter (ΔE) ranged from zero to 0.022, well 

below the EPA screening criteria of 2.0. Visibility impacts would therefore be negligible. 

4.11.1.3 Pacific Connector Pipeline 

Climate 

The Butte Falls Compressor Station would be located in Jackson County, in the Southwestern 

Valley climate region. The region surrounding the Butte Falls Compressor Station receives an 

annual average of 36.5 inches of precipitation per year, as per the Western Regional Climatic 

Center (WRCC), monitored at the Butte Falls 1 SE weather station for the period February 1950 

through March 1986. The prevailing wind direction (not available from the Butte Falls weather 

station) is from the west-southwest, at an average daily speed of 2.5 mph, as recorded at the 

Medford Oregon Weather Station 3W, from October 1994 to August 2006. Average daily 

temperature is 54 °F from the same station and reporting period. 

Ambient Air Quality Standards 

The federal and Oregon ambient air quality standards applicable to this portion of the Project are 

discussed in section 4.11.1.1 above. 

Existing Air Quality 

Most of the background air quality data for Coos County presented in table 4.11.1.1-1 are also 

applicable to the other three counties that the Pacific Connector pipeline would be located in. 

However, additional monitoring data are available for Jackson and Klamath Counties, and are 

shown in table 4.11.1.3-1. 

TABLE 4.11.1.3-1 

2006 Ambient Air Quality Data from Jackson and Klamath Counties

Air Pollutant 

Averaging 

Period 

Medford 

Rogue 

Valley Mall 

Medford 

Welch & 

Jackson 

Medford 

Grant & 

Belmont 

Medford 

7112 Rapp 

Rd Talent 

Medford 

4035 

Dodge Rd. 

Klamath Falls 

Peterson Schl. NAAQS 

CO (μg/m 1-Hour a/ 5,400 - - - - - 40,000 3) 

8-Hour a/ 3,100 - - - - - 10,000 

Ozone (ppm) 1-Hour c/, d/ - - - 0.10 - - 0.12 

8-Hour e/ - - - 0.068 - - 0.075 

PM10 (μg/m 24-Hour d/ - 62 - - - 56 150 3) 

Annual b/, f/ - 20 - - - 20 50 

PM2.5 (μg/m 24-Hour g/ - - 26 - 14 48 35 3) 

Annual b/ - - 10.0 - 5.5 11.1 15.0 

a/ This standard is not to be exceeded more than once per calendar year. 

b/ The annual average concentration. 

c/ The 1-hour ozone standard was revoked effective June 15, 2005 for all areas in Oregon as per 70 FR 44477 (August 3, 2005). 

d/ The standard is met when the expected number of exceedances per year (determined as per 40 CFR 50) is less than one. 

e/ Standards and data are 3-year averages of the fourth highest daily maximum 8-hour concentrations. 

f/ The historical annual PM10 standard was revoked, effective December 18, 2006. 

g/ The standard applies to the 98th percentile 24-hour concentration. 

μg/m3 = micrograms per cubic meter 
4.11-23 4.11 – Air Quality and Noise

All four counties crossed by the pipeline are currently designated as attainment or unclassifiable 

for all NAAQS, with the exception that on December 22, 2008, EPA designated Klamath County 

as a PM2.5 nonattainment area. 

The Medford urban growth boundary/Air Quality Management Area and Klamath Falls Urban 

Growth Boundary (UGB) were previously designated as nonattainment with respect to CO and 

PM10, and are therefore considered “maintenance” areas. However, the Pacific Connector 

pipeline would not infringe on either of these maintenance areas, as the pipeline would pass 

north of the Medford maintenance areas and south of the Klamath Falls UGB. 

Air Quality Control Regions 

Coos, Douglas, and Jackson Counties are part of the Southwest Oregon Intrastate AQCR 

(defined by 40 CFR 81.221). Klamath County is part of the Central Oregon Intrastate AQCR 

(defined by 40 CFR 81.219). 

Regulatory Requirements for Air Quality 

Emissions from all phases of construction and operation of the proposed pipeline and compressor 

station would be subject to applicable state and federal air regulations. Air quality regulations 

affecting construction are primarily concerned with reducing emissions associated with 

construction equipment and fugitive dust. Operation of the compressor station would be 

addressed by air quality regulatory programs for stationary sources of air pollution. 

The new stationary air emission sources that would result from operation of the proposed Butte 

Falls Compressor Station are: 

• two 83.3 MMBtu/hr natural gas-fired combustion turbines; 

• one 2.5 MMBtu/hr natural gas-fired boiler; and 

• one 450 hp 4-stroke rich-burn natural gas-fired emergency generator. 

These proposed air emission sources are regulated at the federal level by the CAA and its 

associated regulations, and at the state level by OARs. 

Federal Air Quality Requirements

The federal regulations that are potentially applicable to the Pacific Connector pipeline include: 

• Mobile Source Regulations; 

• New Source Performance Standards; 

• PSD review or nonattainment New Source Review; 

• Title V Operating Permits; 

• NESHAPs; 

• Federal Class I Area Protection; and 

• General Conformity. 

New Source Performance Standards 

The gas-fired combustion turbines located at the Butte Falls Compressor Station would be 

subject to NSPS Subpart KKKK (and are therefore specifically exempted from NSPS 
4.11-24 4.11 – Air Quality and Noise

Subpart GG for stationary combustion turbines, as per 40 CFR 60.4305(b)). They would be 

required to meet a NOx emission standard of 25 ppm by volume, dry basis, corrected to 15 

percent oxygen (ppmvd @ 15 percent O2) or approximately 1.2 lb NOx per megawatt hour 

generated (lb/MWh). 

The spark-ignition emergency generator at the compressor station would be subject to NSPS 

Subpart JJJJ, which requires that NOx emissions be no higher than 2.0 g/hp-hr = 160 ppmvd @ 

15% O2 and that CO emissions be no higher than 4.0 g/hp-hr = 540 ppmvd @ 15% O2. 

New Source Review 

As stated previously, because all areas are designated as attainment, only PSD regulations are 

potentially applicable. There is no heat recovery proposed from the turbines at the compressor 

station and therefore the 250 TPY permitting threshold would apply. Estimated emissions from 

the compressor station would be well below this threshold. The only emissions from the Pacific 

Connector pipeline would be fugitive emissions, which are specifically exempted from triggering 

PSD requirements for this source type. 

Title V Operating Permit 

Estimated potential emissions of each regulated pollutant emitted from the compressor station 

are below 100 TPY, and the compressor station would not be a major source of HAP; therefore, 

the Butte Falls Compressor Station would be exempt from needing a Title V Operating Permit, 

as per OAR 340-218-0020(4)(a)(C). 

National Emissions Standards for Hazardous Air Pollutants 

Specific types of stationary sources of air pollution can be subject to NESHAPs. HAPs are 

defined in Section 112(b)(1) of the CAA and Title 40 CFR Part 63, Subpart C, and include 

formaldehyde (which is often the most prevalent HAP from internal fuel combustion sources). 

NESHAPs are identified in Title 40 CFR Parts 61 and 63, with standards in the latter Part being 

referred to as MACT standards. Many of the NESHAPs are also incorporated by reference into 

Oregon’s regulations at OAR 340-244-0220. NESHAPs exist for the following source types that 

would be included during operation of the Butte Falls Compressor Station: 

• Stationary Combustion Turbines (Title 40 CFR Part 63, Subpart YYYY); 

• Stationary Reciprocating Internal Combustion Engines (Title 40 CFR Part 63, Subpart 

ZZZZ); and 

• Industrial, Commercial, and Institutional Boilers and Process Heaters (Title 40 CFR Part 

63, Subpart DDDDD). 

However, the NESHAPs for turbines and boilers only apply if emissions sources located in a 

contiguous area and under common control represent a “major source” of HAP, i.e., if they have 

the combined potential to emit 25 TPY of HAPs or 10 TPY of any individual HAP. EPA has 

historically not interpreted pipelines alone as constituting a “contiguous area” between sources 

that they connect; therefore, the Butte Falls Compressor Station would be evaluated separately 

from the Jordan Cove LNG terminal with regard to the “major source” classification. The 

compressor station would not be a “major source” of HAP, and therefore the turbine and boiler 

NESHAPs listed above do not currently apply. The standards for internal combustion engines 

apply to nonmajor sources of HAP, but state that for new sources, compliance with the Subpart 
4.11-25 4.11 – Air Quality and Noise

JJJJ New Source Performance Standards represents compliance with the MACT requirement 

[§63.6590(c)]. 

Federal General Conformity 

The compressor station would not be located in nonattainment or maintenance areas and 

therefore general conformity requirements do not apply. As stated previously, on December 22, 

2008, EPA designated Klamath County as a PM2.5 nonattainment area. However, emissions of 

PM2.5 and PM2.5 precursors associated with pipeline construction activities in Klamath County 

(i.e., the PM2.5 emissions primarily attributable to the construction of Spread 5 as estimated in 

Table 4.11.1.3-4) are expected to be below the thresholds in 40 CFR 93, Subpart B which would 

trigger the need for a general conformity demonstration. 

State Air Quality Requirements 

In addition to the rules identified above, ODEQ has state-specific air quality requirements. 

Those that would be directly applicable to the Project, and those that have the appearance of 

being potentially applicable, are discussed below. 

Oregon Construction Permit

Oregon requires that facilities subject to NSPS regulations with emissions greater than 10 TPY 

obtain a Standard ACDP in accordance with OAR 340-216 prior to construction. As part of this 

permit, PSELs are required to be obtained for all regulated pollutants, as per OAR 340-222-

0020, and an air quality impact analysis must be conducted in accordance with OAR 340-216. 

Pacific Connector has stated that annual emissions from the Butte Falls Compressor Station 

would be restricted below Oregon’s SERs (identified in table 4.11.1.2-1); therefore, the facility 

would be assigned generic PSELs and would not be required to analyze air quality impacts. 

Pacific Connector has prepared an ACDP application, but ODEQ has requested that the 

application be submitted 6 to 12 months prior to the expected construction date in spring 2011 

(Kemmerer and Peterson 2007). 

General Emission Standards 

Under OAR 340-226, sources that are not already subject to NSPS requirements (as identified 

above) or other new source standard and have the potential to emit at least 1 TPY of any criteria 

pollutant must meet requirements for TACT. TACT would therefore apply to the Butte Falls 

Compressor Station’s boiler. 

Visible Emission and Nuisance Requirements 

State visible emissions and nuisance abatement regulations are codified in OAR 340-208. Both 

construction and operation phases of the proposed Pacific Connector pipeline would be subject 

to visible emission limits stated in terms of opacity. During operation the Butte Falls 

Compressor Station may not emit contaminants causing opacity to equal or exceed 20 percent in 

any period or periods aggregating more than 3 minutes in any hour. In addition, no person may 

create an observable deposition of particulate matter on another person’s property (OAR 340-

208-540). 
4.11-26 4.11 – Air Quality and Noise

Air Quality Impacts and Mitigation 

Emissions associated with construction of the Pacific Connector pipeline would be temporary, 

occurring only during the period of construction. Emissions would include (a) exhaust and 

evaporative emissions from construction equipment and other equipment and motor vehicles 

associated with construction work vehicles), and (b) airborne dust associated with excavation 

and vehicle travel (fugitive dust). 

Construction of the Butte Falls Compressor Station is projected to last approximately 9 months; 

exhaust and fugitive emissions from equipment associated with its construction are summarized 

in tables 4.11.1.3-2 and 4.11.1.3-3. Pipeline construction would be conducted during daytime 

hours, and would typically be for 60 hours per week. The exact hours per day and days per week 

would be established after the construction contractors are hired prior to the construction start 

date. Emissions associated with pipeline construction (not including slash handling, which is 

described later in this section) are shown in tables 4.11.1.3-4 and 4.11.1.3-5. 

TABLE 4.11.1.3-2 

Compressor Station Construction - Exhaust and Fugitive Emissions of Criteria Pollutants and HAP

PM10 PM2.5 SO2 NOx CO VOC Aldehydes 

Source tpy tpy tpy tpy tpy tpy tpy 

Fugitive Dust - Unpaved Roadway Travel 4.67 0.47 - - - - - 

Fugitive Dust - Earthwork 2.04 2.04 - - - - - 

Exhaust from Construction Equipment 0.71 0.71 0.66 10.06 3.55 0.85 0.15 

Total 7.42 3.22 0.66 10.06 3.55 0.85 0.15 

TABLE 4.11.1.3-3 

Compressor Station Construction - Exhaust Emissions of Greenhouse Gases

CO2 CH4 N2O 

Total CO2

Equivalents 

Source metric tons/yr metric tons/yr metric tons/yr metric tons/yr 

Exhaust from Construction Equipment 340 0.02 0.01 343 

TABLE 4.11.1.3-4 

Pipeline Construction - Exhaust and Fugitive Emissions of Criteria Pollutants and HAP

PM10 PM2.5 SO2 NOx CO VOC Aldehydes 

Source tons tons tons tons tons tons tons 

Fugitive Dust – Roadway Travel – Timber Removal 30.92 3.22 - - - - - 

Fugitive Dust – Roadway Travel – Construction 123.45 12.55 - - - - - 

Fugitive Dust – Materials Handling 146.32 146.32 - - - - - 

Exhaust from Timber Removal 1.6 1.6 0.2 2.0 15.5 2.7 negligible 

Exhaust from Construction Equipment – Spread 1 6.84 6.64 0.30 91.12 36.85 12.01 5.23 

Exhaust from Construction Equipment – Spread 2 6.24 6.05 0.22 83.13 33.28 9.53 4.79 

Exhaust from Construction Equipment – Spread 3 4.53 4.40 0.22 60.78 24.73 8.29 3.47 

Exhaust from Construction Equipment – Spread 4 4.07 3.96 0.20 53.68 22.62 7.69 3.05 

Exhaust from Construction Equipment – Spread 5 3.77 3.66 0.22 49.97 20.82 8.00 2.84 

Total 328 188 1.4 341 154 48 19 
4.11-27 4.11 – Air Quality and Noise

TABLE 4.11.1.3-5 

Pipeline Construction - Emissions of Greenhouse Gases

CO2 CH4 N2O 

Total CO2

Equivalents 

Source metric tons metric tons metric tons metric tons 

Exhaust from Timber Removal 1,682 0.10 0.04 1,698 

Exhaust from Construction Equipment – 

Spread 1 11,742 0.68 0.30 11,851 

Exhaust from Construction Equipment – 

Spread 2 10,761 0.62 0.28 10,861 

Exhaust from Construction Equipment – 

Spread 3 7,794 0.45 0.20 7,866 

Exhaust from Construction Equipment – 

Spread 4 6,837 0.40 0.18 6,900 

Exhaust from Construction Equipment – 

Spread 5 6,364 0.37 0.17 6,423 

Total 45,180 2.6 1.2 45,599 

Fugitive dust emissions may be an issue during the summer construction periods in some areas 

of the proposed pipeline alignment. However, fugitive dust emissions from construction of the 

compressor station would not be expected to impact the Medford PM10 maintenance area, as 

construction activities would be approximately 12 miles northeast of the maintenance area. 

Pacific Connector has stated it may utilize either a synthetic product such as Dustlock® or water 

to minimize potential impacts from fugitive dust where necessary. Aprons would be used where 

necessary at construction ingress/egress locations on paved roads to control the track-out of mud 

from construction vehicles. Additionally, at the end of each construction day where mud may 

get tracked onto paved roads, the contractor would be required to remove any remaining mud 

from the paved road. 

Dustlock® is a naturally occurring by-product of the vegetable oil refining process. Dustlock® 

penetrates into the bed of the material and bonds to make a barrier that is naturally 

biodegradable, ensuring that the surrounding ground and water are not contaminated, and 

minimizing any potential effects to fish and wildlife. There are no known health risks by the use 

of Dustlock® to fish and wildlife resources. 

Pacific Connector’s primary method of handling slash on the right-of-way during pipeline 

construction and right-of-way clean-up would be to stockpile and redistribute the material on the 

right-of-way. However, in some locations Pacific Connector would also dispose of woody 

debris by open burn. Any slash burned on-site would be done according to standards and 

guidelines set forth by federal, state, and local regulations, including OAR 340 Division 264, 

OAR 603 Division 77, and OAR 837 Division 110. Pacific Connector would develop a 

prescribed burning plan and submit to the appropriate agencies for the necessary burning 

permits. The locations where burning would be conducted, and the amount of burning required, 

would not be determined until during construction. However, typical emissions per 1,000 tons of 

wood slash material burned are shown in tables 4.11.1.3-6 and 4.11.1.3-7. 
4.11-28 4.11 – Air Quality and Noise

TABLE 4.11.1.3-6 

Criteria Pollutant and HAP Emissions from Open Burning of Slash a/

Source 

PM10 tons/1000 

tons slash 

SO2 tons/1000 

tons slash 

NOx tons/1000 

tons slash 

CO tons/1000 

tons slash 

VOC tons/1000 

tons slash 

Total HAP 

tons/1000 tons 

slash 

Slash Burning 10.3 negligible 4.0 111 6.4 6.4 

a/ Based on EPA AP-42 emission factors for broadcast logging slash; HAP emissions conservatively estimated to be the same 

as VOC emissions. 

TABLE 4.11.1.3-7 

Greenhouse Gas Emissions from Open Burning of Slash

CO2 CH4 N2O Total CO2 Equivalents 

Source 

(metric tons/1000 tons 

slash) 

(metric tons/1000 

tons slash) 

(metric tons/1000 tons 

slash) 

(metric tons/1000 tons 

slash) 

Slash Burning 1,544 5.04 0.21 1,714 

Potential emissions from operation of the Butte Falls Compressor Station (not including fugitive 

emissions) are compared to Oregon SELs in table 4.11.1.3-8, and greenhouse gas emissions 

associated with combustion are shown in table 4.11.1.3-9. Pacific Connector would request 

Generic Annual PSELs for the Standard ACDP to ensure that SERs are not exceeded, and 

therefore modeling of cumulative ambient air impacts would not be required by ODEQ. 

Fugitive leaks can be highly variable, but greenhouse gas emissions from these leaks have been 

calculated in table 4.11.1.3-10 based on emission factors developed by the INGAA. These 

factors are based on an assumed natural gas composition that is approximately 88 percent 

methane and 3 percent VOC by weight. 

TABLE 4.11.1.3-8 

Compressor Station Operation - Potential to Emit for Exhaust Criteria Pollutants and HAPs

PM10 SO2 NOx CO VOC Indiv. HAP Total HAP 

Source tpy Tpy tpy tpy tpy tpy tpy 

Turbines (2) 5.40 27.70 43.72 a/ 44.42 25.40 2.36 2.50 

Boiler (1) 0.08 0.65 1.08 0.91 0.06 8.1E-04 0.02 

Generator (1) 0.02 0.06 2.17 3.56 0.03 0.02 0.03 

Total 5.50 28.41 <40 a/ 48.89 25.49 2.38 2.55 

Oregon SERs 15 40 40 100 40 - - 

a/ Turbine emissions shown are conservatively based on maximum operation at an ambient temperature of 0 °F year-round. 

Pacific Connector has committed to maintain NOx emissions below the SER of 40 TPY. 
4.11-29 4.11 – Air Quality and Noise

TABLE 4.11.1.3-9 

Compressor Station Operation - Potential to Emit for Exhaust Greenhouse Gases

CO2 CH4 N2O CO2 Equivalents 

Source tons/yr tons/yr tons/yr tons/yr 

Turbines (2) 86,764 23.1 6.2 89,176 

Boiler (1) 1,165 0.02 0.02 1,172 

Generator (1) 101 0.19 0.00 106 

Total 88,030 23.31 6.22 90,454 

TABLE 4.11.1.3-10 

Compressor Station Operation - Potential to Emit for Fugitive VOC and Greenhouse Gases

VOC CO2 CH4 N2O CO2 Equivalents 

Source tons/yr tons/yr tons/yr tons/yr tons/yr 

Blowdown/Venting 4 0 102 0 2,133 

Fugitives 21 33 572 0 12,007 

Total 25 33 674 0 14,140 

Operating emissions from the proposed Pacific Connector pipeline would be expected to be 

limited to fugitive dust generated by an occasional maintenance vehicle driving on pipeline 

access roads, and fugitive leaks. Fugitive leaks for pipelines are highly variable, but VOC and 

greenhouse gas emissions from these leaks have been calculated in table 4.11.1.3-11 based on 

emission factors developed by INGAA. 

TABLE 4.11.1.3-11 

Pipeline Operation - Potential to Emit for Fugitive VOC and Greenhouse Gases

VOC CO2 CH4 N2O 

CO2

Equivalents 

Source tons/yr tons/yr tons/yr tons/yr tons/yr 

Blowdown 7 0 181 0 3,791 

Fugitives 0.09 0.95 2.4 0 52 

Total 7 0.95 183 0 3,843 

It is recognized that greenhouse gases (i.e., CO2) are also emitted from the combustion of the 

delivered natural gas by end users served by the pipeline. However, these emissions should not 

be associated with this Project, because fuel supply is generally demand-driven rather than 

supply-driven. Regardless of whether the JCE & PCGP Project is constructed, those end users 

still have a need for fuel, and would need to either rely on the importation of natural gas from 

another source or on a fuel such as propane or oil, which generates even more greenhouse gas 

emissions (per unit of energy supplied) than natural gas. 

4.11.1.4 Environmental Consequences on Federal Lands 

As mentioned above, the nearest federal PSD Class I areas are at least 110 km away and impacts 

at these locations are minimal. Air pollution regulations treat other (Class II) federal lands in the 

same manner as non-federal Class II lands. The nearest federal lands include the Oregon Dunes 

NRA immediately north of Coos Bay, COE and BLM land on the North Spit, and various BLM 
4.11-30 4.11 – Air Quality and Noise

and NFS lands where the pipeline would be located. Impacts at these locations would be less 

than the maximum Class II impacts identified above. 

4.11.1.5 Climate Change and Greenhouse Gas Emissions 

Climate change is defined by the Intergovernmental Panel on Climate Change (IPCC) as 

“...a change in the state of the climate that can be identified (e.g., by using 

statistical tests) by changes in the mean and/or the variability of its properties, and 

that persists for an extended period, typically decades or longer. Climate change 

may be due to natural internal processes or external forcings, or to persistent 

anthropogenic changes in the composition of the atmosphere or in land use.” 

(IPCC 2007, p. 943). 

IPCC’s Fourth Assessment Report also concluded that 

“Most of the observed increase in global average temperatures since the mid-20th century 

is very likely [> 90%] due to the observed increase in anthropogenic greenhouse gas 

concentrations. This is an advance since the [Third Assessment Report]’s conclusion that 

‘most of the observed warming over the last 50 years is likely [> 66%] to have been due 

to the increase in greenhouse gas concentrations’. Discernable human influences now 

extend to other aspects of climate, including ocean warming, continental-average 

temperatures, temperature extremes and wind patterns;” (IPCC 2007, p. 10) 

We received several comments regarding the emissions of GHGs from the Project. The principal 

GHGs are methane, CO2, nitrous oxide (N2O), and various fluorinated gases which trap heat in 

the atmosphere and are the primary drivers of the increase in global mean temperature, known as 

global warming. No fluorinated gases would be emitted by the project, so we need only look at 

N2O, methane and CO2. There are no federal regulations at this time limiting the emissions of 

CO2. Methane emissions are limited by valve and pipe leak standards. 

The combined impacts of emissions of different GHGs are typically expressed by weighting 

emissions of each GHG by a global warming potential (GWP). By convention, the combined 

emissions are expressed as CO2 equivalents, meaning that by definition, CO2 has a GWP of 1 and 

GWPs for other gases identify the relative warming potentials of those gases relative to CO2. 

GWPs are dependent on the time horizon (e.g., 20 years, 100 years, or 500 years) and best 

estimates are also continually being updated. However, by international convention, the 100-

year horizon GWPs from the IPCC’s Second Assessment Report (SAR) are used to maintain 

consistency. As shown in IPCC’s Fourth Assessment Report (IPCC 2007), the Second 

Assessment Report (SAR) 100-year GWPs differ relatively little from the best guesses at 100-

year GWPs identified in the Fourth Assessment Report (IPCC 2007); SAR 100-year GWPs for 

methane and N2O are 21 and 310, respectively. These same GWPs are used by the California 

Climate Action Registry, the Chicago Climate Exchange, EPA’s Climate Leaders program, The 

Climate Registry, and the Western Climate Initiative. Jordan Cove has estimated the emissions 

of CO2 and some of the methane and N2O from the project; overall, the total emissions 

(expressed in CO2 equivalents) are dominated by CO2 alone. 

Based on the emissions identified in sections 4.11.1.2 through 4.11.1.4, construction of the 

terminal, compressor station, and pipeline would emit approximately 70,000 tons of CO2 during 
4.11-31 4.11 – Air Quality and Noise

the entire construction period and that annual operations would emit an estimated 630,000 tons 

of CO2. Although the GHG emissions appear large, the operational emissions are less than 

1/100th of 1 percent of the 2006 U.S. Greenhouse Gas Inventory (EPA 2008) of 7.8 billion tons. 

As further described in Section 4.11.1.2 under Energy Facility Siting Requirements, Jordan Cove 

has committed to offset 17 percent of CO2 emissions produced by the terminal’s operation. 

On May 9, 2008, ODE filed an LNG and Natural Gas Review (ODE 2008b), as an attachment to 

a letter from the Governor of Oregon. The report included a literature review, summary and 

comparison of life-cycle assessments of LNG-based natural gas, domestic natural gas, synthetic 

gas (syngas), and coal. A life-cycle assessment looks at all the CO2 emitted during the entire 

“life” of the fuels, from extraction, transportation, processing, and end use. It should be noted 

that this is very different from the approach the EPA takes in regard to regulation of criteria 

pollutants, which typically regulate emissions at the point of release. There have been numerous 

pieces of draft legislation introduced in the United States Senate and House of Representatives 

that propose in some fashion to regulate the emission of GHG. Some of these draft bills would 

impose upon importers of fuels some sort of GHG reporting, while others do not and would 

leave it to the discretion of the EPA. There are two primary regulatory frameworks that have 

been proposed in the draft legislation. One regulatory framework would be a “cap and trade” 

system, which would cap the overall emissions while developing a market to buy and sell 

emission allotments of CO2. The second approach would impose a carbon tax on fuels, thus 

penalizing use of the most carbon intensive fuels. This summary is not intended to be a 

comprehensive list of proposals, merely a brief description of the two primary methods to 

regulate CO2. Should the United States government decide to regulate the emission of CO2 and 

other GHG, it is not known at this time how the legislation and implementing regulations would 

be crafted. 

Intrinsic in the ODE’s analysis is that carbon capture and storage (CCS) would be a viable 

technology. CCS involves removing a portion of the CO2 from combustion emissions and 

injecting it into geologic formations so that it does not enter the atmosphere. To this point, only 

limited trials have been attempted for capturing carbon. Carbon sequestering is not economically 

or technologically feasible at this time; although it has been used in the production of syngas. 

The ODE admits that “it is difficult to assess when CCS will become a commercial technology.” 

The ODE determined that for electric generation, the life-cycle emissions of CO2 for LNG is 

approximately the same as for syngas with upstream carbon sequestration, is significantly less 

than coal, and is greater than domestic sources of natural gas. It should be noted that without the 

CCS in the syngas creation process, the emissions of CO2 from the life cycle of syngas are 

significantly greater than LNG-sourced natural gas. In general we do not dispute the ODE’s 

contention that domestically produced natural gas would have lower life-cycle emissions of CO2 

than LNG-sourced natural gas. However, natural gas from LNG would only produce between 6 

to 12 percent more GHG than domestic natural gas transported by interstate pipelines if both 

were combusted in conventional electric power plants. The ODE added the GHG associated 

with fuels used to liquefy the natural gas into LNG, ship it long distances in LNG carriers, and 

vaporize it back into natural gas at the import terminal as part of its equation for determining the 

life-cycle emissions for LNG. 

The ODE contends that the importation and vaporization of LNG would hinder Oregon’s effort 

to meet 1990 levels of GHG by 2020. This determination relies upon a number of assumptions, 
4.11-32 4.11 – Air Quality and Noise

including: that the LNG facility must also include CO2 emissions from the transportation of the 

LNG (and possibly extraction and processing); that the natural gas would be used primarily in 

Oregon; and that the natural gas would not displace more carbon intensive fuels such as coal and 

fuel oil. Without federal regulatory guidance, it is difficult for us to postulate what might be 

required by future GHG rules. While it is certainly possible that the LNG facility may delay 

meeting Oregon’s GHG 2020 target, it is also possible that under systems such as a cap and trade 

or a carbon tax regulatory framework that it may accelerate Oregon’s ability to meet its GHG 

goals by 2020. 

4.11.2 Noise 

Noise would affect the local environment during both the construction and operation of the 

proposed JCE & PCGP Project. At any location, both the magnitude and frequency of 

environmental noise may vary considerably over the course of the day and throughout the week. 

For construction activities, this variation in noise levels is caused primarily by changes in 

equipment operations and activity locations. For operational noise conditions, this variation is 

caused in part by variations in operational activities and in part by changing weather conditions 

and the effects of seasonal vegetative cover. Two measures commonly used by federal agencies 

to relate the time-varying quality of environmental noise to its known effect on people are the 

24-hour equivalent sound level (Leq(24)) and the day-night sound level (Ldn). The Leq(24) is the 

level of steady sound with the same total (equivalent) energy as the time-varying sound of 

interest, averaged over a 24-hour period. The Ldn is the Leq(24) with 10 decibels on the Aweighted scale (dBA) added to the nighttime sound levels between the hours of 10 p.m. and 7 

a.m., to account for the greater sensitivity of people to sound during the nighttime hours. 

4.11.2.1 Federal Noise Criteria 

In 1974, the EPA published Information on Levels of Environmental Noise Requisite to Protect 

Public Health and Welfare with an Adequate Margin of Safety (EPA 1974). This publication 

evaluates the effects of environmental noise with respect to health and safety. The document 

provides information for state and local governments to use in developing their own ambient 

noise standards. The EPA has determined that in order to protect the public from activity 

interference and annoyance outdoors in residential areas, noise levels should not exceed an Ldn of 

55 dBA. The FERC has adopted this criterion for new compression and associated pipeline 

facilities, and it is used here to evaluate the potential noise impact from operation of the Jordan 

Cove LNG Terminal. An Ldn of 55 dBA is equivalent to a continuous noise level of 48.6 dBA 

for facilities that operate at a constant level of noise. 

4.11.2.2 State Noise Standards 

The State of Oregon has established statewide noise limits for industrial and commercial noise 

sources (OAR, Chapter 340, Division 35). The specified noise limits apply to either the property 

line location closest to the noise source or to locations 25 feet toward the noise source from the 

noise-sensitive building, whichever distance from the noise source is greater. Noise-sensitive 

property includes residences and other facilities normally used for sleeping, schools, churches, 

hospitals, and public libraries. The primary noise limits set by the Oregon regulations are based 

on the statistical distribution of varying noise levels during daytime and nighttime hours. Noise 

limits are specified in terms of three percentile levels: L50, the noise level exceeded 50 percent 

of the time; L10, the noise level exceeded 10 percent of the time, and L01, the noise level 
4.11-33 4.11 – Air Quality and Noise

exceeded 1 percent of the time. In addition to noise limits for noise-sensitive properties, Oregon 

noise regulations establish additional noise limits for industrial and commercial noise sources in 

or near designated quiet areas. Quiet areas are defined as land or facilities where the qualities of 

serenity, tranquility, and quiet are of extraordinary importance and serve a public need. The 

State of Oregon has not designated any quiet areas, but some local noise ordinances have done so 

(Beyer, pers. com., 2007). Noise limits established by the Oregon noise control regulations are 

summarized in table 4.11.2.2-1. OAR Chapter 340, Division 13 establishes a separate noise limit 

for sources located in federal wilderness areas: 50 dBA at a distance of 50 feet from the noise 

source unless a permit is issued allowing noise levels of up to 75 dBA at a distance of 50 feet 

from the noise source. 

In addition to the overall dBA limits summarized in table 4.11.2.2-1, the Oregon noise 

regulations establish additional limits for discrete tones from industrial and commercial noise 

sources. These octave band noise limits are summarized in table 4.11.2.2-2. 

TABLE 4.11.2.2-1. 

Oregon Noise Limits For Industrial and Commercial Noise Sources

Noise-Sensitive Properties Located Outside 

Designated Quiet Areas 

Within Designated Quiet Areas at a Point 400 

Feet or More From the Noise Source 

Percentile Noise 

Level In Any One 

Hour 7 a.m. – 10 p.m. 10 p.m. – 7 a.m. 7 a.m. – 10 p.m. 10 p.m. – 7 a.m. 

L50 55 dBA 50 dBA 50 dBA 45 dBA 

L10 60 dBA 55 dBA 55 dBA 50 dBA 

L01 75 dBA 60 dBA 60 dBA 55 dBA 

Notes: The noise limits in this table do not apply to noise from construction sites, agricultural or forestry operations, vehicle traffic, 

rail traffic, aircraft operations, and various other exempt sources. 

Source: OAR, Sections 340-035-0035(1)(a), 340-035-0035(1)(b), and 340-035-0035(1)(c). 

TABLE 4.11.2.2-2 

Octave Band Noise Limits For Industrial and Commercial Noise Sources

Center Frequency of Octave Band Median Sound Pressure Level Limit 

(Hertz) 7 a.m. – 10 p.m. 10 p.m. – 7 a.m. 

31.5 Hz 68 dB 65 dB 

63 Hz 65 dB 62 dB 

125 Hz 61 dB 56 dB 

250 Hz 55 dB 50 dB 

500Hz 52 dB 46 dB 

1,000 Hz 49 dB 43 dB 

2,000 Hz 46 dB 40 dB 

4,000 Hz 43 dB 37 dB 

8,000 Hz 40 dB 34 dB 

Notes: The noise limits in this table do not apply to noise from construction sites, agricultural or forestry operations, vehicle traffic, 

rail traffic, aircraft operations, and various other exempt sources. 

The noise limits in this table apply to either the property line location closest to the noise source or to locations 25 feet towards the 

noise source from the noise-sensitive building, whichever distance from the noise source is greater. 

If noise levels for any 1/3 octave band exceeds the encompassing octave band limit by more than 10 dB, additional limitations may 

apply. 

Source: OAR, Section 340-035-0035(1)(f). 

Oregon noise regulations also establish a numerical noise level increase standard for new 

industrial or commercial noise sources located on a previously unused site. The regulations limit 

the increase in hourly L10 and L50 noise levels as measured at noise-sensitive properties to 10 

dBA above the ambient background L10 and L50 noise levels (OAR, Section 340-035-
4.11-34 4.11 – Air Quality and Noise

0035(1)(b)(B)(i)). The 10 dBA operational noise increment standard does not apply to noise 

from construction activities, agricultural or forestry operations, vehicle traffic, rail traffic, aircraft 

operations, or various other exempt sources. 

Oregon regulations also establish additional noise limits for blasting and impulsive noise sources 

associated with industrial and commercial operations. Noise limits for blasting operations are 

based on C-weighted decibel measurements in the slow response setting while the noise limits 

for other impulse sounds is based on unweighted decibel measurements in the peak response 

setting. The noise limits for blasting operations are 98 dBC for 7 a.m. to 10 p.m., and 93 dBC 

for 10 p.m. to 7 a.m. as measured at noise sensitive properties (OAR, Section 340-035-

0035(1)(d)(A)). The noise limits for other impulse sound from industrial and commercial 

operations are 100 dB (peak) for 7 a.m. to 10 p.m., and 80 dB(peak) for 10 p.m. to 7 a.m. as 

measured at noise sensitive properties (OAR, Section 340-035-0035(1)(d)(B)). The blasting and 

impulse sound limits do not apply to construction sites, agricultural operations, forestry 

operations, or various other exempt sources. Even though these noise limits do not apply in a 

regulatory context to construction activities, they provide additional criteria for judging blasting 

or impulse noise (such as pile driving) associated with construction activities. 

4.11.2.3 Local Noise Standards 

The City of North Bend has a noise ordinance that prohibits the making of “unnecessary noise,” 

but the ordinance does not establish specific numerical noise limits (North Bend City Code, 

Section 9.04.030). Daytime construction activity between the hours of 7 a.m. and 6 p.m. is 

exempt from the City of North Bend noise ordinance. The counties of Coos, Douglas, Jackson, 

and Klamath, Oregon do not have local noise ordinances. 

4.11.2.4 Noise Levels 

LNG Terminal 

The major existing noise sources in the vicinity of the proposed LNG terminal include vehicle 

traffic on the Trans-Pacific Parkway and US Highway 101, recreational vehicle use in the 

Oregon Dunes National Recreation Area, and boat traffic on Coos Bay. Aircraft operations from 

North Bend Municipal Airport are an additional intermittent noise source. Wind, birds, and 

insects contribute to natural background noise levels. There are no noise-sensitive areas (NSAs) 

within 1 mile of the proposed LNG terminal site. The nearest NSAs are single-family homes in 

the City of North Bend along the south side of Coos Bay about 1.4 miles south of the center of 

the proposed LNG terminal site (figure 4.11-1). The nearest NSAs to the east of the proposed 

terminal site are single-family homes on Russell Point, east of US Highway 101 and about 2.3 

miles from the center of the proposed terminal. 

Jordan Cove monitored the ambient noise levels at the two nearest NSA areas over a 24-hour 

period in 2005. Table 4.11.2.4-1 summarizes the data collected at the south and east NSAs. No 

precipitation occurred during the noise monitoring study, and temperatures ranged from 55 to 64 

degrees F. Skies were clear during the day, with heavy fog forming at night. Winds were 

generally light, ranging from calm to about 8 mph from the northwest. Hourly average noise 

levels at NSA1 ranged from 35.1 dBA to 53.8 dBA, with an overall Ldn value of 53.7 dBA. 

NSA1 was at the corner of Colorado Avenue and Arthur Street. Prominent noise sources at this 

location included infrequent local traffic during the day and the sound of ocean surf at night. 
4.11-35

Figure 4.11-1. Noise Sensitive Areas in the Vicinity of the Proposed LNG Terminal Site 
4.11-36 4.11 – Air Quality and Noise 

TABLE 4.11.2.4-1 

Ambient Noise Levels for the Proposed LNG Terminal Measured at Nearby NSAs

Date Start of Hour Hourly Leq at NSA1, 1.4 miles south (dBA) Hourly Leq at NSA2, 2.3 miles east (dBA) 

Aug. 31, 2005 17:00 49.7 63.8 

 18:00 53.8 61.3 

 19:00 53.4 61.8 

 20:00 52.5 60.4 

 21:00 44.1 57.9 

 22:00 41.6 56.0 

 23:00 41.5 56.9 

Sept. 01, 2005 00:00 39.7 53.1 

 01:00 37.6 48.7 

 02:00 36.1 48.9 

 03:00 35.1 55.3 

 04:00 43.4 59.1 

 05:00 49.5 61.3 

 06:00 53.7 60.9 

 07:00 48.4 64.1 

 08:00 46.8 65.5 

 09:00 45.6 66.4 

 10:00 46.6 64.4 

 11:00 48.0 64.7 

 12:00 51.2 65.2 

 13:00 50.8 66.3 

 14:00 52.2 65.0 

 15:00 51.9 65.0 

 16:00 50.2 64.6 

 Leq(24) 49.4 62.7 

 Ldn 53.7 65.7 

Hourly average noise levels at NSA2 on Russell Point ranged from 48.7 dBA to 66.4 dBA, with 

an overall Ldn of 65.7 dBA. NSA2 was on East Bay Street about 200 feet east of US Highway 

101. Noise levels at this location were dominated by traffic on Highway 101. Noise levels on 

Russell Point at greater distances from Highway 101 would be expected to be somewhat lower. 

Figure 4.11-1 illustrates the locations where noise monitoring was conducted. 

Construction of the LNG terminal would occur over a period of about 3 years. Major 

components would include berth facilities, buildings, LNG storage tanks, and 

mechanical/electrical equipment. Site preparation, berth facility excavation and dredging, and 

preparation of building and tank foundations would occur during the first year of construction. 

Erection of buildings, storage tanks, and installation of mechanical and electrical equipment 

would occur over the remainder of the construction period. Heavy equipment operations would 

generally be limited to daytime periods. Noise from construction activity would vary throughout 

the construction period, but generally would be greater during the first year of construction 

activity. The large distances between the proposed LNG terminal site and the nearest residential 

areas would result in noise impacts from construction activities being well below the background 

ambient noise levels at these locations. Noise from heavy equipment operations would generally 

be reduced to 33 dBA or less at NSA1, and to less than 30 dBA at NSA2. Figure 4.11-2 

illustrates typical noise impacts associated with construction of the LNG terminal. Construction 

of berth facilities would require pile-driving operations. The Port would limit pile driving to 

daytime periods, five days per week over a period of approximately 32 weeks. Pile 
4.11-37

Figure 4.11-2. Estimated Noise Levels From General Construction Activities at the LNG Terminal Sit
Jordan Cove Energy and 

Pacific Connector Gas Pipeline Project 4.11 – Air Quality and Noise 

4.11-38

Figure 4.11-3. Estimated Noise Levels From Pile Driving at the Berth Area 

Figure 4.11-3. 

Estimated Noise Levels From Pile Driving at the Proposed Berth Area 
4.11-39 4.11 – Air Quality and Noise 

driving would be expected to generate peak noise levels of about 48 dBA at NSA1, with 

somewhat lower noise levels at NSA2. These noise levels would be below the 55 dBA threshold 

established by the EPA and FERC to avoid disruption or annoyance of outside activities in 

residential areas. Figure 4.11-3 illustrates noise levels from pile driving during construction of 

the berth facilities. Dredging and pile-driving operations during construction of berth facilities 

would not be expected to generate underwater noise levels in Coos Bay because the berth area 

would be separated from the Coos Bay ship channel by an earthen berm until the access channel 

to the berth area is dredged at the end of the berth construction period. 

Operational noise impacts from the proposed LNG terminal were estimated by use of the 

CadnaA noise model. This noise model takes into account the noise generation of individual 

equipment items, shielding by buildings and barriers, spreading losses, ground and atmospheric 

effects, and reflections from surfaces. Predicted operational noise increments from the LNG 

terminal would be an Ldn of 45.4 dBA at NSA1 and an Ldn of 30.1 dBA at NSA2. The predicted 

noise impact from operation of the LNG terminal is summarized in table 4.11.2.4-2. 

Ldn values include a 10 dBA penalty factor for nighttime noise; thus, the actual average dBA 

level attributable to operation of the proposed LNG facility would be about 39 dBA at NSA1 and 

about 24 dBA at NSA2. The predicted increases in overall noise levels at the nearest NSAs 

would be well below the 55 dBA threshold established by the EPA and FERC to avoid disruption 

or annoyance of outside activities in residential areas. Predicted Ldn levels at NSA1 would 

remain below 55 dBA, and predicted Ldn levels at NSA2 would not change from existing levels. 

Predicted operational noise levels are illustrated in figure 4.11-4. 

TABLE 4.11.2.4-2. 

Predicted Operational Noise Impacts of the LNG Terminal

NSA 

Distance and 

Direction 

Existing Ambient 

Ldn (dBA) 

Predicted Facility 

Ldn Contribution 

(dBA) 

Combined 

Ambient + Facility 

Ldn (dBA) 

Ldn Increase Above 

Existing Ambient Ldn

(dBA) 

NSA 1 1.4 miles south 53.7 45.4 54.3 0.7 

NSA 2 2.3 miles east 65.7 30.1 65.7 0.0 

LNG Carrier Transit Route 

During operation of the proposed LNG terminal, noise would also be generated by the LNG 

carriers transiting the Coos Bay navigation channel. An estimated 80 ships per year would call 

on the proposed LNG terminal. Noise generated from the LNG carriers would be similar to 

noise generated from large vessels that currently traverse the ship channel. The Coast Guard 

would likely impose a moving safety zone around LNG carriers, meaning that only one large 

ship would be traversing any one location along the channel at any point in time. Current ship 

traffic at the Port of Coos Bay is about 50 ship calls per year. The increase in the annual number 

of ship calls with the proposed Jordan Cove terminal would result in total port vessel traffic of 

less than one ship movement per day. Noise levels during ship movements are estimated to be 

about 63 dBA at a distance of 300 feet during each passby event. The increased ship traffic 

would not be expected to create a measurable change in overall noise levels along the Coos Bay 

navigation channel. Average underwater noise from large vessel traffic would increase by about 

4 dB due to the increase in ship movements. Total ship traffic for the Port of Coos Bay with the 

LNG terminal would be less than the historical maximum for port-related ship traffic. 
4.11-40

Figure 4.11-4. Estimated Noise Levels From LNG Terminal Operations 

Figure 4.11-4. 

Estimated Noise Levels From Proposed LNG Terminal Operations 
4.11-41 4.11 – Air Quality and Noise 

Pacific Connector Pipeline 

During construction of the proposed Pacific Connector pipeline, neighbors in the vicinity of the 

construction right-of-way would hear construction noise. Only 6 percent of the land crossed by 

the proposed pipeline (13.9 miles of pipeline corridor) is categorized as having residential, 

commercial, or industrial use. A total of 143 structures have been identified as being within 150 

feet of the pipeline right-of-way or TEWAs. Only 15 residences have been identified as being 

within 50 feet of the pipeline construction right-of-way or TEWAs. Due to the assembly-line 

nature of pipeline construction, activities in any area could occur intermittently over a period 

lasting from several weeks to a few months. 

Construction equipment would be operated on an as-needed basis. Exact noise levels cannot be 

determined; however, we can estimate noise levels as a function of the distance of the receptor 

from the equipment. Assuming the operation of a piece of equipment results in typical noise 

levels of 88 dBA at 50 feet, the noise impact of that equipment would be 82 dBA at 100 feet and 

72 dBA at 300 feet from the equipment. If two items of equipment operate concurrently in the 

same area, typical construction noise levels would be about 91 dBA at 50 feet, 85 dBA at 100 

feet, and 75 dBA at 300 feet from the equipment. Noise would diminish rapidly as the distance 

from the noise source increases. 

In addition to temporary disturbance to noise-sensitive land uses at those locations where the 

pipeline corridor passes near residences or other noise-sensitive land uses, construction noise 

would have localized and temporary disturbance impact to wildlife. The noise impact per se 

would be combined with a visual disturbance impact from human and equipment activity along 

the pipeline corridor. In general, temporary disturbance to wildlife from construction activities 

would result in some daytime wildlife movements away from the pipeline corridor. In most 

cases, the disturbance would be temporary and of limited significance to the affected animals. 

See additional discussion of potential impacts on wildlife in sections 4.5 and 4.6 of this EIS. 

Normally there would be no nighttime noise from pipeline construction. Most pipeline 

construction, except for HDD operations, would be limited to daytime hours. No operational 

noise from the buried pipeline would be detectable at aboveground locations. 

Pacific Connector proposes to use HDD technology to cross three rivers: the Coos River, the 

Rogue River, and the Klamath River. Some portions of HDD operations would occur as 12-hour 

work shifts, while other activities would normally occur as 24-hour per day operations. The 

overall duration of HDD operations is site-specific, and would be determined by the drilling 

contractor. It would not be unusual for HDD drilling operations to take 2 to 4 weeks at each site. 

Coos River HDD Site

The Coos River HDD site would require about 1,800 feet of drilling. At present, it has not been 

determined whether drilling would occur from the western or eastern end of the crossing. The 

closest existing residence to the west end of the Coos River HDD section is about 1,200 feet 

from the probable equipment location. The closest residence to the eastern end of the Coos 

River HDD section is about 400 feet from the probable equipment location. 

Maki Corporation conducted a noise survey of the proposed Coos River HDD area in February 

2007. Daytime background noise levels at the four nearby residences ranged from 38 dBA to 
4.11 – Air Quality and Noise 4.11-42

55.9 dBA. Nighttime background noise levels at these residences ranged from 32.8 dBA to 38 

dBA. Estimated Ldn levels at these residences ranged from 40.6 dBA to 53.3 dBA 

Noise sources associated with HDD operations are assumed to include the following equipment: 

• two power units, 630 hp each; 

• two mud pump units, 630 hp each; 

• one centrifugal cleaner, 360 hp; 

• one shale shaker; and 

• one crane, 360 hp. 

If HDD operations were to occur from the west end of the HDD section, drilling operations 

would generate Ldn levels of 59.9 to 66.2 dBA at the four nearest residences. If HDD operations 

were to occur from the east end of the HDD section, drilling operations would generate Ldn

levels of 55.8 to 77 dBA at the four nearest residences. In either case, noise mitigation measures 

would be required to reduce noise impacts to an Ldn of 55 dBA and to keep nighttime noise 

levels from exceeding the state limit of 50 dBA. 

The noise study for the proposed Coos River HDD crossing (Maki Corporation 2007a) 

recommends use of one of the following mitigation measures if drilling occurs from the west 

side of the Coos River: 

• Install a 20-foot-high barrier wall around the entire HDD site (STC-35 material with 

good acoustic absorption properties (0.75 factor or higher) on the equipment side of the 

wall; bottom of wall in contact with the ground); or 

• Install a vinyl fabric acoustic tent (STC-21 or higher rating) over the entire HDD site, 

using minimum necessary openings and keeping the sidewall of the tent in contact with 

the ground. 

Table 4.11.2.4-3 summarizes predicted Ldn levels at nearby residences if HDD drilling operations 

occur on the west side of the Coos River. 

If drilling occurs from the east side of Coos River, the noise study recommends the following 

mitigation measure: 

• Install a special fabric acoustic tent (STC-30 or higher rating) over the entire HDD site, 

using minimum necessary openings and keeping the sidewall of the tent in contact with 

the ground. 

TABLE 4.11.2.4-3 

Summary of Ldn Levels, HDD Drilling from West Side of the Coos River 

Mitigation Condition NSA1 NSA2 NSA3 NSA4 

No Mitigation 63.4 59.9 66.2 64.2 

20 foot High Barrier 49.0 42.6 47.5 46.0 

Vinyl Acoustic Tent 48.6 45.7 51.0 49.3 

Table 4.11.2.4-4 summarizes predicted Ldn levels at nearby residences if HDD drilling operations 

occur on the east side of the Coos River. 
4.11-43 4.11 – Air Quality and Noise

TABLE 4.11.2.4-4 

Summary of Ldn Levels, HDD Drilling from East Side of the Coos River 

Mitigation Condition NSA1 NSA2 NSA3 NSA4 

No Mitigation 77.0 64.8 60.7 55.8 

Special Acoustic Tent 51.1 40.1 36.7 32.8 

Pacific Connector has stated that it would implement the noise mitigation measures as 

recommended in the Coos River HDD crossing noise study. We believe that with 

implementation of these measures, temporary noise impact on NSAs from pipeline construction 

would be acceptable. 

Rogue River HDD Site

The Rogue River HDD site would require about 3,000 feet of drilling. Pacific Connector has not 

determined whether drilling would occur from the western or eastern end of the crossing. The 

closest existing residence to the west end of the Rogue River HDD section is about 740 feet from 

the probable equipment location. The closest residence to the eastern end of the Rogue River 

HDD section is about 340 feet from the probable equipment location. 

Maki Corporation conducted a noise survey of the proposed Rogue River HDD area in February 

2007. Daytime background noise levels at five nearby residences ranged from 35.7 dBA to 54.1 

dBA. Nighttime rain conditions affected background noise levels at these residences. Nighttime 

background noise conditions without the effects of rain were estimated to be about 35 dBA. 

Estimated Ldn levels at these residences ranged from 41.5 dBA to 52.4 dBA. 

Noise sources associated with HDD operations are assumed to include the following equipment: 

• two power units, 630 hp each; 

• two mud pump units, 630 hp each; 

• one centrifugal cleaner, 360 hp; 

• one shale shaker; and 

• one crane, 360 hp. 

If HDD operations were to occur from the west end of HDD section, drilling operations would 

generate Ldn levels of 62.6 to 70.8 dBA at the three nearest residences. If HDD operations were 

to occur from the east end of the HDD section, drilling operations would generate Ldn levels of 

67.6 to 78.5 dBA at the four nearest residences. In either case, noise mitigation measures would 

be required to reduce noise impacts to an Ldn of 55 dBA and to keep nighttime noise levels from 

exceeding the state limit of 50 dBA. 

The noise study for the proposed Rogue River HDD crossing (Maki Corporation 2007b) 

recommends use of one of the following mitigation measures if drilling occurs from the west 

side of Rogue River: 

• Install a 20-foot high barrier wall around the entire HDD site (STC-35 material with good 

acoustic absorption properties (0.75 factor or higher) on the equipment side of the wall; 

bottom of wall in contact with the ground); or 
4.11 – Air Quality and Noise 4.11-44

• Install a vinyl fabric acoustic tent (STC-21 or higher rating) over the entire HDD site, 

using minimum necessary openings and keeping the sidewall of the tent in contact with 

the ground. 

Table 4.11.2.4-5 summarizes predicted Ldn levels at nearby residences if HDD drilling operations 

occur on the west side of the Rogue River. 

If drilling occurs from the east side of the Rogue River, the noise study recommends the 

following mitigation measure: 

• Install a special fabric acoustic tent (STC-30 or higher rating) over the entire HDD site, 

using minimum necessary openings and keeping the sidewall of the tent in contact with 

the ground. 

Table 4.11.2.4-6 summarizes predicted Ldn levels at nearby residences if HDD drilling operations 

occur on the east side of the Rogue River. 

Pacific Connector has stated that it would implement the noise mitigation measures as 

recommended in the Rogue River HDD crossing noise study. We believe that with 

implementation of these measures, temporary noise impact on NSAs from pipeline construction 

would be acceptable. 

TABLE 4.11.2.4-5 

Summary of Ldn Levels, HDD Drilling from West Side of the Rogue River 

Mitigation Condition NSA5 NSA6 NSA7 

No Mitigation 62.6 70.8 57.1 

20 foot High Barrier 41.9 48.5 38.7 

Vinyl Acoustic Tent 41.5 48.5 42.3 

TABLE 4.11.2.4-6 

Summary of Ldn Levels, HDD Drilling from East Side of the Rogue River 

Mitigation Condition NSA1 NSA2 NSA3 NSA4 

No Mitigation 77.2 67.6 72.0 78.5 

Special Acoustic Tent 51.2 42.6 46.5 52.4 

Klamath River HDD Site

The Klamath River HDD site would require about 2,500 feet of drilling. At present, it has not 

been determined whether drilling would occur from the western or eastern end of the crossing. 

The closest existing residence to the west end of the Klamath River HDD section is about 2,400 

feet from the probable equipment location. The closest residence to the eastern end of the 

Klamath River HDD section is about 300 feet from the probable equipment location. 

The Maki Corporation conducted a noise survey of the proposed Klamath River HDD area in 

February 2007. Daytime background noise levels at the three closest residences ranged from 

52.7 dBA to 62.1 dBA. Nighttime background noise levels at these residences ranged from 43.3 

dBA to 46.6 dBA. Estimated Ldn levels at these residences ranged from 52.9 dBA to 60.6 dBA 
4.11-45 4.11 – Air Quality and Noise

Noise sources associated with HDD operations are assumed to include the following equipment: 

• two power units, 630 hp each; 

• two mud pump units, 630 hp each; 

• one centrifugal cleaner, 360 hp; 

• one shale shaker; and 

• one crane, 360 hp. 

If HDD operations were to occur from the west end of HDD section, drilling operations would 

generate Ldn levels of 57 to 58.4 dBA at the three nearest residences. If HDD operations were to 

occur from the east end of the HDD section, drilling operations would generate Ldn levels of 68.3 

to 79 dBA at the three nearest residences. In either case, noise mitigation measures would be 

required to reduce noise impacts to an Ldn of 55 dBA and to keep nighttime noise levels from 

exceeding the state limit of 50 dBA. 

The noise study for the proposed Klamath River HDD crossing (Maki Corporation 2007c) 

recommends use of one of the following mitigation measures if drilling occurs from the west 

side of Klamath River: 

• Install a 20-foot high barrier wall around the entire HDD site (STC-35 material with good 

acoustic absorption properties (0.75 factor or higher) on the equipment side of the wall; 

bottom of wall in contact with the ground); or 

• Install a vinyl fabric acoustic tent (STC-21 or higher rating) over the entire HDD site, 

using minimum necessary openings and keeping the sidewall of the tent in contact with 

the ground. 

Table 4.11.2.4-7 summarizes predicted Ldn levels at nearby residences if HDD drilling operations 

occur on the west side of the Klamath River. 

TABLE 4.11.2.4-7 

Summary of Ldn Levels, HDD Drilling from West Side of the Klamath River 

Mitigation Condition NSA1 NSA2 NSA3 

No Mitigation 57.0 57.0 52.0 

20-foot High Barrier 44.8 44.8 46.2 

Vinyl Acoustic Tent 37.0 36.9 38.1 

If drilling occurs from the east side of Klamath River, the noise study recommends the following 

mitigation measure: 

• Install a special fabric acoustic tent (STC-30 or higher rating) over the entire HDD site, 

using minimum necessary openings and keeping the sidewall of the tent in contact with 

the ground. 

Table 4.11.2.4-8 summarizes predicted Ldn levels at nearby residences if HDD drilling operations 

occur on the east side of the Klamath River. 
4.11 – Air Quality and Noise 4.11-46

TABLE 4.11.2.4-8 

Summary of Ldn Levels, HDD Drilling from East Side of the Klamath River 

Mitigation Condition NSA1 NSA2 NSA3 

No Mitigation 79.0 68.3 69.5 

Special Acoustic Tent 53.0 43.2 44.2 

Pacific Connector has stated that it would implement the noise mitigation measures as 

recommended in the Klamath River HDD crossing noise study. We believe that with 

implementation of these measures, temporary noise impact on NSAs from pipeline construction 

would be acceptable. 

Butte Falls Compressor Station 

The Butte Falls Compressor Station would be located in Jackson County, Oregon, on a 7.4-acre 

parcel at about MP 132.1 on the Pacific Connector pipeline, about 1,500 feet north of Butte Falls 

Highway. The proposed compressor station site is about 6.4 miles west of Butte Falls, Oregon, 

in a rural agricultural area. Approximately 30 residences are located within 1 mile of the 

proposed compressor station site, with the closest residential dwelling (currently not occupied) 

about 1,900 feet from the center of the proposed site. Two other residences are about 2,000 feet 

from the center of the proposed compressor site. 

The proposed compressor station would include two Solar Taurus 70 turbine units driving Solar 

C452 centrifugal compressor units. The turbines and compressors would be installed inside a 

compressor building that would include inlet filter/separators, lube oil coolers, gas aftercoolers, 

inlet air cleaner/silencers, and exhaust systems. The compressor building would also include 

measurement and regulating equipment and skid-mounted flue gas conditioning equipment. 

Other buildings at the proposed compressor station site would include a control room/ancillary 

equipment building (with an air compressor system, hot water boiler, and back-up generator) and 

two unit valve skid buildings. Suction and discharge headers would be installed between the 

pipeline and the compressor units. An aboveground pig launcher/receiver would be installed in 

the northeast corner of the site where the pipeline enters the property. 

Maki Corporation conducted a noise survey of the proposed compressor station area in 

September 2006. The dominant noise sources in the area are farm animals, light traffic on Butte 

Falls Highway, and an occasional aircraft overhead. Typical background Leq noise levels with 

no traffic or aircraft contribution were 31.2 dBA during the daytime and 25.8 dBA at night. The 

equivalent day-night sound level is approximately 33.5 Ldn. 

Construction of the compressor station would take approximately 9 months. Construction 

equipment noise levels would vary during the construction period, but typically would be less 

than 50 dBA at the nearest NSAs. Construction activity would generally be limited to daytime 

hours, and would be below the 55 dBA threshold established by the EPA and FERC to avoid 

disruption or annoyance of outside activities in residential areas. 

FERC regulations require that during operation, compressor station noise increments not exceed 

an Ldn of 55 dBA (equivalent to a continuous noise level of 48.6 dBA) at the nearest NSA. 

Oregon noise regulations require that operational noise from new commercial or industrial 

facilities must not increase ambient L50 noise levels by more than 10 dBA. For a facility that 
4.11-47 4.11 – Air Quality and Noise

operates continuously at a steady level, the L50 is the same as the Leq level. Because compressor 

stations operate continuously, existing nighttime ambient Leq noise conditions would determine 

the allowable future noise levels. The nighttime ambient noise level of 25.8 dBA means that to 

comply with Oregon noise regulations, future noise levels at a point 25 feet from an existing 

residence must not exceed 35.8 dBA. The compressor station noise increment would have to be 

35.4 dBA or less to keep the combination of compressor station noise and ambient background 

Leq noise level from exceeding 35.8 dBA. 

Operational noise levels for the proposed Butte Falls Compressor Station were predicted using 

the commercial modeling program Noise. This noise model takes into account the noise 

generation of individual equipment items, shielding by buildings and barriers, spreading losses, 

ground and atmospheric effects, and reflections from surfaces. The noise modeling analysis for 

the proposed Butte Falls Compressor Station (Maki Corporation 2006) assumed the following 

noise mitigation measures for the facility: 

• The turbine exhaust systems should be equipped with special silencers that would limit 

the noise level from each stack to no more than 57 dBA at a distance of 50 feet. 

• The turbine exhaust duct located between the compressor building wall and the silencer 

should be acoustically insulated. 

• Turbine air intake systems should be equipped with special silencers that limit the noise 

levels from the intake systems to no more than 57 dBA at a distance of 50 feet. 

• The turbine lube oil coolers should have noise levels approximately equal to Solar’s 85 

dBA cooler. The noise level from each cooler should be no more than 54 dBA at a 

distance of 50 feet. 

• The gas after-coolers should be designed to have noise levels of no more than 60 dBA at 

a distance of 50 feet. 

• The compressor building should be acoustically insulated with 6 inches of 8 pounds per 

cubic foot density mineral wool insulation. The building shell should have 22 gauge 

metal outer sheeting in the walls and roof, and a 26 gauge perforated metal liner. 

• The compressor building roll-up door should have a minimum noise reduction rating of 

STC-28 through the door (this may require a double door). 

• Personnel doors should be standard insulate doors with a noise reduction rating of STC26. 

• The compressor building ventilation system openings should be acoustically designed to 

be consistent with the silencing of the rest of the station. 

• It is expected that unit piping would require acoustic insulation. 

Jordan Cove has committed to implementing all of the above recommended noise mitigation 

measures. 

Noise modeling results for predicted noise from operation of the Butte Falls Compressor Station 

at four property line locations and five nearby NSAs are summarized in table 4.11.4.2-9. 

Predicted Leq noise contours around the Butte Falls Compressor Station site are illustrated in 

figure 4.11-5. 
4.11 – Air Quality and Noise 4.11-48

TABLE 4.11.4.2-9 

Predicted Operational Noise Impacts of the Butte Falls Compressor Station 

Receptor Location Distance and Direction Predicted Leq (dBA) Predicted Ldn (dBA) 

Predicted Increase 

Over Existing Ldn

(dBA) 

Property Line Point 1 North property line 58.0 64.4 +30.9 

Property Line Point 2 East property line 48.7 55.1 +21.6 

Property Line Point 3 South property line 47.6 54.0 +20.5 

Property Line Point 4 West property line 57.7 64.1 +30.6 

NSA1 2,000 feet southeast 31.1 37.5 +5.4 

NSA2 2,200 feet south 32.5 38.9 +6.5 

NSA3 2,900 feet southwest 29.0 35.4 +4.1 

NSA4 3,300 feet northwest 27.7 34.1 +3.3 

NSA5 4,100 feet east 25.6 32.0 +2.3 

We received a comment on the draft EIS that questioned if the noise modeling analysis 

incorporated terrain effects. The analysis did not incorporate terrain effects. However, for most 

existing homes in the vicinity of the compressor station site, this is a conservative assumption. 

Most existing homes in the area are south of Butte Falls Highway to the south and southwest of 

the compressor station site, or east of the compressor station site along McNeil Creek Road. A 

hill southwest of the compressor station site would provide some terrain shielding for many of 

the homes south of Butte Falls Highway. Some of the homes along McNeil Creek Road may 

also receive a small amount of terrain shielding from hills between the homes and the 

compressor station. The ridge north of the compressor station might reflect some noise back to 

the south, but this effect should not be significant for most homes near the compressor station 

site. A more likely factor affecting noise levels in the general area would be nighttime 

temperature inversions. Noise that is originally radiated upwards can be refracted back down 

toward the ground by temperature inversion conditions, resulting in somewhat higher noise 

levels than expected at moderate distances from a noise source. 

The predicted Leq levels at the NSAs surrounding the proposed compressor station are all less 

than 35 dBA, and thus would comply with the Oregon noise regulation requirement that new 

industrial facilities not increase ambient noise levels by more than 10 dBA at noise-sensitive 

locations. The predicted Ldn levels at these NSAs are all less than 40 dBA, and thus comply with 

the FERC Ldn limit of 55 dBA. The predicted increase in noise levels over existing ambient 

noise would be clearly perceptible to the human ear at NSA1 and NSA2, barely perceptible at 

NSA3 and NSA4, and would not be perceptible at NSA5. Consequently, the proposed Butte 

Falls Compressor Station could have some noise impact on surrounding NSAs due to the very 

quiet existing ambient conditions. To ensure that actual operational noise is at or below the 

predicted noise, and that there would be no significant impact to noise quality at the nearest 

NSAs, we recommend that:

• Pacific Connector should make all reasonable efforts to ensure its predicted noise 

levels from the Butte Falls Compressor Station are not exceeded at NSAs, and file 

noise surveys showing this with the Secretary no later than 60 days after placing the 

compressor station in service. If the noise attributable to the operation of the 

compressor station exceeds an Ldn of 55 dBA at any NSA, Pacific Connector should 

file with the Secretary a report on what changes are needed and should install 
4.11-49

Figure 4.11-5. Predicted Leq Noise Contours at Butte Falls Compressor Station 

Figure 4.11-5. 

Predicted Leq Noise Contours at Butte Falls Compressor Station 
4.11-50 4.11– Air Quality and Noise 

additional noise controls within 1 year of the in-service date. Pacific Connector 

should confirm compliance with these requirements by filing a second noise survey 

with the Secretary no later than 60 days after it installs the additional noise controls. 

Other Aboveground Pipeline Facilities 

In addition to the Butte Falls Compressor Station, aboveground facilities associated with the 

proposed Pacific Connector pipeline would include four meter stations (Coos Bay, Clarks 

Branch, Tulelake, and Tuscarora), four pig launchers/receivers co-located with other 

aboveground facilities, and 16 MLVs spaced along the pipeline in accordance with DOT 

requirements. Meter stations and other aboveground facilities typically do not generate 

appreciable noise during normal operation. The source of noise at these facilities would be the 

sound of natural gas moving through underground piping, as transferred to the surface through 

valves and interconnecting piping. Noise would not be expected to be audible beyond the edge 

of the meter station sites or pipeline right of way. However, some commenters have expressed 

concern about this potential impact, especially in rural areas. Therefore, to ensure that there 

would be no significant impact to noise quality at the nearest NSAs as a result of the operation of 

metering station/interconnect, we recommend that:

• Pacific Connector should file the results of noise surveys at each meter station with 

the Secretary no later than 60 days after placing the metering stations/interconnects 

in service. If the noise attributable to the operation of any metering 

station/interconnect exceeds 55 dBA Ldn at an NSA, Pacific Connector should file 

with the Secretary a report on what changes are needed and should install 

additional noise controls to meet the level within one year of the in-service date. 

Pacific Connector should confirm compliance with these requirements by filing a 

second noise survey with the Secretary no later than 60 days after it installs the 

additional noise controls. 

4.11.2.5 Environmental Consequences on Federal Lands 

The southern boundary of the Oregon Dunes NRA is about 1.8 miles north of the proposed 

Jordan Cove LNG terminal site. As shown on the noise contour maps in figures 4.11-2, 4.11-3, 

and 4.11-4, estimated noise from LNG terminal construction and operation at the southern 

boundary of the recreation area would be well below an Ldn of 55 dBA, the noise level used by 

the EPA and FERC to protect the public from activity interference and annoyance outdoors in 

residential areas. 

During pile driving for installation of berth facilities, predicted noise levels at the BLM boat 

ramp located about 1 mile southwest of the LNG terminal site would exceed 55 dBA (figure 

4.11-3). Noise from pile driving would be noticeable to users of the BLM boat ramp during 

construction. The Port would limit pile driving to daytime periods, 5 days per week over a 

period of approximately 32 weeks. This impact would be a temporary annoyance to users of the 

boat ramp. During operation, predicted noise from operation of the LNG terminal would be 

below 55 dBA at the BLM boat ramp (figure 4.11-4), which would be below a noise level that 

would interfere or be an annoyance for users of the boat ramp. 
4.11-51 4.11 – Air Quality and Noise

During operation of the LNG terminal, BLM and COE lands near the Coos Bay navigation 

channel would receive limited noise impacts from LNG carriers arriving at and departing from 

the LNG terminal. An estimated 80 ships per year would call on the proposed LNG terminal. 

Noise levels during ship movements are estimated to be about 63 dBA at a distance of 300 feet 

during each passby event, which would be similar to noise generated from large vessels that 

currently traverse the channel. Because the Coast Guard would impose a moving safety zone 

around LNG carriers, only one large ship would be traversing any one location along the channel 

at any point in time. Current ship traffic at the Port of Coos Bay is about 50 ship calls per year. 

The increase in the annual number of ship calls with the proposed Jordan Cove terminal would 

result in total port vessel traffic of less than one ship movement per day. Noise from LNG 

carriers would not be expected to create a noticeable change in overall noise levels at BLM and 

COE lands along the Coos Bay navigation channel. 

During construction of the Pacific Connector pipeline, there would be temporary noise impacts 

on federal lands crossed by the pipeline or crossed by construction access roads. Construction 

noise could have localized and temporary effects on recreational users and wildlife within federal 

lands. Pipeline construction would proceed in a linear fashion along the right-of-way, and 

equipment would be operated on an as-needed basis; therefore, exact noise at a particular point 

cannot be determined. However, we can estimate noise levels as a function of the distance of the 

receptor from the equipment. Assuming the operation of a piece of equipment results in typical 

noise levels of 88 dBA at 50 feet, the noise impact of that equipment would be 82 dBA at 100 

feet and 72 dBA at 300 feet from the equipment. If two items of equipment operate concurrently 

in the same area, typical construction noise levels would be about 91 dBA at 50 feet, 85 dBA at 

100 feet, and 75 dBA at 300 feet from the equipment. Noise would diminish rapidly as the 

distance from the noise source increases. 

The noise impact on wildlife during pipeline construction would be combined with a visual 

disturbance impact from human and equipment activity along the construction right-of-way and 

work areas. In general, temporary disturbance to wildlife from construction activities would 

result in some daytime wildlife movements away from the pipeline right-of-way. See additional 

discussion of potential noise impacts on wildlife in sections 4.5 and 4.6 of this EIS. 

During operation of the pipeline, there would be no noise generated from the buried pipeline. 

Three aboveground MLVs would be located within BLM lands. During operation, sound is 

sometimes detectable within several feet of MLVs; however, any noise impact during operation 

of the MLVs would not be humanly perceptible beyond the operational right-of-way for the 

pipeline.