4.3 air quality - santa barbara county · 0.03 ppm, annual average 0.053 ppm annual 0.10 ppm 1 hour...

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ERG Operating Company Foxen Petroleum Pipeline Proposed Final EIR 13EIR-00000-00002 / SCH #2013061011 February 2015

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This section describes environmental and regulatory settings related to air quality in the Project

area; identifies air quality impacts of the proposed Project, its principal alternatives, and

cumulative impacts from this and other projects in the region; and recommends mitigation

measures to reduce those impacts.

Emission rates were generated using emission factors and use rates contained within the

CalEEMod modeling program (v2013.2), as applicable, as well as emission factors prescribed by

the SBCAPCD. Emission calculations are included in Appendix 4. This analysis is intended to

provide a reasonable worst-case scenario of potential air emissions resulting from the proposed

activities and recommends mitigation to reduce any significant impacts to less than significant

levels.

This section is divided into two parts: setting and impacts associated with criteria and toxic

pollutants and setting and impacts associated with greenhouse gas (GHG) emissions.

4.3.1 CRITERIA POLLUTANTS AND AIR TOXICS

This section addresses the physical setting, regulatory setting and impact assessment associated

with the emissions of criteria and toxic pollutants.

4.3.1.1 Physical Setting

For the proposed project, the environmental setting and baseline conditions reflect the emissions

associated with the existing facilities. Once these baseline risks are quantified, the significance

criteria can be used to determine if there is an increased level of air emissions associated with a

project or its alternatives, and if the proposed increase in emissions is significant.

Regional Overview

The proposed Project area is located within the South Central Coast Air Basin in northwestern

Santa Barbara County east of Santa Maria. The region has a Mediterranean climate

characterized by mild winters, and warm, dry summers. The influence of the Pacific Ocean

causes mild temperatures year-round along the coast, while inland areas experience a wider

range of temperatures. Table 4.3-1 summarizes the climatic data collected at the weather station

located closest to the Project area, which is the Santa Maria Weather Station.

Table 4.3-1 Climatic Data for the Project Area

Parameter Santa Maria Station Data

Mean Daily Temperature Range 42 – 79, oF

Range Maximum Daily Temperature 49 – 100, oF

Range Minimum Daily Temperature 29 – 62, oF

Average Annual Precipitation 14.4 inches

Peak Winds, mph 58 – 70 (gust)

Notes: T = temperature; F = degrees Fahrenheit. Source: Wunderground History for Santa Maria, 2011

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Precipitation is confined primarily to the winter months. Occasionally, tropical air masses result

in rainfall during summer months. Annual precipitation in the region varies widely over

relatively short distances, primarily due to topographical effects. The long-term annual total

precipitation along the coast is approximately 12 to 16 inches, but on mountaintops, totals are

nearly 30 inches.

The regional climate is dominated by a strong and persistent high-pressure system, which

frequently lies off the Pacific Coast (generally referred to as the East Pacific Subtropical High-

Pressure Zone or Pacific High). The Pacific High shifts northward or southward in response to

seasonal changes or the presence of cyclonic storms. In its usual position, the Pacific High

produces an elevated temperature inversion in the Project area. An inversion is characterized by

a layer of warmer air aloft, and cooler air near the ground surface. The inversion acts like a lid

on the cooler air mass near the ground, preventing pollutants in the lower air mass from

dispersing upward beyond the inversion “lid.” This phenomenon results in higher concentrations

of pollutants trapped below the inversion.

Inversions commonly form in the Project area during the months of May to October. In winter,

weak surface inversions occur, caused by radiation cooling of air in contact with the cold surface

of the earth. During spring and summer, marine inversions occur when cool air from over the

ocean intrudes under the warmer air that lies over the land. During the summer, the Pacific High

can also cause the air mass to sink, creating a subsidence inversion.

Atmospheric stability is a primary factor affecting air quality in the study region. Atmospheric

stability regulates the amount of air exchange (referred to as turbulent mixing) both horizontally

and vertically. Restricted atmospheric turbulence, that is, a high degree of stability, and low

wind speeds are generally associated with higher pollutant concentrations. These conditions are

typically related to temperature inversions that cap the pollutants emitted below or within them.

Airflow also plays an important role in the movement of pollutants. Regional winds are

normally controlled by the location of the Pacific High, and are generally light. This can

contribute to higher levels of pollution, since low wind speeds minimize dispersion of pollutants.

During summer months, northwesterly winds are stronger and persist later into the night. When

the Pacific High weakens, a Santa Ana condition can develop, with air traveling westward into

the County from the east. Stagnant air often occurs at the end of a Santa Ana condition, causing

a buildup of pollutants offshore.

Topography plays a significant role in affecting the direction and speed of winds. Year round,

light onshore winds hamper the dispersion of primary pollutants, and the orientation of the inland

mountain ranges interrupts air circulation patterns. Pollutants become trapped, creating ideal

conditions for the production of secondary pollutants.

Air Quality Monitoring

Air quality is determined by measuring ambient concentrations of air pollutants, which are

known to have adverse health effects. For regulatory purposes, standards have been set for some

of these air pollutants, and they are referred to as “criteria pollutants.” For most criteria

pollutants, regulations and standards have been in effect, in varying degrees, for more than 25

years, and control strategies are designed to ensure that the ambient concentrations do not exceed

certain thresholds. Another class of air pollutants that are subject to regulatory requirements is

called hazardous air pollutants (HAPs) or air toxics. Substances that are especially harmful to

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health, such as those considered under the U.S. EPA hazardous air pollutant program or

California’s AB 1807 and/or AB 2588 air toxics programs, are considered to be air toxics. There

are 186 federal hazardous air pollutants. There are generally no County-specific monitoring data

for the majority of the air toxics or federal HAPs. Regulatory air quality standards are based on

scientific and medical research. These standards establish minimum concentrations of an air

pollutant in the ambient air that could initiate adverse health effects.

For air toxics emissions, however, the regulatory process usually assesses the potential impacts

to public health in terms of “risk,” such as the Air Toxics “Hot Spots” Program in California, or

the emissions may be controlled by prescribed technologies, as in the Federal Clean Air Act

approach for controlling hazardous air pollutants.

The degree of air quality degradation for criteria pollutants is determined by comparing the

ambient pollutant concentrations to health-based standards developed by government agencies.

The current National Ambient Air Quality Standards (NAAQS) and California Ambient Air

Quality Standards (CAAQS) for “criteria pollutants” are listed in Table 4.3-2. Ambient air

quality monitoring for criteria pollutants is conducted at numerous sites throughout California.

Table 4.3-3 presents relevant data from monitoring stations located in the Project area. A

summary of the attainment status for Santa Barbara County is provided in Table 4.3-4. Ambient

air quality in the County is generally good, i.e., within applicable ambient air quality standards,

with the exception of particulate matter with an aerodynamic diameter of ten microns or less

(PM10), and ozone (O3).

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ERG Foxen Petroleum Pipeline Draft EIR 13EIR-00000-00002 / SCH #2013061011 September2014

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Table 4.3-2 State and National Criteria Air Pollutant Standards, Effects, and Sources

Air Pollutant

State Standard

(concentration,

averaging time)

Federal Primary

Standard

(concentration,

averaging time)

Most Relevant Effects

Ozone

0.09 ppm, 1-hour average

0.070 ppm, 8-hour

0.075 ppm, 8-hour

average*

(a) Short-term exposures: (1) Pulmonary function decrements and localized lung

edema in humans and animals (2) Risk to public health implied by alterations in

pulmonary morphology and host defense in animals; (b) Long-term exposures: Risk

to public health implied by altered connective tissue metabolism and altered

pulmonary morphology in animals after long-term exposures and pulmonary

function decrements in chronically exposed humans; (c) Vegetation damage; (d)

Property damage.

Carbon

Monoxide


20 ppm, 1-hour average



(a) Aggravation of angina pectoris and other aspects of coronary heart disease; (b)

Decreased exercise tolerance in persons with peripheral vascular disease and lung

disease; (c) Impairment of central nervous system functions; (d) Possible increased

risk to fetuses.

Nitrogen

Dioxide

0.18 ppm, 1-hour average,

0.03 ppm, annual average

0.053 ppm annual

0.10 ppm 1 hour

98th

percentile, 3-year

average

(a) Potential to aggravate chronic respiratory disease and respiratory symptoms in

sensitive groups; (b) Risk to public health implied by pulmonary and extra-

pulmonary biochemical and cellular changes and pulmonary structural changes; (c)

Contribution to atmospheric discoloration.

Sulfur Dioxide 0.04 ppm, 24-hour average


0.075 ppm, 1-hour,

99th

percentile 3-year

average

Bronchoconstriction accompanied by symptoms which may include wheezing,

shortness of breath and chest tightness, during exercise or physical activity in

persons with asthma.

Suspended

Particulate

Matter (PM10)

20 µg/m3, annual arithmetic

mean

50 µg/m3, 24-hour average

150 µg/m3,

24-hour average

(a) Excess deaths from short-term exposures and exacerbation of symptoms in

sensitive patients with respiratory disease; (b) Excess seasonal declines in

pulmonary function, especially in children.

Suspended

Particulate

Matter (PM2.5 )

12 µg/m3,

annual arithmetic mean

125 µg/m3, annual

arithmetic mean

35 µg/m3, 24-hour

average

Decreased lung function from exposures and exacerbation of symptoms in sensitive

patients with respiratory disease, elderly, and children.

Sulfates 25 µg/m3, 24-hour average No federal standard

(a) Decrease in ventilatory function; (b) Aggravation of asthmatic symptoms; (c)

Aggravation of cardio-pulmonary disease; (d) Vegetation damage; (e) Degradation

of visibility; (f) Property damage due to corrosion.

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ERG Foxen Petroleum Pipeline Draft EIR 13EIR-00000-00002 / SCH #2013061011 September2014

4.3-5

Air Pollutant

State Standard

(concentration,

averaging time)

Federal Primary

Standard

(concentration,

averaging time)

Most Relevant Effects

Lead 1.5 µg/m3, 30-day average

0.15 µg/m3, roll 3-month

average

1.5 µg/m3, calendar

quarter

(a) Increased body burden; (b) Impairment of blood formation and nerve conduction.

Visibility-

Reducing

Particles

In sufficient amount to give

an extinction coefficient of

0.23 per kilometers (visual

range of 10 miles or more)

with relative humidity less

than 70%, 8-hour average

(10 a.m. to 6 p.m. PST)

No federal standard Reduction of visibility, aesthetic impact and impacts due to particulates (see above)

Hydrogen

Sulfide 0.03 ppm, 1-hour average No federal standard Odor annoyance

Vinyl Chloride 0.01 ppm, 24-hour average No federal standard Known carcinogen

ppm = parts per million

Note: µg/m3 = micrograms per cubic meter.

* Effective May 27, 2008. Was 0.08 ppm prior

Source: CARB 2013

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Table 4.3-3 Monitoring Results at the Santa Maria Monitoring Station

Pollutant Standard 2008 2009 2010

Ozone

Maximum 1-hour concentration (ppb) 72 62 70

Number days exceeded: State > 0.09 ppm/1-hour 0 0 0

Max 8-hour concentration (ppb) 64 58 58

Number days exceeded: State > 0.07 ppm/8-hour 0 0 0

Number days exceeded: Federal > 0.075 ppm/8-hour 0 0 0

Particulates (PM10)

Maximum 24-hour concentration (μg/m3) 87 92 72

Number days exceeded: State > 50 μg/m3/24-hour 19 13 10

Number days exceeded: Federal > 150 μg/m3/24-hour 0 - -

Nitrogen Dioxide (NO2)

Daily Maximum NO2 (ppb) 73 47 48

Sulfur Dioxide (SO2)

Maximum 1-hour concentration, ppb 4 3 5

Source: CARB website Air Quality Data, SBC APCD Annual reports, SO2 for Lompoc as Santa Maria does not

collect SO2 data.

Table 4.3-4 Attainment Status of Criteria Pollutants in the South Central Coast Air

Basin

Pollutant State Federal

O3 – 1-hour Non-attainment Revoked

O3 – 8-hour Non-attainment Unclassifiable

PM10 Non-attainment Attainment

PM2.5 Attainment Attainment

CO Attainment Attainment

NO2 Attainment Attainment

SO2 Attainment Attainment

Lead Attainment Attainment

All others Attainment/Unclassified Attainment/Unclassified

Source: CARB 2013

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Specific Air Pollutants

Criteria pollutants are also categorized as inert or photochemically reactive, depending on their

subsequent behavior in the atmosphere. By definition, inert pollutants are relatively stable, and

their chemical composition remains stable as they move and diffuse through the atmosphere.

The photochemical pollutants may react to form secondary pollutants. For these pollutants,

adverse health effects may be caused directly by the emitted pollutant or by the secondary

pollutants.

Inert Pollutants

Criteria pollutants that are considered to be inert include carbon monoxide (CO), nitrogen

dioxide (NO2), sulfur dioxide (SO2), PM, lead, sulfates, and hydrogen sulfide (H2S).

Carbon monoxide is formed primarily by the incomplete combustion of organic fuels. High

values are generally measured during winter, when dispersion is limited by morning surface

inversions. Seasonal and diurnal variations in meteorological conditions lead to lower values in

summer and in the afternoon.

Nitric oxide (NO) is a colorless gas formed during combustion processes that rapidly oxidizes to

form nitrogen dioxide (NO2), a brownish gas. The highest nitrogen dioxide values are generally

measured in urbanized areas with heavy traffic.

Sulfur dioxide (SO2) is a gas produced primarily from combustion of sulfurous fuels by

stationary and mobile sources. However, SO2 can react in the atmosphere to produce acids or

particulate sulfates, which can also cause impacts.

The largest PM10 emissions appear to originate from soils via roads, construction, agriculture,

and natural, windblown dust. Other sources of PM10 include sea salt, particulate matter released

during combustion processes, such as those in gasoline and diesel vehicles, and wood burning.

Also, nitrogen oxides (NOx) and sulfur oxides (SOx) are precursors in the formation of secondary

PM10.

Lead is a heavy metal that in ambient air occurs as a lead oxide aerosol or dust. Since lead is no

longer added to gasoline or to paint products, lead emissions have been reduced significantly in

recent years.

Sulfates are aerosols, i.e., wet particulates, which are formed by sulfur oxides in moist

environments. They exist in the atmosphere as sulfuric acid and sulfate salts. The primary

source of sulfate is from the combustion of sulfurous fuels.

Hydrogen sulfide (H2S) is an odorous, toxic, gaseous compound that can be detected by humans

at very low concentrations. Concentrations detectable by smell (this can vary from 0.5 parts per

billion [ppb] detected by two percent of the population, to 40 ppb, qualified as annoying by 50

percent of the population) are significantly lower than concentrations that could affect human

health (2 parts per million (ppm) [or 2,000 ppb] can cause headaches and increased airway

resistance in asthmatics; inhalation of more than 600 ppm can be instantly lethal). The gas is

produced during the decay of organic material and is also found naturally in petroleum and

natural gas.

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Photochemical Pollutants

Ozone is formed in the atmosphere through a series of complex photochemical reactions

involving oxides of nitrogen (NOx), reactive organic compounds (ROC), and sunlight, occurring

over a period of several hours. Since ozone is not emitted directly into the atmosphere, but is

formed as a result of photochemical reactions, it is classified as a secondary or regional pollutant.

Because these ozone-forming reactions take time, peak ozone levels are often found downwind

of major source areas.

Santa Barbara County is not in attainment for the State 1-hour and State 8-hour ozone standard.

Santa Barbara County is in attainment for the Federal 8-hour ozone standard.

Hazardous Air Pollutants (HAPs)

HAPs are materials that are known or suspected to cause cancer, genetic mutations, birth defects,

or other serious illnesses in humans. HAPs may be emitted from three main source categories:

(1) industrial facilities; (2) internal combustion engines (stationary and mobile); and (3) small

“area sources” (such as solvent use). The California Air Resources Board (CARB) publishes

lists of Volatile Organic Compound Species Profiles for many industrial applications and

substances, some of which are classified as HAPs and some are not.

Generally, HAPs behave in the atmosphere in the same general way as criteria pollutants (only

the inert pollutants that do not react chemically, but preserve the same chemical composition

from point of emission to point of impact). The concentrations of toxic pollutants are therefore

determined by the quantity and concentration emitted at the source and the meteorological

conditions encountered as the pollutants are transported away from the source. Thus, impacts

from toxic pollutant emissions tend to be site-specific and their intensity is subject to constantly

changing meteorological conditions.

Odorous Compounds

Several compounds associated with the oil and gas industry can produce odors that can be

determined to be nuisances. Sulfur compounds, found in oil and gas, have very low odor

threshold levels. For instance, H2S can be detected by humans at concentrations from 0.5 ppb

(detected by two percent of the population), to 40 ppb, qualified as annoying by 50 percent of the

population. These levels are significantly lower than concentrations that could affect human

health – 2 ppm /2,000 ppb can cause headaches and increased airway resistance in asthmatics,

inhalation of more than 600 ppm can be instantly lethal, and inhalation of over 100 ppm can be

lethal if exposure lasts longer than 60 minutes (ERPG-3; AIHA 1989).

Many volatile compounds found in oil and gas (ethane and longer chain hydrocarbons) typically

have petroleum or gasoline odor with various odor thresholds.

Natural gas contains mostly methane (which is odorless), thus it has to be odorized as requried

by law, before being placed into a distribution pipeline. The various compounds that are used for

odorization include sulfur compounds having a very low odor threshold and which can produce

odors if released into the atmosphere.

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Meteorology

The CARB meteorological data from the Santa Maria monitoring station, approximately 1 mile

southeast of the proposed Project site, is the closest station to the Project site that has detailed

wind direction and speed information. This data was plotted into a wind rose (Figure 4.3-1) to

demonstrate the predominant wind direction and speeds at the Project site. Figure 4.3-1 shows

that the predominate wind blows from the west and northwest 36 percent of the time, and from

the east and southeast less than 20 percent of the time. Wind speeds averaged approximately 5

miles per hour, with periods of stronger winds above 20 miles per hour occurring less than one

percent of the time.

Countywide Criteria Pollutant Emission Inventory

Emissions of ROC and NOx within Santa Barbara County were estimated by the Santa Barbara

County Air Pollution Control District (SBCAPCD) in the 2007 Updates to the Clean Air Plan

(Table 4.3-5, also shows total emissions of CO, SO2 and PM10, but these emissions no longer

are included in the Clean Air Plan Emission Inventories). These estimates are used to address

Federal and State clean air mandates. The highest contributors to the ROC emissions are natural

sources, including natural uncontrolled seeps of oil and gas constituents (14 percent of natural

sources) through cracks and voids in the ground. Emissions of CO and NOx mostly occur due to

mobile sources (e.g., on-road vehicles). The majority of SOx emissions in Santa Barbara County

come from mineral processes, specifically from diatomaceous earth processing. Particulate

emissions sources vary from dust caused by agricultural and construction activities, on-road dust,

various mineral processing, to particulate emissions from combustion engines.

Table 4.3-5 Emission Inventory for Santa Barbara County

Emission

Sources

CO

tons/yr

ROC

tons/yr

NOx

tons/yr

SO2

tons/yr

PM10

tons/yr

Stationary 1,551 3,244 2,843 552 554

Area-Wide 9,433 3,051 333 8 10,584

Mobile 82,532 5,039 11,048 305 572

Natural 11,404 47,378 8,707 0 1,843

All Sources 103,369 58,712 22,931 865 13,553

Notes: SBCAPCD 2007 emission inventory for ROC and NOx, 1998 for CO, SO2 and PM10

Sources: SBCAPCD 2010 and 2001 Clean Air Plans.

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Figure 4.3-1 Santa Maria Meteorological Station Wind Rose – 1998-2008

Note: Wind rose shows the direction the wind is coming from.

Source: CARB meteorological data, Santa Maria Station, 1998 – 2008

Countywide Air Toxics Emission Inventory

Air toxics are materials that are known or suspected to cause cancer, genetic mutations, birth

defects, or other serious illnesses in humans. Air toxics may be emitted from three main source

categories: (1) industrial facilities; (2) internal combustion engines (stationary and mobile); and

(3) small “area sources” (such as solvent use). The California Air Resources Board (CARB)

publishes lists of Volatile Organic Compound Species Profiles for many industrial applications

and substances (CARB Speciation Profiles 2013).

Generally, air toxics behave in the atmosphere in the same way as inert pollutants (those that do

not react chemically, but preserve the same chemical composition from point of emission to

point of impact). The concentrations of toxic pollutants are therefore determined by the quantity

and concentration emitted at the source and the meteorological conditions encountered as the

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pollutants are transported away from the source. Thus, impacts from toxic pollutant emissions

tend to be site-specific and their intensity is subject to constantly changing meteorological

conditions. The worst-case meteorological conditions that negatively affect short-term impacts

are low wind speeds, highly stable air mass, and constant wind direction.

4.3.1.2 Regulatory Setting

Federal, State, and local agencies have established standards and regulations that govern the

proposed Project. A summary of the regulatory setting for air quality is provided below.

Federal Regulations

The Federal Clean Air Act of 1970 directs the attainment and maintenance of the NAAQS. The

1990 Amendments to this Act included new provisions that address air pollutant emissions that

affect local, regional, and global air quality. The main elements of the 1990 Clean Air Act

Amendments are summarized below:

Title I, Attainment and maintenance of NAAQS;

Title II, Motor vehicles and fuel reformulation;

Title III, Hazardous air pollutants;

Title IV, Acid deposition;

Title V, Facility operating permits (describes requirements for Part 70 permits);

Title VI, Stratospheric ozone protection; and

Title VII, Enforcement.

The U.S. EPA is responsible for implementing the Federal Clean Air Act and establishing the

NAAQS for criteria pollutants. In 1997, the EPA adopted revisions to the Ozone and Particulate

Matter Standards contained in the Clean Air Act. These revisions included a new 8-hour ozone

standard and a new particulate matter standard for particles below 2.5 microns in diameter.

These standards were suspended, however, when in May 1999, the U.S. Court of Appeals for the

District of Columbia remanded the new ozone standard. In January 2001, the EPA issued a

Proposed Response to Remand, in which it stated that the revised ozone standard should remain

at 0.08 ppm. In February 2001, the U.S. Supreme Court upheld the constitutionality of the Clean

Air Act as the EPA had interpreted it in setting health-protective air quality standards for ground-

level ozone and particulate matter. In April 2004, the EPA issued their Final Non-Attainment

Area Designations for 8-Hour Ozone Standard.

State Regulations

California Air Resources Board (CARB).

The CARB established the California Ambient Air Quality Standards (CAAQS). Comparison of

the criteria pollutant concentrations in ambient air to the CAAQS determines State attainment

status for criteria pollutants in a given region. CARB has jurisdiction over all air pollutant

sources in the State; it has delegated to local air districts the responsibility for stationary sources

and has retained authority over emissions from mobile sources. CARB, in partnership with the

local air quality management districts within California, has developed a pollutant monitoring

network to aid attainment of CAAQS. The network consists of numerous monitoring stations

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located throughout California that monitor and report various pollutants’ concentrations in

ambient air.

California Clean Air Act (CCAA) (California Health and Safety Code, Division 26).

This act went into effect on January 1, 1989, and was amended in 1992. The CCAA mandates

achieving the health-based CAAQS at the earliest practical date.

Air Toxics “Hot Spots” Information and Assessment Act of 1987 – AB2588 (California Health &

Safety Code, Division 26, Part 6).

The Hot Spots Act requires an inventory of air toxics emissions from individual facilities, an

assessment of health risk, and notification of potential significant health risk.

California Health & Safety Code Sections 25531–25543, The Calderon Bill (SB 1889).

These sections set forth changes in the following four areas: (1) provide guidelines to identify a

more realistic health risk; (2) require high-risk facilities to submit an air toxic emission reduction

plan; (3) hold air pollution control districts accountable for ensuring that the plans will achieve

their objectives; and (4) require high-risk facilities to achieve their planned emission reductions.

California Diesel Fuel Regulations

With the California Diesel Fuel Regulations, the CARB set sulfur limitations for diesel fuel sold

in California for use in on-road and off-road motor vehicles. The rule initially excluded harbor

craft and intrastate locomotives, but it later included them with a 2004 rule amendment. Under

this rule, diesel fuel used in motor vehicles, except harbor craft and intrastate locomotives, has

been limited to 500-ppm sulfur since 1993. This sulfur limit was later reduced to 15-ppm,

effective September 1, 2006.

Local Regulations

Local Air Pollution Control Districts in California have jurisdiction over stationary sources in

their respective areas and must adopt plans and regulations necessary to demonstrate attainment

of Federal and State air quality standards. As directed by the Federal and State Clean Air Acts,

local air districts are required to prepare plans with strategies for attaining and maintaining State

and Federal ozone standards. In the Project area, air quality rules and regulations are

promulgated by the SBCAPCD. In order to ultimately achieve the air quality standards, the rules

and regulations limit emissions and permissible impacts from the proposed Project. Some rules

also specify emission controls and control technologies for each type of emitting source. The

regulations also include requirements for obtaining an Authority To Construct (ATC) permit and

a Permit to Operate (PTO).

Santa Barbara County Air Pollution Control District

The SBCAPCD has jurisdiction over air quality attainment in the Santa Barbara County portion

of the SCCAB. Many aspects of the proposed Project and Alternatives occurring in Santa

Barbara County must obtain a SBCAPCD permit, if applicable. The SBCAPCD also has

jurisdiction over Outer Continental Shelf (OCS) sources located within 25 miles (40 km) of the

seaward boundaries of the State of California (Rule 903). Increases in emissions of any non-

attainment pollutant or its pre-cursor from a new or modified project that exceed the thresholds

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which have been identified in the SBCAPCD Regulation VIII, are required to be mitigated.

Other applicable rules are summarized below.

Rule 201, Permits Required – Specifies the permits required for construction or operation of

equipment that emits air contaminants.

Rule 202, Exemptions to Rule 201 – Lists equipment categories that are exempt from the

requirements to obtain an SBCAPCD permit (exempt from Rule 201).

Rule 303, Nuisance, and Rule 310 – Odorous Sulfates – These rules prohibit air emissions

that cause a nuisance, e.g., odorous sulfates.

Regulation XIII – Defines criteria for Part 70 source applicability, and permit content and

requirements for part 70 sources.

Rule 370, Potential to Emit – Limitations for Part 70 Sources – Specifies actual emission

level criteria below which Part 70 sources are exempt from Part 70 permit requirements.

Rule 802, Non-Attainment Review – For new or modified emission sources, this rule specifies

emission limits that would trigger emission offsets (80 lbs/day for PM10, 55 lbs/day for any

non-attainment pollutant and 150 lbs/day for carbon monoxide) or trigger Best Available

Control Technology (BACT) requirements (25 lbs/day for any non-attainment pollutant and

150 lbs/day for carbon monoxide). Note that currently, the area is in non-attainment for NOx,

ROC, PM10 and SOx (the latter as a particulate precursor).

4.3.1.3 Criteria and Toxic Pollutant Impact Assessment

Project operations would produce emissions of criteria pollutants from project equipment and

from offsite mobile emissions; could increase odor events; and could produce health risk

impacts. Each of these is discussed below.

County Environmental Thresholds

Air quality significance thresholds are defined for operations, construction and GHGs and are

discussed below.

Operational Thresholds for Criteria Pollutants

The thresholds used to determine significance are based on the Santa Barbara County

Environmental Thresholds and Guidelines Manual, SBC 2008. A proposed project will not have

a significant air quality effect on the environment, if operation of the project will:

Emit (from all project sources, mobile and stationary), less than the daily trigger for offsets

set in the APCD New Source Review Rule (55 lbs/day for ROC, NOx, SOx and 80 lbs/day

for PM), for any pollutant;

Emit less than 25 pounds per day of oxides of nitrogen (NOx) or reactive organic

compounds (ROC) from motor vehicle trips only;

Not cause or contribute to a violation of any California or National Ambient Air Quality

Standard (except ozone);

Does not allow land uses that create objectionable odors or does not expose sensitive

receptors to objectionable odors;

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Not exceed the APCD health risk public notification thresholds adopted by the APCD

Board for air toxics; and

Be consistent with the adopted federal and state Air Quality Plans.

The CEQA Guidelines §15355 defines cumulative impacts as “two or more individual effects

which, when considered together, are considerable or which compound or increase other

environmental impacts.” The individual effects may be changes resulting from a single project

and more than one projects (CEQA Guidelines §15355(a)). Cumulative impacts may result from

individually minor but collectively significant projects taking place over a period of time (CEQA

Guidelines §15355(b)).

Construction Thresholds

Emissions from construction activities are normally short-term. Currently, neither the County

nor the SBCAPCD have daily or quarterly quantifiable emission thresholds established for short-

term construction emissions. PM10 impacts from dust emissions should be discussed and

standard mitigation measures implemented, e.g., watering, as required in the Scope and Content

of Air Quality Sections in Environmental Documents (SBCAPCD 2014) and the County

Environmental Thresholds and Guidelines Manual (SBC 2008).

Although quantitative thresholds of significance are not currently in place for short-term or

construction emissions, the SBCAPCD requires construction projects that would emit more than

25 tons per year to obtain emission offsets under Rule 804 and would consider these emissions to

be significant under CEQA. SBCAPCD Rule 202 (related to permits and offset requirements

and exemptions), Section D.16, requires that:

Notwithstanding any exemption in these rules and regulations, if the combined

emissions from all construction equipment used to construct a stationary source

which requires an Authority to Construct have a projected actual in excess of 25

tons of any pollutant, except carbon monoxide, in a 12 month period, the owner of

the stationary source shall provide offsets as required under the provisions of Rule

804, Emission Offsets, and shall demonstrate that no ambient air quality standard

would be violated.

Study Area, Scope and Methodology

For this air quality analysis, the study area includes the existing facilities associated with the

Cantin Lease and the area that could be impacted by the proposed project pipeline construction.

The facilities where the air emissions potentially change due to the proposed project include:

The equipment located at the Cantin Lease;

The truck hauling routes from the Cantin and GWP Leases; and

Construction activities along the pipeline route between the field facilities and Foxen

Canyon Road, along Foxen Canyon Road and within the town of Garey.

Construction and operational activities emissions were estimated using spreadsheets for a

number of different sources. Use factors are based on Applicant submittals. Emission factors

are based on CalEEMod version 2013.2 as well as SBCAPCD-approved emission factors for

tanks, heaters and fugitive emissions.

4.3 AIR QUALITY


4.3-15

Offsite emissions are from on-road vehicles traveling both on and off site. Emissions were

calculated for trucks and automobiles that would travel to and from the Project site for all criteria

and GHG pollutants (ROG, CO, NOx, SOx, PM10, PM2.5, N2O, CH4, CO2) utilizing

EMFAC2011. Distances of travel are based on the average distance to Santa Maria (12 miles)

for employee automobiles and the distance to the Phillips 66 Santa Maria Pump Station (SMPS)

on Battles Road for crude haul trucks.

GHG emissions are calculated using the same equations as above except that CO2, CH4 and N2O

emission factors are used. CO2 and CH4 emission factors for mobile sources are taken from the

EMFAC2011 outputs and the N2O emission factors are taken from the California State (and

Federal) reporting rule (Regulation for the Mandatory Reporting of GHG Emissions, Title 17

CCR, section 95100 to 95133).

Receptors that could be impacted by air emissions include both regional receptors, due to the

emissions of ozone precursors, or local receptors, that could be impacted by toxic or odoriferous

emissions. Regional receptors include areas within northern Santa Barbara County and the Santa

Maria Valley. Local receptors include residences along Foxen Canyon Road, the towns of Garey

and Sisquoc, and the Blochman School located within the town of Sisquoc about 3,000 feet from

the Cantin Lease.

Baseline Operations Criteria Pollutant Emissions

Baseline operations include the gathering and storage of crude oil, the loading of crude oil onto

trucks, and the transportation of crude oil by truck to the SMPS. Emissions are tabulated in

Table 4.3-6, below for the baseline year of 2013 with 1,2911,300 bpd average production. Note

that crude oil production in August 2014 had increased to 3,400 bpd. The baseline is defined, as

per CEQA, as the operations when the NOP was issued.

Table 4.3-6 Baseline Daily Criteria Emissions

Emission

Sources

NOx

lbs/day

ROC

lbs/day

CO

lbs/day

SO2

lbs/day

PM10

lbs/day

PM2.5

lbs/day

Fugitive Emissions 0 16.310.2 0 0 0 0

Fugitive Dust 0 0 0 0 6.23 0.94

Offsite 4.805.5 0.20 1.274 0.00 0.192 0.182

Total 4.805.5 16.5110.4 1.274 0.00 6.424 1.12

Note: using 1,2911,300 bpd crude production in year 2013, as per Applicant submittals

Baseline Operations Toxic Emissions

Toxic emissions are emitted from the facility due to fugitive emissions of hydrocarbons

containing primarily BTEX (benzene, toluene, ethylbenzene and xylenes). These emissions

occur from the storage tanks and the loading facility used to load crude oil onto trucks for

transport to the SMPS. The Applicant prepared a Health Risk Assessment (included in the Air

Quality Appendix along with a peer review assessment by MRS) that addresses risk from the

baseline and the Proposed Project operations combined. These risk levels are discussed below

under the Proposed Project Impacts. As emissions from Proposed Project operations would be

higher than the baseline emissions (and equipment arrangements are similar if not less intensive

4.3 AIR QUALITY


4.3-16

for the baseline operations), risk levels associated with the baseline operations would be less than

those identified as part of the Proposed Project. SBCAPCD Health Risk Assessment

prioritization screening spreadsheet was utilized to estimate the cancer, acute and chronic risk

factors. Utilizing a distance to receptors of 850 meters, the cancer risk screening produced a

total facility score of 0.8, which classifies the current operations as a low priority.

Baseline Operations – Odor Emissions

Odors could emanate from the current operations due to the fugitive emissions of hydrocarbons.

Fugitive emissions of hydrocarbons are produced from the crude oil storage tank and the loading

facility. In addition, the presence of some H2S could produce odors. However, no odor

complaints have been logged with the SBCAPCD and, due to the relatively remote location of

the facility (3,000 feet from the closest residence), routine odors would not be expected. Upset

conditions could occur, such as spills or tank releases of vapors, that could cause odors at nearby

receptors. However, none of these events has been recorded by the APCD for the Cantin facility.

Project Impacts – Criteria Pollutants

Criteria pollutants would be emitted by the following processes associated with the proposed

Project:

Construction activities at the Cantin lease and along the pipeline route;

Heater combustion of an estimated 10% field gas, 90% pipeline quality gas;

Fugitive emissions from tanks, valves, flanges, etc. that emit ROC; and

Offsite vehicles transporting light crude oil for blending and employees.

Construction Criteria Pollutant Emissions

Air emissions of criteria pollutants (CO, ROG, NOx, SO2, and PM) during construction would

result from the use of construction equipment with internal combustion engines (e.g., backhoes,

cranes), and off-site vehicles (e.g., construction employee commuter vehicles and trucks

delivering equipment and hauling materials to and from the site). Air emissions from

construction equipment were estimated using the emission factors and equations from the

CalEEMod software for fugitive dust and equipment emission factors, and the assumptions on

the duration and personnel detailed in Chapter 2.0, Project Description. Equipment lists and

usage were supplied by the Applicant.

Emissions from off-site vehicles were estimated using the recent EMFAC2011 factors for light

duty automobiles, light duty trucks and heavy duty trucks at different speeds. Appendix 4 to this

EIR includes details on the construction equipment and periods of operation for each equipment

piece. Emissions are summarized in Table 4.3-7.

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4.3-17

Table 4.3-7 Proposed Project Construction Criteria Emissions, tons

Emission

Sources NOx ROC CO SO2 PM10 PM2.5

Construction

Equipment 0.785 0.132 0.510 0.001 0.047 0.046

Fugitive Dust 0.00 0.00 0.00 0.00 0.13 0.02

Offsite Emissions 0.09 0.01 0.10 0.00 0.00 0.00

Total 0.878 0.139 0.613 0.001 0.176 0.066

Threshold 25 25 - 25 25 25

Significant? No No No No No No

Emissions from construction would not exceed the thresholds and would therefore be less than

significant (Class III).

Operations Criteria Pollutant Emissions

Operational emissions of criteria pollutants would result from combustion of field gas and

pipeline quality gas in the tank heater, from fugitive emissions associated with the tanks, the

loading rack for light crude oil, and from valves and flanges and connections and from offsite

vehicles. The Applicant indicates that they would utilize monthly testing of fugitive components

along with a Leak Detection and Repair threshold of 100 ppm, which would reduce fugitive

emissions further than that required by the APCD Rule 331.

Emissions would result from offsite vehicle traffic related to the transportation of light crude oil

by truck and for the employee visits to the site. EMFAC2011 emission factors were utilized for

offsite emissions.

Onsite emissions were calculated using the APCD spreadsheets for fugitive emissions along with

the Category E for valves and flanges (due to the LDAR of 100ppm and monthly inspections).

Emissions from the heater were calculated using the APCD spreadsheet for boilers and the

corresponding emission factors. Emissions from tanks also used the APCD spreadsheets along

with the tank and throughput characteristics provided by the Applicant. All calculations are

provided in Appendix 4.

Normal operations would involve transporting the crude oil by pipeline. The Applicant indicates

that, during periods of pipeline maintenance or other pipeline related outages (emergency

operations), that the crude oil would be transported by truck for a period of time. Both of these

emission scenarios are tabulated below in Table 4.3-8. Mobile source emissions are shown in

Table 4.3-9 for both the normal and emergency operations scenarios.

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Table 4.3-8 Proposed Project Operational Criteria Emissions - Operations Peak Day

Emission

Sources

NOx

lbs/day

ROC

lbs/day

CO

lbs/day

SO2

lbs/day

PM10

lbs/day

PM2.5

lbs/day

Normal Operations

Onsite Emissions 8.64 31.4233.24 71.28 3.08 7.47 2.62


Total ProjectOnsite

+ Offsite Emissions 14.00 31.6533.46 72.67 3.08 7.68 2.82

Baseline 5.51 10. 4039 1.42 0.00 6.45 1.15

Net Increase 8.49 21.2523.07 71.25 3.08 1.23 1.67

Threshold 55/25* 55/25* - 55 80 80

Significant? No/No No/No No No No No

Emergency Operations (trucking instead of pipeline)

Onsite Emissions 8.64 96.194.7 71.28 3.08 7.47 2.62


Total Onsite +

Offsite

EmissionsTotal

Project

118.42 100.699.17 94.59 3.08 11.85 6.65

Baseline 5.51 10.439 1.42 0.000 6.45 1.15

Net Increase 112.91 90.9588.78 93.18 3.08 5.40 5.51

Threshold 55/25* 55/25* - 55 80 80

Significant? Yes/Yes Yes/No - No No No Notes: * for mobile sources only. The emergency operations scenario assumes all of the crude oil (25,000

bpd) is transported by truck.

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Table 4.3-9 Proposed Project Mobile Source Criteria Emissions - Operations Peak Day

Emission

Sources

NOx

lbs/day

ROC

lbs/day

CO

lbs/day

SO2

lbs/day

PM10

lbs/day

PM2.5

lbs/day

Normal Operations


Baseline 5.51 0.23 1.42 0.00 0.22 0.20

Net Increase -0.15 -0.01 -0.03 0.00 -0.01 -0.01

Threshold 25 25 - - - -

Significant? No No - - - -

Emergency Operations (trucking instead of pipeline)


Baseline 5.51 0.23 1.42 0.00 0.22 0.20

Net Increase 104.42 4.23 21.93 0.00 4.17 3.84

Threshold 25 25 - - - -

Significant? Yes No - - - - Notes: The emergency operations scenario assumes all of the crude oil (25,000 bpd) is transported by

truck.

Emissions of criteria pollutants would not exceed the thresholds during normal operations and

would therefore be less than significant (Class III). During emergency operations, when all of

the crude oil would be transported by truck, emissions would exceed the thresholds for NOx and

for ROC. As per Table 4.3-9, during emergency operations, emissions would also exceed the

mobile source thresholds. Emissions would be significant for the emergency operations case

(Class II).

Impact

Number Impact Description

Project

Phase

Impact

Class

AQ-1

During the emergency operations scenario, when all of

the crude oil is transported by truck, emissions would

exceed the thresholds.

Emergency

operations II

The During emergency operations, the additional emissions associated with the trucks required

to haul the crude oil and from loading activities at the Cantin Lease would cause emissions of

NOx and ROC to exceed the thresholds. In addition, the NOx emissions from mobile sources

would exceed the daily thresholds. This assumes that all of the production is transported by

truck to the SMPS. These emissions would be less than significant (Class II) with

implementation of mitigation measure AQ-1. (Class II).

Toxic Emissions

Toxic emissions would be generated from the fugitive emissions which include BTEX, as well as

from the heater combustion. The Applicant prepared a Health Risk Assessment (included in the

Air Quality Appendix along with a peer review checklist compiled by the EIR consultant MRS).

Emissions of toxic materials utilized the VCAPCD, AP-42 and the CARB speciation factors to

4.3 AIR QUALITY


4.3-20

estimate the emissions of toxic materials from fugitive components, tanks and the heater. The

HRA included the following assumptions:

Cantin tank battery fugitive components were grouped and modeled as a volume source;

Pipeline fugitive components were divided into two groups representing the above

ground sections at each end of the pipeline and each group was modeled as a volume

source;

The pig receiver was modeled as a volume source;

Fixed roof tanks were modeled as point sources in accordance with SBCAPCD

guidelines;

Crude oil loading racks were modeled as volume sources;

LCO unloading emissions were modeled at the Cantin LCO tank release point;

The heater was modeled as a point source;

All sources operate 24 hours per day, 365 days per year, with the exception of pig

receivers and the loading racks.

Building downwash was included for the tanks at the site. No other buildings are located close

enough to the facilities to produce building downwash effects. The HARP model version 1.4f

model was used along with 1988 and 1989 year meteorological data from the Battle met station.

The California Office of Environmental Health Hazard Assessment (OEHHA) provides the latest

information on whether substances are considered to cause acute, chronic, or cancer health

impacts. The purpose of the modeling is to estimate the extent of exposure to each substance for

which potential cancer risk, acute non-cancer health effects, and chronic noncancer health effects

exist. The SBCAPCD has established significance thresholds of 10 in one million for cancer risk

and a Hazard Index of 1.0 for non-cancer (acute and chronic) risk. The modeling results are

listed in Table 4.3-10. Results are presented for the Point of Maximum Impact (PMI), the

Maximally Exposed Individual Resident (MEIR) and the Maximally Exposed Individual Worker

(MEIW).

Table 4.3-10 Proposed Project HRA Results

Impact Class PMI MEIR MEIW Threshold Significant ?

Acute HI 0.85 0.11 0.85 1.0 No

Chronic HI 0.03 0.002 0.003 1.0 No

Cancer Risk per million 2.78 0.16 0.04 10 No

Notes: Utilizing HARP model version 1.4f. See Air Quality Appendix for detailed report. Significance for cancer risk are

determined at the closest residence or worker location.

Impacts would be less than significant for cancer, acute and chronic impacts at all receptors and

impacts would therefore be less than significant (Class III).

4.3 AIR QUALITY


4.3-21

Utilizing the SBCAPCD HRA risk prioritization spreadsheet, the total facility score of the

proposed project facility would be 3.8, which would classify the facility as a medium priority.

This would be a less than significant impact. Calculations are shown in Appendix 4.

Odor Emissions

Fugitive emissions from the facility would increase with the proposed project from a baseline of

about 10 lbs/day to about 26 lbs/day, with the largest sources being the crude oil tanks, the LCO

unloading and the fugitive emissions from valves and connections, respectively. Due to the

relatively remote nature of the location, located 3,000 feet from sensitive receptors, odor issues

are not anticipated from normal operations. The SBCAPCD Rule 3130 related to odorous

organic sulfides requires that operations are not allowed to produce emissions which result in

ground level concentrations at any point at or beyond the property line in excess of 0.06 ppm

with a 3-minute averaging time or 0.03 ppm with a 60-minute averaging time. Utilizing the

SCREEN3 model, the emissions from fugitives containing up to 2,500 ppm H2S treated as an

area source of 100 m2 and stable meteorological conditions (1 m/s, F stability), would produce

impacts at Foxen Canyon Road of less than 1 ppb for both a 3-minute and 60-minute averaging

time (using the conversion for the 3-minute averaging time as per Duffee 1991). Impacts would

therefore be less than significant during normal operations, Class III.

Impacts associated with upset scenarios, such as a crude oil spill or tank hatch release, could

cause odor impacts at nearby sensitive receptors. These events are estimated to occur

infrequently, however, and would not contribute to a nuisance issue within the field. Impacts

would therefore be less than significant (Class III).

Consistency with Clean Air Plan (CAP)

Commercial or industrial projects are considered consistent with the CAP if they are consistent

with SBCAPCD rules and regulations (SBCAPCD 2014). Large industrial stationary source

projects may be found inconsistent if their direct emissions are not considered in the CAP

stationary source emission inventory. The SBCAPCD states that "consistency with the CAP for

the projects subject to these guidelines means that direct and indirect emissions associated with

the project are accounted for in the CAP’s emissions growth assumptions and the project is

consistent with policies adopted in the CAP" (SBCAPCD 2014).

As this project would not involve residential development and would not provide for increased

population growth, the project would be consistent with the CAP for the population growth

component. The project would obtain permits from the SBCAPCD and would comply with all

applicable SBCAPCD Rules and Regulations and would not be a large stationary source.

Therefore, the project would be consistent with the CAP.

Cumulative Criteria Pollutant Impacts

There are several industrial and oil development projects proposed in the South Central Coast

Air Basin. These projects are individually likely to have significant air quality impacts or to

cause changes in the operations associated with existing oil and gas production within the area.

The proposed Phillips 66 Rail Spur project would enable the Santa Maria Refinery (SMR; in San

Luis Obispo County) to import crude oil from out-of-state sources. A number of area producers

use the Phillips 66 pipeline system to transport crude oil to the SMR. These include the Pt.

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Pedernales, Pt. Arguello, Santa Ynez Unit and the Ellwood Field offshore production; the

Lompoc and Orcutt onshore oil and gas fields; and the Cat Canyon field (of which the proposed

Project is a part). The Pt. Arguello, Santa Ynez Units and the Ellwood Field offshore production

all have the capability to transport crude oil either to the SMR or to refineries in Los Angeles

through the All American Pipeline system. The other producers do not have pipeline options for

delivery of their crude oil to Bakersfield or Los Angeles area refining destinations.

In 2012, the SMR had about 11,000 bpd of excess refining capacity available. If the SMR were

to decide, through market forces, to satisfy all of the excess capacity through rail shipments

instead of from local producers, then the local producers would have no option except to truck

their crude oil to other refineries, or shut down production. Under this scenario, the advantages

of the proposed Project, i.e. reduced trauma risks and air quality impacts associated with the full

production scenario (25,000 bbls/day), would not be realized.

Another option would be for the Phillips 66 pipeline connection from the All American pipeline

to the SMPS to be reversed, allowing local producers to ship their crude oil via pipeline from

area sources to Los Angeles via pipeline. A project proposed in 2002 to reverse the pipeline

segment was approved and issued a permit, but the permit subsequently expired and the pipeline

was never reversed. A reversal of the pipeline flow direction would allow production from area

producers to be transported to area markets via pipeline instead of by truck if the SMR is not

available, thereby allowing the benefits of the proposed Project to be realized.

There are also limits on the amount of crude oil that can be received and transported through the

SMPS. According to the Santa Barbara County APCD permits (PTO 08218r8, 11754r2), the

SMPS has a permit throughput limit of 26,000 bpd that could be unloaded by truck at the Santa

Maria Pump Station, and a pipeline throughput capacity of 84,000 bpd as per County permit 91-

DP-003. Therefore, truck transportation of the full production scenario from the proposed

Project to the SMPS (as under the Emergency Operations scenario) may not be possible as trucks

may not be able to unload the full amount without displacing other fields’ production.

In summary, the scenario exists that local producers may have to transport their crude oil via

truck to markets other than the SMR. This would increase air emissions associated with trucking

the crude oil a farther distance or trucking as opposed to pipeline transportation. This could

result in a significant cumulative impact.

There are potentially significant air quality impacts that have been identified for the Project.

Mitigation measures would reduce the significance of the Project’s impacts to a level below the

relevant significance criteria. However, the Project would still contribute to the cumulative

increase in emissions in the air basin, which is currently in non-attainment for ozone. Combined

with other oil and gas projects in the area, the proposed Project might cumulatively have

significant air quality impacts because significant air quality impacts may be identified for the

other projects, and because the area is in non-attainment for ozone.

Due to the distances of the other industrial projects that are likely to have significant air quality

impacts, the proposed Project is not likely to contribute to significant cumulative air quality

impacts associated with localized impacts.

Other residential, commercial, institutional, or recreational projects in the project area may have

significant air quality impacts. Combined with these residential projects, the proposed Project

4.3 AIR QUALITY


4.3-23

might cumulatively have significant air quality impacts because significant air quality impacts

may be identified for the other projects, and because the area is in non-attainment for ozone.

Criteria Pollutant Mitigation and Residual Impacts

The following mitigation measure is related to Impact AQ-1, associated with emissions of NOx

and ROC during the emergency operations scenario when all of the crude oil would be

transported by truck to the Santa Maria Pump Station. Adherence to this mitigation measure

would ensure project and residual impacts to air quality during emergency operations would be

less than significant.

AQ-1 Emergency Operations Trucking Limits. The Applicant shall prepare and implement

an Emergency Operations Air Quality Plan, which shall be approved by the County and

in consultation with the SBCAPCD and which identifies measures to ensure that

emissions of NOx and/or ROC do not exceed the daily thresholds during temporary

trucking operations. These measures shall include but not be limited to, a combination of

the following:

1. Installation of vapor recovery on the crude loading system exceeding 98%, with

annual testing to demonstrate this level of compliance, with the approval and at the

discretion of the SBCAPCD, in combination with Item 2 below;

2. Securing the services of crude hauling service providing model year 2010 or newer

haul trucks to reduce NOx emissions. A model year 2007 truck could be used if

associated with a reduction in the crude oil transportation levels to a level that would

prevent exceedance of the threshold, in combination with a loading Vapor Recovery

Unit (VRU) efficiency of 98 percent. This allows for some combination of loading

VRU efficiency, truck model year and crude transportation level that ensures

emissions remain below the applicable thresholds for both mobile sources and NOx

and ROC total emissions. (For example: 98% loading VRU efficiency, 50% 2007

model year, 50% 2010 model year and 15,000 bpd, or transportation of only 11,000

bpd with 98% efficiency on the VRU).

PLAN REQUIREMENTS AND TIMING: The Applicant shall provide P&D and the

SBCAPCD with the Plan for review and approval prior to issuance of the Zoning

Clearance.

MONITORING: P&D compliance monitoring staff will maintain the approved plan on

file and monitor for compliance during construction activities in coordination

consultation with with the SBCAPCD.

Residual Impact: Adherence to MM AQ-1 would ensure that impacts to air quality during

emergency operations (Impact AQ-1) would be less than significant with mitigation, Class II.

4.3.2 GREENHOUSE GAS EMISSIONS

Greenhouse gases (GHGs) are defined as any gas that absorbs infrared radiation in the

atmosphere, including water vapor, carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O)

4.3 AIR QUALITY


4.3-24

and fluorocarbons. These GHGs lead to the trapping and buildup of heat in the atmosphere near

the earth’s surface, commonly known as the “greenhouse effect”. The accumulation of GHGs in

the atmosphere regulates the earth’s temperature. Without natural GHGs, the Earth’s surface

would be cooler (CA 2006b). Emissions from human activities, such as electricity production

and vehicles, have elevated the concentration of these gases in the atmosphere.

GHGs have varying global warming potential (GWP). The GWP is the potential of a gas or

aerosol to trap heat in the atmosphere. Because GHGs absorb different amounts of heat, a

common reference gas (CO2) is used to relate the amount of heat absorbed to the amount of the

gas emissions, referred to as the “CO2 equivalent”. This is the amount of GHGs emitted

multiplied by the GWP. The GWP of CO2 is defined as one, whereas the GWP of methane, for

example, is 2125, meaning that methane gas absorbs 21 25 times as much heat, and therefore has

21 25 times greater impact on global warming per pound of emissions, as CO2.

Water vapor is the most abundant and variable GHG in the atmosphere. It is not considered a

pollutant, however, as in the atmosphere it maintains a climate necessary for life. The main

source of water vapor is evaporation from the oceans (approximately 85 percent). Other sources

include evaporation from other water bodies, sublimation (change from solid to gas) from ice

and snow, and transpiration from plant leaves (AEP 2007).

Carbon dioxide is an odorless, colorless GHG. Natural sources of CO2 include decomposition of

dead organic matter; respiration of bacteria, plants, animals, and fungus; evaporation from

oceans; and volcanic outgassing. Anthropogenic (human caused) sources of CO2 include

burning fuels, such as coal, oil, natural gas, and wood. Atmospheric CO2 concentrations are

currently around 400 ppm (ESRL 2014).

Methane gas is the main component of natural gas used in homes. As discussed above, it has a

GWP of about 2125. Natural sources of methane arise from the decay of organic matter and

from geological deposits known as natural gas fields, from which methane is extracted for fuel.

Sources of decaying organic material include landfills and manure.

Nitrous oxide (NO2) is a colorless gas with a GWP of about 310 298 that is produced by

microbial processes in soil and water, including those reactions which occur in fertilizer

containing nitrogen. In addition to agricultural sources, some industrial processes (nylon

production, nitric acid production) also emit N2O. It is used in rocket engines, as an aerosol

spray propellant, and in race cars. During combustion, NOx (NOx is a generic term for mono-

nitrogen oxides, NO and NO2) is produced as a criteria pollutant (see above), and is not the same

as N2O. Very small quantities of N2O may be formed during fuel combustion by reaction of

nitrogen and oxygen (API 2004).

Chlorofluorocarbons (CFCs) are gases formed synthetically by replacing all hydrogen atoms in

methane or ethane with either chlorine and/or fluorine atoms. CFCs are nontoxic,

nonflammable, insoluble, and chemically nonreactive in the troposphere (the level of air at the

earth’s surface). CFCs were first synthesized in 1928 for use as refrigerants, aerosol propellants,

and cleaning solvents. They destroy stratospheric ozone; therefore their production was stopped

as required by the Montreal Protocol. Hydrofluorocarbons (HFCs) are synthetic man-made

chemicals that are used as a substitute for CFCs in automobile air conditioners and refrigerants.

Perfluorocarbons (PFCs) are used in aluminum production and semiconductor manufacture

industry. In general, fluorocarbons have a GWP of between 140 12 and 11,70014,800.

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4.3-25

Sulfur hexafluoride (SF6) is an inorganic, odorless, colorless, nontoxic, nonflammable gas. It

also has the highest GWP of any gas at 23,900. Sulfur hexafluoride is used for insulation in

electric power transmission and distribution equipment, in the magnesium industry, in

semiconductor manufacturing, and as a tracer gas for leak detection.

Ozone is a greenhouse gas; however, unlike the other greenhouse gases, ozone in the troposphere

is relatively short-lived and therefore is not global in nature. According to CARB, it is difficult

to make an accurate determination of the contribution of ozone precursors (NOx and volatile

organic compounds (VOCs)) to global warming (CARB 2006).

Table 4.3-119 shows a range of gasses that contribute to GHG warming with their associated

global warming potential. The table also shows their estimated lifetime in the atmosphere and the

range in global warming potential over 20 100 years.

4.3.2.1 Physical Setting

Fossil fuel combustion is responsible for the vast majority of the United State’s GHG emissions,

and CO2 is the primary GHG. In 2012, U.S. greenhouse gas emissions totaled 6,526 million

MTCO2e. This 2012 total represents a 5 percent increase since 1990 but a 10 percent decrease

since 2005. GHG emissions peaked at 7,263 in 2007. In 2012, approximately 28 percent of

GHG emissions were associated with transportation, approximately 32 percent were associated

with electricity generation and 20 percent were associated with industrial.The total U.S. GHG

emissions were 6,702 million metric tons of carbon equivalents (MMTCE) in 2011, of which 84

percent were CO2 emissions (EPA 2013). In 2011, approximately 26 percent of GHG emissions

were associated with transportation and about 32 percent with electricity generation (USEPA

2013).

In order to quantify the emissions associated with electrical generation, the “resource mix” for a

particular area must be determined. The resource mix is the proportion of electricity that is

generated from different sources. Electricity generated from coal or oil combustion produces

greater GHG emissions than electricity generated from natural gas combustion due to the higher

carbon content of coal and oil. Electricity generated from wind turbines, hydroelectric dams or

nuclear power is assigned zero GHG emissions. Although these sources have some GHG

emissions associated with the manufacture of the wind generators, the mining and enrichment of

uranium or the displacement of forest areas for reservoirs, these emissions have not been

included in the lifecycle analysis as they are assumed to be relatively small compared to the

electricity generated. Estimates of nuclear power GHG emissions associated with uranium

mining and enrichment range up to about 60 pounds per megawatt-hour (lbs/MWh), or about

five percent of natural gas turbine GHG emissions (CNS 1998).

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Table 4.3-119 Global Warming Potential of Various Gases

Gas Life in the

Atmosphere (years)

100-year GWP

(average)

Carbon

DioxideCarbon

Dioxide 50-20050-200 11

MethaneMethane 1212 2521

Nitrous

OxideNitrous

Oxide 120120 298310

HFCsHFC-23 1.5-264264 12-14,80011,700

Sulfur

HexafluorideHFC-

125 3,20032.6 22,8002,800

HFC-134a 14.6 1,300

HFC-143a 48.3 3,800

HFC-152a 1.5 140

HFC-227ea 36.5 2,900

HFC-236fa 209 6,300

HFC-4310mee 17.1 1,300

CF4 50,000 6,500

C2F6 10,000 9,200

C4F10 2,600 7,000

C6F14 3,200 7,400

SF6 3,200 23,900

Note: GWP = global warming potential

Source: EPA 40 CFR Part 98, Subpart A, Table A-1, dated Nov 29, 2013USEPA 2013. The 100 year timeframe

from the IPCC Second Assessment Report (1995) used for reporting under the UNFCCC values are used in this

report as per the IPCC 2007 and USEPA 2013. These may be revised under the most recent CARB Scoping Plan

CARB 2013.

Detailed information on the power generation plants, their contribution to area electricity

“resource mix” and their associated emissions have been developed by the Federal EPA in a

database called the Emissions & Generation Resource Integrated Database (eGRID). eGRID is a

comprehensive inventory of environmental attributes of electric power systems and is developed

from a variety of data collected by the U.S. Environmental Protection Agency (EPA), Energy

Information Administration (EIA), and Federal Energy Regulatory Commission (FERC). The

most recent version released in 2012 contains information as recent as 2009.

About half of the electricity in the United States is generated from coal, producing a U.S. GHG

emissions level of about 1,222 lbs/MWh. The GHG emissions rate is lower for western states,

primarily due to the increased use of hydroelectric and natural gas. The California area has a

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GHG emission rate of about 661 lbs/MWh due to the contribution of hydroelectric, nuclear and

renewable sources. Table 4.3-120 shows the resource mix and the nationwide and California

GHG emission rates.

Table 4.3-120 Electricity Generation Resource Mix and Greenhouse Gas Emissions

Resource Mix* United States

California Area (CAMX)

Coal 44.5 7.3

Oil 1.1 1.4

Gas 23.3 53.0

Other Fossil 0.3 0.2

Biomass 1.4 2.7

Hydro 6.8 12.7

Nuclear 20.2 14.9

Wind 1.9 2.8

Solar 0.02 0.3

Geo 0.4 4.4

Other 0.1 0.3

Non-Renewables 69.2 62.0

Renewables 30.8 38.0

CO2 Rate, lb/MWh 1,222 661

*Resource Mix is the percentage of total mega-watt hours.

Source: eGRID database with modifications and updates, EPA 2012, data for year 2009.

The Pacific Gas and Electric (PG&E) GHG emission rate is slightly lower than the California

average due to its reliance on nuclear and hydroelectric power. The PG&E service area includes

partial use of electricity from the Diablo Canyon nuclear power plant, the use of hydroelectric in

the Sierra Nevada and the use of geothermal plants located in Nevada. The rate used in this

analysis was taken from CalEEMod modeling program (version 2013.2.2) and is 641 lbs/MWh.

The GHG emission rate for electricity obtained from PG&E is about 45 percent less than the rate

associated with direct natural gas combustion due to the electricity resource mix which includes

non-GHG emission creating resources (hydroelectric, nuclear, renewables).

Calculation of Greenhouse Gas Emissions

The quantification of GHG emissions associated with a particular project can be complex and

relies on a number of assumptions. GHG emissions are, by their nature, cumulative impacts.

Emissions from all sources contribute to the total amount of GHGs in the atmosphere and the

effects of GHG emissions are not limited to the localities where they are generated.

Emissions are generally classified as either direct or indirect. Direct emissions are associated

with the production of GHG emissions at the Project site. These include the combustion of

natural gas in heaters or stoves, the combustion of fuel in engines and construction vehicles, and

fugitive emissions (including methane) from valves and connections.

Indirect emissions include the emissions from vehicles (both gasoline and diesel) delivering

materials and equipment to the site and the use of electricity. Electricity also produces GHG

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emissions because it is often generated using fossil fuels. Indirect GHG emissions associated

with trash hauling and other services that might visit the proposed Project site are incorporated

through the inclusion of the travel of diesel trucks that would visit and service the Project site.

This report utilizes the California Climate Action Registry General Reporting Protocol and the

CARB Compendium of Emission Factors and Methods to support the Mandatory Reporting of

Greenhouse Gas Emissions as methods to calculate GHG emissions (CCAR 2009, CARB 2007).

Statewide Greenhouse Gas Emissions

With a population of 33 million, California is the most populous state in the United States. In

2012, California produced 459 MMTCE of GHG emissions (CARB 2014). Figure 4.3-3 shows

the breakdown of California GHG emissions since 2000. The transportation sector was the

single largest contributor of California’s GHG emissions in 2012, producing 37 percent of the

State’s total GHG emissions. Electrical generation produced 21 percent and industrial processes

produced 19 percent. With a population of over 37 million, California is the most populous state

in the United States. In 2011, California produced close to 456 MTCO2E of GHG emissions

(CARB 2013). Overall, over 80 percent of California’s emissions are CO2 from fossil fuel

combustion (CARB 2013). The transportation sector is the single largest contributor of

California’s GHG emissions, producing 37 percent of the State’s total GHG emissions in 2011.

In contrast, electrical generation produced 19 percent. Nonetheless, California ranks fourth

lowest of the 50 states in CO2 emissions per capita. Figure 4.3-2 shows the historical GHG

emissions in California.

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Figure 4.3-2 California GHG Emissions 2000-2011

Source: CARB website 2014

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Source: CARB 2013

Impacts of GHG Emissions

Global climate change is a change in the average weather of the earth, which can be measured by

wind patterns, storms, precipitation, and temperature. Historical records have shown that

dramatic temperature changes have occurred in the past, such as during previous ice ages. Some

data indicate that the current temperature record differs from previous climate changes in both

rate and magnitude (AEP 2007, IPCC 2014). These climate changes could lead to alterations in

weather, rainfall patterns, and increasing sea levels leading to flooding. The worldwide scientific

consensus is that global climate change is caused by anthropogenic GHG emissions. The issue

of how best to respond to climate change and its effects is currently one of the most widely

debated economic and political issues in the United States.

Atmospheric CO2 concentrations are currently around 400 ppm (ESRL 2014) and concentrations

may increase to 540 ppm by 2100 as a direct result of anthropogenic sources.

CARB (CARB 2008) notes that a warming California climate would generate more smoggy days

by contributing to ozone formation while also fostering more large brush and forest fires.

Continuing increases in global greenhouse gas emissions at business-as-usual rates would result,

by late in the century, in California losing 90 percent of the Sierra snowpack, sea level rising by

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more than 20 inches, and a three to four times increase in heat wave days. Increases in

temperature will lead to increased concentrations and emissions of harmful pollutants in

California. The California State Assembly Select Committee Sea Level Rise and the California

Economy issued a report in 2014 (CSA 2014) indicating that sea level rise could total 1.4 to 5.5

feet by 2100 in Southern California, giving rise to impacts on infrastructure, saltwater intrusion,

and coastal erosion.

In the Findings and Declarations for AB 32 (the California Global Warming Solutions Act of

2006), the state Legislature found that:

The potential adverse impacts of global warming include the exacerbation of air

quality problems, a reduction in quality and supply of water to the state from the

Sierra snowpack, a rise in sea levels resulting in the displacement of thousands of

coastal businesses and residences, damage to the marine ecosystems and the

natural environment, and an increase in the incidences of infectious diseases,

asthma, and other health-related problems.

Warming of the climate system is unequivocal, and since the 1950s, many of the observed

changes are unprecedented over decades to millennia. The atmosphere and ocean have warmed,

the amounts of snow and ice have diminished, and sea level has risen (IPCC 2014).

The linear warming trend over the years from 1951 to 2012 (0.12 °C per decade) is nearly twice

that for the 100 years from 1906 to 2005. Over the period 1901 to 2010, global mean sea level

rose by 8 inches (IPCC 2014).

AB 32 addresses the results of these studies conducted by the Intergovernmental Panel on

Climate Change (IPCC 2001, 2007, 2014) that examined a range of scenarios that estimated an

increase in globally averaged surface temperature and ocean rise by 2100 due to human causes.

The IPCC Studies indicate that “In order to stabilize the concentration of GHGs in the

atmosphere, emissions would need to peak and decline thereafter. The lower the stabilization

level, the more quickly this peak and decline would need to occur”. The studies also found that

stabilization of atmospheric CO2 concentrations at less than 450 ppm would limit temperature

rise to less than 3.6°F by the year 2100 and would require global anthropogenic CO2 emissions

to drop below the year 1990 levels within a few decades (by 2020). If GHG emissions, and

atmospheric CO2 levels, were kept to this "low" or “Category I” level impacts to gross domestic

product (GDP) are projected to “produce market benefits in some places and sectors while, at the

same time, imposing costs in other places and sectors” (IPCC 2007, 2014). Higher levels of

CO2, could cause a reduction in global GDP of more than 5%, with regional losses substantially

higher. Scenarios that are likely to maintain warming at below 3.6 F are characterized by a 40

percent to 70 reduction in GHG emissions by 2050, relative to 2010 levels, and emissions level

near zero or below in 2100.

Warming of the climate system is unequivocal, as is now evident from observations of increases

in global average air and ocean temperatures, widespread melting of snow and ice and rising

global average sea level. The linear warming trend over the 50 years from 1956 to 2005 (0.13 °C

per decade) is nearly twice that for the 100 years from 1906 to 2005. Global average sea level

rose at an average rate of 1.8 mm per year over 1961 to 2003 and at an average rate of about 3.1

mm per year from 1993 to 2003 (IPCC 2007).

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AB 32 addresses the results of studies conducted by the Intergovernmental Panel on Climate

Change (IPCC 2001, 2007) that examined a range of scenarios that estimated an increase in

globally averaged surface temperature of 0.5 to 11.5°F over the period 1990 to 2100, with ocean

rise between 0.6 to 1.9 feet over the same timeframe.

The IPCC Studies (2007) indicate that “In order to stabilize the concentration of GHGs in the

atmosphere, emissions would need to peak and decline thereafter. The lower the stabilization

level, the more quickly this peak and decline would need to occur”. The studies also found that

stabilization of atmospheric CO2 concentrations at less than 450 ppm would limit temperature

rise to less than 3.6°F by the year 2100 and would require global anthropogenic CO2 emissions

to drop below the year 1990 levels by 2020. If GHG emissions, and atmospheric CO2 levels,

were kept to this “Category I” level (producing increases in global average temperature of less

than 1.8-5.4 °F above 1980-1999 levels), impacts to gross domestic product (GDP) are projected

to “produce market benefits in some places and sectors while, at the same time, imposing costs in

other places and sectors” (IPCC 2007). Higher levels of CO2, ranging above 700 ppm with

corresponding temperature increases of 7°F, could cause a reduction in global GDP of more than

5%, with regional losses substantially higher. Reductions in GHG emissions between the year

2000 and the year 2050 would need to be 50-85% in order to be kept in this "Category 1" level

(IPCC 2007 Table 4.3-1 and Figure 4.3-1), with global GHG emissions peaking in the years

2010 to 2015.

Therefore, stabilizing GHG emissions levels at 1990 levels over the next 2 decades, and reducing

GHG emissions by 50-85% by the year 2050, would reduce the impacts of climate change to

"Category 1" levels that would produce nominal changes in global average GDP and would be

less than significant.

Countywide Greenhouse Gas Emissions

The Santa Barbara County Climate Action Strategy (CAS) is being developed to address

greenhouse gas (GHG) emissions pursuant to the Board of Supervisors’ March 2009 direction

(BOS Resolution 09-059) “to take immediate, cost effective, and coordinated steps to reduce the

County’s collective GHG emissions.“ The CAS follows a two-phase structure to reduce

emissions. Phase 1 is preparation of a Climate Action Study and phase 2 is the development of

an Energy and Climate Action Plan. The Study is the first phase of the CAS. It includes: a GHG

inventory and forecast for the unincorporated County, a discussion of GHG emission reduction

target options that the County could pursue, a list of current County activities which reduce GHG

emissions, evaluation of potential additional emission reduction measures (ERMs) the County

could implement, and recommendations for implementation of the Study through an Energy and

Climate Action Plan (ECAP).

The Climate Action PlanECAP would represent the second phase of the CAS and would seek to

reduce the County’s GHG emissions through implementation of selected programs with the goal

of achieving a GHG reduction target to be selected by the Board as part of the CAP.

Additionally, a CAP could allow for programmatic mitigation of GHG emissions as required

under CEQA.

The Climate Action Study was released in September 2011 and addresses municipal operations,

countywide operations and implementation. Total GHG emissions were estimated at about 1.5

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million tons in 2007. See Figure 4.3-3 for a categorization of the County’s GHG emissions. The

ECAP was recently update in August 2014.

Figure 4.3-3 Santa Barbara County GHG Emissions – 2007 revised

Note: Total emissions equal 1,522.410 metric tonnes of CO2e. Figure shows unincorporated Santa Barbara County

only. It does not include emissions from other sources in County, such as cities, state and federal lands, Native

American reservations, UCSB, and offshore seeps.

Source: SBC 2012 revised 2013.

Baseline Operations GHG Emissions

GHG emissions are produced both from fugitive emissions of gasses that contain some methane

as well as from trucks used to transport crude oil from the Cantin and GWP Leases to the SMPS.

Total baseline (year 2013) GHG emissions are estimated to be 135 MTCO2e annually. See

Appendix 4 for more details. Since the NOP was issued, in August 2014, crude production

levels, and associated trucking, has increased to 3,400 bpd, in August 2014, which would

generate about 300 MTCO2e per year.

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4.3.2.2 GHG Regulatory Setting

International GHG Regulations

Kyoto Protocol

The Kyoto Protocol is a treaty made under the United Nations Framework Convention on

Climate Change, which was signed on March 21, 1994. The Convention was the first

international agreement to regulate GHG emissions. It has been estimated that if the

commitments outlined in the Kyoto Protocol are met, global GHG emissions would be reduced

by an estimated 5 percent from 1990 levels during the first commitment period from 2008 until

2012. However, while the US is a signatory to the Kyoto Protocol, Congress has not ratified it;

therefore, the US is not bound by the Protocol’s commitments.

Federal GHG Regulations

Clean Air Act

In the past, the US EPA has not regulated GHG under the Clean Air Act. However, in 2007 the

US Supreme Court held that the EPA can, and should, consider regulating motor-vehicle GHG

emissions. In Massachusetts v. Environmental Protection Agency, 12 states and cities, including

California, in conjunction with several environmental organizations sued to force the EPA to

regulate GHG as a pollutant pursuant to the Clean Air Act (US Supreme Court No. 05-1120;

127 S.Ct. 1438 (2007)). The Court ruled that GHG fit within the Clean Air Act’s definition of a

pollutant and that the EPA’s reason for not regulating GHG was insufficiently grounded.

40 CFR Section 98 specifies mandatory reporting requirements for a number of industries. The

final 40 CFR part 98 applies to certain downstream facilities that emit GHG, and to certain

upstream suppliers of fossil fuels and industrial GHG. For suppliers, the GHG emissions

reported are the emissions that would result from combustion or use of the products supplied.

The rule also includes provisions to ensure the accuracy of emissions data through monitoring,

recordkeeping and verification requirements. The mandatory reporting requirements generally

apply to facilities that produce more than 25,000 MTCO2E (or 10,000 MTCO2E for combustion

and process source emissions).

State GHG Regulations and Programs

Executive Order S-3-05

The 2005 California Executive Order S-3-05 established the following GHG emission-reduction

goals for California:

By 2010, reduce GHG emissions to 2000 levels;

By 2020, reduce GHG emissions to 1990 levels; and

By 2050, reduce GHG emissions to 80 percent below 1990 levels.

The Secretary of the California Environmental Protection Agency (CalEPA) is charged with

coordinating oversight of efforts to meet these targets and formed the Climate Action Team to

carry out the Order. Emission reduction strategies or programs developed by the Climate Action

Team to meet the emission targets are outlined in a March 2006 report (CalEPA 2006). The

Climate Action Team also provided strategies and input to the CARB Scoping Plan.

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Executive Order B-16-2012

The 2012 California Executive Order B-16-2012 directed that all State entities support and

facilitate the rapid commercialization of zero-emission vehicles. The directive ordered state

agencies to work with the Plug-in Electric Vehicle Collaborative and the California Fuel Cell

Partnership to achieve by 2015 that the State’s major metropolitan areas will be able to

accommodate zero-emission vehicles, each with infrastructure plans and streamlined permitting.:

Assembly Bill 1493

In 2002, the legislature declared in AB 1493 (the Pavley regulations) that global warming was a

matter of increasing concern for public health and the environment in the state. AB 1493

required the CARB to develop and adopt GHG emission standards for automobiles. The CARB

responded by adopting CO2-equivalent fleet average emission standards. The standards will be

phased in from 2009 to 2016, reducing emissions by 22 percent in the “near term” (2009 to

2012) and 30 percent in the “mid-term” (2013 to 2016), as compared to 2002 fleets.

The legislature passed amendments to AB 1493 in September 2009. Implementation of AB 1493

requires a waiver from the EPA, which was granted in June 2009.

Assembly Bill 32

AB 32 codifies California’s GHG emissions 2020 goal by requiring the state to reduce global

warming emissions to 1990 levels by 2020. It further directs the CARB to enforce the statewide

cap that would begin phasing in by 2012. AB 32 was signed and passed into law by Governor

Arnold Schwarzenegger on September 27, 2006. Key milestones of AB 32 include:

June 20, 2007 – Identification of “discrete early action GHG emission-reduction measures.”

January 1, 2008 – Identification of the 1990 baseline GHG emissions levels and approval of a

statewide limit equivalent to that level. Adoption of reporting and verification requirements

concerning GHG emissions.

January 1, 2009 – Adoption of a scoping plan for achieving GHG emission reductions.

January 1, 2010 – Adoption and enforcement of regulations to implement the actions.

January 1, 2011 – Regulatory adoption of GHG emission limits and reduction measures.

January 1, 2012 – GHG emission limits and reduction measures become enforceable.

Since the passage of AB 32, the CARB published Proposed Early Actions to Mitigate Climate

Change in California. This publication indicated that the issue of GHG emissions in CEQA and

General Plans was being deferred for later action, so the publication did not discuss any early

action measures generally related to CEQA or to land use decisions.

California Senate Bill 1368

In 2006, the California legislature passed SB 1368, which requires the Public Utilities

Commission (PUC) to develop and adopt a “greenhouse gases emission performance standard”

by March 1, 2007, for private electric utilities under its regulation. The PUC adopted an interim

standard on January 25, 2007, requiring that all new long-term commitments for base load

generation involve power plants that have emissions no greater than a combined cycle gas

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turbine plant. That level is established at 1,100 lbs/MWh of CO2. The California Energy

Commission has also adopted similar rules.

Senate Bill 97 – CEQA: Greenhouse Gas Emissions

In August 2007, Governor Schwarzenegger signed into law SB 97 – CEQA: Greenhouse Gas

Emissions, SB 97 requires the Office of Planning and Research (OPR), by July 1, 2009, to

prepare, develop, and transmit to the Resources Agency guidelines for the feasible mitigation of

GHG emissions or the effects of GHG emissions, as required by CEQA, including, but not

limited to, effects associated with transportation or energy consumption.

Office of Planning and Research Technical Advisory and Preliminary Draft CEQA Guidelines

Amendments for Greenhouse Gas Emissions

Consistent with SB 97, on March 18, 2010, the CEQA Guidelines were amended to include

references to GHG emissions. The amendments offer guidance regarding the steps lead agencies

should take to address climate change in their CEQA documents.

According to OPR, lead agencies should determine whether GHG may be generated by a

proposed project, and if so, quantify or estimate the GHG emissions by type and source. Second,

the lead agency must assess whether those emissions are cumulatively significant. When

assessing whether a Project’s effects on climate change are cumulatively considerable, even

though its GHG contribution may be individually limited, the lead agency must consider the

impact of a project when viewed in connection with the effects of past, current, and probable

future projects. Finally, if the lead agency determines that the GHG emissions from a proposed

project are potentially significant, it must investigate and implement ways to avoid, reduce, or

otherwise mitigate the impacts of those emissions.

The Amendments do not identify a threshold of significance for GHG emissions, nor do they

prescribe assessment methodologies or specific mitigation measures. The Preliminary

Amendments maintain CEQA discretion for lead agencies to establish thresholds of significance

based on individual circumstances.

California Air Resources Board: Scoping Plan

On December 11, 2008, the CARB adopted the Scoping Plan as directed by AB 32 (CARB

2008). The Scoping Plan proposes a set of actions designed to reduce overall GHG emissions in

California. The numerous measures in the Scoping Plan approved by the Board are being

implemented in phases with Early Action Measures that have already been implemented.

Measures include a cap-and-trade system, car standards, low carbon fuel standards, landfill gas

control methods, energy efficiency, green buildings, renewable electricity standards, and

refrigerant management programs.

Since 2008, ARB has updated the projected business as usual (BAU) emissions based on current

economic forecasts (i.e., as influenced by the economic downturn) and GHG-reduction measures

already in place. The BAU projection for 2020 GHG emissions in California was originally, in

the 2008 Scoping Plan, estimated to be 596 MMTCO2E. ARB subsequently derived an updated

estimate of emissions by considering the influence of the recent recession and reduction

measures that are already in place. The 2011 Scoping plan estimates the year 2020 emissions at

507 MMTCO2E (as the BAU estimate).

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The 2011 Scoping Plan concluded that achieving the 1990 levels by 2020 meant cutting

approximately 16 percent, compared to the original 2008 Scoping Plan that estimated a 29%

reduction (CARB 2011). The 2011 Scoping Plan sets forth the expected GHG emission

reductions from a variety of measures, including the Pavley I automobile standards and the

Renewables Portfolio Standard, neither of which were assumed in the 2008 Scoping Plan.

CARB approved the first update to the Scoping Plan on May 22, 2014 with recommendations for

a mid-term target (between 2020 and 2050) and sector-specific actions. The First Update

addresses issues such as a revision to the GWP for gasses (to a 20 year instead of the 100 year

timeframe), the establishment of a mid-term 2030 goal (of between 33-40% reduction over 1990

levels), and the development of post-2020 emissions caps related to Cap-and-Trade to reflect the

establishment of a 2030 midterm target. This first revision also provides an update on climate

science and a report on progress toward the 2020 target, including achievements of the 2008 and

2011 Scoping Plans, an update on the inventory of GHG emissions, and an update of the

economy and its potential affect on future emissions’ forecasting. It also addresses post-2020

goals, including Executive Order S-3-05.

The Scoping Plan provides an approach to reduce emissions to achieve the 2020 target, and to

initiate the transformations required to achieve the 2050 target. The 2008 Scoping Plan indicated

that a 29 percent reduction below the estimated “business as usual” levels would be necessary to

return to 1990 levels by 2020. The 2011 supplement (Functional Equivalent Document) to the

Scoping Plan emission inventory revisions indicated that a 16 percent reduction below the

estimated “business as usual” levels would be necessary to return to 1990 levels by 2020. This

revision was due to the slowing economy between 2008 and 2010 and to reduction measures that

were already in place (CARB, 2011a, p. 10). The first update of the Scoping Plan was approved

by the state Air Resources Board on May 22, 2014. The next update is required in 2018.

Scoping Plan 2014 First Update Document

The Board approved the First Update to the Climate Change Scoping Plan on May 22, 2014.

The First Update to California’s Climate Change Scoping Plan was developed by the Air

Resources Board in collaboration with the Climate Action Team. The First Update indicates that

California is on track to meet the near-term 2020 greenhouse gas limit and is well positioned to

maintain and continue reductions beyond 2020 as required by AB 32. It also encourages the

adoption of a mid-term target to help achieve the year 2050 goal.

California Air Resource Board Cap-and-Trade Regulation

The California Air Resource Board has implemented a cap-and-trade type program, as per the

Scoping Plan, applicable to specific industries that emit more than 25,000 MTCO2E. The AB 32

Scoping Plan identifies a Cap-and-Trade program as one of the strategies California will employ

to reduce the greenhouse gas (GHG) emissions that cause climate change. Under cap-and-trade,

an overall limit on GHG emissions from capped sectors will be established by the Cap-and-Trade

program and facilities subject to the cap will be able to trade permits (allowances) to emit GHGs.

The program started on January 1, 2012, with an enforceable compliance obligation beginning

with the 2013 GHG emissions for GHG emissions from stationary sources. The petroleum and

natural gas systems sector is covered starting in 2013 for stationary and related combustion,

process vents and flare emissions if the total emissions from these sources exceed 25,000

MTCO2E per year. Suppliers of natural gas and transportation fuels are covered beginning in

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2015 for combustion emissions from the total volume of natural gas delivered to non‐covered

entity or for transportation fuels.

California Climate Action Registry General Reporting Protocol

The California Climate Action Registry is a program of the Climate Action Reserve and serves

as a voluntary GHG registry. The California Climate Action Registry was formed in 2001 when

a group of chief executive officers, who were investing in energy efficiency projects that reduced

their organizations’ GHG emissions, asked the state to create a place to accurately report their

emissions history. The California Climate Action Registry publishes a General Reporting

Protocol, which provides the principles, approach, methodology, and procedures to estimate such

emissions.

California Air Resource Board Proposed Mandatory Reporting Regulation

The Air Resources Board approved a mandatory reporting regulation in December 2007, which

became effective January 2009 (which appears at sections 95100-95133 of Title 17, California

Code of Regulations), which require the mandatory reporting of GHG emissions for specific

industries emitting more than 10,000 - 25,000 MTCO2E or 10,000 MTCO2E for combustion and

processdepending on the source emissions.

4.3.2.3 GHG Impact Assessment

The Notice of Preparation for this EIR identified a potential for greenhouse gas emissions to

result from the proposed Project, and that such emissions would not be expected to exceed the

prescribed threshold during long-term operations. n addition, potential greenhouse gas emissions

related to trucking of oil could be reduced over the long-term with use of the pipeline rather than

trucking to transport oil to the Santa Maria Pump Station. These are discussed below.

Greenhouse Gas Thresholds

Climate Change under CEQA differs from most other types of impacts in that, by definition, it is

only examined as a cumulative impact that results not from any one project under CEQA, but

rather from greenhouse gas (GHG) emissions “…generated globally over many decades by a

vast number of different sources.” (Kostka, 2007, §20.83; Hegerl, 2007.) Accordingly, climate

change is treated herein as a cumulative impact, subject to the CEQA Guidelines for conducting

cumulative impact analyses. CEQA Guidelines direct that a project’s contribution to a significant

cumulative impact will be rendered less than significant if the project is required to implement or

fund its fair share of a mitigation measure designed to alleviate the cumulative impact

(§15130(a)(3)). Such determinations must be based on analysis in the environmental document

with evidence to demonstrate that mitigation required of a project represents the project’s “fair-

share” contribution.

Recently, the California Natural Resources Agency amended the Guidelines for Implementation

of the California Environmental Quality Act in 2009, placing specific requirements on CEQA

lead agencies for the treatment of greenhouse gas emissions in environmental documents. Under

CEQA, lead agencies must “…make a good-faith effort, based to the extent possible on scientific

and factual data, to describe, calculate, or estimate the amount of greenhouse gas emissions

resulting from a project” (Section 15064.4 was added to the CEQA Guidelines on October 23,

2009). These amendments further obligate the lead agency to consider if the estimated amount

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of greenhouse gas (GHG) emissions from a proposed project exceed a threshold of significance

that the lead agency determines to apply to the project, and consider the extent to which the

project complies with regulations or requirements adopted to implement a statewide, regional, or

local plan for the reduction or mitigation of GHG emissions.

Santa Barbara County and the Santa Barbara County Air Pollution Control District (APCD) are

currently developing draft thresholds for determining if the projected GHG emissions of a

proposed project constitute a considerable contribution to global climate change, and therefore

would be classified as a cumulative significant impact. Absent formally adopted thresholds, the

CEQA lead agency must make such significance determinations on a case-by case basis.

California does not have one, statewide-accepted significance threshold as of yet. Several

approaches have been discussed and, to some extent, implemented (CAPCOA 2008, pp. 23-57;

Crockett 2011, pp. 213-245). Some have been, or are being, litigated. These approaches are

numerous but generally fall into one of two categories for addressing stationary sources of GHG

emissions: Numeric “Bright Line” thresholds or a specified reduction in “Business as Usual”

(BAU) thresholds.

Numeric Bright-Line Thresholds

Numeric bright line thresholds are specific numeric thresholds above the baseline operations

that, if exceeded, would produce a significant cumulative impact. To date, bright line thresholds

have ranged from zero to 100,000 metric tonnes of CO2 equivalent (MTCO2E) annually. With

the exception of a threshold of zero, sources that produce emissions below the threshold are

considered insignificant, and thus do not have to reduce their GHG emissions, based on their

relatively small individual and cumulative contributions. The Bright Line threshold approach has

the advantage of being easy to apply; however, it more strictly regulates larger sources than

smaller sources.

Multiple agencies/districts have applied bright line thresholds. For example, the South Coast Air

Quality Management District (SCAQMD), the Bay Area Air Quality Management District

(BAAQMD) and the San Luis Obispo Air Pollution Control District (SLOAPCD) and the

County of San Luis Obispo have established 10,000 MTCO2E per year CEQA interim

significance thresholds for industrial/stationary sources that apply to all components of a

proposed project (i.e .. GHG emissions from stationary and non-stationary sources).

Alternatively. the Bay Area Air Quality Management District (BAAOMD) and the County of

San Diego have established 10,000 MTCO2e per year CEOA interim significance thresholds for

GHG emissions only from stationary-source components of a proposed project, and employ

different bright-line thresholds (1,100 and 2,500 MTCO2e per year, respectively) for GHG

emissions derived from mobile and indirect sources of GHG emissions.

The 10,000is threshold was applied to the Santa Maria Energy project Project approved by the

County in November 2013.

BAU Thresholds

BAU thresholds are based on a reduction from a “business-as-usual” scenario, where BAU

emissions equate to the emissions that would have occurred in the absence of the mandated

reductions under AB 32 programs. In the CARB Scoping Plan, the BAU case is a representation

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of what the State of the California economy will be in the year 2020 assuming that none of the

measures recommended in the Scoping Plan are implemented.

Project EIR Significance Threshold

The approach taken in this EIR is to screen out the smaller projects as having a less than

significant impact if they are below a 10,000 MTCO2e emissions levels. If a project exceeds the

10,000 MTCO2e level, then mitigation will be developed on a case-by-case basis to establish

consistency with the AB 32 goals.

Project GHG Impacts

GHG emissions are generated onsite due to combustion in the heater and fugitive emissions from

tanks, valves, and the light crude oil unloading components, which contain methane and carbon

dioxide. In addition, offsite vehicles, including the LCO trucks and employees, also generate

GHG emissions. Electrical use to power the pumps and miscellaneous equipment, estimated at a

500 kW annual average load (for the proposed Project at 25,000 bpd), would also generate

emissions offsite. CalEEMod GHG intensity factors for Pacific Gas & Electric were used to

estimate the GHG emissions from electricity generation. Greenhouse gas emissions associated

with trucking the crude oil (baseline of 1,2911,300 bpd; _an average of 8.21_ truck trips per day)

would be eliminated. Table 4.3-131 summarizes the proposed project’s operational GHG

emissions.

Table 4.3-131 Proposed Project Operational GHG Emissions, tons/year

Emission Sources N2O CH4 CO2 MTCO2e

Normal Operations

Onsite Fugitives 0.000 0.7546 0.9 1410.6

Onsite Combustion 0.010 1.6550 5,460 4,946952

Offsite Emissions 0.002 0.002 1254.6 1132.7

Electricity 0.014 0.1064 1404.5 1,269

Total Project** 6,3487

Baseline (trucking, etc.) (1365)

Net Increase over baseline 6,212

Screening Threshold 10,000

Significant? No Notes: * for mobile sources only. ** GHG from construction are included herein. Construction emissions would

total 108 MTCO2e. Amortized over 25 years, this adds about 4 MTCO2e per year.

During maintenance operations, increased trucking would contribute to GHG emissions.

Emergency trucking for 30 days would add about 200 MTCO2e to the annual GHG emissions.

Emissions of GHG would be below the screening threshold and impacts would therefore be less

than significant (Class III).

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4.3.2.4 Greenhouse Gas References

AEP 2007. Recommendations by the Association of Environmental Professionals (AEP) on

How to Analyze Greenhouse Gas Emissions and Global Climate Change in CEQA

Documents. Comment Draft. White Paper. March.

American Industrial Hygiene Association, ODOR Thresholds for Chemicals with Established

Occupational Health Standards, 1989.

American Petroleum Institute (API), 2004. Compendium Of Greenhouse Gas Emissions

Methodologies For The Oil And Gas Industry, Feb, 2004.

CalEEMod 2013, California Emission Estimator Model, http://www.caleemod.com/

CARB 2013, Website standards designations, http://www.arb.ca.gov/desig/desig.htm

CARB Air Quality Data, http://www.arb.ca.gov/adam/index.html

CARB Speciation Profiles, 2013 http://www.arb.ca.gov/ei/speciate/speciate.htm

CARB 2006. Public Workshop to Discuss Establishing the 1990 Emissions Level and the

California 2020 Limit and Developing Regulations to Require Reporting of Greenhouse Gas

Emissions; December 1; Sacramento, CA.

CARB 2008. Climate Change Proposed Scoping Plan; December.

CARB, 2014. First Update to Climate Change Scoping Plan, May 22.

http://www.arb.ca.gov/cc/scopingplan/scopingplan.htm

CARB 2007, CARB Compendium Of Emission Factors And Methods To Support Mandatory

Reporting Of Greenhouse Gas Emissions, Subchapter 10, Article 2, sections 95100 to 95133,

title 17, California Code of Regulations

CARB 2011, California Air Resources Board, Attachment D: Final Supplement to the AB 32

Scoping Plan Functional Equivalent Document, August 19, 2011.

http://www.arb.ca.gov/cc/scopingplan/fed.htm

CARB 2011b “Status of Scoping Plan Recommended Measures,” July 2011.

http://www.arb.ca.gov/db/search/search_result.htm?q=Status+of+Scoping+Plan+Recommen

ded+Measures&which=arb_google&cx=006180681887686055858%3Abew1c4wl8hc&srch_

words=&cof=FORID%3A11&submit.x=15&submit.y=10

CARB, 2011c. California Air Resources Board, Overview of ARB Emissions Trading Program,

Revised 10/20/11. http://www.arb.ca.gov/newsrel/2011/cap_trade_overview.pdf

CARB, 2012. California Air Resources Board, Greenhouse Gas Facility Emissions Report to the

California Air Resources Board – 2010. www.arb.ca.gov/cc/reporting/ghg-

rep/reported_data/ghg-reports.htm

CARB 2013, Climate Change Scoping Plan First Update Discussion Draft for Public Review and

Comment, October 2013

http://www.arb.ca.gov/desig/desig.htm

http://www.arb.ca.gov/adam/index.html

http://www.arb.ca.gov/ei/speciate/speciate.htm

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CARB, 2013a. California Air Resources Board, Annual Summary of 2011 Greenhouse Gas

Emissions Data Reported to the California Air Resources Board, January 11, 2013, (Excel

spreadsheet). www.arb.ca.gov/cc/reporting/ghg-rep/reported_data/ghg-reports.htm

CARB, 2013b. California Air Resources Board, Greenhouse Gas Inventory Data – 2000 to 2011,

issued 2013. http://www.arb.ca.gov/cc/inventory/data/data.htm

Canadian Nuclear Society (CNS). 1998. 19th Annual Conference. October.

CCAR 2009. California Climate Action Registry General Reporting Protocol Version 3.1,

January.

Crockett, 2011. Crockett, Alexander, “Addressing the Significance of Greenhouse Gas

Emissions Under CEQA: California’s Search for Regulatory Certainty in an Uncertain

World,” Golden Gate University Environmental Law Journal, Volume 4, Issue 2 (2011),

Article 3.

CSA 2014, California State Assembly Select Committee Sea Level Rise and the California

Economy, Sea-Level Rise: a Slow-Moving Emergency, August 2014

Duffee 1991, with O'Brien, Ostojic, Odor Modeling - Why and How. Page 295, Recent

Developments and Current Practices in Odor Regulations, Controls and Technology. Air &

Waste Management Association, 1991.

ESRL 2014. Earth System Research Laboratory, Global Monitoring Division, NOAA.

http://www.esrl.noaa.gov/gmd/ July 7.

Environmental Protection Agency (EPA). 2007. Inventory of U.S. Greenhouse Gas Emissions

and Sinks: 1990-2005. USEPA #430-R-07-002.

Environmental Protection Agency (EPA). 2012. The Emissions & Generation Resource

Integrated Database for 2012 (eGrid2012) Technical Support Document.

ESRL, Earth Systems Research Laboratory, NOAA, website, http://www.esrl.noaa.gov/ accessed

2014.

IPCC 2007 Intergovernmental Panel on Climate Change. 2007. “Fourth Assessment Report”.

2007.

IPCC 2014, Intergovernmental Panel on Climate Change (Climate change 2014: Synthesis

Report). Available from http://www.ipcc.ch/

Hegerl, 2007. Hegerl, G.C., et. al., “Chapter 9: Understanding and Attributing Climate Change,”

Climate Change 2007: The Physical Basis, Contribution of Working Group I to the Fourth

Assessment Report of the Intergovernmental Panel on Climate Change (Cambridge:

Cambridge University Press, 2007).

Kostka, 2013. Kostka, Stephen L and Michael H. Zischke, Practice Under the California

Environmental Quality Act Second Edition, Volume 2, (Oakland, CA: 2013, Continuing

Education of the BAR).

http://www.esrl.noaa.gov/gmd/

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Santa Barbara County 2012, Baseline and Forecasted Community GHG Emissions Inventory,

March 2012, Revise January 2013

Santa Barbara County APCD 20141. Scope and Content of Air Quality Sections in

Environmental Documents. Updated March 2014.

US EPA 2013, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 – 2011

4.3.3 PROJECT ALTERNATIVES ANALYSIS

Alternatives analyzed below include the No Project Alternative and the Due North Alternative

pipeline route. The alternatives are compared to the proposed Project in Section 6.0.

No Project. Under the No Project alternative, the pipeline would not be built and the equipment

would not be installed at the Cantin Lease. Without the pipeline, crude oil would continue to be

transported by truck, up to the APCD limits of 600 bpd from the Cantin Lease and 2,500 bpd

from the GWP Lease. Emissions from equipment at the Cantin lease would increase due to the

increased crude oil loading and storage, increasing fugitive emissions from tank and the loading

facility. These increased emissions would be less than the proposed Project due to the reduced

throughput, but less than significant (Class III).

Due North. This alternative pipeline route would be approximately 4,000 feet shorter than the

proposed Project pipeline route. Emissions from the Cantin Lease would be identical to the

proposed Project as the same equipment would be installed and utilized to the same extent. The

only difference would be related to construction, which would generate fewer total emissions as

less pipeline would need to be installed. This alternative reduces the air pollutant emissions

compared to the proposed Project primarily through a reduced pipeline length and construction

requirements. However, as the same daily construction activities would be occurring (just over

fewer days), the peak-day emissions related to construction would be the same as for the

proposed Project. Overall, construction air quality impacts for this alternative would be less than

significant (Class III). Operational impacts would be the same as the Proposed Project.

Odor impacts and toxic impacts would be the same as for the proposed Project; less than

significant (Class III).

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