HomeMy WebLinkAboutEnergize Eastside Phase 2 Draft EIS_Volume 2_Appendices
Energize Eastside Project
Phase 2 Draft Environmental Impact Statement
Volume 2: Appendices
May 8, 2017
Prepared for the Cities of Bellevue,
Newcastle, Redmond and Renton
Prepared by:
ESA
General Construction and
Access Description
A
PHASE 2 DRAFT EIS PAGE A‐1
APPENDIX A CONSTRUCTION AND ACCESS MAY 2017
APPENDIX A. GENERAL CONSTRUCTION AND
ACCESS DESCRIPTION
Note: Information provided by PSE
Construction of transmission lines require pre-construction field surveying, site preparation,
construction (i.e., installation of new structures, removal of existing structures), demobilization, and
property restoration, which are performed following a relatively standardized sequence.
In general, construction activities include the installation of new structures, removal of existing
structures, and property restoration. PSE aims to avoid or minimize impacts where practicable through
project design considerations (e.g., pole types and access routes). Along some route segments, PSE has
easement rights that outline access agreements for the purpose of maintaining PSE’s existing facilities
and/or accessing PSE’s right-of-way (ROW). Depending upon the segments chosen for the preferred
route option, PSE plans to exercise these rights and, if necessary, acquire additional rights for
construction of the project. To the extent possible, PSE uses existing or acquires new easement rights to
provide access necessary to maintain and/or construct facilities.
TYPICAL CONSTRUCTION SEQUENCING
Construction of a transmission line typically occurs in the following sequence:
1) Pre-construction surveying
a. Conducting environmental surveys and obtaining geotechnical data by
conducting soil borings
b. Identifying pole locations
c. Surveying, including ROW and boundary and structure locations (i.e.,
footings, underground utilities)
2) Site preparation
a. Staking the ROW, critical areas, and pole locations
b. Installing temporary erosion control measures
c. If necessary, constructing access routes to the pole sites and developing
installation sites
d. Brushing, trimming, and clearing of vegetation in the ROW to ensure the
safe operation of the line
3) Construction
a. Installing pole foundations or auger holes for direct embedment
b. Assembling and erecting the poles
c. Stringing the conductor and wires
d. Removing existing structures, if necessary
PHASE 2 DRAFT EIS PAGE A‐2
APPENDIX A CONSTRUCTION AND ACCESS MAY 2017
4) Demobilization and clean up
5) Restoration and re-planting vegetation
The general process for the various types of poles being proposed are essentially the same, except for
poles with engineered foundations (e.g., drilled piers), which require additional steps.
The subsequent sections describe specific construction activities in further detail.
PRE-CONSTRUCTION - IDENTIFYING POLE LOCATIONS
The placement, or “spotting,” of poles depends upon factors such as available ROW width, location of
access routes, topography, and obstacle avoidance. In turn, the height, loading, foundation type, and
overall size of each structure will be greatly affected by the location of the structures.
The process for the spotting of poles is as follows:
PSE will work with individual landowners to adjust pole locations where practicable to
reduce impacts for the landowners.
Proposed pole locations discussed with landowners will represent where poles are generally
expected to be located, pending geographical and site-specific environmental review
following city or county approval of a route. Unforeseen subsurface obstacles, such as
geologic erratics, can cause a pole to be moved up or down the corridor (typically less than
20 feet).
In general, PSE considers the following factors when locating poles:
Technical considerations, including electrical clearances, severe terrain accommodations,
structural loading, manufacturability of structures, constructability of the line, and code
requirements.
Critical Areas (e.g., wetlands and streams) so as to locate poles outside of critical areas
and their buffers to the extent possible.
Electrical effects to maintain additional buffers or install mitigation measures when co-
located with other facilities (e.g., pipelines).
Landowner considerations by moving poles farther away from residences and/or
locating poles on property lines and edges of tree lines.
Cost to provide a cost efficient and feasible design within set parameters.
To reduce the environmental impacts of pole locations, where practicable, PSE will:
Place new poles in approximately the same location of the existing poles;
Locate poles near existing accessible routes to minimize construction traffic impacts;
Avoid placing poles in areas that require significant access disturbance;
Avoid environmental features by making small adjustments in the route and through
careful structure placement; and
Avoid critical areas unless another constraint forces a pole into such areas.
PHASE 2 DRAFT EIS PAGE A‐3
APPENDIX A CONSTRUCTION AND ACCESS MAY 2017
SITE PREPARATION
Vegetation Management and Maintenance
Using the existing transmission line ROW is one of PSE’s preferred routing criteria, as the vegetation in
such corridors is already maintained to some degree. This includes selective removal of problem trees
from beneath power lines or removal of hazardous trees that may fall into the electrical system as part of
regular maintenance on all power line ROW. Proper pruning and discriminating use of growth
regulators and herbicides are also among the methods employed. The method selected is dependent
upon factors such as location, property use, and access. Growth regulators and herbicides are not
commonly used in urban environments.
Emphasis is placed on removal of large, problem-tree species, especially in the case of those that have
disease or insect infestation that can result in irreversible decline. Tree removal is especially important
where pruning alone cannot achieve safe clearance from power lines.
Trimming, natural pruning techniques, or directional trimming will be used if proper line clearances can
be achieved. Directional trimming concentrates on removing limbs and branches where the tree would
normally shed them and direct future growth out and away from the electrical wires. While a newly
pruned tree might look different to some, natural pruning is designed to protect the health of the tree. It
minimizes re-growth and reduces trimming costs.
Directional trimming is the recommended method of the International Society of Arboriculture (ISA),
American National Standards Institute (ANSI), and the National Arbor Day Foundation.
Both tree removal and natural pruning would be performed by specially trained contract crews. Upon
completing of tree work, the crews would clean up the site and any wood that is cut would be left on site
in pieces of manageable size at the property owner’s request.
Guidelines for 230 KV Lines
Vegetation within a utility corridor that has transmission line(s) with an operational voltage of more
than 200 kV must be managed in compliance with federal requirements. The fines/penalties associated
with having a power outage caused by vegetation can be substantial. To ensure compliance with the
North American Electric Reliability Corporation (NERC) standard, PSE allows vegetation with a
mature height of no greater than 15 feet within the wire zone. For evaluation purposes, the same
vegetation requirement was applied to the managed ROW zone. The area outside of the managed ROW,
but still within the legal ROW, is subject to select clearing of trees that pose a risk of damaging the line.
The wire zone is the area measured 10 feet away from the outermost conductor(s) in a static position,
whereas the managed ROW zone is the area that extends roughly 16 feet from the outside of the
transmission wires in their static position.
The vegetation impact assessment used GIS analysis to evaluate the tree inventory data and the
preliminary transmission line design to assess the number of trees that would likely require removal
within a specific route.
PHASE 2 DRAFT EIS PAGE A‐4
APPENDIX A CONSTRUCTION AND ACCESS MAY 2017
Guidelines for 115 kV Lines
Some of the alternatives for the Energize Eastside project include rebuilding or relocating 115 kV lines.
NERC vegetation standards do not apply to PSE’s 115 kV transmission or distribution line rights-of-
way; however, in general, PSE will remove trees that mature at a height of greater than 25 feet near 115
kV lines. It should be noted that, some trees within the corridor or along roadways with a height of
greater than 25 feet, may be allowed to remain in the wire zone if they can be pruned in a manner that
allows sufficient clearance from the lines.
Access
Use of existing access routes is preferred as that is typically the best way to minimize impacts. When a
project entails replacement of an existing transmission line, such as Energize Eastside, efforts are made
to identify the existing or historic access routes. During initial construction of the transmission line,
access routes are established along the corridor. As an area develops and structures are built along the
corridor, some of the original access points are no longer viable and new ones need to be established to
replace or maintain existing transmission line equipment.
Access to each structure location is identified in the field with a preference to those areas that require the
least amount of improvement (e.g., use of existing roads or trails). The field identified access routes are
mapped using hand held GPS units. The GPS data is imported into the surveyed route maps for
reference. Each route will be assessed on site with the affected property owners to gather site specific
limitations and if necessary, identify improvement and restoration details.
Along the corridor, the access and pole locations are identified by the land surveyor and engineering
team. As necessary, the access to each pole location is improved or created. Preliminary access routes
for construction and maintenance are shown on figures at the end of this appendix, by segment.
Utility Locates and Civil Work
As required by state law, utility locates are performed prior to ground disturbing activities. Appropriate
temporary erosion control measures may be installed prior to and during work activities. Initial
vegetation management activities then commence, removing those species that are incompatible with the
safe operation of the transmission line. If civil work is required to establish either a temporary or
permanent construction area, that work typically takes place following vegetation removal.
A work area with an approximate radius of 50 feet around the new pole location would be typical. This
area would provide a safe working space for placing equipment, vehicles, and materials.
CONSTRUCTION
PSE will work to restore property impacted by construction to its previous or an improved state, as
practical and required under applicable law. PSE will mitigate in-kind when restoration is not possible,
as required by applicable law. PSE will comply with local codes related to construction noise. PSE will
work with property owners to minimize impacts during construction as much as practicable.
PHASE 2 DRAFT EIS PAGE A‐5
APPENDIX A CONSTRUCTION AND ACCESS MAY 2017
Pole Installation
Each steel pole will be installed either by direct embedment or placed on a drilled pier foundation. The
type of foundation that will be used to support the poles will be dependent upon the structural loading,
structural strength of the soil, and site accessibility. In areas near co-located underground utilities, such
as the Olympic pipelines, the proposed pole location is reviewed in the field with BP, the pipeline
operator. As appropriate, BP’s general construction procedures will be followed when construction
activities are to take place in the area of the Olympic pipelines.
The hole for the transmission pole is typically initiated using a vactor truck, which is one of the least
invasive methods of excavation. If soil conditions allow, the entire hole could be excavated using a
vactor truck; however, it may be necessary to use traditional auger equipment to achieve the necessary
depth. Typical hole diameter is approximately 18-inches greater than the diameter of the base of the
pole. Generally, the depth of the hole will be 10 percent of the pole height plus 2 feet.
In areas of soft soils, a steel casing may be used during drilling to hold the excavation open, after which
the steel casing would be cut below grade and backfilled upon completion.
For direct embed poles, the base section of the pole is installed in the hole and the annulus filled with
select backfill. When backfill must be imported, material is obtained from commercial sources.
For poles that require drilled pier foundations, the hole is advanced in the same manner as that for the
direct embed poles. Reinforced-steel anchor bolt cages are then installed in the excavation. These cages
are inserted in the holes prior to pouring concrete and are designed to strengthen the structural integrity
of the foundations and are delivered to the structure site via flatbed truck. The excavated holes
containing the reinforcing anchor bolt cages would be filled with concrete and be left to cure for 28
days.
To construct the actual steel structure, two methods of assembly can be used, the first of which is to
assemble the poles, braces, cross arms, hardware, and insulators on the ground. A crane is then used to
set the fully framed structure by placing the poles in the excavated holes or on the drilled pier
foundation. Alternatively, aerial framing can be used by setting the first pole section in the ground or on
the foundation, and subsequently adding the remaining sections and equipment via a crane.
Stringing
Installation of the conductor, shield wire, and communication fiber on the transmission line support
structures is called stringing. The first step of wire stringing would be to install insulators (if not already
installed on the structures during ground assembly) and stringing pulleys, which are temporarily
attached to the lower portion of the insulators at each transmission line support structure to allow
conductors to be pulled along the line. When an existing transmission line is being replaced, the new
poles will be installed and the existing wires would be transferred to them from the existing poles that
will be removed. This is done so that the existing conductor can be used to pull in the new conductor in
a more efficient manner.
PHASE 2 DRAFT EIS PAGE A‐6
APPENDIX A CONSTRUCTION AND ACCESS MAY 2017
Once the existing conductors have been transferred to the stringing sheaves, they would be attached to
the new conductors and used to pull them through the sheaves into their final location. Pulling the lines
may be accomplished by attaching them to a specialized wire stringing vehicle. Following the initial
stringing operation, pulling and sagging of the line would be required to achieve the correct tension of
the transmission lines between support structures. After the new lines have been set, the existing poles
are then removed.
Pulling and tensioning sites are expected to be required approximately every 2 miles along the corridor.
Equipment at sites required for pulling and tensioning activities would include tractors and trailers with
spooled reels that hold the conductors and trucks with the tensioning equipment. To the extent
practicable, pulling and tensioning sites would be located within the existing corridor.
Depending on topography, minor grading may be required at some sites to create level pads for
equipment. Finally, the tension and sag of conductors and wires would be fine-tuned, stringing sheaves
would be removed, and the conductors would be permanently attached to the insulators at the support
structures.
Demobilization and Restoration
Construction sites, staging areas, material storage yards, and access roads would be kept in an orderly
condition throughout the construction period. Disturbed areas not required for access roads and
maintenance areas around structures would be restored and revegetated, as agreed to with the property
owner or land management agency.
PHASE 2 DRAFT EIS PAGE A‐7
APPENDIX A CONSTRUCTION AND ACCESS MAY 2017
Preliminary Construction Access Routes Prior to Property Owner Consultation – Redmond Segment
PHASE 2 DRAFT EIS PAGE A‐8
APPENDIX A CONSTRUCTION AND ACCESS MAY 2017
Preliminary Construction Access Routes Prior to Property Owner Consultation – Bellevue North Segment
PHASE 2 DRAFT EIS PAGE A‐9
APPENDIX A CONSTRUCTION AND ACCESS MAY 2017
Preliminary Construction Access Routes Prior to Property Owner Consultation – Bellevue Central Segment
PHASE 2 DRAFT EIS PAGE A‐10
APPENDIX A CONSTRUCTION AND ACCESS MAY 2017
Preliminary Construction Access Routes Prior to Property Owner Consultation – Bellevue South Segment
PHASE 2 DRAFT EIS PAGE A‐11
APPENDIX A CONSTRUCTION AND ACCESS MAY 2017
Preliminary Construction Access Routes Prior to Property Owner Consultation – Newcastle Segment
PHASE 2 DRAFT EIS PAGE A‐12
APPENDIX A CONSTRUCTION AND ACCESS MAY 2017
Preliminary Construction Access Routes Prior to Property Owner Consultation – Renton Segment
Supplemental Information: Land Use
B
PHASE 2 DRAFT EIS PAGE B‐1
APPENDIX B SUPPLEMENTAL INFORMATION: LAND USE MAY 2017
APPENDIX B-1. METHODS FOR DETERMINING
STUDY AREA
The adjacent parcel study area was created for the right-of-way by selecting all parcels adjoining the
right-of-way where the corridor will be running. For areas not in a current right-of-way, a qualitative
approach was used. The goal was to capture all of the parcels that were next to or adjoining the PSE
easement. This included both the parcel the easement runs through (easement parcel) and the
adjoining parcels, within a reasonable distance. A reasonable distance methodology assumes that if
the easement parcel is large, the adjoining parcels on the nearby side are brought in, while those on
the far side are left out. A common example is represented in Figure B-1. Here, it is reasonable to
assume that the parcels on the east are close enough to be adjacent, but the parcels on the west are
not.
Figure B-1. Adjacent Parcels for Study Area Example
PHASE 2 DRAFT EIS PAGE B‐2
APPENDIX B SUPPLEMENTAL INFORMATION: LAND USE MAY 2017
APPENDIX B-2. APPLICABLE ZONING REGULATIONS
BY STUDY AREA CITY
The tables below list the zoning districts of parcels included in the study area, shown by segment and
option. In each zoning district, an electric utility facility would either be designated as a permitted,
conditional, or prohibited use. If an electrical facility is considered a conditional use, the applicable
jurisdiction would require a level of review to determine whether the facility should be granted a
permit. This review can either be an administrative review or one that would require a public hearing
in front of the hearing examiner. Also included in the tables is each jurisdiction’s definition of an
electrical utility facility or utility.
Redmond Segment
Electrical Utility
Facility
Electrical Utility Facility defined as: unstaffed facilities, except for the presence
of security personnel, that are used for or in connection with or to facilitate the
transmission, distribution, sale, or furnishing of electricity, including but not
limited to electric power substations (RZC 21.78)
Zoning Districts Permitted Conditionally Permitted Prohibited
R-1 X
R-4 X
R-5 X
R-6 X
R-12 X
BP X
MP X
Source: City of Redmond Municipal Code. Accessed August 2016. Available at:
http://online.encodeplus.com/regs/redmond-wa/doc-viewer.aspx?tocid=003#secid-1067.
PHASE 2 DRAFT EIS PAGE B‐3
APPENDIX B SUPPLEMENTAL INFORMATION: LAND USE MAY 2017
Bellevue Segments
Electrical Utility
Facility
Electrical Utility Facility defined as: distribution substations, transmission
stations, transmission switching stations, or transmission lines that are built,
installed, or established. (Bellevue LUC 20.50.018 E)
Zoning Districts Permitted Conditionally Permitted Prohibited
R-1 X
R-1.8 X
R-2.5 X
R-3.5 X
R-4 X
R-5 X
R-7.5 X
R-10 X
R-15 X
R-20 X
R-30 X
BR-GC X
CB X
F-2 X
F-3 X
GC X
OLB X
PO X
BR-GC X
LI X
F-1 X
BR-OR X
BR-OR-2 X
BR-RC-1 X
BR-RC-2 X
BR-CR X
BR-ORT X
Source: http://www.codepublishing.com/WA/Bellevue/LUC/BellevueLUC2020.html#20.20.255
PHASE 2 DRAFT EIS PAGE B‐4
APPENDIX B SUPPLEMENTAL INFORMATION: LAND USE MAY 2017
Newcastle Segment
Electrical Utility
Facility
(Regional)
Electrical Utility Facility (Regional) defined as: a facility for the distribution or
transmission of services from or to an area beyond Newcastle; including but
not limited to: electrical distribution substations, electrical transmission
stations, electrical transmission switching stations, electrical transmission lines
greater than 115 kV and maintenance and utility yards (NMC 18.96.689).
Zoning Districts Permitted Conditionally Permitted Prohibited
R-1 X
R-4 X
R-6 X
R-6-P X
R-18 X
CB X
O X
LOS X
Source: http://www.codepublishing.com/WA/Newcastle/#!/Newcastle18/Newcastle1808.html#18.08.060
Renton Segment
Utilities Large Utilities Large defined as: Utilities Large includes large-scale facilities with
either major above-ground visual impacts, or serving a regional need such as
two hundred thirty (230) kV power transmission lines, natural gas transmission
lines, and regional water storage tanks and reservoirs, regional water
transmission lines or regional sewer collectors and interceptors. (RMC4-11-
210)
Zoning Districts Permitted Conditionally Permitted Prohibited
R-1 X
R-4 X
R-6 X
R-8 X
R-10 X
R-14 X
IL X
RC X
COR X
CV X
CA X
Source: http://www.codepublishing.com/WA/Renton/#!/renton04/Renton0403/Renton0403090.html#4-3-090
PHASE 2 DRAFT EIS PAGE B‐5
APPENDIX B SUPPLEMENTAL INFORMATION: LAND USE MAY 2017
APPENDIX B-3. APPLICABLE POLICIES BY STUDY
AREA CITY
Subarea Plan Policy
Renton
No applicable subarea plans.
Bellevue
Comprehensive Plan UT-67: Encourage consolidation on existing facilities where reasonably
feasible and where such consolidation leads to fewer impacts than
would construction of separate facilities. Examples of facilities that
could be shared are towers, electrical, telephone and light poles,
antenna, substation sites, trenches, and easements.
UT-98: Discourage new aerial facilities within corridors that have no
existing aerial facilities.
Bel-Red Corridor Plan Utility-related cabinets that occur in the right-of-way should not call
attention to themselves, and therefore should not be decorated.
Wilburton Grand
Connection Initiative
N/A
Bel-Red Subarea Plan N/A
Bridle Trails Subarea Plan
Policy S-BT-34: Provide Bellevue-owned utility service to surrounding
jurisdictions in accordance with the Annexation Element of the
Comprehensive Plan.
Eastgate Subarea Plan N/A
Factoria Subarea Plan Policy S-FA-24: Encourage the undergrounding of utility distribution
lines in areas of new development and redevelopment.
Policy S-FA-35: Minimize disruptive effects of utility construction non
property owners, motorists, and pedestrians.
Policy S-FA-49: Incorporate infrastructure improvements and implement
design guidelines that will enhance pedestrian crossings (respecting the
significant traffic volumes and multiple turning movements at these
intersections), improve transit amenities, and develop an active building
frontage along Factoria Boulevard with direct pedestrian routes to retail
storefronts from the public sidewalk and weather protection for
pedestrians.
Policy S-FA-52. Allow buildings to abut the Factoria Boulevard public
right-of-way, so long as there is adequate space for the arterial
sidewalks.
Policy S-FA-51: Consider establishing a maximum building setback from
the right-of-way for structures along the Factoria Boulevard commercial
PHASE 2 DRAFT EIS PAGE B‐6
APPENDIX B SUPPLEMENTAL INFORMATION: LAND USE MAY 2017
Subarea Plan Policy
corridor.
Newport Hills Plan Policy S-NH-55: Encourage undergrounding of utility distribution lines
on existing development where reasonably feasible.
Policy S-NH-50. Include the following elements in a redeveloped
commercial district: new commercial buildings at the street edge
Richards Valley Plan Policy S-RV-19. Encourage the combination of utility and transportation
rights-of-way in common corridors and coordinate utility construction
with planned street and bike lane improvements which could result in a
more efficient allocation of funds.
Policy S-RV-20. Use common corridors for new utilities if needed.
Discussion: If new power lines are needed in the Subarea, they should
be developed in areas that already contain power lines, rather than
causing visual impacts in new areas.
SE Bellevue Plan N/A
Wilburton/NE 8th St Plan Policy S-WI-43: Encourage the undergrounding of utility distribution
lines in developed areas and require the undergrounding of utility
distribution lines in new developments when practical.
Policy S-WI-49. Allow flexibility for commercial buildings to be sited near
frontage property lines.
Newcastle
Newcastle Subarea Plan Policy S-NC-44: Encourage the use of utility and railroad easements and
rights-of-way for hiking, biking, and equestrian trails wherever
appropriate in the Subarea.
Redmond
No applicable subarea plans.
PHASE 2 DRAFT EIS PAGE B‐7
APPENDIX B SUPPLEMENTAL INFORMATION: LAND USE MAY 2017
APPENDIX B-4. APPLICABLE SHORELINE
REGULATIONS
City of Bellevue
Part 20.25E Shoreline Overlay District
20.25E.010 Definition of district.
The Shoreline Overlay District encompasses those lake waters 20 acres in size or greater and those
stream waters with a mean annual water flow exceeding 20 cubic feet per second; the lands
underlying them; the lands extending landward for 200 feet in all directions as measured on a
horizontal plane from the ordinary high water mark; floodways and contiguous floodplain areas
landward 200 feet from such floodways associated with such streams and lakes; and marshes, bogs,
swamps and river deltas associated with such streams and lakes. Specifically included within the
district are the following:
A. Lake Washington, including Mercer Slough upstream to Interstate 405 – The lake waters,
underlying lands and the area 200 feet landward of the ordinary high water mark, plus associated
floodways, floodplains, marshes, bogs, swamps, and river deltas;
B. Lake Sammamish – The lake waters, underlying lands and the area 200 feet landward of the
ordinary high water mark, plus associated floodways, floodplains, marshes, bogs, swamps and
river deltas;
C. Lower Kelsey Creek – The creek waters, underlying lands, and territory between 200 feet on
either side of the top of the banks, plus associated floodways, floodplains, marshes, bogs,
swamps and river deltas; and
D. Phantom Lake – The lake waters, underlying lands and the area 200 feet landward of the ordinary
high water mark, plus associated floodways, floodplains, marshes, bogs, swamps and river deltas.
Development within the Shoreline Overlay District may also be subject to the requirements of Part
20.25H LUC. In the event of a conflict between the provisions of this Part 20.25E and Part 20.25H
LUC, the provisions providing the most protection to critical area functions and values shall prevail.
(Ord. 5681, 6-26-06, § 1; Ord. 4055, 3914, 9-25-89, § 1)
Part 20.30C Shoreline Conditional Use Permit
20.30C.155 Decision criteria.
The City may approve or approve with modifications an application for a Shoreline Conditional Use
Permit if:
A. The proposed use will be consistent with the policies of RCW 90.58.020 and the policies of the
Bellevue Shoreline Master Program; and
B. The proposed use will not interfere with the normal public use of public shorelines; and
PHASE 2 DRAFT EIS PAGE B‐8
APPENDIX B SUPPLEMENTAL INFORMATION: LAND USE MAY 2017
C. The proposed use of the site and design of the project will be compatible with other permitted
uses within the area; and
D. The proposed use will cause no unreasonably adverse effects to the shoreline environment
designation in which it is to be located; and
E. The public interest suffers no substantial detrimental effect; and
F. The proposed use complies with all requirements of WAC 173-14-140; and
G. The proposed use is harmonious and appropriate in design, character and appearance with the
existing or intended character and quality of development in the immediate vicinity of the subject
property and with the physical characteristics of the subject property; and
H. The proposed use will be served by adequate public facilities including streets, fire protection,
water, stormwater control and sanitary sewer; and
I. The proposed use will not be materially detrimental to uses or property in the immediate vicinity
of the subject property; and
J. The proposed use has merit and value for the community as a whole; and
K. The proposed use is in accord with the Comprehensive Plan; and
L. The proposed use complies with all other applicable criteria and standards of the Bellevue City
Code.
City of Renton
4-3-090 Shoreline Master Program Regulations
Part 4-3-090(C)(2)(c) Shoreline High Intensity Overlay District Acceptable Activities and
Uses
Acceptable Activities and Uses: As listed in RMC 4-3-090E Use Regulations.
Part 4-3-090(C)(4)(c) Shoreline High Intensity Overlay District Acceptable Activities and
Uses
Subject to RMC 4-3-090E Use Regulations, which allows land uses in RMC Chapter 4-2 in this
overlay district, subject to the preference for water-dependent and water-oriented uses. Uses adjacent
to the water's edge and within buffer areas are reserved for water oriented development,
public/community access, and/or ecological restoration.
Part 4-3-090(D)(2)(a) General Development Standards, Environmental Effects, No Net
Loss of Ecological Functions
i. No net loss required: Shoreline use and development shall be carried out in a manner that prevents
or mitigates adverse impacts to ensure no net loss of ecological functions and processes in all
development and use. Permitted uses are designed and conducted to minimize, in so far as practical,
any resultant damage to the ecology and environment (RCW 90.58.020). Shoreline ecological
functions that shall be protected include, but are not limited to, fish and wildlife habitat, food chain
PHASE 2 DRAFT EIS PAGE B‐9
APPENDIX B SUPPLEMENTAL INFORMATION: LAND USE MAY 2017
support, and water temperature maintenance. Shoreline processes that shall be protected include, but
are not limited to, water flow; erosion and accretion; infiltration; ground water recharge and
discharge; sediment delivery, transport, and storage; large woody debris recruitment; organic matter
input; nutrient and pathogen removal; and stream channel formation/maintenance. ii. Impact
Evaluation Required: In assessing the potential for net loss of ecological functions or processes,
project-specific and cumulative impacts shall be considered and mitigated on- or off-site. iii.
Evaluation of Mitigation Sequencing Required: An application for any permit or approval shall
demonstrate all reasonable efforts have been taken to provide sufficient mitigation such that the
activity does not result in net loss of ecological functions. Mitigation shall occur in the following
prioritized order: (a) Avoiding the adverse impact altogether by not taking a certain action or parts of
an action, or moving the action. (b) Minimizing adverse impacts by limiting the degree or magnitude
of the action and its implementation by using appropriate technology and engineering, or by taking
affirmative steps to avoid or reduce adverse impacts. (c) Rectifying the adverse impact by repairing,
rehabilitating, or restoring the affected environment. (d) Reducing or eliminating the adverse impact
over time by preservation and maintenance operations during the life of the action. (e) Compensating
for the adverse impact by replacing, enhancing, or providing similar substitute resources or
environments and monitoring the adverse impact and taking appropriate corrective measures.
Part 4-3-090(D)(2)(c) General Development Standards, Environmental Effects, Critical
Areas within Shoreline Jurisdiction
i. Applicable Critical Area Regulations: The following critical areas shall be regulated in
accordance with the provisions of RMC 4-3-050 Critical Area Regulations, adopted by reference
except for the provisions excluded in subsection 2, below. Said provisions shall apply to any use,
alteration, or development within shoreline jurisdiction whether or not a shoreline permit or
written statement of exemption is required. Unless otherwise stated, no development shall be
constructed, located, extended, modified, converted, or altered, or land divided without full
compliance with the provision adopted by reference and the Shoreline Master Program. Within
shoreline jurisdiction, the regulations of RMC 4-3-050 shall be liberally construed together with
the Shoreline Master Program to give full effect to the objectives and purposes of the provisions
of the Shoreline Master Program and the Shoreline Management Act. If there is a conflict or
inconsistency between any of the adopted provisions below and the Shoreline Master Program,
the most restrictive provisions shall prevail.
(a) Aquifer protection areas.
(b) Areas of special flood hazard.
(c) Sensitive slopes, twenty-five percent (25%) to forty percent (40%), and protected slopes,
forty percent (40%) or greater.
(d) Landslide hazard areas.
(e) High erosion hazards.
(f) High seismic hazards.
(g) Coal mine hazards.
(h) Fish and wildlife habitat conservation areas: Critical habitats.
PHASE 2 DRAFT EIS PAGE B‐10
APPENDIX B SUPPLEMENTAL INFORMATION: LAND USE MAY 2017
(i) Fish and wildlife habitat conservation areas: Streams and Lakes: Classes 2 through 5 only.
ii. Inapplicable Critical Area Regulations: The following provisions of RMC 4-3-050 Critical Area
Regulations shall not apply within shoreline jurisdiction:
(a) RMC 4-3-050N Alternates, Modifications and Variances, Subsections 1 and 3 Variances, and
(b) RMC 4-9-250 Variances, Waivers, Modifications and Alternatives.
(c) Wetlands, including shoreline associated wetlands, unless specified below.
iii. Critical Area Regulations for Class 1 Fish Habitat Conservation Areas: Environments designated
as Natural or Urban Conservancy shall be considered Class 1 Fish Habitat Conservation Areas.
Regulations for fish habitat conservation areas Class 1 Streams and Lakes are contained within
the development standards and use standards of the Shoreline Master Program, including but not
limited to RMC 4-3-090F.1 Vegetation Conservation, which establishes vegetated buffers
adjacent to water bodies and specific provisions for use and for shoreline modification in
Subsections 4-3-090E and 4-3-090F. There shall be no modification of the required setback and
buffer for non-water dependent uses in Class 1 Fish Habitat Conservation areas without an
approved shoreline conditional use permit.
iv. Alternate Mitigation Approaches: To provide for flexibility in the administration of the
ecological protection provisions of the Shoreline Master Program, alternative mitigation
approaches may be applied for as provided in RMC 4-3-050N Alternates, Modifications and
Variances, subsection 2. Modifications within shoreline jurisdiction may be approved for those
critical areas regulated by that section as a Shoreline Conditional Use Permit where such
approaches provide increased protection of shoreline ecological functions and processes over the
standard provisions of the Shoreline Master Program and are scientifically supported by specific
studies performed by qualified professionals.
Scenic Views and Aesthetic
Environment Methodology
C
PHASE 2 DRAFT EIS PAGE C‐1
APPENDIX C SCENIC VIEWS AND AESTHETIC ENVIRONMENT METHODOLOGY MAY 2017
Data Used to Determine
Study Area
King County 2002/2003 Digital
Surface Model (DSM)(King
County, 2003a)
PSE GIS Alignment Data (PSE,
2016a)
APPENDIX C. SCENIC VIEWS AND AESTHETIC
ENVIRONMENT METHODOLOGY
1. INTRODUCTION
This appendix describes the process for assessing impacts to scenic views and the aesthetic
environment as a result of the Energize Eastside project. Scenic views are the observation of a visual
resource from a particular location, with visual resources generally defined as natural and constructed
features of a landscape that are viewed by the public and contribute to the overall visual quality and
character of an area. Such features often include distinctive landforms, water bodies, vegetation, or
components of the built environment that provide a sense of place, such as city skylines. The
aesthetic environment is the portion of the environment that influences human perception of the
world. It is comprised of the natural (topography, presence of trees, water bodies) and built
(buildings, utility infrastructure) environments. This appendix details the process used to identify
impacts to scenic views and the aesthetic environment and how significance was assigned.
2. GUIDANCE USED
SEPA (WAC 197-11) requires all major actions sponsored, funded, permitted, or approved by state
and/or local agencies to undergo planning to ensure that environmental considerations, such as
impacts related to scenic views and the aesthetic environment, are given due weight in decision-
making. Because the value of scenic views and the aesthetic environment is subjective, based on the
viewer, it is difficult to quantify or estimate impacts. In particular, little guidance exists supporting a
standard methodology for assessing visual impacts associated with transmission line projects. A
number of methodologies were reviewed to inform the methodology used for this project. For this
project, the assessment of impacts was generally based on methods described in the Federal Highway
Administration (FHWA) Guidelines for Visual Impact Assessment (FHWA, 2015). FHWA
guidelines do not specify thresholds for determining significant impacts, nor do state or local
regulations. Therefore, significance was assigned based on criteria similar to those described in The
State Clean Energy Program Guide: A Visual Impact Assessment Process for Wind Energy Projects
(Vissering et al., 2011).
3. STUDY AREA
The FHWA Guidance suggests identifying an Area of Visual Effect
(AVE) based on the physical constraints of the environment and the
physiological limits of human sight (FHWA, 2015). This concept
was used for determining the study area, which takes into account
where the project would be visible given the topographical and
human sight constraints. Impacts to scenic views and the aesthetic
environment would only occur in places where the project would be
visible. To identify areas where the project would be visible, a
geographic information system (GIS) analysis was conducted.
PHASE 2 DRAFT EIS PAGE C‐2
APPENDIX C SCENIC VIEWS AND AESTHETIC ENVIRONMENT METHODOLOGY MAY 2017
Two sets of tools in ArcMap allow a user to run such an analysis: (1) Viewshed, and (2) Observer
Points (ESRI, 2016). For this analysis, the viewshed tool was used because it allows use of lines as
key visual elements. The viewshed tool creates a raster1 that records the number of times an input
point or polyline feature2 can be viewed from a particular area. When polyline input is used, every
node3 and vertex4 along each input line is processed as an individual observation point, so an area
where multiple vertices can be viewed would have a higher raster value.
For this analysis, the EIS Consultant Team used the PSE alignment data (a GIS file that shows where
the project would be located) as the input polyline to determine what areas of the landscape have line
of sight to the proposed transmission line.5 Applying an offset informs the viewshed model that the
line being observed would be located above the ground (Figure C-1). The heights identified in Table
C-1 were used to prescribe an offset height to the polyline in the viewshed analysis.6
Table C-1. PSE GIS Alignment Data - Proposed Maximum Pole Height by Segment
Segment Option(s) Proposed Maximum Pole
Height (feet)
Redmond N/A 120’
Bellevue North N/A 100’
Bellevue Central Existing Corridor 115’
Bellevue Central Bypass 1 115’
Bellevue Central Bypass 2 115’
Bellevue South Existing Corridor 95’
Bellevue South SE Newport Way 80’
Bellevue South SE 30th St | Factoria Blvd | Coal Creek Parkway 125’
Bellevue South 124th Ave SE 80’
Newcastle N/A 100’
Renton N/A 125’
Source: PSE, 2016b.
1 A raster is a matrix of cells (or pixels) organized into a grid where each cell contains a value representing
information, such as whether or not a view can be seen.
2 A polyline feature is a continuous line composed of one or more line segments.
3 A node is a point at which lines intersect or branch.
4 A vertex is an angular point of a polygon.
5 Note: line of sight does not necessarily mean the object is within the range of human sight.
6 Pole heights were assigned at the “option(s)” level, with the highest proposed pole option being used.
PHASE 2 DRAFT EIS PAGE C‐3
APPENDIX C SCENIC VIEWS AND AESTHETIC ENVIRONMENT METHODOLOGY MAY 2017
Figure C-1. Factoring Line Heights (ESRI, 2016)
The data used as the “ground” for this analysis were the King County Digital Surface Model (DSM).
The King County DSM was used instead of bare earth data because it gives the heights of vegetation
and buildings, in addition to taking into account the underlying topography. The EIS Consultant
Team used DSM data because in urban environments views are often obstructed by vegetation and
buildings, rather than by the topography of the landscape alone (GIS Geography, 2016).
Figure C-2 shows the output from the GIS analysis described above. The GIS analysis provides a
rough approximation of where the project would be visible. It includes areas where the line would be
so small that it is unrealistic that it would be distinguishable on the horizon. Also, in some instances
dense areas of tree stands were misinterpreted by the GIS analysis as being a rise in topography from
which views could be had, skewing the results to show more areas as being potentially impacted than
would actually occur. In general, the highest concentrations of areas with views of the project
corridor would be within one-quarter mile of the corridor. This is consistent with what is commonly
found for transportation projects (FHWA, 2015).
For the purposes of this project, a study area with a one-quarter mile radius from the edge of the
proposed transmission line corridor (including all segment options) was used. However, Interstate
405 (I-405) and all areas to the west of I-405 were removed because the freeway provides such a
wide separation that the project is not expected to visually impact I-405 drivers or the neighborhoods
west of the freeway. The study area focuses on areas where the proposed transmission line would be
within the foreground view, where viewers are most likely to experience the scale of the project and
observe details and materials. While the project would be visible at greater distances, significant
scenic or aesthetic impacts are not probable given the project’s scale relative to its largely mixed
urban context.
PHASE 2 DRAFT EIS PAGE C‐4
APPENDIX C SCENIC VIEWS AND AESTHETIC ENVIRONMENT METHODOLOGY MAY 2017
Figure C-2. Study Area
PHASE 2 DRAFT EIS PAGE C‐5
APPENDIX C SCENIC VIEWS AND AESTHETIC ENVIRONMENT METHODOLOGY MAY 2017
4. CHARACTERIZING THE AESTHETIC ENVIRONMENT
The existing aesthetic environment was characterized through an assessment of the visual character
(what is present in the built and natural environments), the affected population (viewers), and the
existing visual quality. Visual quality is based on consistency of visual character with viewer
preferences. To assess the visual quality of the study area, the visual quality criteria described in the
FHWA Guidance were used. These concepts were applied by the EIS Consultant Team in the manner
described in the table below based on professional experience and consideration of viewer
preferences stated in study area comprehensive plans and public comments received during the EIS
process.
Table C-2. Application of FHWA Methodology to Determine Visual Quality
FHWA Visual
Quality Criteria FHWA Description Application
Natural Harmony What a viewer likes and dislikes
about the natural environment.
The viewer labels the natural
environment as being either
harmonious or inharmonious.
Harmony is considered
desirable; disharmony is
undesirable.
High: A natural area that is relatively
undisturbed by development. Could include
secluded lakes, open plains, forests, etc.
Medium: An area with a small amount of
development that blends with the natural
environment and does not disrupt the natural
harmony of the area.
Low: An area with a large amount of
development where the built environment
takes precedence in the viewshed over the
underlying natural environment.
Built Order What a viewer likes and dislikes
about the built environment. The
viewer labels the built
environment as being either
orderly or disorderly. Orderly is
considered desirable; disorderly
is undesirable.
High: A built environment with urban design
that is identified in a comprehensive plan or
other planning document as being
aesthetically pleasing.
Medium: An area with consistent building
height and form. It does not overtly meet any
set design standards, but also is not
inconsistent with set design standards.
Low: An area with inconsistent building
height and form that does not meet set
design standards (if they exist).
Utility Coherence What the viewer likes and
dislikes about the utility
environment, which is
comprised of the utility’s
geometrics, structures, and
fixtures. The viewer labels the
utility environment as being
either coherent or incoherent.
Coherent is considered
desirable; incoherent is
undesirable.
High: Minimal utility presence, small poles
with few wires*. Configuration is consistent in
height and form. Utility infrastructure blends
with the rest of the aesthetic environment.
Medium: Moderate utility presence. There
could be larger, taller poles or more wires.*
Configuration is consistent in height and
form. Utility infrastructure blends with the
rest of the aesthetic environment for the
most part.
PHASE 2 DRAFT EIS PAGE C‐6
APPENDIX C SCENIC VIEWS AND AESTHETIC ENVIRONMENT METHODOLOGY MAY 2017
FHWA Visual
Quality Criteria FHWA Description Application
Low: High utility presence. There are larger,
taller poles with configurations that are
inconsistent in height and form. The utility
infrastructure is the prominent feature in the
viewshed and does not blend with the rest of
the aesthetic environment.
*Note: Changes in wire diameter are not expected to be perceivable and therefore are not considered as part of this analysis
(See Attachment 1).
5. CHARACTERIZING SCENIC VIEWS
Scenic views are views of visual resources that are considered special attributes of the study area and
region. Visual resources associated with the study area were identified in the Phase 1 Draft EIS based
on study area plans, regulatory codes (as summarized in Section 9), and scoping comments. These
are listed in Table C-3. The visual resources evaluated in the Phase 2 Draft EIS were selected
because there was the potential for significant scenic view impacts under the proposed project. The
EIS Consultant Team determined that some of the visual resources identified in the Phase 1 Draft
EIS were no longer applicable due to distance, topographic constraints, or the presence of dense
vegetation between viewers and the visual resources. Table C-3 details why scenic views of certain
Phase 1 visual resources were not evaluated further in the Phase 2 EIS.
Table C-3. Identification of Study Area Scenic Views
Visual Resource
Identified in Phase 1
Included in
Phase 2 GIS
Analysis?
Reason
Mount Rainier Yes Scenic views could be impacted by the project.
Cascade Mountain Range Yes Scenic views could be impacted by the project.
Issaquah Alps
(Cougar Mountain, Tiger
Mountain, and Squak Mountain)
Yes Scenic views could be impacted by the project.
Used Cougar Mountain because it is in the
foreground.
Lake Washington Yes Scenic views could be impacted by the project.
Lake Sammamish Yes Scenic views could be impacted by the project.
Seattle skyline Yes Scenic views could be impacted by the project.
Bellevue skyline Yes Scenic views could be impacted by the project.
Lake Sammamish Yes Scenic views could be impacted by the project.
Sammamish Valley No Topography makes is unlikely that scenic views
would be impacted with the powerline in the
foreground and background views would not be
significant because the line would be too far away
from the viewer.
PHASE 2 DRAFT EIS PAGE C‐7
APPENDIX C SCENIC VIEWS AND AESTHETIC ENVIRONMENT METHODOLOGY MAY 2017
Data Used To Assess Impacts to
the Aesthetic Environment
GIS Shapefiles:
- Parks (Bellevue, 2015; Newcastle,
2015; Renton, 2015; Issaquah, 2015;
Kirkland, 2015; Redmond, 2015; King
County, 2015b)
- Water Bodies (Ecology, 2014)
- Land Use (King County, 2015a)
- Land Cover (NOAA, 2011)
- Topography (King County, 2003b)
Public Comments
Visual Resource
Identified in Phase 1
Included in
Phase 2 GIS
Analysis?
Reason
Cedar River No Due to topographic constraints and the presence
of dense vegetation within the Cedar River ravine,
scenic views of the Cedar River are unlikely from
outside of the ravine. No residential views of the
river would be obstructed by the lines and, due to
the topography, the line would be located high
enough above the roadway that it would not
impact drivers’ views of the river. Therefore,
impacts to views of the Cedar River are assessed
as impacts to the aesthetic environment, with the
primary viewers considered being users of the
Cedar River Trail or Riverview Park.
Beaver Lake No Visual resource would not be visible from the
Phase 2 study area.
Pine Lake No Visual resource would not be visible from the
Phase 2 study area.
6. IMPACTS TO THE AESTHETIC ENVIRONMENT
The assessment of impacts to the aesthetic environment was based on the FHWA concepts of
compatibility of impact (degree of contrast), sensitivity to the impact (viewer sensitivity), and degree
of impact (whether it would result in a beneficial, neutral, or adverse impact).
6.1 Degree of Contrast
To assess impacts to the aesthetic environment, visual
simulations were used to determine the degree of contrast
produced by the project. The degree of contrast is the extent
to which a viewer can distinguish between an object and its
background. It was assessed by taking into consideration the
project form, materials, and visual character in comparison
to existing conditions and the surrounding areas.
The tool of identifying landscape units was not employed
due to the length of the corridor and the diversity of the
natural, cultural, and project landscapes; however, the
concept of identifying unique natural, cultural, and project
landscapes to select key views was used. For this
assessment, the discussion was divided into the natural
(topographic, land cover, water bodies) and built (building
form, utility infrastructure) environments to reduce
confusion associated with use of the terms “cultural” and “project” environments.
To assess changes to each component of the aesthetic environment, viewpoints were selected at
various locations along the transmission line corridor to show different ways the natural and built
PHASE 2 DRAFT EIS PAGE C‐8
APPENDIX C SCENIC VIEWS AND AESTHETIC ENVIRONMENT METHODOLOGY MAY 2017
environments could be impacted; for instance, areas where the project corridor would cross unique
topography, water bodies, vegetation, land uses (different land uses typically have different building
forms and impacted viewers), or where the existing transmission infrastructure would be changed
(e.g., different pole heights or configurations). Areas identified as being sensitive during the public
scoping period were also used as viewpoints (Table C-4).
Visual simulations of what the project would look like at these viewpoints provide the foundation for
assessing aesthetic impacts. The concept of discussing dynamic versus static viewsheds was adopted
as part of the impacts analysis (view duration), but viewsheds were not identified as being dynamic
or static.
Table C-4. Public Comments that Requested Visual Simulations
Suggested Viewpoint Location Rationale behind why it
was or was not included
Lower Somerset homeowners’ view of Willow 2. Included – covered via the Somerset Drive SE
simulation.
Factoria Boulevard and Coal Creek Pkwy. Included – covered via the 5365 Coal Creek
Parkway simulation.
West viewing section of Somerset in Bellevue. Included – covered via the Somerset Drive SE
simulation.
Newport Way SE corridor from the on the west
side of the street.
Included – covered via the 12919 SE Newport
Way simulation.
Public parks and rights-of-way. Included – covered via the Lake Boren Park
simulation and 8030 128th Ave SE simulation.
Because of the topography of Newcastle,
vantage points should include locations on the
west and east boundaries of the route.
Included – 8030 128th Ave SE simulation looks to
the east and Lake Boren Park simulation looks to
the west.
Because of the topography of Newcastle,
vantage points should include vantage points to
the east of Coal Creek Parkway from which the
project would be visible.
Not included – the transmission line would not
be visible due to topography and the presence of
dense vegetation.
Houses that line Somerset Drive SE, all of which
will have the lines parallel to the view sides of the
houses.
Included – covered via the Somerset Drive SE
simulation.
Newport Way at the driveway of Monthaven
Community.
Included – covered via the 13357 SE Newport
Way simulation.
Skyridge/College Hill and Sunset communities. Included – covered via the Skyridge Park (1990
134th Pl SE, Bellevue) simulation.
Skyridge hiking trail, which starts at the end of
134th Ave SE (dead end) and ends at the Skyridge
Park playground. This is a new trail and has views
of Richard's Valley, especially in the winter.
Included – covered via the Skyridge Park (1990
134th Pl SE, Bellevue) simulation.
Sunset Park should be considered for Route 2. Not included – Sunset Park was considered, but
PHASE 2 DRAFT EIS PAGE C‐9
APPENDIX C SCENIC VIEWS AND AESTHETIC ENVIRONMENT METHODOLOGY MAY 2017
Suggested Viewpoint Location Rationale behind why it
was or was not included
a simulation was not created. The EIS Consultant
Team visited that portion of the site and
determined that the presence of dense vegetation
would reduce the likelihood that the project
would be visible. The substation simulation
provides a representative simulation.
Grand Connection just east of I-405 and the
viewing platform at the western edge of the
Bellevue Botanical Garden are two of these --
and high tension poles are unsightly.
Not included – There are no aesthetic guidelines
applicable to the project that are associated with
the Grand Connection. The Lake Hills Connector
simulation is considered to be sufficient for
representing the highest degree of adverse
aesthetic impacts in this portion of the study
area.
The viewing platform at the western edge of the
Bellevue Botanical Garden.
Not included – EIS Consultant Team visited the
site and confirmed that the project would not be
visible due to the topography and presence of
dense vegetation.
Residents east of 108th Street. Not included – outside of study area. Assume
commenter meant “108th Avenue.”
Residents in western Wilburton. Included – covered via NE 8th Street simulation.
Residents in the Spring District. Included - covered via Spring District simulation.
Residents looking east from the central business
district, west from Wilburton and southwest and
south from the Spring District.
Not included – outside of study area.
Drivers on I-405. Not included – outside of study area.
Table C-5 provides the list of viewpoints used in the EIS, the segment they are viewing, and the
reasons supporting the selection of each viewpoint (i.e., unique natural or built environment or
scoping comment). Table C-6 provides a list of viewpoints that were used to inform the analysis, but
were not incorporated directly into the EIS. Figure C-3 shows all of the simulations created by Power
Engineers and their locations, and the simulations area included as Attachment 2.
To the extent possible, these viewpoints were selected to align with visual simulations that had
already been completed for the project. The visual simulations were created by Power Engineers.
Their methods for creating the visual simulations are detailed in Attachment 2. Power Engineers
collected photos using a full frame Canon 5D Mark II or III professional Digital Camera. All photos
were taken with a 50mm. lens. In some extreme foreground situations a 28mm. lens may be used.
Power Engineers developed an existing conditions 3D Model of the study area, including terrain and
structures. The photos were registered into a 3D modeling program and 3D sun and atmosphere
conditions were applied based on notes taken when the photo was shot. Power Engineers then used
PLS-CAD model data (3D engineering designs developed for each transmission line structure)
provided by PSE to create a 3D rendering. Photoshop was used to create foreground screening
PHASE 2 DRAFT EIS PAGE C‐10
APPENDIX C SCENIC VIEWS AND AESTHETIC ENVIRONMENT METHODOLOGY MAY 2017
elements (e.g., trees, structures, etc.) (Power Engineers, 2016). All of the renderings show brown
poles because Patina7 would be applied under all of the segment options.
6.2 Viewer Sensitivity
The evaluation of viewer sensitivity was also based on FHWA guidance, and considered viewer
exposure and viewer awareness. Exposure considers the proximity, extent, and duration of views.
Awareness considers viewer attention and focus, and whether affected views are protected by policy,
regulation, or custom (FHWA, 2015). All viewers within the study area were considered to be close
to the project. Viewer extent is specific to each component because it depends on the number of
viewers impacted. This was assessed by identifying areas with higher residential density and
recreational resources that are heavily used. The viewer extent of residential viewers was determined
by assigning areas of high, medium, and low population density by assessing American Community
Survey 2014 Census block data on a segment-by-segment basis within the quarter-mile radius study
area (U.S. Census Bureau, 2014). Figure C-4 shows areas with high, medium, and low population
density. The viewer extent of recreational users was assessed by identifying those recreation areas
(parks, trails, outdoor recreation facilities) that lie within the study area, and determining whether or
not the view or natural setting of the recreation areas is identified as a defining feature (based on
findings in the Phase 1 Draft EIS; see Table 11-1 in the Phase 1 Draft EIS, and the recreation
analysis in the Phase 2 Draft EIS; see Section 3.6)8. If a recreation area that is used for its views or
natural setting would be impacted, how frequently the recreation area is used was assessed. The
duration of views is consistent for all components, with residential viewers experiencing the longest
view duration due to their stationary nature and fixed views of the transmission line. Recreational
users have a shorter view duration that is confined to the time spent at the recreational resource, with
park users having longer view duration and trail users, who are more mobile, having shorter view
duration. Drivers would have the shortest view duration due to the speed at which they travel.
It was assumed that two groups were the most sensitive to changes in the aesthetic environment and
scenic views: residents and recreational users in parks and other recreational settings. These two
groups would have the greatest exposure to the project because they are often located near the project
and would observe the project for longer durations (particularly residential viewers). They would
also likely have the greatest awareness, given that these two types of viewers are most often
protected by city policies (Section 9).
7 Patina is a film applied to the surface of metals that turns brown as oxidation occurs over long periods
of time.
8 Please note: the study area for the scenic views and aesthetic environment assessment is larger than
the study area used for the recreation analysis.
PHASE 2 DRAFT EIS PAGE C‐11
APPENDIX C SCENIC VIEWS AND AESTHETIC ENVIRONMENT METHODOLOGY MAY 2017
Table C-5. List of Viewpoints and Rationale for Selection
Key
Viewpoint
(KVP)
Location Segment/ Option
Reason for selecting viewpoint
(Natural Environment or Built
Environment and why)
1 SE 30th St All Segments/ Options Shows the new substation when
taking into account grading and
clearing.
2 Redmond Way Redmond Representative of the natural
environment along the segment
(topography and vegetation).
Representative of the built
environment (shows project
configuration and height for entire
segment).
3 13540 NE 54th Pl Bellevue North Representative of the natural
environment along the segment
(topography and vegetation).
Representative of the built
environment (single-family residential
development; project configuration
and height for entire segment).
4 13606 Main St Bellevue Central –
Existing Corridor
Shows project from rise in
topography.
Is identified in the Wilburton Subarea
Plan as a key view.
5 13636 Main St Bellevue Central –
Existing Corridor
Shows project from rise in
topography, but from a side view.
Is identified in the Wilburton Subarea
Plan as a key view.
6 12828 Bel-Red Rd Bellevue Central –
Bypass 1 and 2 Options
Shows project surrounded by
commercial and industrial uses.
Shows project from an area slated for
increased density.
7 12253 NE 8th St Bellevue Central –
Bypass 1 and 2 Options
Identified in the Wilburton Subarea
Plan as a key view.
8 Lake Hills
Connector
Bellevue Central –
Bypass 1 and 2 Options
Identified in the Wilburton Subarea
Plan as a key view.
Shows how project would be viewed
by future users of the Eastside Rail
Corridor.
9 1680 Richards Rd Bellevue Central–
Bypass 2 Option
Richards Rd is identified in Richards
Valley Subarea Plan as an area where
the City wants to preserve the
vegetated appearance.
Shows impacts to an area with
wetland land cover.
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APPENDIX C SCENIC VIEWS AND AESTHETIC ENVIRONMENT METHODOLOGY MAY 2017
Key
Viewpoint
(KVP)
Location Segment/ Option
Reason for selecting viewpoint
(Natural Environment or Built
Environment and why)
Shows the project impacts near the
Woodridge Trail trailhead.
10 4122 Factoria Blvd
SE
Bellevue South - Oak 1
and Oak 2 Options
(Only used Oak 1
Option for EIS)
Visual connections along Factoria
Blvd are protected in the Factoria
Subarea Plan.
Oak 1 Option was used in EIS
because it is a taller pole
configuration with a higher likelihood
of aesthetic impacts.
11 5365 Coal Creek
Pkwy
Bellevue South - Willow
2, Oak 1, Oak 2 Options
(Only used Oak 1
Option for EIS)
Identified via a public comment.
Oak 1 Option was used in EIS
because it is a taller pole
configuration with a higher likelihood
of aesthetic impacts.
12 12513 SE 38th St Bellevue South - Oak 2
Option
Shows construction of poles where
they do not currently exist.
13 4730 134th PL SE Bellevue South
Segment - All Options
(Only used Willow 1
Option for EIS)
Identified via public comment.
Shows the option with the tallest
poles in the Somerset neighborhood.
14 12892 SE Newport
Way
Bellevue South
Segment - Willow 2
Option
Shows a change in built environment
from a 40-foot 12.5kV line on
wooden poles to 75-foot steel
monopoles.
Shows removal of underbuild and
reduction in clutter.
15 8446 128th Ave SE Newcastle Representative of the built
environment (single-family residential
development; project configuration
and height for entire segment).
Shows the project from the ridge
near the corridor.
16 Lake Boren Park Newcastle View from recreational use.
Shows the project from a lower
elevation looking up at the project.
17 1026 Monroe Ave
NE
Renton Shows project surrounded by
institutional and single-family
residences.
18 318 Glennwood
Court SE
Renton Segment Shows project surrounded by single-
family residential development and
placed on a ridge.
PHASE 2 DRAFT EIS PAGE C‐13
APPENDIX C SCENIC VIEWS AND AESTHETIC ENVIRONMENT METHODOLOGY MAY 2017
Table C-6. List of Other Simulations that Informed the Analysis
Location Segment/Option
13505 NE 75th St Redmond
267 140th Ave NE Bellevue Central – Existing Corridor
106 136th Ave SE Bellevue Central – Existing Corridor
13600 SE 5th St Bellevue Central – Existing Corridor
13633 SE 5th St Bellevue Central – Existing Corridor
13810 Lake Hills Connector Bellevue Central – Existing Corridor
13711 SE 18th St Bellevue Central – Existing Corridor
1990 134th Pl SE Bellevue Central – Existing Corridor
2160 135th PL SE Bellevue Central – Existing Corridor
1227 124th Ave NE Bellevue – Bypass Options 1 and 2
11757 SE 5th St Bellevue – Bypass Options 1 and 2
SE 8th St and Lake Hills Connector Bellevue – Bypass Options 1 and 2
2070 132nd Ave SE Bellevue Central Segment – Bypass Option 2
13630 SE Allen Rd Bellevue South Segment - All Options
13744 SE Allen Rd Bellevue South Segment - All Options
4411 137th Ave SE Bellevue South Segment - All Options
4489 137th Ave SE Bellevue South Segment - All Options
4901 Coal Creek Parkway Bellevue South Segment - All Options
13300 SE 42nd PL Bellevue South Segment - Willow 2 Option
13371 SE Newport Way Bellevue South Segment - Willow 2 Option
13357 SE Newport Way Bellevue South Segment - Willow 2 Option
4256 134th Ave SE Bellevue South Segment - Willow 2 Option
12919 SE Newport Way Bellevue South Segment - Willow 2 Option
12727 SE 73rd Pl Newcastle
SE 84th St Newcastle
12732 SE 80th Way Newcastle
7954 129th Pl SE Newcastle
3000 NE 4th St Renton
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APPENDIX C SCENIC VIEWS AND AESTHETIC ENVIRONMENT METHODOLOGY MAY 2017
Figure C-3. Viewpoint Map
PHASE 2 DRAFT EIS PAGE C‐15
APPENDIX C SCENIC VIEWS AND AESTHETIC ENVIRONMENT METHODOLOGY MAY 2017
Figure C-4. Population Density Map
PHASE 2 DRAFT EIS PAGE C‐16
APPENDIX C SCENIC VIEWS AND AESTHETIC ENVIRONMENT METHODOLOGY MAY 2017
7. IMPACTS TO SCENIC VIEWS
The assessment of impacts to scenic views was based the potential for view obstruction and the
FHWA concept of sensitivity to the impact (viewer sensitivity).
7.1 Scenic View Obstruction
A GIS analysis was conducted to identify areas from which a portion of the proposed transmission
line would obstruct the view of an identified visual resource. This GIS analysis identified where
visual resources can be seen based on the location and height of the visual resource and the
topography of the surrounding area. This area was further refined based on a similar analysis that
determined where the proposed transmission line could be seen based on the location of the segment,
the proposed height of the poles, and the surrounding topography. The outputs from these two
analyses were overlaid to determine where the project may impact scenic views. This is a
conservative estimate that was qualitatively refined through identification of barriers to views (dense
tree stands, etc.).
For this analysis, the viewshed tool was also used. To determine the area where scenic views can be
observed, a process similar to the one used for the aesthetic environment study area was adopted.
However, for this analysis, visual resources were used as observation points and their unique offsets
were applied (Table C-7).
Table C-7. Visual Resources input into Viewshed Tool
Visual Resource Offset Applied
Mount Rainier Line of frontage at 14,411 feet (based on mountain height)
Cascade Mountain
Range
Line of frontage at 5,000 feet (based on Typical King County DEM data
height)
Issaquah Alps
(Cougar Mountain)
Line of frontage at 1,600 feet (based on Typical King County DEM data
height)
Lake Washington Line along the eastern shoreline at 20 feet above sea level
Lake Sammamish Line along the western shoreline at 30 feet above sea level
Seattle skyline Line of downtown frontage with a height of 650 feet (slightly higher than
Safeco Plaza)
Bellevue skyline Line encompassing downtown Bellevue at 460 feet (slightly higher than
Bellevue Towers Two)
To assess the areas that would be affected under different build scenarios, the heights of the existing
and proposed lines were “burned” into the DSM to identify which areas with scenic views are
already impacted by views of a transmission line and which areas with scenic views are not currently
impacted, but would be after construction of the project (Table C-8). The heights used for the
“proposed maximum pole heights” for the GIS analysis differ slightly from the final proposed
maximum heights, due in part to design changes made during the course of the EIS assessment.
These design changes were considered qualitatively as part of the impacts assessment, but the EIS
Consultant Team decided not to rerun the scenic view obstruction analysis because in some instances
PHASE 2 DRAFT EIS PAGE C‐17
APPENDIX C SCENIC VIEWS AND AESTHETIC ENVIRONMENT METHODOLOGY MAY 2017
a more conservative pole height was used. In the instances where a less conservative pole height was
used, the difference was considered to not substantially change the results of the GIS analysis.
Table C-8. Existing and Proposed Maximum Pole Height by Roadway
Segment
Height Used for the GIS Analysis
Redmond 120'
Bellevue North 100'
Bellevue Central Existing 115'
Bellevue Central Bypass 1 115'
Bellevue Central Bypass 2 115'
Bellevue South Oak 1 Corridor: 90’
SE 30th St /Factoria Blvd/Coal Creek Pkwy: 125'
Bellevue South Oak 2 Corridor: 90’
SE 30th St /Factoria Blvd/Coal Creek Pkwy: 125'
124th Ave SE: 80'
Bellevue South Willow 1 95'
Bellevue South Willow 2 Corridor: 95'
Newport Way: 80'
Factoria Blvd/Coal Creek Pkwy: 90'
Newcastle 100'
Renton 125'
Source: PSE, 2016b.
To burn the lines into the DSM, a raster of the proposed alignment was created with a value of 0
assigned to everywhere except along the line, which was assigned a value equal to pole height
(specified in Table C-8). Then, using a raster calculator, the line height was burned into the DSM to
get a DSM+LINE (DLI) raster (Figure C-5).
Figure C-5. Factoring Line Heights
PHASE 2 DRAFT EIS PAGE C‐18
APPENDIX C SCENIC VIEWS AND AESTHETIC ENVIRONMENT METHODOLOGY MAY 2017
The following DLIs were created:
One DLI as if no lines were present.
One DLI where the existing transmission heights would be burned in.
One DLI with the heights for the Redmond, North Bellevue, Newcastle, and Renton
segments. These segments can be grouped into one DLI because there are no different pole
height options.
Four DLIs for the Bellevue South Segment options.
Three DLIs for bypass Bellevue Central Segment options.
Each of the DLIs was used as the ground raster for a viewshed analysis to identify where the scenic
resources would be viewable on the landscape, creating results for each pole height scenario. To
understand the areas where views would be negatively impacted by the project, areas where scenic
views are already impacted by the transmission line were subtracted from the area with scenic views
that would be impacted by the proposed transmission line.
Figure C-6 shows the output from the GIS analysis described above. Similar to the GIS analysis
conducted for the study area, some areas may have been identified as having scenic view impacts but
in reality should not have been included because the line would be so small that it is unrealistic that it
would be distinguishable on the horizon, or dense areas of tree stands were misinterpreted by the GIS
analysis as being a rise in topography from which views could be had (rather than being considered
hindrances to views). For areas where it was questionable if scenic views would actually be
impacted, a field survey was conducted to verify. In general, areas where potential scenic views were
identified had scenic views in the approximate vicinity; however, in some cases these views were
less frequent than may have been shown by the analysis depending on the presence of dense
vegetation. The only area that was completely eliminated from consideration was where scenic views
were identified in the Liberty Ridge area. A field visit conducted on October 7, 2016 confirmed that
scenic views from that location were not present due to the topography of the area. The EIS
Consultant Team believes that the reason the GIS analysis identified this area as an area with
potential scenic view impacts was because the DSM used was from 2002/2003. Since that time,
significant grading has occurred to support development of the Liberty Ridge neighborhood. These
changes to the topography are thought to have resulted in the loss of scenic views. In general, the
highest concentrations of areas with scenic views that could be impacted by the project were within
approximately 550 feet of the corridor.
7.2 Viewer Sensitivity
Viewer sensitivity was evaluated as described in Section 6.2.
PHASE 2 DRAFT EIS PAGE C‐19
APPENDIX C SCENIC VIEWS AND AESTHETIC ENVIRONMENT METHODOLOGY MAY 2017
Figure C-6. Potential Areas Where Scenic Views May Be Impacted
PHASE 2 DRAFT EIS PAGE C‐20
APPENDIX C SCENIC VIEWS AND AESTHETIC ENVIRONMENT METHODOLOGY MAY 2017
8. THRESHOLD OF SIGNIFICANCE
The value of scenic views and the aesthetic environment is subjective, making it difficult to quantify
or estimate impacts. There is no widely accepted definition of significant visual effects because the
significance of an activity varies with the setting and viewer preferences. For this project,
significance was determined based on criteria similar to those described in The State Clean Energy
Program Guide: A Visual Impact Assessment Process for Wind Energy Projects (Vissering et al.,
2011). These criteria, while not developed for transmission lines, were used for wind turbines, which
can be similar in height and scale to utility poles and are widely studied for visual impacts. This
guide suggests that the following criteria be considered when determining if a project would result in
undue or unreasonable visual impacts: violation of aesthetic standards, dominance of the project in
views from highly sensitive viewing areas, and failure to take reasonable mitigation measures
(Vissering et al., 2011).
A review of policies and regulations applicable to the study area revealed that the existing regulatory
framework was insufficient for determining significance because no clear written standards are
included for impacts to scenic views or the aesthetic environment.
To develop a threshold for significance that reflects the policies of the Partner Cities, the EIS
Consultant Team held a workshop in August 2016 with staff from the Partner Cities that would
potentially experience scenic view or aesthetic impacts (Redmond, Bellevue, Newcastle, and
Renton). The purpose of the workshop was to collaboratively define significance thresholds based on
policies, past precedent, and practice within the Partner City jurisdictions.
During the workshop, city staff were provided with the following:
A map showing where scenic views would be impacted along the entire corridor.
Visual simulations showing key examples of how the project could change the aesthetic
environment.
A handout with each city’s applicable policies and regulations.
The EIS Consultant Team walked through examples for each segment/option, and the group as a
whole refined a set of significance criteria. The following significance criteria were adopted for the
EIS evaluation and incorporate findings from the Partner Cities workshop:
Less-than-Significant:
Aesthetic environment - The degree of contrast between the project and the existing
aesthetic environment would be minimal, or viewer sensitivity is low.
Scenic views - The area with impacted scenic views would not include a substantial number
of sensitive viewers, including residential viewers, viewers from parks and trails, or viewers
from outdoor recreation facilities; or the degree of additional obstruction of views compared
to existing conditions would be minimal.
PHASE 2 DRAFT EIS PAGE C‐21
APPENDIX C SCENIC VIEWS AND AESTHETIC ENVIRONMENT METHODOLOGY MAY 2017
Significant:
Aesthetic environment - The degree of contrast between the project and the existing
aesthetic environment would be substantial and viewer sensitivity is high.
Scenic views - The area with scenic views impacted includes a substantial number of
sensitive viewers, including residential viewers, viewers from parks and trails, or viewers
from outdoor recreation facilities; and the degree of additional obstruction of views compared
to existing conditions would be substantial.
It was agreed that significant impacts should be assigned on a sub-option level.
PHASE 2 DRAFT EIS PAGE C‐22 APPENDIX C SCENIC VIEWS AND AESTHETIC ENVIRONMENT METHODOLOGY MAY 2017 9. SUMMARY OF PLANNING POLICIES AND CODE REQUIREMENTS Table C-9. Planning Policies and Code Requirements Plans Protected Views and Visual Resources Guidance for Reducing Visual Impacts King County Eastside Rail Corridor Master Plan 2016 In some cases, bridges may also be locations for viewpoints. N/A Existing landscape that does not need to be removed for trail construction will be evaluated to determine if it is consistent with public use, including aesthetics and overall trail design. N/A Redmond Vision 2030 City of Redmond Comprehensive Plan Views of Mount Rainier, the Cascade Mountains, and Lake Sammamish. N/A Unique public views that provide a sense of place N/A Scenic, public view corridors toward the Cascades and the Sammamish Valley (Plan Policy NR-10). N/A Views of surrounding hillsides, mountains, and tree line N/A Tree stands and views from the valley (Plan Policy N-SV-4) N/A Woodland views from neighborhood residences N/A N/A Throughout the plan, landscaping is encouraged to provide aesthetic value, unify site design, and soften or disguise “less aesthetically pleasing features of a site” (Policy CC-23). The Plan requires “reasonable screening or
PHASE 2 DRAFT EIS PAGE C‐23 APPENDIX C SCENIC VIEWS AND AESTHETIC ENVIRONMENT METHODOLOGY MAY 2017 Plans Protected Views and Visual Resources Guidance for Reducing Visual Impacts architecturally compatible design of above ground utilityfacilities, such as transformers and associated vaults” (Policy UT-15). It suggests promoting well-designed utility facilities through use of color, varied and interesting materials, art work, and superior landscape design. Redmond Zoning Code (RZC) Current through June 16, 2015 Appearance of Public Ways Underground electrical facilities if economically-feasible (RZC 21.17). Public view corridors and gateways should be protected (RZC 21.42) N/A Bellevue Bellevue Comprehensive Plan 2015 Urban design that exemplifies a “City in a Park” with tree-lined streets, public art, vast parks, natural areas, wooded neighborhoods, two large lakes, and mountain views. N/A Views of water, mountains, and skylines from public places (Plan Policy UD-62). Link increased intensity of development with increased view preservation (Plan Policy UD-48). N/A Implement new and expanded transmission and substation facilities in such a manner that they are compatible and consistent with the local context and the land use pattern established in the Comprehensive Plan (Plan Policy UT-95). N/A Conduct a siting analysis for new facilities and expanded facilities at sensitive sites (areas in close proximity to residentially-zoned districts) (Plan Policy UT-96). N/A States preference for use of new technology to reduce visual impacts. Green belts and open spaces per Parks and Open Space System Plan. Avoid locating overhead lines in greenbelts or open spaces (Plan Policy UT-69). Distinctive neighborhood character within Bellevue’s diverse neighborhoods (Plan Policy N-9). Design, construct, and maintain facilities to minimize their impact on surrounding neighborhoods (Plan Policy UT-8).
PHASE 2 DRAFT EIS PAGE C‐24 APPENDIX C SCENIC VIEWS AND AESTHETIC ENVIRONMENT METHODOLOGY MAY 2017 Plans Protected Views and Visual Resources Guidance for Reducing Visual Impacts Design boulevards adjacent to parks, natural areas and open spaces to reflect scenic elements of the surrounding areas and neighborhoods. Streetscape design should promote a safe and comfortable park-like experience for all users (Plan Policy UD-70). This includes: Bel-Red Road Lake Hills Connector Richards Road Factoria Blvd SE Coal Creek Parkway SE Newport Way N/A Bridle Trails Subarea Plan 2015 Wooded, natural, rural, and equestrian character of the Subarea (Plan Policy S-BT-3). N/A N/A Encourage retention of vegetation on the lower slopes of the bluff adjacent to SR 520 at approximately 136th Avenue NE to provide a visual separator between residential areas and the freeway (Plan Policy S-BT-42). Roadsides in Bridle Trails Subarea. Improve roadsides to create a unified visual appearance (Plan Policy S-BT-43). Bel-Red Subarea Plan 2015 Bel-Red Subarea street environment (Plan Policy S-BR-25; S-BR-39; S-BR-59). N/A Bel-Red Subarea parks and open space system (Plan Policy S-BR-35). N/A Wilburton/NE 8th St Subarea Plan 2015 N/A Utilities should be provided to serve the present and future needs of the Subarea in a way that enhances the visual quality of the community (where practical) (Plan Policy S-WI-44) Significant views from park lands (Plan Policy S-WI-11) N/A
PHASE 2 DRAFT EIS PAGE C‐25 APPENDIX C SCENIC VIEWS AND AESTHETIC ENVIRONMENT METHODOLOGY MAY 2017 Plans Protected Views and Visual Resources Guidance for Reducing Visual Impacts Views of prominent landforms, vegetation, watersheds, drainage ways, Downtown and significant panoramas in the Subarea (Plan Policy S-WI-40). Key views include: West from NE 8th Street and NE 5th Street on the ridge between 122nd and 123rd Avenue, South from the Lake Hills Connector north of SE 8th Street, and From SE 1st Street and Main Street at the power line right-of-way at 136th Avenue. N/A Southeast Bellevue Subarea Plan 2015 Existing residential character (Plan Policy S-SE-2) N/A Richards Valley Subarea Plan 2015 Views from Woodridge Hill and the wooded areas and wetlands in the valley. Retain the remaining wetlands within the 100-year floodplain along Richards Creek and Kelsey Creek for the aesthetic value and character of the community (Plan Policy S-RV-5). Develop sites in accordance with Sensitive Areas Regulations (Plan Policy S-RV-12). N/A Use common corridors for new utilities if needed (Plan Policy S-RV-20). N/A New development, should install a dense visual vegetative screen along Richards Road (Plan Policy S-RV-31). Eastgate I-90 Corridor Encourage site design that includes visibly recognizable natural features such as green walls, façade treatments, green roofs, and abundant natural landscaping (Plan Policy S-RV-24).
PHASE 2 DRAFT EIS PAGE C‐26 APPENDIX C SCENIC VIEWS AND AESTHETIC ENVIRONMENT METHODOLOGY MAY 2017 Plans Protected Views and Visual Resources Guidance for Reducing Visual Impacts Streets and arterials Disturb as little of the natural character as possible when improving streets and arterials (Plan Policy S-RV-26). Green and wooded character of the Richards Road corridor (Plan Policy S-RV-30). N/A Eastgate Subarea Plan 2015 View amenities of adjacent single-family neighborhoods (Plan Policy S-EG-22). N/A N/A Discourage new development from blocking existing views from public spaces (Plan Policy S-EG-23). Factoria Subarea Plan 2015 Natural setting for residential areas N/A Cohesiveness and compatibility of commercial districts Manage change in the commercial district N/A Protect single family neighborhoods from encroachment by more intense uses (Plan Policy S-FA-2). Pathways and access points with views of Sunset Creek, Richards Creek, Coal Creek, (Plan Policy S-FA-18). N/A Visual connections along Factoria Boulevard(Plan Policy S-FA-32). N/A N/A Minimize disruptive effects of utility construction on property owners, motorists, and pedestrians (Plan Policy S-FA-35). Newport Hills Subarea Plan 2015 Emphasize as a distinct visual element thepreservation of existing trees on protected slopes and hilltops (Plan Policy S-NH-44). Use these trees to screen incompatible land uses. N/A Make edges between different land uses distinct without interfering with security or visual access (Plan Policy S-NH-48). Existing visual features such as trees andhilltops, views of water, and passive open N/A
PHASE 2 DRAFT EIS PAGE C‐27 APPENDIX C SCENIC VIEWS AND AESTHETIC ENVIRONMENT METHODOLOGY MAY 2017 Plans Protected Views and Visual Resources Guidance for Reducing Visual Impacts space (Plan Policy S-NH-54).Bellevue City Code Current through August 3, 2015 N/A Electrical utility facilities shall be sight-screened through landscaping and fencing (BCC 20.20.255.F). City of Bellevue Draft SMP 2013 Shoreline New or expanded utility systems and facilities shall be designed and aligned to minimize impacts to natural systems and features and shall minimize topographic modification. New or expanded utility systems and facilities shall be co-located underground and within existing or planned improved rights-of-way, driveways, and/or utility corridors whenever possible. Where the visual quality of the shoreline or surrounding neighborhood will be negatively impacted, new or expanded utility systems and facilities shall incorporate screening and landscaping sufficient to maintain the shoreline aesthetic quality and shall provide screening of facilities from the lake and adjacent properties in a manner that is compatible with the surrounding environment. New or expanded utilities shall incorporate shoreline public access, consistent with the requirement contained in LUC 20.25E.060.I, (Public Access). When allowed, utility facilities located above ground shall be: (1) Housed in a building that incorporates design features that are compatible with the character of the surrounding neighborhood or area, unless housing the facility in a structure would fundamentally interfere with the maintenance and operation of the facility. (2) Sight-screened, if the facility does not conform with the standards in paragraph E.3.b.ix.(1) of this section, with evergreen trees, shrubs, and other native landscaping
PHASE 2 DRAFT EIS PAGE C‐28 APPENDIX C SCENIC VIEWS AND AESTHETIC ENVIRONMENT METHODOLOGY MAY 2017 Plans Protected Views and Visual Resources Guidance for Reducing Visual Impacts materials planted in sufficient depth to form an effectivesight barrier within five (5) years. Newcastle City of Newcastle 2035 Comprehensive Plan Existing character, scale, and neighborhood quality (Plan Policy LU-G3). N/A Open space, wildlife habitats, recreational areas, trails, connection of critical areas, natural and scenic resources, as well as shoreline areas (Plan Policy LU-G6). N/A Natural features that contribute to the City’s scenic beauty (Plan Policy LU-G8). N/A N/A The City shall require that the undergrounding of new utilitydistribution lines, with the exception of high voltage electrical transmission lines (Plan Policy UT-P1). N/A The City shall require the undergrounding of existing utilitydistribution lines where physically feasible as streets are widened and/or areas are redeveloped based on coordination with local utilities (Plan Policy UT-P2). N/A The City shall promote collocation of major utilitytransmission facilities such as high voltage electrical transmission lines and water and natural gas trunk pipe lines within shared utility corridors, to minimize the amount of land allocated for this purpose and the tendency of such corridors to divide neighborhoods (Plan Policy UT-P3). N/A The City shall encourage utility providers to limitdisturbance to vegetation within major utility transmission corridors to what is necessary for the safety and maintenance of transmission facilities (Plan Policy UT-P8). N/A The City should encourage utility providers to exerciserestraint and sensitivity to neighborhood character in planting appropriate varieties and trimming tree limbs around aerial lines (Plan Policy UT-P9).
PHASE 2 DRAFT EIS PAGE C‐29 APPENDIX C SCENIC VIEWS AND AESTHETIC ENVIRONMENT METHODOLOGY MAY 2017 Plans Protected Views and Visual Resources Guidance for Reducing Visual Impacts N/A The City should require utility providers to design andconstruct overhead transmission lines in a manner that is environmentally sensitive, safe, and aesthetically compatible with surrounding land uses (Plan Policy UT-P10). N/A The City should require utility providers to minimize visualand other impacts of transmission towers and overhead transmission lines on adjacent land uses through careful siting and design (Plan Policy UT-P14). N/A The City should require new, modified, or replacement transmission structures (such as lattice towers, monopoles, and the like) to be designed to minimize aesthetic impacts appropriate to the immediate surrounding area whenever practical (Plan Policy UT-P16). N/A The City shall, where appropriate, require reasonable landscape screening of site-specific above-ground utility facilities in order to diminish visual impacts (Plan Policy UT-P20). Renton City of Renton Comprehensive Plan (2015) High volume of trees and clear mountain views. N/A Public scenic views and public view corridors, such as “physical, visual, and perceptual linkages to Lake Washington and Cedar River” (Plan Policy L-55). N/A Natural forms, vegetation, distinctive stands of trees, natural slops, and scenic areas that “contribute to the City’s identity, preserve property values, and visually define the N/A
PHASE 2 DRAFT EIS PAGE C‐30 APPENDIX C SCENIC VIEWS AND AESTHETIC ENVIRONMENT METHODOLOGY MAY 2017 Plans Protected Views and Visual Resources Guidance for Reducing Visual Impacts community neighborhoods” (Plan Policy L-56).Lakes and shorelines. N/A Views of the water from public property or views enjoyed by a substantial number of residences. N/A N/A Design shoreline developments to maintain or enhance aesthetic values and scenic views (Plan Policy SH-16). N/A Make facility improvements and additions within existing corridors wherever possible (Plan Policy U-73). City of Renton Municipal Code (RMC) Current through November 16, 2015 Shoreline Design shoreline use and development to maintain shoreline scenic and aesthetic qualities derived from natural features, such as shore forms and vegetative cover (RMC 4-3-090.D.3.a). Prohibits utilities in the Shoreline Natural shoreline environment designation (RMC 4-3-090.E.1). N/A Visual prominence of structures must be minimized, including light, glare, and reflected light (RMC 4-3-090.D.3.b.vii). N/A Aboveground utilities must be screened with masonry, decorative panels, and/or evergreen trees, shrubs, and landscaping sufficient to form an effective sight barrier within a period of five (5) years (RMC 4-6-090.11.a.xvi). City of Renton SMP 2011 Scenic and aesthetic qualities derived from natural features of the shoreline, such as vegetative cover and shore forms (Ordinance No. 5633). N/A
PHASE 2 DRAFT EIS PAGE C‐31
APPENDIX C SCENIC VIEWS AND AESTHETIC ENVIRONMENT METHODOLOGY MAY 2017
10. REFERENCES
City of Bellevue. 2015. Parks GIS Data
City of Issaquah. 2015. Parks GIS Data.
City of Kirkland. 2015. Parks GIS Data.
City of Newcastle. 2015. Parks GIS Data.
City of Redmond. 2015. Parks GIS Data.
City of Renton. 2015. Parks GIS Data.
ESRI. 2016. Using Viewshed and Observer Points for visibility analysis.
http://pro.arcgis.com/en/pro-app/tool-reference/3d-analyst/using-viewshed-and-observer-
points-for-visibility.htm.
FHWA (Federal Highway Administration). 2015. Guidelines for the Visual Impact Assessment of
Highway Projects.
GIS Geography. 2016. DEM, DSM, DTM Differences. http://gisgeography.com/dem-dsm-dtm-
differences/.
King County. 2003a. King County 2002/2003 Digital Surface Model (DSM).
King County. 2003b. King County 100-foot contours. GIS Data.
King County. 2015a. 2012 Assessor Real Property Data and 2015 Parcel Data, updated July 10,
2015.
King County. 2015b. Parks GIS Data.
NOAA (National Oceanic and Atmospheric Administration). 2011. LandCoverClip.tif. GIS Data.
PSE (Puget Sound Energy). 2016a. Segment Alignment GIS Data. Provided to ESA in June 2016.
PSE (Puget Sound Energy). 2016b. Segment Data Table. Provided to ESA on July 15, 2016.
Power Engineers. 2016. Energize Eastside Photo Simulation Methodology. Memorandum from Jason
Pfaff, Department Manager, to Puget Sound Energy. June 10, 2016.
U.S. Census Bureau. 2014. Total Population, 2010–2014 American Community Survey 5-Year
Estimates.
Available: http://factfinder.census.gov/faces/tableservices/jsf/pages/productview.xhtml?pid=
ACS_10_5YR_B01003&prodType=table. Accessed: Aug. 16, 2016.
Vissering, Jean; Mark Sinclair; and Anne Margolis. 2011. State Clean Energy Program Guide: A
Visual Impact Assessment Process for Wind Energy Projects. Clean Energy States Alliance.
May 2011.
Ecology (Washington State Department of Ecology). 2014. Water Resources GIS Data.
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Attachment 1. Diameter of Existing Wire and Proposed Wire
PHASE 2 DRAFT EIS PAGE C‐33
APPENDIX C SCENIC VIEWS AND AESTHETIC ENVIRONMENT METHODOLOGY MAY 2017
Attachment 2. Methodology and Visual Simulations
MEMORANDUM
PAGE 1 OF 2
2041 SOUTH COBALT POINT WAY
MERIDIAN, ID 83642 USA
PHONE
FAX
208-288-6100
208-288-6199
DATE: June 10, 2016
TO: Puget Sound Energy
C:
FROM: Jason Pfaff, Department Manager
SUBJECT: Energize Eastside Photo Simulation Methodology
MESSAGE
POWER Engineers Used the Following Photo Simulation Approach on the Energize
Eastside Transmission Line Project:
1. Key Observation Point Identification (KOPs) – POWER worked with PSE to
determine KOP locations. KOPs are loaded into Google Earth, and discussed as a
team to ensure all visual issues are addressed. KOP coordinates and markers were
prepared for the field photo shoot.
2. Photo Collection – During the field Photo Shoot, POWER collected the following
information:
a. Camera – POWER uses a full frame Canon 5D Mark II or III professional
Digital Camera. All photos are taken with a 50mm. lens. In some extreme
foreground situations a 28mm. lens may be used. Up to 3 images were
taken from a single location.
b. Atmospheric Conditions – POWER documented the following information,
as it has an impact of the photo simulation accuracy.
i. Date, Time of Day (Hour/Minutes) – Determines color of sunlight,
shadow location and irradiance levels.
ii. Atmospheric conditions – Haze and light diffusion has an impact on
contrast at distance
iii. Lens length (50 mm is typical, in some cases 28mm)
3. Post field photo shoot – After the photography collection, representative
photography from each KOP were compiled into a photo KMZ for PSE to review
photography and locations.
4. 3D Existing Conditions Model – POWER developed an existing conditions 3D
Model of the study areas including terrain and structures. The existing conditions
models were used in the 3D photo registration process. Once the 3D existing
conditions model has been developed using a minimum of 30 meter contour
elevation data, GPS data was be imported into the 3D model and checked for spatial
accuracy.
5. 3D Photo Registration – All photos carried forward for photo simulation
development were registered into a 3D modeling program. Virtual Cameras were
aligned with the field camera (Canon 5D Mark II, 5D Mark III) through the use of
GPS, compass heading and horizontal angle information. Accuracy was further
refined by importing and aligning the existing 3D model information into the 3D
Program and ensuring it aligned exactly with the photographic background.
MEMORANDUM POWER ENGINEERS, INC.
PAGE 2 OF 2
6. 3D Sun and Atmospheric Conditions – POWER imported all atmospheric data into
the 3D Software to develop a sun and atmospheric system that matched the
photography.
7. 3D Proposed Project Development – POWER developed the proposed project into a
3D Model. PSE worked with POWER to provide the PLS-CAD model data, as with
any other CAD and GIS data available. PLS-CAD models are 3D engineering
designs developed for each transmission line structure. All information was
imported into the 3D existing conditions model and checked for accuracy. 3D
materials (Corten Steel or Wood), and associated specular reflectance information
were applied to the proposed 3D information.
8. 3D Rendering – After all information has been properly aligned, atmospherics
checked and materials applied, POWER “rendered” the 3D information over the top
of the 2D photography. The result was a new 3D image with an alpha channel
allowing existing and proposed information to be separated different layers.
9. Photoshop – Photoshop was used in the last step of the process. Foreground
screening elements such as trees, structures, etc are extracted and placed on separate
layers. Proposed transmission line information was placed on separate layers, and
background information is placed on their own layers. Separation of layers is an
important step; as it allows for fine-tune adjustments to color, grain, and depth of
field, atmospherics and contrast. Once all elements have been correctly adjusted
and masking elements correct, all layers were merged into one single photo
simulation.
10. Board Layouts – POWER created existing and proposed layouts, showing both
images side by side in a PDF form.
Sincerely,
Jason Pfaff
Director of Visualization Services
TimeViewing DirectionDateAddress2:59 PMNorthwestPole Heights: Existing Conditions~50 feetPole Heights: Conceptual Project~85 feet3/8/2016Redmond Way, RedmondPhoto simulations are for discussion purposes only and may change pending public, regulatory and utility review Existing Conditions3/16/2016Conceptual ProjectKOPNORTH 15SEGMENT1
Existing Conditions
Conceptual Project
Photo simulations are for discussion purposes only and may change pending public, regulatory and utility review
Address 13505 NE 75th St, Redmond
Date 3/8/2016
Time 2:41 PM
Viewing Direction South
Existing Pole Heights -75feet
Proposed Pole Heights -110 feet
I
energ1ze EASTSIDE
KOP NORTH 14
SEGMENT 1
• PUGET SOUND ENERGY
1Pole Heights: Existing Conditions ~55 feet ~90 feetPole Heights: Conceptual ProjectKOP North 3SEGMENT 1
Conceptual Project
Photo simulations are for discussion purposes only and may change pending public, regulatory and utility review
Address 267 140th Ave NE, Bellevue
Date 5/13/2016
Time 10:40AM
Viewing Direction North
Existing Pole Heights -60 feet
Proposed Pole Heights -95feet
I
energ1ze EASTSIDE
KOP CENTRAL 22
SEGMENT 1
• PUGET SOUND ENERGY
Conceptual Project
Photo simulations are for discussion purposes only and may change pending public, regulatory and utility review
Address 13606 Main St, Bellevue
Date 3/30/2016
Time 3:52 PM
Viewing Direction North
Existing Pole Heights -50 feet
Proposed Pole Heights -100 feet
I
energ1ze EASTSIDE
KOP CENTRAL 20
SEGMENT 1
• PUGET SOUND ENERGY
Conceptual Project
Photo simulations are for discussion purposes only and may change pending public, regulatory and utility review
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Address 106136th Ave SE, Bellevue
Date 3/30/2016
Time 3:48 PM
Viewing Direction South
Existing Pole Heights -75feet
Proposed Pole Heights -110 feet
I
energ1ze EASTSIDE
KOP CENTRAL 21
SEGMENT 1
• PUGET SOUND ENERGY
Address 13600 SE 5th St, BellevueDate 4/2/2014Time 2:54 PMViewing Direction NorthPole Heights: Existing Conditions ~60 feetPole Heights: Conceptual Project ~100 feet1
Conceptual Project
Photo simulations are for discussion purposes only and may change pending public, regulatory and utility review 8/10/2016
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Address 13810 Lake Hills Connector, Bellevue
Date an /2016
Time 2:09 PM
Viewing Direction West
Existing Pole Heights NA
Proposed Pole Heights -100feet
I
energ1ze EASTSIDE
KOP CENTRAL 25
BYPASS
• PUGET SOUND ENERGY
Address 13711 SE 18th St, BellevueDate 4/2/2014Time 3:19 PMViewing Direction WestPole Heights: Existing Conditions ~55 feetPole Heights: Conceptual Project ~90 feet1
Existing Conditions
Conceptual Project i-----------~~=·,==:::::::!...
Photo simUlations are for discussion purposes only and may change pending public, regulatory and utility review
Address 1990 134th Pl SE, Bellevue
Date
Time
Viewing Direction
Existing Pole Heights
Proposed Pole Heights
I
energ1ze EASTSIDE
3/30/2016
3:22 PM
South
55feet
-95feet
KOP CENTRAL 28
SEGMENT I
• PUGET SOUND ENERGY
Address 2160 135th Pl SE, BellevueDate 3/31/2014Time 4:00 PMViewing Direction SoutheastPole Heights: Existing Conditions ~55 feetPole Heights: Conceptual Project ~95 feet1SEGMENT
Existing Conditions
Photo simulations are for di scussion purposes onl y and may change pending publ ic, regulatory and utili ty re view
Conceptual Project
5/5/2016
Time
Viewing Direction
Date
Address
3:48 PM
South
3/30/2016
136th Ave NE & SE 1st St
E
KOP
SEGMENT
CENTRAL 21Address SE 30th Street, Bellevue
Date 7/25/2016
Viewing Direction East
Pole Heights: Existing Conditions ~65-70 feet
Pole Heights: Conceptual Project ~70-90 feet
Richards Creek
SUBSTATION
Existing Conditions
Conceptual Project
1/13/2017
Conceptual Project
Photo simulations are for discussion purposes only and may change pending public, regulatory and utility review
Address 12828 Bel-Red Rd, Bellevue
Date 7/15/2016
Time 11:30 AM
Viewing Direction Southwest
Existing Pole Heights NA
Proposed Pole Heights -120feet
I
energ1ze EASTSIDE
KOP CENTRAL 26
BYPASS
• PUGET SOUND ENERGY
Conceptual Project
Photo simulations are for discussion purposes only and may change pending public, regulatory and utility review
Address 1227 124th Ave NE, Bellevue
Date 8/24/2016
Time 5:31 PM
Viewing Direction South
Existing Pole Heights NA
Proposed Pole Heights -90feet
I
energ1ze EASTSIDE
KOP CENTRAL 36
BYPASS
• PUGET SOUND ENERGY
Conceptual Project
Photo simulations are for discussion purposes only and may change pending public, regulatory and utility review
Address 12253 NE 8th St, Bellevue
Date 8/24/2016
Time 5:10 PM
Viewing Direction West
Existing Pole Heights NA
Proposed Pole Heights -100feet
I
energ1ze EASTSIDE
KOP CENTRAL 29
BYPASS
• PUGET SOUND ENERGY
Conceptual Project
Photo simulations are for discussion purposes only and may change pending public, regulatory and utility review
Address 11751 SE 5th Street, Bellevue
Date 9/12/2016
Time 1:58 PM
Viewing Direction Northwest
Existing Pole Heights NA
Proposed Pole Heights 100-105 feet
KOP CENTRAL 33
BYPASS
energize EASTSIDE .PUGET SOUND ENERGY
Existing Conditions
Photo simul ati ons are for discussion purpose s onl y and may change pending public, re gul atory and utility review
Conceptual Project
1/25/2017
Time
Viewing Direction
Date
Address
2:58 PM
East
6/7/2016
Lake Hills Connector, Bellevue
KOP CENTRAL 38
Existing Pole Heights NA
Proposed Pole Heights ~100 feet
BYPASS
.
Existing Conditions
Conceptual Project
Photo simulations are for discussion purposes only and may change pending public, regulatory and utility review
Address SE 8th St and Lake Hills Connector, Bellevue
Date 6/7 /2016
Time 2:20 PM
Viewing Direction Northwest
Existing Pole Heights NA
Proposed Pole Heights -110 feet
I
energ1ze EASTSIDE
KOP CENTRAL 23
BYPASS
• PUGET SOUND ENERGY
Conceptual Project
Photo simulations are for discussion purposes only and may change pending public, regulatory and utility review
Address 1680 Richards Rd, Bellevue
Date
Time
Viewing Direction
Existing Pole Heights
Proposed Pole Heights
I
energ1ze EASTSIDE
8/24/2016
4:09 PM
Northwest
NA
-110 feet
KOP CENTRAL 27
BYPASS
• PUGET SOUND ENERGY
Conceptual Project
Photo simulations are for discussion purposes only and may change pending public, regulatory and utility review
Address 2070 132nd Ave SE, Bellevue
Date 6fl/2016
Time 1:37 PM
Viewing Direction North
Existing Pole Heights NA
Proposed Pole Heights -100 feet
KOP CENTRAL 24
BYPASS
energize EASTSIDE .PUGET SOUND ENERGY
TimeViewing DirectionDateAddress1:44 PMNortheast3/30/201613630 SE Allen Rd, Bellevue Photo simulations are for discussion purposes only and may change pending public, regulatory and utility review Existing Conditions4/13/2016Conceptual ProjectKOP SOUTH 24SEGMENT2Pole Heights: Existing Conditions ~60 feetPole Heights: Conceptual Project ~95 feet
TimeViewing DirectionDateAddress1:42 PMNortheastPole Heights: Existing ConditionsPole Heights: Conceptual Project ~65 feet ~95 feet3/30/201613744 SE Allen Rd, BellevuePhoto simulations are for discussion purposes only and may change pending public, regulatory and utility review Existing Conditions4/13/2016Conceptual ProjectKOP SOUTH 25SEGMENT2
2Pole Heights: Existing Conditions~50 - 60 feetPole Heights: Conceptual Project~65 feet,
Photo simulations are for discussion purposes only and may change pending public, regulatory and utility review
Existing Conditions
J
5/09/2016
Conceptual Project
Time
Viewing Direction
Date
Address
9:32 AM
North
4/10/2014
4489 137th Ave SE KOP
SEGMENT
CENTRAL 15
Photo simulations are for discussion purposes only and may change pending public, regulatory and utility review
Existing Conditions
J
5/09/2016
Conceptual Project
Time
Viewing Direction
Date
Address
9:32 AM
North
4/10/2014
4489 137th Ave SE KOP
SEGMENT
CENTRAL 15Address 4489 137th Ave SE, Bellevue
Date 4/10/2014
Time 9:32 AM
Viewing Direction North
Pole Heights: Existing Conditions ~50 - 60 feet
Pole Heights: Conceptual Project ~65 feet
2
TimeViewing DirectionPole Heights: Existing ConditionsDateAddress1:00 PMNorthwestNAPole Heights: Conceptual Project 3/30/201613300 SE 42nd Place, BellevuePhoto simulations are for discussion purposes only and may change pending public, regulatory and utility review Existing Conditions4/19/2016Conceptual ProjectKOPSOUTH 28SEGMENT2~70 feet
TimeViewing DirectionDateAddress1:30 PMNortheastPole Heights: Existing ConditionsPole Heights: Conceptual Project~40 - 50 feet~70 feet3/30/201613371 SE Newport Way, BellevuePhoto simulations are for discussion purposes only and may change pending public, regulatory and utility review Existing Conditions4/13/2016Conceptual ProjectKOPSOUTH 26SEGMENT2
TimeViewing DirectionDateAddress1:25 PMNorthwestPole Heights: Existing Conditions~ 40 - 50 feetPole Heights: Conceptual Project~ 70 feet3/30/201613357 SE Newport Way, BellevuePhoto simulations are for discussion purposes only and may change pending public, regulatory and utility review Existing Conditions4/13/2016Conceptual ProjectKOPSOUTH 27SEGMENT2Address 13357 SE Newport Way, BellevueDate 3/30/2016Time 1:25 PMViewing Direction NorthwestPole Heights: Existing Conditions ~40 - 50 feetPole Heights: Conceptual Project ~70 feet1
TimeViewing DirectionDateAddress1:04 PMNorthwestPole Heights: Existing ConditionsPole Heights: Conceptual Project~40 - 50 feet70 feet3/30/20164256 134th Ave SE, BellevueExisting Conditions4/19/2016Conceptual ProjectKOPSOUTH 29Due to existing vegetation, views of the proposed transmission line are blocked from this location.Photo simulations are for discussion purposes only and may change pending public, regulatory and utility review.SEGMENT2
TimeViewing DirectionDateAddress2:02 PMEastPole Heights: Existing Conditions~40 feetPole Heights: Conceptual Project~70 feet3/30/201612919 SE Newport Way, BellevuePhoto simulations are for discussion purposes only and may change pending public, regulatory and utility review Existing Conditions4/19/2016Conceptual ProjectKOPSOUTH 31SEGMENT2
TimeViewing DirectionDateAddress2:01 PMWestPole Heights: Existing Conditions~40 feetPole Heights: Conceptual Project~75 feet3/30/2016 12892 SE Newport Way, BellevuePhoto simulations are for discussion purposes only and may change pending public, regulatory and utility review Existing Conditions4/19/2016Conceptual ProjectKOPSOUTH 30SEGMENT2
Existing Conditions
Conceptual Project
Photo simulations are for discussion purposes only and may change pending public, regulatory and utility review
Address 4122 Factoria Blvd SE, Bellevue
Date sn1201s
Time 12:24 PM
Viewing Direction North
Existing Pole Heights -SO feet
Proposed Pole Heights -90feet
I
energ1ze EASTSIDE
KOP CENTRAL 13
OAK 1 -SEGMENT 2
• PUGET SOUND ENERGY
Existing Conditions
Conceptual Project
Photo simulations are for discussion purposes only and may change pending public, regulatory and utility review
Address 4122 Factoria Blvd SE, Bellevue
Date sn1201s
Time 12:24 PM
Viewing Direction North
Existing Pole Heights -SO feet
Proposed Pole Heights -90feet
I
energ1ze EASTSIDE
KOP CENTRAL 13
OAK 2 -SEGMENT 2
• PUGET SOUND ENERGY
Existing Conditions
Conceptual Project
I
I
I
I
1/
I I
//
I
I
Photo simulations are for discussion purposes only and may change pending public, regulatory and utility review
Address 12513 SE 38th St, Bellevue
Date 3/30/2016
Time 3:00 PM
Viewing Direction Southeast
Existing Pole Heights NA
Proposed Pole Heights -70 feet
I
energ1ze EASTSIDE
KOP SOUTH 34
SEGMENT 2
• PUGET SOUND ENERGY
Existing Conditions
Conceptual Project
I
I
I
I
1/
I I
//
I
I
Photo simulations are for discussion purposes only and may change pending public, regulatory and utility review
Address 12513 SE 38th St, Bellevue
Date 3/30/2016
Time 3:00 PM
Viewing Direction Southeast
Existing Pole Heights NA
Proposed Pole Heights -70 feet
I
energ1ze EASTSIDE
KOP SOUTH 34
SEGMENT 2
• PUGET SOUND ENERGY
Conceptual Project
Photo simulations are for discussion purposes only and may change pending public, regulatory and utility review
Address 5365 Coal Creek Parkway, Bellevue
Date 9/12/2016
Time 4:36 PM
Viewing Direction Northwest
Existing Pole Heights 65feet
Proposed Pole Heights 75-80feet
I
energ1ze EASTSIDE
KOP CENTRAL 35
OAK 1 -SEGMENT 2
• PUGET SOUND ENERGY
Conceptual Project
Photo simulations are for discussion purposes only and may change pending public, regulatory and utility review
Address 5365 Coal Creek Parkway, Bellevue
Date 9/12/2016
Time 4:36 PM
Viewing Direction Northwest
Existing Pole Heights 65feet
Proposed Pole Heights 75-80feet
I
energ1ze EASTSIDE
KOP CENTRAL 35
OAK 2 -SEGMENT 2
• PUGET SOUND ENERGY
Conceptual Project
Photo simulations are for discussion purposes only and may change pending public, regulatory and utility review
Address 5365 Coal Creek Parkway, Bellevue
Date 9/12/2016
Time 4:36 PM
Viewing Direction Northwest
Existing Pole Heights 65feet
Proposed Pole Heights 75-80feet
I
energ1ze EASTSIDE
KOP CENTRAL 35
WILLOW 1 -SEGMENT 2
• PUGET SOUND ENERGY
Conceptual Project
Photo simulations are for discussion purposes only and may change pending public, regulatory and utility review
Address 5365 Coal Creek Parkway, Bellevue
Date 9/12/2016
Time 4:36 PM
Viewing Direction Northwest
Existing Pole Heights 65feet
Proposed Pole Heights 75-80feet
I
energ1ze EASTSIDE
KOP CENTRAL 35
WILLOW 2 -SEGMENT 2
• PUGET SOUND ENERGY
1026 Monroe Ave NE, RentonPole Heights: Conceptual Project~90 feetPole Heights: Existing Conditions~55 feet3
! • " ••
Existing Conditions
Conceptual Project
Photo simulations are for discussion purposes only and may change pending public, regulatory and utility review
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Address 3000 NE 4th St, Renton
Date 3/8/2016
Time 1:55 PM
Viewing Direction North
Existing Pole Heights -65feet
Proposed Pole Heights -100feet
I
energ1ze EASTSIDE
KOP SOUTH 23
SEGMENT 3
• PUGET SOUND ENERGY
Existing Conditions
1
Conceptual Project
Photo simulations are for discussion purposes only and may change pending public, regulatory and utility review
Address 318 Glennwood Ct SE, Renton
Date 8/24/2016
Time 10:20AM
Viewing Direction North
Existing Pole Heights -50-70feet
Proposed Pole Heights -90feet
I
energ1ze EASTSIDE
KOP SOUTH 24 - W
SEGMENT 3
• PUGET SOUND ENERGY
Critical Areas Regulations by City
D
PHASE 2 DRAFT EIS PAGE D‐1 APPENDIX D CRITICAL AREAS REGULATIONS BY CITY MAY 2017 APPENDIX D. CRITICAL AREAS REGULATIONS BY CITY City/County Critical Area Description Mitigation City of Redmond (Redmond Zoning Code (RZC) Section 21.64.010) General (applicable to all critical areas) Utility installation, construction, and associated facilities and lines are exempt from CAO regulations if located in City road ROWs and are subject to restoration. If not exempt, then utilities project (facilities and poles) are prohibited from locating in critical areas but are allowed in critical area buffers provided mitigation standards are met. A critical areas permit is required. Mitigation is required (for all critical areas) to be provided on-site, in-kind if feasible. If not feasible, then off-site (within Redmond city limits), out-of-kind mitigation may be considered. RZC 21.64.030 Wetlands Wetlands are categorized according to Class I, II, III, and IV based on the Ecology Wetland Rating System. Buffers range from 25-300 feet. Alterations to category I wetlands are prohibited, alterations to II, III, and IV may be allowed subject to performance standards and mitigation. Wetland acreage replacement ratios are required for mitigation (in addition to general mitigation requirements) and determined according to mitigation activity (creation, reestablishment, rehabilitation, and/or enhancement) and Category. RZC 21.64.020 Streams Streams are classified according to Class I, II, III, and IV based on fish use. Buffers range from 25 to 200 feet. Utility facilities and poles may be permitted within the stream buffer if no feasible alternative location exists. Additional specific mitigation standards (outside of general requirements) apply in restoration or enhancement of stream corridors, including: using native, adaptable, and perennial plants; depth and type of substrate; planting densities; fertilizer application; pesticide use limitations, etc.
PHASE 2 DRAFT EIS PAGE D‐2 APPENDIX D CRITICAL AREAS REGULATIONS BY CITY MAY 2017 City/County Critical Area Description Mitigation RZC 21.64.020 Fish and Wildlife Habitat Conservation Areas (FWHCAs) Classification of FWHCAs determined by adopted City maps, Washington Department of Fish and Wildlife Priority Habitats and Species maps, Washington State Conservation Commission habitat-limiting factors reports, federal and state info, and technical reports. Alterations to FWHCAs may be permitted subject to mitigation. Additional mitigation measures are required during mitigation planning: a)consider habitat in site planning and design; b) locating buildings and structures that preserve and minimize adverse impacts to important habitat areas; c)integrate retained habitat into open space and landscaping consistent with RZC 21.32; d)where possible, consolidate habitat and vegetated open space in contiguous blocks; e)Locate habitat contiguous to other habitat, open space, or landscaped areas to contribute to a continuous system or corridor that provides connections to adjacent habitat areas; f) Use native species in any landscaping of disturbed or undeveloped areas and in any enhancement of habitat or buffers; g) Emphasize heterogeneity and structural diversity of vegetation in landscaping; h) Remove and/or control any noxious weeds or animals as defined by the City; and i). Preserve significant trees, preferably in groups, consistent with RZC 21.72, Tree Preservation, and with achieving the objectives of these standards. RZC 21.64.050 Critical Aquifer Recharge Areas (CARAs) CARAs are classified into Wellhead Protection Zone 1, 2, 3, and 4 based on proximity to and travel time of groundwater to City's public water source wells. Utility facilities and poles are permitted for location within these zones subject to the performance standards specific to each zone in RZC 21.64.050.D. No additional mitigation measures.
PHASE 2 DRAFT EIS PAGE D‐3 APPENDIX D CRITICAL AREAS REGULATIONS BY CITY MAY 2017 City/County Critical Area Description Mitigation City of Bellevue Land Use Code (LUC) Part 20.25H LUC 20.25H.215 (mitigation sequencing) 20.25H.220 (Mitigation and restoration plan requirements) General Critical Areas Land Use Permit is required for any utility facilities and poles located in any of the designated critical areas and/or buffers. Require mitigation or restoration plan, and mitigation sequencing LUC 20.25H.095 (designation of critical area and buffers) 20.25H.100 (performance standards) 20.025H.105 (Mitigation and monitoring - additional provisions) Wetlands Wetlands are classified according to Category I, II, III, and IV using the Ecology Wetland Rating System. Buffers range from 40 to 225 feet. Structure setbacks range from 0-20 feet. Utility facilities and poles may be allowed in a wetland and/or wetland buffer subject to performance standards (20.25H.100) and mitigation. Mitigation actions that require compensation of impacted critical area buffer are required to occur in the following order of preference and in the following locations: a. On-site, through replacement of lost critical area buffer; b. On-site, through enhancement of the functions and values of remaining critical area buffer; c. Off-site, through replacement or enhancement, in the same sub-drainage basin; d. Off-site, through replacement or enhancement, out of the sub-drainage basin but in the same drainage basin. Wetland Acreage replacement ratios apply to creation or restoration mitigation activities: Category I, 6-to-1; Category II, 3-to-1; Category III, 2-to-1; Category IV, 1.5-to-1. Enhancement of existing significantly degraded wetlands may also be allowed subject to a critical areas report.
PHASE 2 DRAFT EIS PAGE D‐4 APPENDIX D CRITICAL AREAS REGULATIONS BY CITY MAY 2017 City/County Critical Area Description Mitigation LUC 20.25H.075 (designation of critical areas and buffers) 20.25H.080 (performance standards) Streams Streams are classified according to Type S, F, N and O based on the Washington State Department of Natural Resources (WDNR) typing. Buffers range from 25-100 feet. Structure setbacks range from 0-50 feet. Stream channels can be modified for new or expanded utility facilities and poles, subject to performance standards (LUC 20.25H.080) and mitigation. A. Mitigation plans for streams and stream critical area buffers are required to provide mitigation for impacts to critical area functions and values in the following order of preference: 1. On-site, through replacement of lost critical area buffer; 2. On-site, through enhancement of the functions and values of remaining critical area buffer; 3. Off-site, through replacement or enhancement, in the same sub-drainage basin; 4. Off-site, through replacement or enhancement, out of the sub-drainage basin but in the same drainage basin. Mitigation off-site and out of the drainage basin shall be permitted only through a critical areas report. B. Buffer Mitigation Ratio. Critical area buffer disturbed or impacted under this part shall be replaced at a ratio of one-to-one. LUC 20.25H.150 (Designation of critical area) 20.25H.155 (uses in habitat for species of local importance) 20.25H.160 (performance standards) Habitat Associated with Species of Local Importance Buffers depend if they're required for known species or are 35 feet for naturally occurring ponds w/o any other CA designation. Utility facilities and poles are allowed within habitat associated with species of local importance subject to the following performance standards (LUC 20.25H.160) : If habitat associated with species of local importance will be impacted by a proposal, the proposal shall implement the wildlife management plan developed by the Department of Fish and Wildlife for such species. Where the habitat does not include any other critical area or critical area buffer, compliance with the wildlife management plan shall constitute compliance with this part. No additional mitigation measures.
PHASE 2 DRAFT EIS PAGE D‐5 APPENDIX D CRITICAL AREAS REGULATIONS BY CITY MAY 2017 City/County Critical Area Description Mitigation City of Newcastle Municipal Code (NMC), Chapter 18.24 Critical Areas NMC 18.24.130 (mitigation and monitoring) 18.24.135 (off-site mitigation) General A. If mitigation is required to compensate for adverse impacts, unless otherwise provided, an applicant shall: 1. Mitigate adverse impacts to: a. Critical areas and their buffers; and b. The development proposal as a result of the proposed alterations on or near the critical areas; and 2. Monitor the performance of any required mitigation. On-site mitigation is preferred, but off-site mitigation (in same drainage subbasin as development proposal site) can be approved if on-site isn't practical and off-site mitigation will achieve equivalent or greater hydrological, water quality and wetland or aquatic area functions.
PHASE 2 DRAFT EIS PAGE D‐6 APPENDIX D CRITICAL AREAS REGULATIONS BY CITY MAY 2017 City/County Critical Area Description Mitigation NMC 18.24.310 (categories) 18.24.315 (Buffers) 18.24.316 (development standards) 18.24.320 (permitted alterations) 18.24.325 (specific mitigation requirements) Wetlands Wetlands are classified into Category I, II, III, and IV based on the Ecology Wetland Rating System. Buffers range between 25 and 225 feet depending on Category and land use. If no practical alternative location exists utility facilities and poles can be located within wetland buffers if: 1. The utility corridor is not located in a buffer where the buffer or associated wetland is used as a fish spawning area or by species listed as endangered or threatened by the state or federal government or contains critical or outstanding actual habitat for those species or heron rookeries or raptor nesting trees; 2. The construction area and resulting utility corridor are the minimum widths practical; 3. Except as provided in subsection (G) of this section, the utility corridor is located within the outer 25 percent of the buffer or within a roadway, the improved area of an existing utility corridor or the improved area of an approved trail; 4. The wetland and its buffer are protected during utility corridor construction and maintenance; 5. The utility corridor is aligned to avoid cutting significant trees, to the maximum extent practical; 6. Vegetation removal is limited to the minimum necessary to construct the corridor; 7. Vegetation removal for the purpose of corridor maintenance is the minimum necessary to maintain the utility’s function; 8. Any corridor access for maintenance is at specific points into the buffer rather than by a parallel road, to the maximum extent practical; 9. If the department determines that a parallel maintenance road is necessary, the following conditions shall be complied with: a. The width of the roadway shall be as small as possible and not greater than 15 feet; and b. The location of the roadway shall be contiguous to the utility corridor on the side farthest from the wetland; Development subject to performance standards (18.24.316) and mitigation. In addition to general mitigation requirements, mitigation for wetland or wetland buffer impacts: A. Mitigation measures must achieve equivalent or greater wetland functions, including, but not limited to: 1. Habitat complexity, connectivity and other biological functions; and 2. Seasonal hydrological dynamics, as provided in the King County Surface Water Design Manual; B. The following ratios of area of mitigation to area of alteration apply to mitigation measures: 1. For alterations to a wetland buffer, a ratio of one to one; and 2. For alterations to a wetland, proposed mitigation shall be in compliance with the acreage replacement ratios in NMC 18.24.325. C. Credit/Debit Method. To more fully protect functions and values, and as an alternative to the mitigation ratios found in the joint guidance Wetland Mitigation in Washington State Parts I and II (Ecology Publication No. 06-06-011a-b, Olympia, WA, March 2006), the administrator may allow mitigation based on the “credit/debit” method developed by the Department of Ecology in Calculating Credits and Debits for Compensatory Mitigation in Wetlands of Western Washington: Final Report.
PHASE 2 DRAFT EIS PAGE D‐7 APPENDIX D CRITICAL AREAS REGULATIONS BY CITY MAY 2017 City/County Critical Area Description Mitigation NMC 18.24.306 (classifications) 18.24.307 (development standards) 18.24.308 (permitted alterations) 18.24.309 (specific mitigation requirements) Streams Streams are classified as Types, F, Np, and Ns based on the WDNR typing system. Buffers range between 25 and 200 feet. If no practical alternative location exists utility corridors in stream buffers are allowed if: 1. The utility corridor is not located in a buffer where the buffer or associated stream is used by species listed as endangered or threatened by the state or federal government or contains critical or outstanding actual habitat for those species or heron rookeries or raptor nesting trees: 2. The construction area and resulting utility corridor are the minimum widths practical; 3. Except as provided in subsection (E) of this section, the utility corridor is located within the outer 25 percent of the buffer or within a roadway, the improved area of an existing utility corridor or the improved area of an approved trail; 4. The stream and its buffer are protected during utility corridor construction and maintenance; 5. The utility corridor is aligned to avoid cutting significant trees, to the maximum extent practical; 6. Vegetation removal is limited to the minimum necessary to construct the corridor; 7. Vegetation removal for the purpose of corridor maintenance is the minimum necessary to maintain the utility’s function; 8. Any corridor access for maintenance is at specific points into the buffer rather than by a parallel road, to the maximum extent practical; 9. If the department determines that a parallel maintenance road is necessary, the following conditions shall be complied with: a. The width of the roadway shall be as small as possible and not greater than 15 feet; and b. The location of the roadway shall be contiguous to the utility corridor on the side farthest from the stream; and subject to mitigation In addition to general mitigation requirements, mitigation for streams or their buffers is required to include: 1. For permanent alterations, restoration or enhancement of the altered stream or buffer, as determined by the city, using the following formulae: a. For mitigation on site: i. Correcting the adverse impact to any class of stream by repairing, rehabilitating or restoring the affected stream or buffer shall be on a 1:1 areal and functional basis; ii. Enhancement or restoration which is not mitigation of an alteration associated with a Type F, Np or Ns stream shall be on a 1.5:1 area and functional basis; iii. Enhancement or restoration which is not mitigation of an alteration associated with a Type S stream shall be on a 2:1 area and functional basis; b. For mitigation off site: i. Enhancement or restoration which is not mitigation of an alteration associated with a Type F, Np or Ns stream shall be on a 2:1 area and functional basis; ii. Enhancement or restoration which is not mitigation of an alteration associated with a Type S stream shall be on a 3:1 area and functional basis; and 2. For temporary alterations, restoration of the altered stream or buffer, as determined by the city; Off-site mitigation is only approved if it isn't practical to mitigate on site and it will achieve biologic, habitat, and hydrologic functions equivalent to or better than on-site mitigation.
PHASE 2 DRAFT EIS PAGE D‐8 APPENDIX D CRITICAL AREAS REGULATIONS BY CITY MAY 2017 City/County Critical Area Description Mitigation NMC 18.24.302 Fish and Wildlife Habitat Conservation Areas Designated FWHCAs include: areas with which state or federally designated endangered, threatened, and sensitive species have a primary association; state priority habitats and areas associated with state priority species; state-designated priority habitat or critical habitat for state-designated species; habitats and species of local importance; naturally occurring ponds under 20 acres; waters of the state; lakes, ponds, streams, and rivers planted with game fish; and land useful for preserving habitat and open space connections. Buffers based on a CAR. Utility facilities and poles located in FWHCAs subject to development standards (18.24.305) and mitigation. Mitigation of alterations to habitat conservation areas shall achieve equivalent or greater biological functions. Mitigation shall address each function affected by the alteration to achieve functional equivalency or improvement on a per function basis. Mitigation shall be detailed in a fish and wildlife habitat conservation area mitigation plan, which may include the following as necessary: a. A native vegetation plan; b. Plans for retention, enhancement or restoration of specific habitat features; c. Plans for control of nonnative invasive plant or wildlife species; and d. Stipulations for use of innovative, sustainable building practices. City of Renton Municipal Code (RMC) Chapter 4-3-050 RMC 4-3-050.C.3 (exemptions - critical areas and buffers) RMC 4-3-050.G.2 (critical area buffers and structure setbacks from buffers) RMC 4-3-050.L. (mitigation maintenance and monitoring) General Utilities may be located within geologic hazard areas, habitat conservation areas, streams and lakes (Types F, Np, & Ns), and wetlands when they area within existing and improved public road rights-of-way or easements. If activities exceed the existing improved area or the public right-of-way, this exemption does not apply. Where applicable, restoration of disturbed areas would need to be conducted. Overbuilding or replacement of existing utility systems may occur in geologic hazard areas, habitat conservation areas, or wetlands if the work does not increase the footprint of the structure or line by more than 10% within the critical area and/or buffer areas, and occurs in the existing right-of-way boundary or easement boundary. Mitigation shall be provided on site, unless on-site mitigation is not scientifically feasible due to physical features of the property. The burden of proof shall be on the applicant to demonstrate that mitigation cannot be provided on site. When mitigation cannot be provided on site, mitigation shall be provided in the immediate vicinity of the permitted activity on property owned or controlled by the applicant, and identified as such through a recorded document such as an easement or covenant, provided such mitigation is beneficial to the habitat area and associated resources. In-kind mitigation shall be provided except when the applicant demonstrates and the City concurs that greater functional and habitat value can be achieved through out-of-kind mitigation.
PHASE 2 DRAFT EIS PAGE D‐9 APPENDIX D CRITICAL AREAS REGULATIONS BY CITY MAY 2017 City/County Critical Area Description Mitigation When a mitigation plan is required, the proponent shall submit a final mitigation plan for the approval of the Administrator prior to the issuance of building or construction permits for development. The proponent shall receive written approval of the mitigation plan prior to commencement of any construction activity. Where the City requires increased buffers rather than standard buffers, it shall be noted on the subdivision plan and/or site plan. RMC 4-3-050.G.2 (critical area buffers and structure setbacks from buffers) RMC 4-3-050.6 Habitat Conservation Areas Critical Habitats are habitats that have a primary association with the documented presence of non-salmonid or salmonid species (RMC 4-3-090.L1)) species proposed or listed by the Federal government or State of Washington as endangered, threatened, sensitive and/or of local importance. Buffers consist of an undisturbed area of native vegetation, or areas identified for restoration, established to protect the integrity, functions and values of the affected habitat. Critical area buffer widths are established based on: (1) the type and intensity of human activity proposed, (2) recommendations contained within a habitat assessment report, and (3) management recommendations issued by the Washington Department of Fish and Wildlife. Structure setback beyond the buffer is 15 ft. The Administrator may approve mitigation to compensate for adverse impacts of a development proposal to habitat conservation areas through use of a federally and/or state certified mitigation bank or in-lieu fee program. See RMC 4-3-050.L.
PHASE 2 DRAFT EIS PAGE D‐10 APPENDIX D CRITICAL AREAS REGULATIONS BY CITY MAY 2017 City/County Critical Area Description Mitigation RMC 4-3-050.G.2 (critical area buffers and structure setbacks from buffers) RMC 4-3-050.G.7 (streams and lakes) RMC 4-3-050.J.2 (Alterations to Critical Areas) 4-3-050.I.2 (Alterations to Critical Areas Buffers) Streams and Lakes Streams are classified as Type S, F, Np, and Ns based on the WDNR permanent water typing system (WAC 222-16-030). Buffers range between 50 and 175 feet. Structure setback beyond the buffer is 15 ft. Permit approval for projects on or near regulated Type F, Np and Ns water bodies are only granted if no net loss of regulated riparian area or shoreline ecological function in the drainage basin would occur and one of the following conditions is met: (1) project would meet the standard provisions of RMC 4-3-050.7, (2) project would meet alternative administrative standard provisions of RMC 4-3-050.7, or (3) a variance is acquired. New utility lines and facilities may be permitted to cross water bodies in accordance with an approved stream/lake study, if : fish and wildlife habitat areas are avoided to the maximum extent possible; utilities are designed to bore beneath the scour depth and hyporheic zone of the water body and channel migration zone, cross at the centerline of the stream channel at an angle greater than 60 degrees, or have crossings be contained within the footprint of an existing road or utility crossing; new utility routes avoid paralleling the stream or following a down-valley course near the channel; utility installation does not increase or decrease the natural rate of shore migration or channel migration; seasonal work windows are determined and made a condition of approval; and mitigation criteria of subsection L of RMC 4-3-050 are met.
PHASE 2 DRAFT EIS PAGE D‐11 APPENDIX D CRITICAL AREAS REGULATIONS BY CITY MAY 2017 City/County Critical Area Description Mitigation RMC 4-3-050.G.2 (critical area buffers and structure setbacks from buffers) RMC 4-3-050.G.8 (wellhead protection areas) Wellhead Protection Areas Wellhead Protection Areas are the portion of an aquifer within the zone of capture and recharge area for a well or well field owned or operated by the City. They are delineated into zones based on the Renton Wellhead Protection Plan. These include Zone 1, Zone 1 Modified, and Zone 2. There are no critical area buffers. Construction activities within zones 1 and 2 must comply with RMC 4-3-050.G.8. RMC 4-3-050.G.2 (critical area buffers and structure setbacks from buffers) RMC 4-3-050.G.9 (wetlands) RMC 4-3.050.J.4 4-3-050.I.3 (Alterations to Critical Areas Buffers) Wetlands Wetlands are classified into Category I, II, III, and IV based on the Ecology Wetland Rating System. Buffers range between 0 and 200 feet depending on Category and land use. Structure setback beyond the buffer is 15 ft. for all uses and all wetland types. Utilities can be located within wetland buffers if they are located within an existing and improved public road rights-of-way or easements. Overbuilding or replacement of existing utility systems may occur in wetlands if the work does not increase the footprint of the structure or line by more than 10% within the critical area and/or buffer areas and occurs in the existing right-of-way or easement boundary. Development subject to performance standards (4-3-050.G) and mitigation. Compensatory mitigation for wetland alterations shall be based on the wetland category and the type of mitigation activity proposed. The replacement ratio shall be based on wetland category. The created, re-established, rehabilitated, or enhanced wetland area shall at a minimum provide a level of functions equivalent to the wetland being altered and shall be located in an appropriate landscape setting.
PSE Vegetation Management Standards
E
PHASE 2 DRAFT EIS PAGE E‐1 APPENDIX E VEGETATION MANAGEMENT STANDARDS MAY 2017 APPENDIX E. PSE VEGETATION MANAGEMENT STANDARDS
PHASE 2 DRAFT EIS PAGE E‐2 APPENDIX E VEGETATION MANAGEMENT STANDARDS MAY 2017
PHASE 2 DRAFT EIS PAGE E‐3 APPENDIX E VEGETATION MANAGEMENT STANDARDS MAY 2017
PHASE 2 DRAFT EIS PAGE E‐4 APPENDIX E VEGETATION MANAGEMENT STANDARDS MAY 2017
PHASE 2 DRAFT EIS PAGE E‐5 APPENDIX E VEGETATION MANAGEMENT STANDARDS MAY 2017
PHASE 2 DRAFT EIS PAGE E‐6 APPENDIX E VEGETATION MANAGEMENT STANDARDS MAY 2017
PHASE 2 DRAFT EIS PAGE E‐7 APPENDIX E VEGETATION MANAGEMENT STANDARDS MAY 2017
Recreation Policies
F
PHASE 2 DRAFT EIS PAGE F‐1
APPENDIX F RECREATION POLICIES MAY 2017
APPENDIX F. RECREATION RELATED STUDY
AREA POLICIES BY JURISDICTION
Policy Title Policy Text
City of Redmond
Utilities Policy: UT-9 Promote the efficiency of utility placement both in cost and timing through
methods such as the following: Encourage joint use of utility corridors for
utilities, recreation and appropriate non-motorized connections.
City of Bellevue
Parks & Open Space
System Plan Goals
Define and enhance neighborhood character by using open space as visual
relief to separate and buffer between uses.
Parks and Open Space
Policy: PA-30
Protect and retain, in a natural state, significant trees and vegetation in
publicly and privately-dedicated greenbelt areas.
Parks and Open Space
Policy: PA-37
Require a public review process for the conversion to non-recreational use
of park lands and facilities.
Utilities Policy: UT-68 Encourage the use of utility corridors as non-motorized trails. The city and
utility company should coordinate the acquisition, use, and enhancement
of utility corridors for pedestrian, bicycle and equestrian trails and for
wildlife corridors and habitat.
Utilities Policy: UT-69 Avoid, when reasonably possible, locating overhead lines in greenbelt and
open spaces as identified in the Parks and Open Space System Plan.
Richards Valley Sub
Area Plan Policy: S-RV-
11
Protect and preserve publicly owned land.
Discussion: This policy refers to land set aside for storm drainage and
detention, the right-of-way along the Lake Hills Connector, and potential
links in the trail and park system.
Bridle Trails Sub Area
Plan Policy: S-BT-20
Work with utility companies to gain public non-motorized trail easements
along power line corridors to complete the equestrian trail facilities plan.
City of Newcastle
Utilities Policy: UT-P7 Where found to be safe, the City of Newcastle shall promote recreational
use of utility corridors such as trails, sport courts, and similar facilities.
King County
Objective 3.2 Invest in planning, design, and construction of new major trail corridors, the
Eastside Rail Corridor and the Lake to Sound Trail.
Source: City of Bellevue, 2015; City of Newcastle, 2016a; and City of Redmond, 2015; King County, 2016
Note: City of Renton does not have relevant recreation policies.
Supplemental Information:
Historic Resources
G
PHASE 2 DRAFT EIS PAGE G‐1 APPENDIX G SUPPLEMENTAL INFORMATION: HISTORIC RESOURCES MAY 2017 APPENDIX G. SUPPLEMENTAL INFORMATION: HISTORIC RESOURCES Table G‐1. Historic Register Resources Map # Property Name Address Year Built NRHP – Recom. Eligible NRHP – Determ. Eligible NRHP - Listed WHR - Listed WHB -Listed Desig. KC Landmark 1 Sammamish-Lakeside-Talbot Hill transmission lines #1 and #2 and the Eastside transmission corridor Redmond to Renton 1920s Yes No No No No No 2 Safeway Distribution Center Truck Repair Building 1227 124th AVE NE, Bellevue 1958 No Yes No No No No 3 Wilburton Trestle Burlington Northern Railroad spanning Mercer Slough 1904 No Yes No Yes No No 4 Twin Valley Dairy 410 130th Place SE 1933 Yes Yes No No Yes No 5 Somerset Neighborhood Bellevue 1960s Yes No No No No No 6 Newcastle Cemetery SW of 69th Way off 129th Ave SE c.1870 Yes No No Yes No Yes 7 Greenwood Memorial Park 3401 NE 4th Street, Renton c.1910 No No No No No No 8 Mt. Olivet Cemetery 100 Blaine Ave NE, Renton c.1875 Yes No No No No No KC = King County; NRHP = National Register of Historic Places; WHBR = Washington Heritage Barn Register; WHR = Washington Heritage Register.
PHASE 2 DRAFT EIS PAGE G‐2 APPENDIX G SUPPLEMENTAL INFORMATION: HISTORIC RESOURCES MAY 2017 Table G‐2. Unevaluated Historic Resources PIN Year Built Segment Option Pole Type Applicable Register Age Threshold New Corridor 1524059032 1961 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 1951700010 1968 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 1951700020 1968 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 1951700110 1968 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 1951700120 1968 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 1951700730 1967 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 1951700740 1967 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 1951700750 1967 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 1951700800 1968 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 2206500015 1955 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 2206500020 1957 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 2206500025 1956 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 2206500030 1956 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 2206500035 1957 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 2206500040 1957 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 2206500045 1956 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 2206500185 1955 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 2206500220 1955 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972)
PHASE 2 DRAFT EIS PAGE G‐3 APPENDIX G SUPPLEMENTAL INFORMATION: HISTORIC RESOURCES MAY 2017 PIN Year Built Segment Option Pole Type Applicable Register Age Threshold 2206500225 1955 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 2206500230 1955 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 2206500235 1955 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 2206500240 1955 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 2206500245 1955 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 2206500250 1955 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 2206500255 1955 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 2206500260 1956 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 2206500265 1956 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 2206500280 1956 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 2206500285 1956 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 2206500375 1955 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 2206500380 1955 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 2206500385 1955 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 2206500390 1955 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 2206500395 1956 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 2206500400 1955 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 2206500405 1955 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 2206500410 1955 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 2206500415 1955 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972)
PHASE 2 DRAFT EIS PAGE G‐4 APPENDIX G SUPPLEMENTAL INFORMATION: HISTORIC RESOURCES MAY 2017 PIN Year Built Segment Option Pole Type Applicable Register Age Threshold 2206500420 1955 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 2206500425 1955 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 2206500430 1955 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 2206500435 1955 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 6071800730 1962 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 6071800740 1962 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 6071900130 1962 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 6071900140 1962 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 6071900150 1962 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 6071900160 1963 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 6071900170 1962 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 6071900180 1963 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 6071900190 1962 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 6071900200 1963 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 6071900210 1963 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 6071900220 1962 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 6072200350 1966 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 6072200360 1965 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 6072200410 1965 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 6072200420 1965 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972)
PHASE 2 DRAFT EIS PAGE G‐5 APPENDIX G SUPPLEMENTAL INFORMATION: HISTORIC RESOURCES MAY 2017 PIN Year Built Segment Option Pole Type Applicable Register Age Threshold 6072200430 1965 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 6072200440 1965 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 7855000010 1962 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 7855000020 1970 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 7855000230 1969 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 7855000250 1970 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 7855000260 1962 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 7855000270 1962 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 7855000280 1961 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 7855000290 1968 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 7855000300 1967 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 7855000310 1962 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 7855000320 1961 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 7855000325 1961 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 7855000350 1967 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 7855000360 1961 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 7855000370 1968 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 7855800010 1966 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 7855800030 1966 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 7855800040 1967 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972)
PHASE 2 DRAFT EIS PAGE G‐6 APPENDIX G SUPPLEMENTAL INFORMATION: HISTORIC RESOURCES MAY 2017 PIN Year Built Segment Option Pole Type Applicable Register Age Threshold 7855800050 1968 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 7855800060 1970 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 7855800070 1966 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 7855800080 1968 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 7855800090 1968 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 7855800100 1968 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 7855800120 1970 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 7855800130 1970 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 7855800140 1968 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 7855801540 1971 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 7855801570 1969 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 7855801580 1967 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 7855801590 1968 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 7855801600 1967 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 7855801610 1967 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 7855801660 1967 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 7855801690 1968 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 7855801700 1968 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 7855801710 1968 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 7855801720 1972 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972)
PHASE 2 DRAFT EIS PAGE G‐7 APPENDIX G SUPPLEMENTAL INFORMATION: HISTORIC RESOURCES MAY 2017 PIN Year Built Segment Option Pole Type Applicable Register Age Threshold 7855801730 1968 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (100) NRHP 45 (1972) 7855801770 1963 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 7856410110 1970 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) 7856410120 1972 Bellevue South Willow 1 | Willow 2 | Oak 1 | Oak 2 2 Single-Circuit Monopoles NRHP 45 (1972) New Corridor 2825059066 1969 Bellevue Central Bypass 1 | Bypass 2 1 Single-Circuit Monopole (100) NRHP 45 (1972) 2825059085 1962 Bellevue Central Bypass 1 | Bypass 2 1 Single-Circuit Monopole (100) NRHP 45 (1972) 0424059039 1960 Bellevue Central Bypass 2 1 Single-Circuit Monopole NRHP 45 (1972) 0424059052 1943 Bellevue Central Bypass 2 1 Single-Circuit Monopole NRHP 45 (1972) 0424059067 1959 Bellevue Central Bypass 2 1 Single-Circuit Monopole NRHP 45 (1972) 0424059132 1960 Bellevue Central Bypass 2 1 Single-Circuit Monopole NRHP 45 (1972) 5453300031 1972 Bellevue Central Bypass 2 1 Single-Circuit Monopole NRHP 45 (1972) 0672100010 1968 Bellevue Central Bypass 2 1 Single-Circuit Monopole NRHP 45 (1972) 0924059088 1963 Bellevue South Oak 1 | Oak 2 1 Double-Circuit Monopole (80) NRHP 45 (1972) 0924059182 1972 Bellevue South Oak 1 | Oak 2 1 Double-Circuit Monopole (80) NRHP 45 (1972) 0924059228 1964 Bellevue South Oak 1 | Oak 2 1 Double-Circuit Monopole (80) NRHP 45 (1972) 5453300166 1969 Bellevue South Oak 1 | Oak 2 1 Double-Circuit Monopole (80) NRHP 45 (1972) 5453300180 1970 Bellevue South Oak 1 | Oak 2 1 Double-Circuit Monopole (80) NRHP 45 (1972) 1524059027 1951 Bellevue South Willow 2 1 Single-Circuit Monopole NRHP 45 (1972) 1524059112 1964 Bellevue South Willow 2 1 Single-Circuit Monopole NRHP 45 (1972)
PHASE 2 DRAFT EIS PAGE G‐8 APPENDIX G SUPPLEMENTAL INFORMATION: HISTORIC RESOURCES MAY 2017 PIN Year Built Segment Option Pole Type Applicable Register Age Threshold 1624059065 1943 Bellevue South Willow 2 1 Single-Circuit Monopole NRHP 45 (1972) 1624059104 1959 Bellevue South Willow 2 1 Single-Circuit Monopole NRHP 45 (1972) 1624059223 1964 Bellevue South Willow 2 1 Single-Circuit Monopole NRHP 45 (1972) 5603500050 1963 Bellevue South Willow 2 1 Single-Circuit Monopole NRHP 45 (1972) 5603500070 1959 Bellevue South Willow 2 1 Single-Circuit Monopole NRHP 45 (1972) 5603500110 1960 Bellevue South Willow 2 1 Single-Circuit Monopole NRHP 45 (1972) 5603500115 1963 Bellevue South Willow 2 1 Single-Circuit Monopole NRHP 45 (1972) 1624059079 1961 Bellevue South Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (80) NRHP 45 (1972) 1624059093 1949 Bellevue South Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (80) NRHP 45 (1972) 1624059168 1960 Bellevue South Willow 2 | Oak 1 | Oak 2 1 Double-Circuit Monopole (80) NRHP 45 (1972)
Supplemental Information:
EMF (Unique Uses in the Study Area)
H
PHASE 2 DRAFT EIS PAGE H‐1
APPENDIX H SUPPLEMENTAL INFORMATION: EMF MAY 2017
APPENDIX H. SUPPLEMENTAL INFORMATION:
ELECTRIC AND MAGNETIC FIELDS
Figure H‐1. Unique Uses in the EMF Study Area
Supplemental Information: Pipeline Safety
I
PHASE 2 DRAFT EIS PAGE I‐1
APPENDIX I SUPPLEMENTAL INFORMATION: PIPELINE SAFETY MAY 2017
APPENDIX I. SUPPLEMENTAL INFORMATION:
PIPELINE SAFETY
APPENDIX I-1: PIPELINE INCIDENTS
The two pipeline incidents that led to the passage of the Pipeline Safety Improvement Act of 2002 and
the current pipeline integrity management rules are as follows:
Bellingham, Washington, June 10, 1999. According to the National Transportation
Safety Board (NTSB) accident report, “About 3:28 p.m., Pacific daylight time, on June 10,
1999, a 16-inch diameter steel pipeline owned by Olympic Pipe Line Company (Olympic)
ruptured and released about 237,000 gallons of gasoline into a creek that flowed through
Whatcom Falls Park in Bellingham, Washington. About one and one half hours after the
rupture, the gasoline ignited and burned approximately one and one half miles along the
creek. Two 10-year-old boys and an 18-year-old man died as a result of the accident.
Eight additional injuries were documented. A single-family residence and the City of
Bellingham’s water treatment plant were severely damaged. As of January 2002, Olympic
estimated that total property damages were at least $45 million.
The major safety issues identified during this investigation were excavations performed by
IMCO General Construction, Inc., in the vicinity of Olympic’s pipeline during a major
construction project and the adequacy of Olympic Pipe Line Company’s inspections
thereof; the adequacy of Olympic Pipe Line Company’s interpretation of the results of in-
line inspections of its pipeline and its evaluation of all pipeline data available to it to
effectively manage system integrity; the adequacy of Olympic Pipe Line Company’s
management of the construction and commissioning of the Bayview products terminal; the
performance and security of Olympic Pipe Line Company’s supervisory control and data
acquisition system; and the adequacy of Federal regulations regarding the testing of relief
valves used in the protection of pipeline systems.” (NTSB, 2002).
Carlsbad, New Mexico, August 19, 2000. Per the National Transportation Safety
Board accident report, “At 5:26 a.m., mountain daylight time, on Saturday, August 19,
2000, a 30-inch diameter natural gas transmission pipeline operated by El Paso Natural
Gas Company ruptured adjacent to the Pecos River near Carlsbad, New Mexico. The
released gas ignited and burned for 55 minutes. Twelve persons who were camping under
a concrete-decked steel bridge that supported the pipeline across the river were killed and
their three vehicles destroyed. Two nearby steel suspension bridges for gas pipelines
crossing the river were extensively damaged. According to El Paso Natural Gas Company,
property and other damages or losses totaled $998,296.
The major safety issues identified in this investigation were the design and construction of
the pipeline, the adequacy of El Paso Natural Gas Company’s internal corrosion control
program, the adequacy of Federal safety regulations for natural gas pipelines, and the
adequacy of Federal oversight of the pipeline operator.” (NTSB, 2003).
PHASE 2 DRAFT EIS PAGE I‐2
APPENDIX I SUPPLEMENTAL INFORMATION: PIPELINE SAFETY MAY 2017
References
NTSB (National Transportation Safety Board). 2002. Pipeline Rupture and Subsequent Fire in
Bellingham, Washington, June 10, 1999. Pipeline Accident Report NTSB/PAR-02/02.
Washington, D.C.
NTSB (National Transportation Safety Board). 2003. Pipeline Rupture and Subsequent Fire near
Carlsbad, New Mexico, August 19, 2000. Pipeline Accident Report NTSB/PAR-03/01.
Washington, D.C.
PHASE 2 DRAFT EIS PAGE I‐3
APPENDIX I SUPPLEMENTAL INFORMATION: PIPELINE SAFETY MAY 2017
APPENDIX I-2: BP PIPELINES CONSTRUCTION REQUIREMENTS
PHASE 2 DRAFT EIS PAGE I‐4
APPENDIX I SUPPLEMENTAL INFORMATION: PIPELINE SAFETY MAY 2017
PHASE 2 DRAFT EIS PAGE I‐5
APPENDIX I SUPPLEMENTAL INFORMATION: PIPELINE SAFETY MAY 2017
PHASE 2 DRAFT EIS PAGE I‐6
APPENDIX I SUPPLEMENTAL INFORMATION: PIPELINE SAFETY MAY 2017
APPENDIX I-3: OLYMPIC DATA REQUEST AND RESPONSES (FOR
ENERGIZE EASTSIDE EIS PIPELINE RISK ASSESSMENT)
PHASE 2 DRAFT EIS PAGE I‐7
APPENDIX I SUPPLEMENTAL INFORMATION: PIPELINE SAFETY MAY 2017
PHASE 2 DRAFT EIS PAGE I‐8
APPENDIX I SUPPLEMENTAL INFORMATION: PIPELINE SAFETY MAY 2017
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APPENDIX I SUPPLEMENTAL INFORMATION: PIPELINE SAFETY MAY 2017
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APPENDIX I SUPPLEMENTAL INFORMATION: PIPELINE SAFETY MAY 2017
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APPENDIX I SUPPLEMENTAL INFORMATION: PIPELINE SAFETY MAY 2017
APPENDIX I-4: PSE ENERGIZE EASTSIDE CORRIDOR SAFETY
FAQ SHEET
PHASE 2 DRAFT EIS PAGE I‐12
APPENDIX I SUPPLEMENTAL INFORMATION: PIPELINE SAFETY MAY 2017
PHASE 2 DRAFT EIS PAGE I‐13
APPENDIX I SUPPLEMENTAL INFORMATION: PIPELINE SAFETY MAY 2017
APPENDIX I-5: ENERGIZE EASTSIDE EIS PIPELINE SAFETY
TECHNICAL REPORT (PREPARED BY EDM SERVICES)
Energize Eastside EIS
Pipeline Safety Technical Report
Prepared for
Environmental Science Associates
(ESA)
EDM Services, Inc.
4100 Guardian Street, Suite 250
Simi Valley, California 93063
Web Site Address: edmsvc.com
Phone: (805) 527-3300
FAX: (805) 583-1607
EDM Services Job Number 16-136-1982
[r,;IEXPIRES 1
EDM Services, Inc.
April 27, 2017
Technical Report, Pipeline Safety and Risk of Upset
Page ii
Table of Contents
Energize Eastside EIS – Pipeline Safety and Risk of Upset ________________________________ 5
Introduction and General Approach ______________________________________________ 5
1.0 Environmental Setting ______________________________________________________ 7
1.1 Existing Olympic Pipeline (OPL) Company Pipelines _____________________________ 7
1.1.1 16‐inch outside diameter, OPL Allen to Renton Pipeline ______________________ 7
1.1.2 20‐inch outside diameter, OPL Allen to Renton Pipeline ______________________ 8
1.1.3 OPL Leak Detection System _____________________________________________ 8
1.1.4 OPL Emergency Response ______________________________________________ 9
1.1.5 OPL Identified Hazards Presented by Proximity to Proposed Overhead High Voltage
Transmission Lines _________________________________________________________ 9
1.2 Refined Petroleum Products Pipeline Public Risks _____________________________ 10
1.3 Refined Petroleum Products Characteristics __________________________________ 11
1.3.1 Jet Fuel ____________________________________________________________ 11
1.3.2 Diesel Fuel _________________________________________________________ 12
1.3.3 Gasoline ___________________________________________________________ 12
1.4 Major Pipeline Incident Summaries _________________________________________ 12
1.4.1 San Bernardino, California, May 25, 1989 _________________________________ 12
1.4.2 Bellingham, Washington, June 10, 1999 __________________________________ 13
1.4.3 Carlsbad, New Mexico, August 19, 2000 __________________________________ 14
1.4.4 Walnut Creek, California, November 9, 2004 ______________________________ 14
1.4.5 San Bruno, California, September 9, 2010 _________________________________ 15
2.0 Regulatory Setting ________________________________________________________ 17
2.1 Regulatory Framework ___________________________________________________ 17
2.2 Federal Pipeline Regulations ______________________________________________ 17
2.2.1 Overview of 49 CFR Part 190 ___________________________________________ 18
2.2.2 Overview of 49 CFR Part 195 ___________________________________________ 18
2.2.3 Overview of 49 CFR Part 199, (Drug Testing, Requirements) __________________ 25
2.2.4 Overview of 40 CFR Parts 109, 110, 112‐114 ______________________________ 25
2.2.5 Oil Pollution Act of 1990 (OPA) _________________________________________ 26
2.3 State Pipeline Regulations ________________________________________________ 27
2.3.1 Revised Code of Washington (RCW) Title 81 _______________________________ 27
2.3.2 Washington Administrative Code, Title 480 (WAC‐480) ______________________ 28
2.3.3 Revised Code of Washington (RCW), Title 19 ______________________________ 28
2.3.4 Washington Administrative Code, Title 173 (WAC‐173) ______________________ 29
3.0 Significance Criteria _______________________________________________________ 30
3.1 Aggregate Risk _________________________________________________________ 30
3.2 Individual Risk __________________________________________________________ 30
3.3 Societal Risk ___________________________________________________________ 33
4.0 Potential Hazards _________________________________________________________ 35
4.1 Fire Hazards to Humans __________________________________________________ 35
4.2 Explosion Hazards to Humans _____________________________________________ 36
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5.0 Baseline Data ____________________________________________________________ 37
5.1 U.S. Hazardous Liquid Pipeline Releases, January 2010 through December 2015 _____ 37
5.2 U.S. Refined Petroleum Product Releases, January 2010 through December 2015 ____ 39
5.2.1 Spill Size Distribution, U.S. Refined Petroleum Product Pipelines, Normalized to 18‐
inch Diameter Pipe ________________________________________________________ 42
5.2.2 Olympic Pipeline Leak History __________________________________________ 44
5.3 Population Density ______________________________________________________ 45
5.4 Potential Hazards of Collocated Overhead HVAC Lines and Hazardous Liquid Pipelines 45
5.5 Pipeline Incidents Caused By Close Proximity to Electrical Utilities ________________ 47
5.5.1 Chevron Pipe Line Company June 11, 2010 Incident ________________________ 47
5.5.2 Oneok NGL Pipeline August 8, 2011 Incident ______________________________ 48
5.5.3 Crimson Pipeline September 8, 2013 Incident _____________________________ 49
5.5.4 Buckeye Partners LP March 14, 2014 Incident _____________________________ 49
5.5.5 Marathon Pipeline (MPL) February 17, 2015 Incident _______________________ 49
5.5.6 Kinder Morgan September 9, 2015 Incident _______________________________ 49
5.6 A.C. Interference Analysis, Proposed 115/230 kV Project (Willow 2) _______________ 49
5.6.1 Soil Resistivity _______________________________________________________ 50
5.6.2 Model and Simulation Validation _______________________________________ 50
5.6.3 Predicted Results for Proposed 115/230 kV Project (Willow 2) ________________ 52
5.7 A.C. Interference Analysis, Existing 115 kV Corridor ____________________________ 60
5.7.1 Estimated Induced A.C. Voltage (Touch Potential) __________________________ 60
5.7.2 Estimated A.C. Current Density _________________________________________ 62
5.7.3 Estimated Coating Stress Voltage _______________________________________ 64
5.7.4 Estimated Arcing Distance _____________________________________________ 64
6.0 Qualitative Aggregate Risk Assessment _______________________________________ 65
7.0 Release Modeling Results __________________________________________________ 67
7.1 Pool Fires _____________________________________________________________ 68
7.2 Explosions _____________________________________________________________ 71
7.3 Flash Fires _____________________________________________________________ 72
8.0 Conditional Probabilities ___________________________________________________ 74
8.1 Pipeline Contents _______________________________________________________ 74
8.2 Pipeline Operability _____________________________________________________ 74
8.3 Pool Fire Spill Volumes ___________________________________________________ 74
8.4 Fire and Explosion _______________________________________________________ 75
8.5 Likelihood of Fatal Injuries ________________________________________________ 76
8.6 Other Primary Assumptions _______________________________________________ 76
9.0 Individual Risk Assessment _________________________________________________ 78
9.1 Two OPL Pipelines Not Collocated within Overhead HVAC Corridor _______________ 78
9.2 Two OPL pipelines Collocated with Existing 115 kV Line (No Action Alternative) _____ 80
9.2.1 Induced A.C. Voltage _________________________________________________ 80
9.2.2 A.C. Current Density __________________________________________________ 80
9.2.3 Coating Stress Voltage Resulting from Fault _______________________________ 81
9.2.4 Arc Distance Resulting from Fault _______________________________________ 81
9.2.5 Estimated Frequency of Unintentional Releases ____________________________ 82
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9.3 Two OPL Pipelines Collocated with 115/230 kV Lines (Alternative 1) _______________ 82
9.3.1 Induced A.C. Voltage _________________________________________________ 82
9.3.2 A.C. Current Density __________________________________________________ 83
9.3.3 Coating Stress Voltage Resulting from Fault _______________________________ 84
9.3.4 Arc Distance Resulting from Fault _______________________________________ 84
9.3.5 Frequency of Unintentional Releases ____________________________________ 86
9.3.6 Operational Individual Risk ____________________________________________ 87
9.3.7 Construction Individual Risk ____________________________________________ 89
10.0 Societal Risk Assessment __________________________________________________ 92
10.1 Two OPL Pipelines Not Collocated within Overhead HVAC Corridor ______________ 92
10.1.1 Maximum Population Density _________________________________________ 92
10.1.2 Average Population Density ___________________________________________ 94
10.1.3 Minimum Population Density _________________________________________ 96
10.2 Two OPL Pipelines Collocated with 115/230 kV Lines (Alternative 1) _____________ 96
10.2.1 Maximum Population Density _________________________________________ 96
10.2.2 Average Population Density ___________________________________________ 98
10.2.3 Minimum Population Density ________________________________________ 100
10.2.4 Construction Societal Risk ___________________________________________ 100
11.0 Risk Reduction Measures _________________________________________________ 105
11.1 Surcharge Loading ____________________________________________________ 105
11.2 Third Party Damage ___________________________________________________ 105
11.3 Electrical Interference _________________________________________________ 106
12.0 References ____________________________________________________________ 107
12.1 Acronyms ___________________________________________________________ 107
12.2 Definitions ___________________________________________________________ 108
12.3 Reference Documents _________________________________________________ 110
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ENERGIZE EASTSIDE EIS – PIPELINE SAFETY AND RISK OF UPSET
Introduction and General Approach
The purpose of this report is to present the results of a risk assessment that has been performed
to estimate the risks posed to the public from the existing Olympic Pipeline Company (OPL)
pipelines. This report also presents and estimate of the potential additional risks that could be
posed where the proposed Energize Eastside overhead high voltage alternating current (HVAC)
transmission line would be collocated with the OPL pipeline(s). The general approach used to
conduct this risk assessment is summarized below:
1. Information was gathered regarding the existing 16‐inch and 20‐inch diameter OPL pipelines.
2. Historical unintentional release data was obtained from the United States Department of
Transportation (USDOT) for similar refined petroleum product transmission pipelines. This
included the USDOT database of all hazardous liquid pipeline incidents that have occurred since
January 1, 2010. These data are presented in Section 5.0, Baseline Data, of this Report. These
data were analyzed to develop the following estimates:
Frequency of unintentional releases,
Frequency of public injuries and fatalities,
Spill size distribution,
Causes of the unintentional releases, and the
Likelihood of fires or explosions following an unintentional release.
3. Using the above historical and OPL unintentional release data, high level estimates of the
likelihood of various size releases, fires, and public fatalities resulting from unintentional releases
from OPL’s pipelines were developed. This analysis is included in Section 6.0, Qualitative
Aggregate Risk Assessment, of this Report.
4. Using the actual pipeline operating parameters, release modeling was performed to evaluate the
range of potential impacts to the public from fires, explosions and flash fires. The results of this
release modeling are presented in Section 7.0, Release Modeling Results, of this Report.
5. Using the above data, the conditional probabilities for each of the following items were estimated.
The development of these estimates is presented in Section 8.0, Conditional Probabilities, of this
Report.
Probability of the pipelines carrying diesel, jet fuel, or gasoline, since the potential risks to the
public differ somewhat for each;
Percentage of the time that the OPL pipeline(s) would be operational;
Probability of various size unintentional releases from the OPL pipeline(s);
Probability of fires or explosions following an unintentional release;
Probability of fatal injuries following a fire or explosion.
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6. The increased risks of an unintentional release from the OPL pipelines due to the proposed
Energize Eastside overhead high voltage alternative current (HVAC) transmission line were
estimated by reviewing a number of publications and reports.
7. An individual risk assessment has been conducted. This assessment estimates the likelihood of a
public fatality to an individual exposed to the potential hazards 24 hours per day, 365 days per
year. The results of this analysis are presented in Section 9.0, Individual Risk Assessment, of this
report.
8. A societal risk assessment has been conducted. This assessment estimates the probability that a
specified number of people could be fatally injured following an unintentional release. This
assessment used three different population densities in order to estimate the number of
individuals that could be fatally injured. The results of this analysis are presented in Section 10.0,
Societal Risk Assessment, of this Report.
9. Risk reduction measures are presented in Section 11.0 of this Report. These measures could be
employed to reduce the likelihood and severity of unintentional releases from the OPL pipelines.
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1.0 Environmental Setting
1.1 Existing Olympic Pipeline (OPL) Company Pipelines
Much of the HVAC electrical transmission line corridor contains either one, or two refined
petroleum product pipelines. These pipelines transport gasoline, diesel and jet fuel1 and are
owned by OPL. This Technical Report will present the life safety risks posed by these pipelines in
three different situations:
Where the pipeline(s) operate in a corridor without any overhead HVAC electrical
transmission line,
Where the pipeline(s) are collocated within the corridor with the existing overhead HVAC
electrical transmission line, and
Where the pipeline(s) would be collocated within the corridor with the proposed overhead
HVAC electrical transmission line.
1.1.1 16-inch outside diameter, OPL Allen to Renton Pipeline
The 16‐inch outside diameter, Allen to Renton pipeline has the following parameters (Olympic
Pipeline):
This pipeline is constructed of API 5L X52 grade, 0.312‐inch wall thickness2.
The length of this line which is collocated with the overhead HVAC line is 62,906‐feet.
This pipeline was originally constructed in 1965. After initial construction, this pipeline was
subjected to a hydrostatic test that was at least 1.25 times the maximum operating pressure.
The majority of this line is externally coated with coal tar enamel and is protected by an
impressed current cathodic protection system.
This line was most recently hydrostatically tested in 2001, to a test pressure of 1,806 psi (89%
SMYS)3.
The normal operating pressure is 500 to 800 psi within the electrical transmission corridor.
This pipeline was internally inspected using a high resolution deformation and high resolution
magnetic flux leakage tool in April 2014. The next planned internal inspection is early 2019.
The normal flow rate is approximately 5,400 barrels per hour (228,000 gallons per hour).
This pipeline ships the following commodities: 18% Diesel, 37% Jet Fuel, and 45% Gasolines.
The typical depth of cover is three to four feet.
The pipeline does not contain any electric resistance welded pipe (ERW) within the electrical
transmission corridor under analysis.4
1 In this Report, these hazardous liquids are also called refined petroleum products.
2 Since initial construction, there have been some relatively short pipe replacements (re‐routes) which may
have an increased wall thickness and/or higher grade pipe.
3 See Section 12.1 for a list of acronyms used in this Report.
4 There is significant evidence that inferior electric‐resistance welded (ERW) pipe was manufactured and
installed, especially before 1970; some of this pipe has yielded increased frequencies of pipeline incidents.
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1.1.2 20-inch outside diameter, OPL Allen to Renton Pipeline
The 20‐inch outside diameter, Allen to Renton pipeline has the following parameters (Olympic
Pipeline):
This pipeline is constructed of API 5L X52 grade, 0.250‐inch wall thickness5.
The length of this line which is collocated with the overhead HVAC line is 68,122‐feet.
This pipeline was originally constructed in 1972 to 1974.
The majority of this line is externally coated with coal tar enamel and is protected by an
impressed current cathodic protection system.
This line was most recently hydrostatically tested in 2001, to a test pressure of 1,157 psi (89%
SMYS).
The normal operating pressure is 300 to 500 psi within the electrical transmission corridor.
This pipeline was internally inspected using a high resolution deformation and high resolution
magnetic flux leakage tool in April 2014. The next planned internal inspection is early 2019.
The normal flow rate is approximately 7,900 barrels per hour (333,000 gallons per hour).
This pipeline ships the following commodities: 40% Diesel, 3% Jet Fuel, and 57% Gasolines.
The typical depth of cover is three to four feet.
The pipeline does not contain any electric resistance welded pipe (ERW) within the electrical
transmission corridor under analysis.
1.1.3 OPL Leak Detection System
Olympic Pipe Line Company's (OPL’s) Pipeline Leak Detection System (PLDS) has been in service in
the OPL control center since the early 1990's. PLDS is a real‐time pipeline simulation that detects
and locates leaks by comparing the volume in and the volume out, with volume adjustments
based on pressure (compression of the pipe contents) and predicted pressures within a defined
pipeline section. When the difference exceeds a defined loss threshold, the software provides a
warning to the operator. If the condition persists, an alarm is provided. Alarms are
communicated through the SCADA alarm and event system. OPL’s enterprise SCADA System
covers 60 sites over its roughly 400 miles of main and lateral pipeline segments, including the pipe
segments under consideration. PLDS is a separate software package but is integrated with the
SCADA software.
OPL’s PLDS meets or exceeds State and Federal requirements for pipeline leak detection including
WAC 480‐75‐3006,7.
5 Since initial construction, there have been some relatively short pipe replacements (re‐routes) which may
have an increased wall thickness and/or higher grade pipe.
6 Leak detection systems must be capable of detecting an eight percent (8%) of maximum flow leak within
fifteen (15) minutes or less.
7 OPL pipeline, leak detection system, and emergency response data were provided by OPL in their July 25,
2016 response to our data request.
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OPL did not provide specific details regarding the precise type and location of their mainline block
valves and related facilities within this segment. OPL treats these data as confidential information
which is not available for public disclosure due to potential security risks8.
1.1.4 OPL Emergency Response
OPL maintains a 24‐hour Emergency Hotline (1‐888‐271‐8880). OPL’s current manual for
responding to emergencies is based on the Northwest Area Contingency Plan, as approved by the
Washington State Department of Ecology and the Federal Pipeline and Hazardous Materials
Safety Administration (PHMSA). OPL considers specific details regarding OPL’s emergency
response procedures as confidential information not available for public disclosure due to
potential security risks8.
In the event of an unintentional release, response times would vary depending on the incident
location and traffic conditions, among other factors. Access to the pipeline along the relevant
segment is relatively good, which can significantly reduce response times. Members of OPL’s
Damage Prevention Team are located nearby at all times and are able to respond to certain types
of events quickly. During normal working hours, OPL has qualified personnel located to the North
and South of this segment, at its facilities in Woodinville and Renton, Washington. Outside of
normal working hours, OPL has on‐call personnel who live in close proximity to this segment. In
addition, OPL has contracted with the National Response Corporation – Environmental Services
(NRCES) to respond anywhere along its pipeline system within two hours.
In the event of an evacuation along the pipeline right‐of‐way, local first responders and the OPL
employees would set up exclusion zones. Door to door notifications would be made to impacted
homeowners. Air monitoring equipment would be utilized and the conditions would be
documented throughout the incident to ensure that the exclusion zones are properly identified in
accordance with atmospheric conditions (e.g., wind speed, direction, etc.).
1.1.5 OPL Identified Hazards Presented by Proximity to Proposed Overhead High
Voltage Transmission Lines
This section describes the existing OPL procedures that address the OPL identified hazards posed
by the collocated overhead HVAC transmission lines. In Section 5.4, these and other potential
hazards will be discussed further.
Excavation Activities
Any situation in which construction requires excavation in close proximity to a pipeline places the
pipeline at risk of damage by the construction equipment. There are a number of mitigation
measures which reduce the risk of physical damage to the pipeline. To minimize the likelihood of
a pipeline being damaged by excavation activities, the Washington State legislature enacted the
8 See Northwest Gas Association v. WUTC, 141 Wn. App. 98, 168 P.3d 443 (2007), rev. denied, 163 Wn.2d
1049 (2008).
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“one‐call” locator service law9. Under the one‐call program, anyone planning to excavate near an
underground utility is required to provide advance notice of the excavation by calling a
designated central number. The affected utility is then notified and required to monitor the
excavation work to ensure no damage is done.
Consistent with these requirements, if a project is within 100 feet of OPL’s pipeline, the OPL
Damage Prevention Team meets with the construction team at the construction site at the start
of the project and weekly thereafter to reinforce the importance of following established safety
protocols. The OPL Damage Prevention Team is also on‐site to monitor the excavation project
any time equipment with the ability to reach within 10‐feet of the pipeline is being used. While
the relevant federal regulations generally require at least 12‐inches of clearance between a
pipeline and any underground structures, OPL’s practice is to double the federal standard and
ensure there is at least 24‐inches of clearance between OPL pipelines and any underground
structure. In compliance with the federal regulations, OPL also installs and maintains right‐of‐way
signs along the corridor and conducts regular aerial and/or ground based right‐of‐way patrols.
Surcharge Loading
There is also some risk of damage to a pipeline from weight of equipment working over an
operating pipeline. The OPL Damage Prevention Team mitigates this risk during construction by
monitoring construction activities. In addition, OPL conducts an engineering review of any
planned equipment crossings prior to commencement of work.
Electrical Interference
Overhead HVAC lines can induce a current which can interfere with cathodic protection systems.
This can increase the frequency of external corrosion caused unintentional releases.
There are a number of proven practices and guidelines that can be employed to mitigate the
potential for alternating current (AC) interference related corrosion of the pipelines. OPL employs
a program to actively monitor and, where necessary, mitigate the impact of AC interference. As
part of this program, AC interference is currently monitored along this corridor. AC grounding
systems are commonly installed in connection with power transmission towers to safely dissipate
any energy to ground. OPL also plans to undertake an engineering analysis to assess the necessity
for installation of similar systems along the pipeline.
1.2 Refined Petroleum Products Pipeline Public Risks
Unintentional releases of refined petroleum products from the existing pipelines could pose risks
to human health and safety. For example, refined petroleum products could be released from a
leak or rupture in one of the pipelines. If an ignition source was present, a fire and/or explosion
could occur, resulting in possible injuries and/or deaths.
9 Chapter 19.122, Revised Code of Washington (RCW) – Underground Utilities
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Additionally, an unintentional release could present an environmental hazard. For example, soil
could be impacted, waterways could be degraded, and wildlife and vegetation could be
jeopardized. This Report presents the life safety risks posed to the public.
1.3 Refined Petroleum Products Characteristics
The OPL pipelines transport jet fuel, gasolines, and diesel, the characteristics of which are
described in the following sections. The National Fire Protection Association (NFPA) rating sign
for each of these fuels is depicted below. For each hazard, the severity ranges from 0 (no hazard)
to 4 (health ‐ lethal health hazard, flammability ‐ will vaporize and readily burn at normal
temperatures, and reactivity ‐ may explode at normal temperatures and pressures).
Figure 1.3-1 NFPA Rating Sign for Jet, Diesel, and Gasoline Fuels Respectively
1.3.1 Jet Fuel10
Jet Fuel (aviation turbine fuel) is comprised primarily of hydrocarbons11 (e.g., paraffins,
naphthenes, olefins, and aromatics). It is colorless to clear light yellow and has a gasoline and/or
kerosene‐like odor. It may cause eye and skin irritation. Inhalation can produce headaches,
dizziness, drowsiness, and nausea, lassitude, weariness, and over excitation. Exposure to very
high levels can result in unconsciousness and death.
Kerosene‐type jet fuel has thermal stability and a relatively high flashpoint. The flash point12 is
approximately 100°F; the auto‐ignition temperature is between 410 ‐ 475°F, depending on fuel
type and additives13. Its upper explosive limit is 8.0% by volume and the lower explosive limit is
0.7%14.
10 See ASTM D1655 for jet fuel specifications.
11 Organic compounds composed entirely of carbon and hydrogen atoms.
12 The flash point is the lowest temperature at which the liquid vaporizes and is therefore able to ignite.
ASTM D93 is used to determine this threshold.
13 The auto‐ignition temperature is affected by the chemical properties. ASTM E659 defines the standard
method for determining the auto‐ignition temperature.
14 Flammable liquid only burns in its gaseous state. If the ratio of jet fuel to air is greater than about 8.0%,
the mixture is too rich to burn; if it is less than 0.7%, the mixture is to lean to burn.
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1.3.2 Diesel Fuel15
Diesel Fuel is similar to Jet Fuel. It is comprised primarily of hydrocarbons. It is colorless to brown
and has a kerosene odor. It may cause eye and skin irritation.
Diesel Fuel has a flash point between 100 and 130°F, and an auto‐ignition temperature between
351 ‐ 624°F, depending on the type and the additives. Its upper explosive limit is 6.5% by volume
and its lower explosive limit is 0.6%.
1.3.3 Gasoline16
Gasoline is a complex mixture of hydrocarbons. It is colorless to light yellow and has a strong
gasoline and/or kerosene odor. It may cause eye and skin irritation. Inhalation of concentrations
over 50 parts per million (ppm) can produce headaches, dizziness, drowsiness, and nausea,
lassitude, weariness, over excitation. Exposure to very high levels can result in unconsciousness
and death.
Gasoline is more volatile17 than the other fuels described above, and is described as flammable18
by the National Fire Protection Association (NFPA).
Unleaded gasoline has a relatively low flash point of ‐45°F and an auto‐ignition temperature of
approximately 480°F, depending on the percent ethanol and other additives. The higher the
octane number the higher the auto‐ignition temperature. Its upper explosive limit is 8.0% by
volume and its lower explosive limit is 1.0%.
1.4 Major Pipeline Incident Summaries
Although transportation of hazardous liquids and natural gas has proven to be a very safe mode
of transportation19, there have been a few significant pipeline incidents. Five (5) of these
incidents have resulted in changes, and proposed changes, to the Federal pipeline regulations
which should further improve pipeline safety.
1.4.1 San Bernardino, California, May 25, 1989
On May 12, 1989, a Southern Pacific Transportation Company freight train derailed in San
Bernardino, California. On May 25, 1989, 13 days later, a regulated interstate petroleum products
pipeline ruptured. The National Transportation Safety Board summarized this incident in their
15 See ASTM D975 for diesel fuel specifications.
16 See ASTM D4814 for gasoline specifications.
17 A fuel’s tendency to vaporize.
18 According to NFPA 30 a flammable liquid has a flash point lower than 100°F. A liquid with a flashpoint
higher than 100°F is described as combustible.
19 Payne, Brian L. el al. EDM Services, Inc. 1993. California Hazardous Liquid Pipeline Risk Assessment,
Prepared for California State Fire Marshal, March.
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public information report entitled, Railroad Derailment Incidents Involving Pipelines: 1981 ‐ 1990
as follows:
"A Southern Pacific westbound train lost its brakes as it headed down the Cajon grade
toward San Bernardino. After reaching a speed of over 100 mph the train derailed at a
curve adjacent to a residential section of San Bernardino. Derailing cars and engines left
the track and literally tumbled into several houses, killing two children and two train crew
members. All sixty‐nine of the cars and five of the locomotive units were destroyed and
four others sustained extensive damage.
During the derailment, and later during the movement of heavy equipment to remove the
wreckage, a high‐pressured gasoline pipeline adjacent to the tracks was damaged and
weakened. Less than two weeks after the wreck, the pipeline ruptured and spewed over
300,000 gallons of flaming gasoline into the neighborhood, resulting in two more deaths,
serious burns to three others, and the destruction of eleven more homes and 21 vehicles.
Total damage to the train and track alone was estimated to be well over nine million
dollars with an additional damage estimate to the neighborhood of over five million
dollars."
The extremity of this incident stimulated a good deal of public concern. As a result, steps were
taken to determine that public safety was not being endangered by the proximity of pipelines to
rail lines. One of the results was the passage of California Assembly Bill 385 (Elder). California
Senate Bill 268 (Rosenthal), which was signed by the Governor at the same time, resulted from
chronic leaks from one of the oldest crude oil pipelines in the Los Angeles area. These bills
included requirements for the State Fire Marshal to perform certain studies which address the
risk levels associated with hazardous liquid pipelines on railroad rights‐of‐way and other factors.
Among other things, they required the State Fire Marshal to:
Study the spacing of shut‐off valves that would limit spillage into standard metropolitan
statistical areas and environmentally sensitive areas and, if existing standards were deemed
insufficient, to adopt regulations to require the addition of new valves on existing, and new or
replacement pipelines.20
1.4.2 Bellingham, Washington, June 10, 1999
According to the National Transportation Safety Board (NTSB) accident report,
“…about 3:28 p.m., Pacific daylight time, on June 10, 1999, a 16‐inch diameter steel
pipeline owned by Olympic Pipe Line Company ruptured and released about 237,000
gallons of gasoline into a creek that flowed through Whatcom Falls Park in Bellingham,
Washington. About one and one half hours after the rupture, the gasoline ignited and
burned approximately and one half miles along the creek. Two 10‐year‐old boys and an
20 Payne, Brian L. el al. EDM Services, Inc. 1993. California Hazardous Liquid Pipeline Risk Assessment,
Prepared for California State Fire Marshal, March.
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18‐year‐old young man died as a result of the accident. Eight additional injuries were
documented. A single‐family residence and the City of Bellingham’s water treatment
plant were severely damaged. As of January 2002, Olympic estimated that total property
damages were at least $45 million.
The major safety issues identified during this investigation are excavations performed by
IMCO General Construction, Inc., in the vicinity of Olympic’s pipeline during a major
construction project and the adequacy of Olympic Pipe Line Company’s inspections
thereof; the adequacy of Olympic Pipe Line Company’s interpretation of the results of in‐
line inspections of its pipeline and its evaluation of all pipeline data available to it to
effectively manage system integrity; the adequacy of Olympic Pipe Line Company’s
management of the construction and commissioning of the Bayview products terminal;
the performance and security of Olympic Pipe Line Company’s supervisory control and
data acquisition system; and the adequacy of Federal regulations regarding the testing of
relief valves used in the protection of pipeline systems.21”
1.4.3 Carlsbad, New Mexico, August 19, 2000
According to the NTSB accident report,
“At 5:26 a.m., mountain daylight time, on Saturday, August 19, 2000, a 30‐inch diameter
natural gas transmission pipeline operated by El Paso Natural Gas Company ruptured
adjacent to the Pecos River near Carlsbad, New Mexico. The released gas ignited and
burned for 55 minutes. 12 persons who were camping under a concrete‐decked steel
bridge that supported the pipeline across the river were killed and their three vehicles
destroyed. Two nearby steel suspension bridges for gas pipelines crossing the river were
extensively damaged. According to El Paso Natural Gas Company, property and other
damages or losses totaled $998,296.
The major safety issues identified in this investigation are the design and construction of
the pipeline, the adequacy of El Paso Natural Gas Company’s internal corrosion control
program, the adequacy of Federal safety regulations for natural gas pipelines, and the
adequacy of Federal oversight of the pipeline operator.22”
1.4.4 Walnut Creek, California, November 9, 2004
According to the California State Fire Marshal pipeline failure investigation report:
“At 1322 hours on 9 November 2004, excavation equipment operated by Mountain
Cascade, Inc., struck Kinder Morgan’s LS‐16 pipeline, a 51.4 mile long intrastate products
pipeline that travels from Concord to San Jose. The excavator was working on a large‐
21 National Transportation Safety Board (NTSB 2002). Pipeline Rupture and Subsequent Fire in Bellingham,
Washington, June 10, 1999. Pipeline Accident Report NTSB/PAR‐02/02. Washington, D.C.
22 National Transportation Safety Board (NTSB 2003). Pipeline Rupture and Subsequent Fire near Carlsbad,
New Mexico, August 19, 2000. Pipeline Accident Report NTSB/PAR‐03/01. Washington, D.C.
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diameter water supply expansion project in Walnut Creek, CA for the East Bay Municipal
Utility District (EBMUD).
Upon puncture of the Kinder Morgan pipeline, gasoline under high pressure was
immediately released into the surrounding area. Kinder Morgan control center operators
in Concord immediately noticed the large pressure drop and started to shut the pipeline
down. Several seconds after the line was hit, the gasoline streaming out of the line was
ignited by welders employed by Matamoros Pipelines, Inc. who were also working on the
new water supply pipeline. The ensuing explosion and fire resulted in the deaths of five
workers and significant injury to four others. One nearby two‐story structure was burned
and other property was damaged.
The direct cause of the accident was the excavator’s bucket striking the pipeline and
puncturing through the wall of the pipe. However, there were several factors that
significantly contributed to this accident. These include inadequate line locating,
inadequate project safety oversight and communication, and failure to follow the one‐call
law.23”
This incident demonstrates that even with one‐call laws, significant incidents can and do occur
due to third party damage. In this case, the Office of the State Fire Marshal (California) found the
following:
The pipeline operator did not properly mark the location of the pipeline in accordance with
their damage prevention program and the California Government Code.
The pipeline operator did not follow the company’s line locating procedures.
Within one minute of the incident, the operator received an alarm indicating a pressure drop
in the line. Within four minutes, pump shut down was initiated. Within 38 minutes, the
pipeline operator had officials at the accident site.
1.4.5 San Bruno, California, September 9, 2010
According to the NTSB accident report,
“On September 9, 2010, about 6:11 p.m. Pacific daylight time, a 30‐inch‐diameter
segment of an intrastate natural gas transmission pipeline known as Line 132, owned and
operated by the Pacific Gas and Electric Company (PG&E), ruptured in a residential area in
San Bruno, California. The rupture occurred at mile point 39.28 of Line 132, at the
intersection of Earl Avenue and Glenview Drive. The rupture produced a crater about 72
feet long by 26 feet wide. The section of pipe that ruptured, which was about 28 feet long
and weighed about 3,000 pounds, was found 100 feet south of the crater. PG&E
estimated that 47.6 million standard cubic feet of natural gas was released. The released
natural gas ignited, resulting in a fire that destroyed 38 homes and damaged 70. Eight
people were killed, many were injured, and many more were evacuated from the area.
23 Office of the State Fire Marshal, Pipeline Failure Investigation Report, November 9, 2004. California.
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Probable Cause
The National Transportation Safety Board determines that the probable cause of the
accident was the Pacific Gas and Electric Company's (PG&E) (1) inadequate quality
assurance and quality control in 1956 during its Line 132 relocation project, which allowed
the installation of a substandard and poorly welded pipe section with a visible seam weld
flaw that, over time grew to a critical size, causing the pipeline to rupture during a
pressure increase stemming from poorly planned electrical work at the Milpitas Terminal;
and (2) inadequate pipeline integrity management program, which failed to detect and
repair or remove the defective pipe section.
Contributing to the accident were the California Public Utilities Commission's (CPUC) and
the U.S. Department of Transportation's exemptions of existing pipelines from the
regulatory requirement for pressure testing, which likely would have detected the
installation defects. Also contributing to the accident was the CPUC's failure to detect the
inadequacies of PG&E's pipeline integrity management program.
Contributing to the severity of the accident were the lack of either automatic shutoff
valves or remote control valves on the line and PG&E's flawed emergency response
procedures and delay in isolating the rupture to stop the flow of gas.24”
As a result of this incident, the NTSB made a number of recommendations that resulted in
significant new gas pipeline regulations which require improvements in gas pipeline integrity
management.
24 National Transportation Safety Board (NTSB 2011). Pacific Gas and Electric Company Natural Gas
Transmission Pipeline Rupture and Fire, San Bruno, California, September 9, 2010. Pipeline Accident Report
NTSB/PAR‐11/01. Washington, D.C.
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2.0 Regulatory Setting
2.1 Regulatory Framework
The United States Department of Transportation (DOT) provides oversight for the nation’s
hazardous liquid pipeline transportation system. Its responsibilities are promulgated under Title
49, United States Code (USC) Chapter 601. The Pipeline and Hazardous Materials Safety
Administration (PHMSA), Office of Pipeline Safety (OPS), administers the national regulatory
program to ensure the safe transportation of gas and other hazardous materials by pipeline.
PHMSA was originally the Research and Special Programs Administration (RSPA) within DOT.
Two statutes provide the framework for the Federal pipeline safety program. The Natural Gas
Pipeline Safety Act of 1968 as amended (NGPSA) authorizes the DOT to regulate pipeline
transportation of natural (flammable, toxic, or corrosive) gas and other gases as well as the
transportation and storage of liquefied natural gas (LNG). Similarly, the Hazardous Liquid Pipeline
Safety Act of 1979 as amended (HLPSA) authorizes the DOT to regulate pipeline transportation of
hazardous liquids (crude oil, petroleum products, anhydrous ammonia, and carbon dioxide). Both
of these Acts have been re‐codified as 49 USC Chapter 601.
The Federal Pipeline Safety Act of 2002 (Public Law 107‐355 dated December 17, 2002) provided
for the sharing of the oversight of hazardous liquid pipelines with authorized State agencies.
States must demonstrate to the Secretary of the Department of Transportation that their
programs are consistent with the Federal pipeline safety regulations. The Secretary can then
authorize that State’s hazardous liquid pipeline agency to participate in the oversight of intrastate
pipelines and some activities of interstate pipelines.
The Revised Codes of Washington (RCW) Title 81, Chapter 81.88 established the Washington State
Utilities & Transportation Commission. As referred to in this regulation, the law’s short title is the
Washington Pipeline Safety Act of 2000. It established a Commissioner whose duties included,
“The development and administration of a comprehensive pipeline safety program for natural gas
and hazardous liquid pipelines, and the acquisition of a Federal certification of the pipeline safety
program to act as a delegate to OPS”. The Washington State Utilities & Transportation
Commission developed and demonstrated that the State’s pipeline programs were consistent
with the Federal program and gained authorization to share oversight of hazardous liquids
pipelines.
2.2 Federal Pipeline Regulations
Interstate and intrastate hazardous liquid transportation by pipeline and rail fall under the
jurisdiction of the U.S. Department of Transportation. Hazardous liquid pipelines must conform
with the design, construction, testing, operation and maintenance regulations contained in Title
49 Code of Federal Regulations (CFR) Part 195, "Transportation of Hazardous Liquids by Pipeline,"
as authorized by the Hazardous Liquid Pipeline Safety Act of 1979 (HLPSA ‐ 49 USC § 2004).
However, the DOT does not issue a construction permit or conduct a plan check for all pipeline
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projects. Within this study, 49 CFR Parts 195 will be referred to as the “regulations,” or the
“pipeline regulations.” After the HLPSA was originally written, several pipeline safety measures
have been passed by Congress to improve pipeline safety and to revise 49 CFR Part 195. Some
portions of the laws initiated studies in specific areas that led to subsequent changes in the
Regulations.
49 CFR Part 194 prescribes the federal requirements for response plans for onshore oil pipelines.
Other relevant federal requirements applicable to the transportation of hazardous liquids by
pipeline are contained in 40 CFR Parts 109, 110, 112, 113, and 114, which pertain to the need for
"Oil Spill Prevention Control & Countermeasures (SPCC) Plans" and Public Law 101‐380 (H.R.),
promulgated in response to the Oil Pollution Act (OPA) of 1990.
2.2.1 Overview of 49 CFR Part 190
This part prescribes procedures that are used by the DOT relative to DOT’s duties regarding
natural gas and hazardous liquid pipeline safety.
2.2.2 Overview of 49 CFR Part 195
2015 PHMSA Notice of Proposed Rulemaking
A number of Congressional Acts have been passed since the initial Pipeline Safety Act of 1979 with
the intent of improving hazardous liquid pipeline safety. Recently, The Pipeline Safety, Regulatory
Certainty, and Jobs Creation Act of 2011 gave direction to PHMSA to perform a number of studies
relating to hazardous liquid pipeline safety and to develop regulations to address the findings of
those studies. In October 2015, PHMSA drafted a document outlining proposed rulemaking as a
result of the safety studies initiated by the Congressional Act of 2011. The proposed rulemaking
includes the following proposed changes to 49 CFR Part 195:
195.1 ‐ The regulation will now consider certain gathering lines to be considered jurisdictional
to the regulations, specifically those that cross navigable waterways.
195.2 ‐ The regulations will now include ethanol, ethanol blends, and other biofuels in the
definition of hazardous liquids. This section will also add the definition ``Significant Stress
Corrosion Cracking'' and require such damage to be excavated and repaired.
195.11 ‐ The regulation will now require certain gathering pipelines to be subject to the
pipeline integrity assessment and leak detection requirements of the regulations.
195.13 ‐ The regulations will now require hazardous liquid gravity lines to be included in the
annual, safety related, and incident reporting requirement of the regulations.
195.120 ‐ The regulations will no longer allow operators to petition to not make changes to
their systems that would accommodate internal instrumentation tools.
195.134 ‐ The regulation will now require all new pipeline designs to include computational
pipeline modeling (CPM) leak detection based on API 1130 or other applicable standard(s).
195.401 ‐ The regulation will now define the timeframe for all non‐integrity management
repairs.
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195.414 ‐ The regulation will now require operators to inspect their pipelines after the
cessation of any of the listed events to insure the safe operation of their pipelines.
195.416 ‐ The regulations will now include this new section that requires the integrity
assessment of current non‐integrity management pipelines every 10 years.
195.422 ‐ The regulations will now include requirements for the repairs of pipelines outside of
HCA’s (non‐integrity management jurisdictional pipeline segments) analogous to the repair
requirements within HCA’s to insure the safe operation of the pipelines.
195.444 ‐ The regulations will now include requirements that all pipelines have CPM leak
detection.
195.452 ‐ The regulations will now eliminate obsolete deadlines currently stated within this
part. The regulation will now include clarifications on the requirements of newly identified
HCA’s. The regulations will include the consideration of local environmental factors (including
seismicity) that have an effect on pipeline integrity. The regulation will expand the criteria
required for integrity analysis. The regulation will include new timeframes for repairs
including revised language pertinent to the discovery of a condition and the reporting of that
condition to PHMSA. The regulations will also require all pipelines to be able to accommodate
an internal inspection tool within 20 years that cross existing HCA’s and within 5 years of
newly identified HCA’s.
If enacted as published, the existing OPL pipelines would be subject to these new requirements, as
applicable.
Subpart A – General (Sections 195.0 – 195.12)
This part provides the definition of a jurisdictional hazardous liquid pipeline and the general
responsibilities of a hazardous liquid pipeline operator. Section 195.3 of the regulation
incorporates, by reference, the applicable national safety standards of the following
organizations:
American Petroleum Institute (API)
American Society of Mechanical Engineers (ASME)
American National Standards Institute (ANSI)
American Society for Testing and Materials (ASTM)
Manufacturers Standardization Society of the Valve and Fittings Industry (MSS)
Section 195.6 was added to the regulations on December 21, 2000, which defines Unusually
Sensitive Areas (USAs). USAs are drinking water or ecological resource areas that are unusually
sensitive to environmental damage from a hazardous liquid pipeline release, including the
following resources:
Certain drinking water resources (e.g., community water systems, certain aquifers, sole source
aquifers, etc.),
Certain ecological resources (e.g., critically imperiled species, multi‐species assemblage area,
threatened or endangered species, etc.), and
Alternative drinking water sources.
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It should be noted that all USAs are High Consequence Areas (HCAs), as discussed later in this
report (49 CFR 195, Subpart F). Unfortunately, the USDOT does not publish maps of USAs due to
security concerns.
Subpart B – Annual, Accident, and Safety‐Related Condition Reporting (Sections 195.48 –
195.64)
This part outlines the various reporting requirements of a hazardous liquid pipeline operator as
well as the timing of submission of various incident, accident and safety related conditions
discovered by the operator. Sections 195.50 to 195.54 require reporting of the following
scenarios caused by unintentional releases:
An incident which resulted in an explosion or fire not intentionally set by the operator.
Effective January 1, 2002, the reportable spill volume was reduced to any release of 5 gallons
or more of hazardous liquid or carbon dioxide, unless the spill resulted from maintenance
activity, in which case the reportable spill volume is 5 barrels (210 gallons) or more. (Prior to
January 1, 2002, the reportable spill volume was 2,100 gallons or more of liquid for any
unintentional release.)
Death of a person.
Effective January 1, 2002, an accident resulting in an injury necessitating hospitalization must
be reported. (Prior to January 1, 2002, an accident resulting in serious injury to any person
resulting in loss of consciousness, necessity to carry the individual from the scene, medical
treatment, or disability which prevents the discharge of normal duties or the pursuit of
normal activities beyond the day of the incident was required to be reported.)
Damage to property of operator, or others, or both, greater than $50,000 (including the cost
of clean‐up and recovery, property damage, and lost product).
Sections 195.55 and 195.56 require reporting of the following safety related conditions. The
pipeline operator is required to file a written report with the DOT within five working days of the
time in which the operator first determined that the condition exists.
General corrosion which has reduced the wall thickness to less than that required for the
maximum operating pressure or localized corrosion which could result in a leak;
Unintended movement or abnormal loading of a pipeline by environmental causes (e.g.,
earthquake, landslide, flood) that impairs its serviceability;
Any material defect or physical damage that impairs the serviceability of a pipeline;
Any malfunction or operating error that causes the pressure of a pipeline to rise above 110
percent of the maximum operating pressure;
A leak in a pipeline that constitutes an emergency; and
Any safety related condition that could lead to an imminent hazard and causes (either directly
or indirectly by remedial action of the operator) a 20 percent or more reduction in operating
pressure or shutdown of pipeline operation.
The following safety related conditions are excluded from the above reporting requirements:
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A safety related condition that is more than 220 yards from a human occupancy or outdoor
assembly place. (Please note that reports are required for safety related conditions within
railroad rights‐of‐way, paved roadways, or where an incident could reasonably be expected to
pollute any stream, river, lake, reservoir, or other body of water.);
Is an accident that is required to be reported under 195.50 or results in such an accident
before the deadline for filing the safety‐related condition report; or
Any safety related condition that is corrected by repair or replacement in accordance with
applicable safety standards before the report deadline. (Please note that reports are required
for general corrosion on all lines and localized corrosion on unprotected lines.)
Subpart C – Design Requirements (Sections 195.100 – 195.134)
This part includes the design requirements for new pipelines, relocated pipeline segments, pipe
replacements, and other changes to existing systems that use steel pipe. These requirements
include:
Qualification of metallic components other than pipe,
Design temperature,
Variations in pressure,
Internal design pressure,
External pressure,
External loads,
Fracture propagation,
New pipe,
Used pipe,
Valves,
Fittings,
Passage of internal inspection devices,
Fabricated branch connections,
Closures,
Flange connections,
Station piping,
Fabricated assemblies,
Design and construction of breakout tanks, and
Computational pipeline monitoring (CPM) leak detection.
Subpart D – Construction (Sections 195.200 – 195.266)
This part provides the minimum requirements for constructing new pipelines, relocating existing
pipelines, replacing pipe segments, or otherwise changing existing pipeline systems that use steel
pipe. These requirements include:
Compliance with written standards and specifications,
Construction inspection,
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Repair, alteration, and reconstruction of aboveground breakout tanks that have been in
service,
Welding,
Pipeline location,
Pipe bending,
Welding procedure qualification,
Welder qualification,
Production welding,
Welding inspection and nondestructive testing of welds,
Defective weld repair and removal,
External corrosion protection and cathodic protection,
External pipe coating,
Installing pipe in the ditch,
Pipe burial depth (cover),
Clearances between the pipeline and other substructures (49 CFR Part 195.250 requires 12
inches of clearance between a buried pipeline and any other buried structure, with few
exceptions)25,
Clearances between the pipeline and other substructures,
Backfilling,
Rail and highway crossings,
Valves,
Valve locations,
Pumping equipment,
Breakout tanks, and
Construction records.
Subpart E – Pressure Testing (Sections 195.300 – 195.310)
This part prescribes the minimum requirements for hydrostatic testing, compliance dates, test
pressures and duration, test medium, and records. Basically, this section requires new pipeline
segments to be tested at 125% of the maximum allowable operating pressure (MAOP) for a
period of four hours and an additional four hours at 110% of the MAOP (if buried) prior to
operation. The regulations do not require the periodic re‐testing of pipelines after the initial
construction test. The regulations do require that any new pipe, installed within an existing
pipeline, be pre‐tested prior to installation into the pipeline system, or the existing pipeline
segment be re‐tested after the new pipe is installed. Also, operators do have the option of using
hydrostatic pressure testing as a means to establish their baseline integrity assessment as part of
their integrity management plans in lieu of using internal electronic inspection tools.
Subpart F – Operation and Maintenance (Sections 195.400 – 195.452)
25 49 CFR 195 does not currently contain any specific requirements for pipeline separation from buildings or
other structures.
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This part specifies the following minimum requirements for operating and maintaining steel
pipeline systems. Of special interest to this study is Section 195.402 (c) (10) that requires the
development of a written plan for the abandonment of pipelines (permanently removed from
service per 195.2 Definitions) and what activities must be performed to properly abandon a
pipeline. Other requirements of this part include:
Correction of unsafe conditions within a reasonable time,
Procedural manual for operations, maintenance, and emergencies (including abandonment of
pipelines),
Training,
Maps and record maintenance,
Maximum operating pressure,
Communication system,
Line markers,
Inspection of right‐of‐way and navigable water crossings,
Cathodic protection systems,
External and internal corrosion control,
Valve maintenance,
Pipeline repairs,
Pipeline movement,
Scraper and sphere facilities,
Over pressure safety devices,
Firefighting equipment,
Breakout tank inspections,
Signs around pump stations and breakout tanks,
Security of facilities,
Smoking or open flames in pump station and breakout tank areas,
Public awareness and education program for hazardous liquid pipeline emergencies and
reporting,
Pipeline integrity management in high consequence areas,
Damage prevention programs,
Computerized leak detection monitoring, and
Control room management.
On December 1, 2000, significant operation and maintenance requirements (49 CFR 195.452)
were added to this subpart. These are the pipeline integrity management program requirements.
These requirements apply to hazardous liquid pipelines that may affect high consequence areas
(HCAs). Operators of these pipelines must conduct a baseline assessment within prescribed
deadlines. These assessments may include the following tests: internal inspection tools (smart
pigs), pressure testing, and other equivalent technologies. For operators of more than 500 miles
of pipeline that is subject to 49 CFR Part 195, at least 50% of the pipeline mileage, beginning with
the highest risk segment of pipeline, must have been assessed by September 30, 2004; the
remaining mileage must be assessed by March 31, 2008. For operators of less than 500 miles of
pipe subject to this regulation, the deadlines are August 16, 2005 and February 17, 2009,
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respectively. The new regulation also requires that certain defects be repaired within prescribed
timeframes, depending on their severity. HCA’s are defines as follows (49 CFR 195.450):
(1) A commercially navigable waterway, which means a waterway where a substantial
likelihood of commercial navigation exists;
(2) A high population area, which means an urbanized area, as defined and delineated by the
Census Bureau, that contains 50,000 or more people and has a population density of at least
1,000 people per square mile;
(3) An other populated area, which means a place, as defined and delineated by the Census
Bureau, that contains a concentrated population, such as an incorporated or unincorporated
city, town, village, or other designated residential or commercial area;
(4) An unusually sensitive area, as defined in §195.6. (See also Subpart A discussion above.)
The OPL pipelines corridor are within a highly populated area. As a result, they are subject to these
pipeline integrity management program requirements.
Subpart G – Qualification of Pipeline Personnel (Sections 195.500 – 195.509)
This part of the regulations (effective August 29, 1999) prescribes the minimum qualification
requirements for hazardous liquid pipeline operations and maintenance personnel. This involves
the development of an operator qualification program and documentation that employees have
been qualified to perform their daily tasks.
Subpart H – Corrosion Control (Sections 195.551 – 195.589)
This part prescribes the minimum corrosion control requirements for hazardous liquid pipeline
systems. These requirements include:
Qualification of corrosion control program supervisors,
Requirements for external corrosion control,
Inspection of external coatings,
What pipelines must have cathodic protection in place,
Installation of cathodic protection on breakout tanks,
Cathodic protection test leads,
Examination of exposed portions of buried pipelines,
Criteria for the evaluation of adequate cathodic protection,
Monitoring of external corrosion,
Pipeline electrical isolation, inspection, testing, safeguards, and repairs,
Alleviation of stray electrical currents on pipelines,
Atmospheric corrosion protection, control and acceptable coating materials,
Monitoring of atmospheric corrosion,
Corrective measures for corroded pipes,
Methods available to determine the strength of corroded pipes,
Standards for direct assessment of corrosion, and
Maintenance and retention of corrosion control maps and records.
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Appendix A to Part 195 ‐ Delineation between Federal and State Jurisdiction ‐ Statement
of Agency Policy and Interpretation
This appendix describes the jurisdictional relationship between intrastate and interstate pipelines
and how the regulations are enforced by DOT and the state agencies.
Appendix B to Part 195—Risk‐Based Alternative to Pressure Testing Older Hazardous
Liquid and Carbon Dioxide Pipelines
As stated in the appendix, “This Appendix provides guidance on how a risk‐based alternative to
pressure testing older hazardous liquid and carbon dioxide pipelines rule allowed by 195.303 will
work. This risk‐based alternative establishes test priorities for older pipelines, not previously
pressure tested, based on the inherent risk of a given pipeline segment. The first step is to
determine the classification based on the type of pipe or on the pipeline segment's proximity to
populated or environmentally sensitive area. Secondly, the classifications must be adjusted based
on the pipeline failure history, product transported, and the release volume potential.”
Appendix C to Part 195—Guidance for Implementation of an Integrity Management
Program
As stated in the appendix, “This Appendix gives guidance to help an operator implement the
requirements of the integrity management program rule in 195.450 and 195.452.”
2.2.3 Overview of 49 CFR Part 199, (Drug Testing, Requirements)
Operators of interstate hazardous liquid pipeline systems are required to comply with the drug
testing requirements of this regulation. The regulation requires operators to maintain an anti‐
drug plan, provide pre‐employment employee testing, conduct post‐accident drug testing, and
perform random testing such that half of the employee pool is tested each twelve‐month period.
All employees that perform operating, maintenance, or emergency response functions are subject
to these requirements. Employees who fail or refuse a drug test may not be used in these
functions unless they completed a rehabilitation program and have met other requirements.
2.2.4 Overview of 40 CFR Parts 109, 110, 112-114
The Federal Environmental Protection Agency (EPA), as authorized by 40 CFR, to develop
regulations to prevent and respond to oil spills onto navigable waters of the United States. The
Oil Spill Prevention Control & Countermeasures (SPCC) covered in these regulations apply to oil
storage and transportation facilities and terminals, tank farms, bulk plants, oil refineries, and
production facilities, as well bulk oil consumers such as apartment houses, office buildings,
schools, hospitals, farms, and state and federal facilities.
Part 109 establishes the minimum criteria for developing oil removal contingency plans for certain
inland navigable water by state, local, and regional agencies in consultation with the regulated
community (e.g., oil facilities).
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Part 110 prohibits discharge of oil in such a manner that applicable water quality standards would
be violated, or in such a manner that would cause a film or sheen upon or in the water. These
regulations were updated in 1987 to adequately reflect the intent of Congress in Section 311(b)
(3) and (4) of the Clean Water Act.
Part 112 deals with oil spill prevention and preparation of SPCC Plans. These regulations establish
procedures, methods, and equipment requirements to prevent the discharge of oil from onshore
and offshore facilities into or upon the navigable waters of the United States. Current wording
applies these regulations to facilities that are non‐transportation related. However, proposed
rules would make the spill emergency planning in these rules applicable to all oil facilities. Part
112 should be used by pipeline operators as additional guidelines for the development of oil spill
prevention, control, and emergency response plans.
Part 113 establishes financial liability limits; however, these limits have now been preempted by
the Oil Pollution Act of 1990.
Part 114 provides civil penalties for violations of the oil spill regulations. The amount of the
penalty is determined considering the gravity of the violation and demonstrated good faith efforts
to achieve rapid compliance after notification of a violation. The amount is assessed during the
hearing process, or may be assessed by the Regional Administrator if a hearing is not requested.
2.2.5 Oil Pollution Act of 1990 (OPA)
The Oil Pollution Act of 1990 (OPA), together with the Oil Pollution Liability and Compensation Act
of 1989, builds upon Section 311 of the Clean Water Act (CWA) to create a single federal law
providing cleanup authority, penalties, and liability for oil pollution. The bill creates a single fund
to pay for removal of and damages from oil pollution. This new fund replaces those created
under the Trans‐Alaska Pipeline Act, Deep Water Port Act of 1974, and Outer Continental Shelf
Lands Act, and supersedes the contingency fund established under Section 311 of CWA. OPA‐90
also authorized the Oil Spill Liability Trust Fund (OSLTF) up to $1 billion to pay for expeditious oil
removal and uncompensated damages up to $1 billion per incident. The administration of OSLTF
was delegated to the United States Coast Guard by executive order.
The Oil Spill Compensation Fund will be available for all removal costs and compensatory
damages (limited to $1 billion per incident). The OPA provides for liability and availability of funds
to pay removal costs and compensation in case of discharges of oil. It adopts the standard of
liability of dischargers for cleanup costs‐strict, several, and joint liability, under Section 311. The
OPA establishes financial liability of all oil facility operators, including pipeline operators. The OPA
provides for financial liability related to land‐based pipelines, but only as they relate to
"discharges of oil, unto or upon the navigable waters or adjoining shorelines...”
The OPA affirms the rights of states to protect their own air, water, and land resources by
permitting them to establish state standards which are more restrictive than federal standards.
More stringent state laws are specifically preserved. Section 106 of the OPA explicitly preserves
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authority of any state to impose its own requirements or standards with respect to discharges of
oil within each state.
As a result of this legislation, 49 CFR Part 194 was codified to require operators to prepare oil spill
response plans for onshore oil pipelines (including pipelines transporting petroleum, fuel oil, etc.).
The intent of these regulations is to reduce the environmental impact of oil discharged from
onshore pipelines. The operator is required to determine the worst case discharge in each
response zone and meet specified criteria. The completed plan must be submitted to the DOT
Pipeline Response Plans Officer for review and approval. These spill response plans must be
consistent with the National and Area Contingency Plans for oil spill response (see state
regulations below establishing the Northwest Area Contingency Plan ‐ NWACP).
2.3 State Pipeline Regulations
The State of Washington’s Utilities and Transportation Commission is responsible for the
administration and oversight of hazardous liquid pipeline operations in the State as authorized by
the USDOT. The State has adopted the Federal hazardous liquids pipeline regulations as a part of
their own enhanced regulations. The following section outlines the regulatory framework within
the State of Washington that constitutes the State’s hazardous liquid pipeline regulations.
2.3.1 Revised Code of Washington (RCW) Title 81
The RCW Title 81, Chapter 81.88 establishes the Washington State Utilities & Transportation
Commission. As referred to in this regulation, the law’s short title is the Washington Pipeline
Safety Act of 2000. It establishes a Commissioner whose duties include:
The development and administration of a comprehensive pipeline safety program for natural
gas and hazardous liquids pipelines,
The creation of a State 3rd Party Damage Prevention Program,
The development of a State pipeline mapping program,
The acquisition of a Federal certification of the pipeline safety program to act as a delegate to
OPS,
The inspections of maps, records, and procedures of hazardous liquid pipeline operators, and
The establishment of a citizen’s committee on pipeline safety.
The RCW Title 81, Chapter 81.88.144 establishes the above‐mentioned Citizens Committee on
Pipeline Safety. This is a 13‐member group, appointed by the Governor, to serve 3 year staggered
terms. The members will include 9 voting members that are elected officials, and representatives
of the public, and 4 non‐voting members that represent owners and operators of hazardous
liquids and gas pipelines. As stated in the regulation, “The citizens committee on pipeline safety is
established to advise the state agencies and other appropriate federal and local government
agencies and officials on matters relating to hazardous liquid and gas pipeline safety, routing,
construction, operation, and maintenance.”
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2.3.2 Washington Administrative Code, Title 480 (WAC-480)
As developed and administered by the Washington Utilities and Transportation Commission,
WAC‐480 contains two chapters relating to hazardous liquid pipelines within the State that fulfill a
portion of the Utilities & Transportation Commissioner’s charge.
Chapter 480‐73: Hazardous Liquid Pipeline Companies: This State regulation defines the
applicability of the regulations and the administrative guidelines and rules hazardous liquid
pipeline companies must follow.
Chapter 480‐75: Hazardous Liquid Pipelines, Safety – This State regulation provides
Washington State specific pipeline safety rules. This regulation contains requirements similar
to 49 CFR Part 195 for the design, construction, operation and maintenance, and reporting for
hazardous liquid pipelines. The Chapter require compliance, by reference, with 49 CFR Part
195.
Of particular interest is this State’s adoption of the natural gas class location definitions published
in 49 CFR Part 192, Chapter 480‐75. The Washington State regulation governing hazardous liquid
pipelines adopts design factors, based on population density (area class), that limit the operating
pressure in more densely populated areas. It also requires that for station piping, the design
factor be 0.50. These requirements are the same as the Federal requirements for gas pipelines;
they are more conservative than the Federal requirements for hazardous liquid pipelines.
Unlike the Federal hazardous liquid regulations, WAC 480‐75‐300, Leak Detection, specifically
defines the performance measures of a computerized leak detection system where the 49 CFR
Part 195.134 Computational Pipeline Monitoring (CPM) Leak Detection refers compliance to API
RP 1130. The State requires a CPM leak detection system to be able to detect a leak equivalent to
8% of maximum flow within 15 minutes. These exact limits are not defined by the API RP because
of such variability in pipeline CPM methods, pipeline configurations, pipeline contents, etc.
WAC 480‐75‐640, Depth‐of‐Cover Survey also requires an operator to perform a survey of the
depth of cover every 5 years. Areas found to have less than the originally required depth of
cover, must be lowered back to the regulatory required depth of cover. This requirement is also
more conservative than the Federal hazardous liquid pipeline regulation, which only requires the
specified depth of cover at the time of construction, although the pipeline must be maintained in
a safe manner.
2.3.3 Revised Code of Washington (RCW), Title 19
RCW‐19 contains a number of various titles for business operations within the State. Within this
Title, Chapter 122 (RCW‐19.122) was developed specific to underground utilities.
RCW‐19.122 addresses one of the assigned responsibilities of the Utilities and Transportation
Commission for administering hazardous liquids pipelines. It establishes a comprehensive one‐
call excavation damage prevention program for the state.
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Underground Utilities, Damage Prevention Law RCW 19.122 addresses public health and safety
and prevention of disruption of vital utility services through a comprehensive damage prevention
program.
2.3.4 Washington Administrative Code, Title 173 (WAC-173)
WAC‐173 empowers the State of Washington Department of Ecology with the protection of the
ecological resources of the state. This includes water, air and shoreline protection from pollution.
Specific to pipelines are the requirements in Chapter 182 Oil Spill Contingency Plan requirements
for the State.
WAC‐173‐182 empowers the State of Washington Department of Ecology to require pipeline
operators, and others (vessel operators), to develop and submit for approval, Oil Spill Contingency
Plans to the State. Generally, these are the same plans developed for Federal plan compliance
with minor adjustments for State specific requirements. This is the OPA‐90 required Oil Spill
Contingency Plan. The plan developed by pipeline operators must be consistent with the national
and area oil spill contingency plans as required by OPA‐90. The area contingency plan is titled the
Northwest Area Contingency Plan (NWACP). The United States Coast Guard, 13th District, along
with the support of numerous multi‐state organizations, develops and administers the NWACP.
These organizations assist with developmental input to the plan, assistance with emergency spill
response, and incident reporting. The States of Washington, Oregon, and Idaho participate in the
NWACP as well as Native American Communities. All spill emergency response activities are
initiated by calling the National Response Center (NRC) in Washington, D.C., who in turn, notifies
the trustees of the NWACP.
WAC‐173‐182 has not been revised since 2006. There is a proposed rulemaking by the
Washington State Department of Ecology that would involve changes to the regulations that
govern hazardous liquids pipelines with the State. Per the Department of Ecology website, the
proposed rulemaking would, if enacted as published:
Update definitions to ensure clarity and consistency with existing federal regulations,
Clarify the Worst Case Discharge calculation for pipelines,
Create a new pipeline geographic information planning standard which will use available geo‐
referenced data to support preparedness planning and initial decision making during pipeline
oil spills,
Enhance the existing air monitoring requirements for pipelines to ensure safety of oil spill
responders and the general public,
Enhance the spills to ground requirements to ensure rapid, aggressive and well‐coordinated
responses to spills to ground which could impact ground water,
Update the pipeline planning standard storage requirements to ensure the equipment
required is appropriate for the environments pipelines may impact,
Expand the Best Achievable Protection (BAP) Review Cycle to facilities and pipelines, and
Other changes to clarify language and make any corrections needed.
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3.0 Significance Criteria
3.1 Aggregate Risk
Aggregate risk, or probable loss of life (PLL), is one risk measure used to evaluate projects.
Aggregate risk is the total anticipated frequency of a particular consequence, normally fatalities,
that could be anticipated over a given time period, for all project components being analyzed.
Aggregate risk is a type of risk integral; it is the summation of risk, as expressed by the product of
the anticipated consequences and their respective likelihood. The integral is summed over all of
the potential events that might occur for all of the project components, over the entire project
length. For example, if one were evaluating a ten mile pipeline system, which included a storage
tank and pump station, the aggregate risk would be the risk posed by all components – ten miles
of pipeline, pumps, station piping, storage tank, etc. There are no known codified bright line
thresholds26 for acceptable levels of PLL or aggregate risk. (This risk is presented in Section 6.0,
Qualitative Aggregate Risk Assessment of this Report.)
3.2 Individual Risk
Individual risk (IR) is most commonly defined as the frequency that an individual may be expected
to sustain a given level of harm from the realization of specific hazards, at a specific location,
within a specified time interval. Individual risk is typically measured as the probability of a fatality
per year. The risk level is typically determined for the maximally exposed individual; in other
words, it assumes that a person is present continuously – 24 hours per day, 365 days per year.
To our knowledge, the United States federal and Washington state governments have not
adopted individual risk thresholds; the acceptable level of risk is left to local decision makers and
project proponents. Figure 3.2‐1 presents the individual risk thresholds for a number of
jurisdictions, where such thresholds have been adopted.
26 A bright‐line rule (or bright‐line test) is a clearly defined rule or standard, composed of objective factors,
which leaves little or no room for varying interpretation. The purpose of a bright‐line rule is to produce
predictable and consistent results in its application. The term "bright‐line" in this sense generally occurs in
a legal context. Bright‐line rules are usually standards established by courts in legal precedent or by
legislatures in statutory provisions.
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Figure – 3.2-1 Individual Risk Criteria by Jurisdiction27
The upper end of the green areas represent the de minimus28 risk values for each jurisdiction; IR
risk levels within the green range are considered broadly acceptable. Risks within this green
region are considered so low that no further consideration is warranted. In addition, risks within
the green band are generally considered so low that it is unlikely that any risk reduction would be
cost effective, since extraordinary measures would normally be required to further reduce the
risk. As a result, a benefit – cost analysis of risk reduction is typically not undertaken.
27 Sources: (CDE 2007, SBCO 2008, API 752, Marszal 2001, Hong Kong
28 Latin term for "of minimum importance" or "trifling." Essentially it refers to something or a difference
that is so little, small, minuscule, or tiny that the law does not refer to it and will not consider it. In a million
dollar deal, a $10 mistake is de minimus.
Individual Risk Criteria by Jurisdiction
1.E-10
1.E-09
1.E-08
1.E-07
1.E-06
1.E-05
1.E-04
1.E-03
1.E-02
Calif Dept ofEducationSanta BarbaraCountyAPI 752WesternAustraliaHong KongUnited KingdomTheNetherlands(2010 Pending)Czech RepublicIR of Annual Fatality
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The lower end of the red areas represent the de manifestus29 risk values; IR risk levels within the
red range are considered unacceptable and the risks are not normally justified on any grounds.
For example, the California Department of Education and Santa Barbara County use 1.0 x 10‐6 as
their bright line threshold; this is equivalent to a one in one million (1 : 1,000,000) likelihood that
an individual at a specific location, would be fatally injured over a one year period30.
Some jurisdictions have adopted a “grey area”, where the risk levels may be negotiated or
otherwise considered. The United Kingdom developed the ALARP (as low as reasonably
practicable) approach. This approach is depicted by the yellow areas in Figure 3.2‐1. Generally,
risks within the yellow area may be tolerable only if risk reduction is impractical or if its cost is
grossly disproportionate to the risk improvement gained. The underlying concept is to maximize
the expected utility of an investment, but not expose anyone to an excessive increase in risk.
The United States government has opposed setting tolerable risk guidelines. The 1997 final report
of the Presidential/Congressional Commission on Risk Assessment and Risk Management
(Commission), entitled Framework for Environmental Health Risk Management, included the
following finding, “There is much controversy about bright lines, “cut points,” or decision criteria
used in setting and evaluating compliance with standards, tolerances, cleanup levels, or other
regulatory actions. Risk managers sometimes rely on clearly demarcated bright lines, defining
boundaries between unacceptable and negligible upper limits on cancer risk, to guide their
decisions. Congress has occasionally sought to include specified bright lines in legislation. A strict
“bright line” approach to decision making is vulnerable to misapplications since it cannot explicitly
reflect uncertainty about risks, population within, variation in susceptibility, community
preferences and values, or economic considerations – all of which are legitimate components of
any credible risk management process.” The report states further, “Furthermore, use of risk
estimates with bright lines, such as one‐in‐a‐million, and single point estimates in general, provide
a misleading implication of knowledge and certainty. As a result, reliance on command‐and‐
control regulatory programs and use of strict bright lines in risk estimates to distinguish between
safe and unsafe are inconsistent with the Commission’s Risk Management Framework and with
the inclusion of cost, stakeholder values, and other considerations in decision‐making.”
(Commission 1997)
The United States is not alone in its opposition to establishing fixed risk thresholds. The vast
majority of nations do not have government established risk tolerance criteria. In these cases,
risk tolerance is left to individual owners and other decision makers.
Despite the fact that the United States does not have a bright line individual risk threshold, the
country has an exemplary safety record. Many believe that this is due to two factors. First, the
free market allows the application of capital where it will produce the most risk reduction
29 ALARP (as low as reasonably practical) principle states that there is a level of risk that is intolerable,
sometimes called the de manifestus risk level. Above this level risks cannot be justified.
30 For reference, National Geographic Magazine estimates that the odds of becoming a victim of a lightning
strike in the United States is 1 in 700,000 (1 :700,000).
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benefits. And secondly, the tort system provides a mechanism to determine third party liability
costs in the event of an injury or fatality. These factors generally result in sound risk reduction
decisions which are normally based on a cost‐benefit analysis. (Marszal 2001)
3.3 Societal Risk
Societal risk is the probability that a specified number of people will be affected by a given event.
The accepted number of casualties is relatively high for lower probability events and much lower
for more probable events. As shown in Figure 3.3‐1, the acceptable values for societal risk vary
greatly by different agencies and jurisdictions. We are not aware of any prescribed societal risk
guidelines for the United States, nor the State of Washington. (See also Section 3.2.)
The California Department of Education and The County of Santa Barbara, California have upper
and lower bounds for unacceptable and acceptable societal risk levels respectively. The upper
bound is represented by the red line in the following figure; risks above this line are deemed
intolerable. The lower bound is represented by the green line in the following figure; risks below
this line are deemed acceptable. Between these two bounds is a “gray area” similar to that
discussed above for individual risks.
Using the Netherlands, as one possible criteria, for a given number of fatalities, if the likelihood is
greater than the value represented by the blue line (e.g., above the line), then the societal risk is
deemed unacceptable; if the likelihood is less than the value represented by the line (e.g., below
the line) then the societal risk that falls below the line is acceptable. For example, for one
hundred (100) fatalities, as shown on the “x” axis, the bright line threshold for the Netherlands
(blue line) is 1.00E‐07 (or 1.0 x 10‐7, or 1 : 10,000,000), as shown on the “y” axis. In other words, if
the likelihood of one hundred (100) fatalities is less than one in ten million (1 : 10,000,000), the
risk is deemed acceptable; if not, it is unacceptable.
It should be noted that societal risk does not assume that individuals would be exposed one
hundred percent (100%) of the time, as with individual risk. For societal risk, the time that
individuals would be exposed to the potential risk is considered in the analysis.
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Figure 3.3-1 – Various Societal Risk Criteria31
31 Sources – CDE 2005 and 2007, API 752, SBCO 2008, Marzal 2001, Hong Kong
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4.0 Potential Hazards
The proposed project could pose additional risks to the public. For example, if the proposed
project were to impact either, or both, of the OPL pipelines, refined petroleum product could be
released from a leak or rupture. If the fluid reached a combustible mixture and an ignition source
were present, a fire and/or explosion could occur, resulting in possible injuries and/or deaths.
An unintentional release could also present an environmental hazard. As noted earlier, soil could
be impacted, waterways could be degraded, and wildlife and vegetation could be jeopardized.
This Report presents the life safety risks posed to the public; an analysis of potential
environmental impacts is beyond the scope of this Report.
As will be presented later in this Report, only a small percentage of refined petroleum product
releases are ignited, resulting in fire and/or explosion.
4.1 Fire Hazards to Humans
The physiological effect of fire to humans depends on the rate at which heat is transferred from
the fire to the person, and the amount of time the person is exposed to the fire. Skin that is in
contact with flames can be seriously injured, even if the duration of the exposure is just a few
seconds. Thus, a person wearing normal clothing is likely to receive serious burns to unprotected
areas of the skin when directly exposed to the flames from a flash fire (vapor cloud fire).
Humans in the vicinity of a fire, but not in contact with the flames, would receive heat from the
fire in the form of thermal radiation. Radiant heat flux decreases with increasing distance from a
fire. Therefore, those close to the fire would receive thermal radiation at a higher rate than those
farther away. The ability of a fire to cause skin burns due to radiant heating depends on the
radiant heat flux to which the skin is exposed and the duration of the exposure. As a result, short‐
term exposure to high radiant heat flux levels can be injurious. However, if an individual is far
enough from the fire, the radiant heat flux would be lower, likely incapable of causing injury,
regardless of the duration of the exposure.
An incident heat flux level of 1,600 Btu/ft2‐hr is generally considered hazardous for people located
outdoors and unprotected. Generally, humans located beyond this heat flux level would not be at
risk to injury from thermal radiation resulting from a fire. The radiant heat flux effects to humans
are summarized below. The first three endpoints have been used to evaluate the risk of public
fatalities.
12,000 Btu/ft2‐hr (37.7 kW/m2) – 100% mortality after 30 second exposure (CDE 2007).
8,000 Btu/ft2–hr (25.1 kW/m2) – 50% mortality after 30 second exposure (CDE 2007).
5,000 Btu/ft2‐hr (15.7 kW/m2) – 1% mortality after 30 second exposure (CDE 2007). In many
instances, an able bodied person would increase the separation distance or seek cover during
this 30 second period.
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3,500 Btu/ft2‐hr (11.0 kW/m2) ‐ Second degree skin burns after ten seconds of exposure, 15%
probability of fatality (Quest 2003). This assumes that an individual is unprotected or unable
to find shelter soon enough to avoid excessive exposure (Quest 2003). Other data sources
provide a 10% mortality at 5,500 Btu/hour‐square foot and 15% mortality at 5,800 Btu/hour‐
square foot (CDE 2007).
1,600 Btu/ft2‐hr (5.0 kW/m2) ‐ Second degree skin burns after thirty seconds of exposure.
440 Btu/ft2‐hr (1.4 kW/m2) ‐ Prolonged skin exposure causes no detrimental effect (CDE 2007,
Quest 2003).
4.2 Explosion Hazards to Humans
Refined petroleum product vapors do not explode unless they are in a confined space within a
specific range of mixtures with air and are ignited. However, if an explosion does occur, the
physiological effects of overpressures depend on the peak overpressure that reaches a person.
Exposure to overpressure levels can be fatal. People located outside the flammable cloud when a
combustible mixture ignites would be exposed to lower overpressure levels than those inside the
flammable cloud. If a person were far enough from the source of overpressure, the explosion
overpressure level would be incapable of causing injuries. The generally accepted hazard level for
those inside buildings is an explosion overpressure is 1.0 psig. This level of overpressure can
result in injuries to humans inside buildings, primarily from flying debris. The consequences of
various levels of overpressure are outlined in the table below.
Table 4.2-1 Explosion Over-Pressure Damage Thresholds32
Side-On Over-Pressure Damage Description
0.02 psig Annoying Noise
0.03 psig Occasional Breaking of Large Window Panes Under Strain
0.04 psig Loud Noise; Sonic Boom Glass Failure
0.10 psig Breakage of Small Windows Under Strain
0.20 psig Glass Breakage - No Injury to Building Occupants
0.30 psig Some Damage to House Ceilings, 10% Window Glass Broken
0.50 to 1.00 psig Large and Small Windows Usually Shattered, Occasional Damage to Window
Frames
0.70 psig Minor Damage to House Structures, Injury, but Very Unlikely to Be Serious
1.00 psig
1% Probability of a Serious Injury or Fatality for Occupants in a Reinforced
Concrete or Reinforced Masonry Building from Flying Glass and Debris
10% Probability of a Serious Injury or Fatality for Occupants in a Simple Frame,
Unreinforced Building
2.30 psig 0% Mortality to Persons Inside Buildings or Persons Outdoors (CDE 2007)
3.10 psig 10% Mortality to Persons Inside Buildings (CDE 2007)
3.20 psig <10% Mortality to Persons Outdoors (CDE 2007)
14.5 psig 1% Mortality to Those Persons Outdoors (LEES)
32 Sources: LEES, CDE 2007, Quest 2003
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5.0 Baseline Data
In the following paragraphs, the anticipated frequency of unintentional releases and impacts to
humans will be estimated using data from the following sources:
United States Hazardous Liquid Pipelines (USDOT)
United States Refined Petroleum Project Pipelines (USDOT)
5.1 U.S. Hazardous Liquid Pipeline Releases, January 2010 through December
2015
49 CFR 195.50 requires that the following incidents be reported:
“An accident report is required for each failure in a pipeline system subject to this part in
which there is a release of the hazardous liquid or carbon dioxide transported resulting in
any of the following:
(a) Explosion or fire not intentionally set by the operator.
(b) Release of 5 gallons (19 liters) or more of hazardous liquid or carbon dioxide, except
that no report is required for a release of less than 5 barrels (0.8 cubic meters) resulting
from a pipeline maintenance activity if the release is:
(1) Not otherwise reportable under this section;
(2) Not one described in § 195.52(a)(4);
(3) Confined to company property or pipeline right‐of‐way; and
(4) Cleaned up promptly;
(c) Death of any person;
(d) Personal injury necessitating hospitalization;
(e) Estimated property damage, including cost of clean‐up and recovery, value of lost
product, and damage to the property of the operator or others, or both, exceeding
$50,000.”
In August 2016, the raw incident data file for hazardous liquid pipeline releases occurring since
January 1, 2010 was downloaded. Releases33 which have occurred since December 31, 2015 were
then deleted, since the data set is incomplete for the 2016 calendar year. This left 2,362 reported
33 As used herein, the terms release, spill, or leak are used interchangeably. They all refer to unintentional
releases from the pipeline.
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releases which occurred during the six year period between January 1, 2010 and December 31,
201534. These incidents are summarized in the following table.
Table 5.1-1 – Reported U.S. Hazardous Liquid Pipeline Releases and Fatalities,
January 2010 through December 2015
Calendar
Year
Total Hazardous
Liquid Pipeline
Mileage
Number of Reported
Incidents Total Fatalities35 General Public
Fatalities
2015 200,00036 454 1 1
2014 199,627 445 0 0
2013 192,417 401 1 0
2012 186,211 366 3 2
2011 183,580 346 1 0
2010 181,986 350 1 1
Totals 1,143,831 2,362 7 4
Using the above data, the following incident rates have been developed:
Frequency of Reported Incidents – 2.0650 incidents per 1,000 mile years37
Frequency of Fatalities38 – 0.0061 fatalities per 1,000 mile years
Frequency of General Public Fatalities – 0.0035 fatalities per 1,000 mile years
Frequency of General Public Injuries – 0.0035 injuries per 1,000 mile years
It should be noted that during this reporting period, although there were seven (7) fatalities, only
four (4) were members of the general public. There were a total of four reported (4) general
public injuries.
34 When there is a new change in operator incident reporting requirements, the USDOT often begins a new
database to ensure that all data contained within a given database is consistent. The most recent database
began in January 2010. Since 2016 data is incomplete, incidents occurring in 2016 were deleted from the
analysis. The resulting data includes a complete six year history of over one million mile‐years of pipeline
operation.
35 The total number of fatalities includes fatalities of the pipeline operator’s personnel, the pipeline
operator’s contractor’s personnel, and the general public.
36 The total hazardous liquid pipeline mileage for 2015 is not yet available. This value has been assumed.
37 This unit provides a means of predicting the number of incidents for a given length of line, over a given
period of time. For example, if one considered an incident rate of 1.0 incidents per 1,000 miles years, one
would expect one incident per year on a 1,000 mile pipeline. Using this unit, frequencies of occurrence can
be calculated for any combination of pipeline length and time interval.
38 The total number of fatalities includes fatalities of the pipeline operator’s personnel, the pipeline
operator’s contractor’s personnel, and the general public.
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5.2 U.S. Refined Petroleum Product Releases, January 2010 through December
2015
Since the OPL pipelines only transport refined petroleum products, the U.S. Hazardous Liquid
Pipeline release data summarized above was filtered to include only refined petroleum product
pipelines releases. Releases from hazardous liquid pipelines which transport other commodities
(e.g., crude oil, highly volatile liquid, carbon dioxide, biofuel, etc.) were excluded. The results for
this data subset are summarized below:
Table 5.2-1 – Reported U.S. Refined Petroleum Product Releases and Fatalities,
January 2010 through December 2015
Calendar
Year
Total Refined
Petroleum Product
Pipeline Mileage
Number of Reported
Incidents Total Fatalities39 General Public
Fatalities
2015 61,00040 133 0 0
2014 61,763 157 0 0
2013 63,351 134 0 0
2012 64,042 133 0 0
2011 64,130 123 0 0
2010 64,800 125 0 0
Totals 379,086 805 0 0
Using the above data, the following incident rates have been developed:
Frequency of Reported Incidents – 2.1235 incidents per 1,000 mile years41
Frequency of Fatalities42 – 0.0000 fatalities per 1,000 mile years
Frequency of General Public Fatalities – 0.0000 fatalities per 1,000 mile years
Frequency of General Public Injuries – 0.0000 injuries per 1,000 mile years
It should be noted that during this reporting period, there were zero (0) fatalities. There were a
total of two (2) reported injuries, but neither of these were members of the general public; one
(1) was the pipeline operator’s employee and one (1) was the pipeline operator’s contractor’s
employee.
39 The total number of fatalities includes fatalities of the pipeline operator’s personnel, the pipeline
operator’s contractor’s personnel, and the general public.
40 The total hazardous liquid pipeline mileage for 2015 is not yet available. This value has been assumed.
41 This unit provides a means of predicting the number of incidents for a given length of line, over a given
period of time. For example, if one considered an incident rate of 1.0 incidents per 1,000 miles years, one
would expect one incident per year on a 1,000 mile pipeline. Using this unit, frequencies of occurrence can
be calculated for any combination of pipeline length and time interval.
42 The total number of fatalities includes fatalities of the pipeline operator’s personnel, the pipeline
operator’s contractor’s personnel, and the general public.
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The releases presented in Table 5.2‐1 fall into three categories, as identified on PHMSA Form F
7000‐1, Accident Report – Hazardous Liquid Pipeline Systems.
Contained on Pipeline Operator Property – 610 of the 805 (76%) releases occurred on pipeline
operator controlled property and were entirely contained within the property boundary.
These releases were identified as occurring at the following types of facilities: valve stations,
terminals, tank farms, junctions, pump stations, meter stations, etc. The “system part”
identified on the accident reports included: onshore pipeline, including valve sites (41
releases, 6%); onshore terminal or tank farm equipment and piping (242 releases, 40%);
onshore pump or meter station equipment and piping (237 releases, 39%); and onshore
breakout tank or storage vessel, including attached appurtenances (90 releases, 15%).
Extended Beyond Operator Property ‐ 38 of the 805 (5%) releases occurred on pipeline
operator controlled property, but the release migrated beyond the parcel boundary.
Pipeline Right‐of‐Way ‐ 157 of the 805 (19%) releases were identified as occurring along the
pipeline right‐of‐way. These included releases which occurred at valve sites.
The proposed collocated OPL pipeline and overhead HVAC line corridor does not include any of
the types of facilities identified on the accident reports as “pipeline operator controlled property”
(e.g., valve stations, terminals, tank farms, junctions, pump stations, meter stations, etc.).
Further, the releases that occurred on the pipeline operator’s controlled property which did not
extend beyond the operator controlled property boundary would not normally affect the public.
As a result, these 610 releases (first bullet above) were not included in the data set used to
evaluate the risks posed to the public from the OPL pipeline(s).
The average spill size from the remaining 195 releases (157 releases which occurred along the
pipeline right of way plus 38 releases which occurred on the pipeline operator controlled
property, but the release migrated beyond the parcel boundary) was 306 barrels (12,900 gallons).
The largest reported unintentional release was 9,000 barrels (378,000 gallons). These data are
presented in the Figure 5.2‐1.
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Figure 5.2-1 – Spill Size Distribution, 2010 thru 2015 U.S. Refined Petroleum Product Pipeline
Releases43
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
10,000
1 11 21 31 41 51 61 71 81 91 101 111 121 131 141 151 161 171 181 191Spill Size, barrelsNumber of Releases
2010 thru 2015 U.S. Refined Petroleum Pipeline
Spill Size Distribution
The resulting frequency of unintentional releases which affect property beyond that of the
pipeline operator was 0.5144 incidents per 1,000 mile years. The distribution of these incidents
by cause is shown in Table 5.2‐2 below.
43 This includes all releases which occurred along the pipeline right‐of way and all releases which occurred
on the pipeline operator controlled property, which migrated beyond the property boundary. Releases
which occurred on the pipeline operator controlled property and totally contained on the operator’s
property, have not been included.
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Table 5.2-2 – Reported U.S. Refined Petroleum Product Pipeline Releases by Cause,
January 2010 through December 2015
Cause
Number of
Reported
Incidents
Percentage
Frequency
(incidents per
1,000 mile years)
Average Spill Size
(Barrels44)
Equipment Failure45 48 24.6% 0.1266 246
Incorrect Operation46 15 7.7% 0.0396 704
External Corrosion 43 22.1% 0.1134 269
Outside Force/Excavation 38 19.5% 0.1002 473
Material Failure 33 16.9% 0.0871 194
Internal Corrosion 4 2.0% 0.0106 21
Natural Force47 8 4.1% 0.0211 154
Other 6 3.1% 0.0158 18
5.2.1 Spill Size Distribution, U.S. Refined Petroleum Product Pipelines, Normalized to 18-
inch Diameter Pipe
For large releases (e.g., pipe rupture), pipe diameter can have a direct impact on the volume that
may be released during a major incident. As a result, for larger releases (e.g., full bore ruptures),
using the spill size distribution presented in Figure 5.2‐1 above, for the relatively large diameter
OPL pipelines, would not be appropriate. For large releases, the volume and flow rate are
generally proportional to the pipe diameter squared. For example, the pipe volume and flow rate
for a 16‐inch diameter pipe is generally four times greater than for an 8‐inch diameter pipe [e.g.,
(16 / 8)2 = 4].
On the other hand, for a relatively slow corrosion caused release, one would expect a similar spill
volume regardless of pipe diameter, since the release volume would generally depend on the size
of the pipe defect, not the pipe diameter. For example, for a ¼‐inch diameter hole in the pipe
wall, the release volume from a 6‐inch diameter pipe would be similar to that from a 20‐inch
diameter line, assuming similar operating pressures.
Figure 5.2.1‐1 and Table 5.2.1‐1 present a “normalized” spill size distribution; for releases that
were identified on the incident report as “ruptures” (12 incidents), the unintentional release
44 Barrels is a measure of volume equal to 42 U.S. gallons.
45 Includes items such as: defective or loose tubing, malfunction of control or relief equipment, non‐
threaded equipment failure, pump, threaded connection, or coupling failure.
46 Includes items such as: incorrectly installed equipment, over‐pressure, overfill tank or vessel, valve left in
wrong position, wrong equipment installed, etc.
47 Includes items such as: earth movement, floods, lightning, temperature, etc.
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volumes presented in Figure 5.2‐1 have been multiplied by (18.048 / Pipe Diameter)2. For ruptures
of pipes larger than 18‐inches in diameter, the spill volume was reduced. For releases from lines
smaller than 18‐inches, the spill volume was increased. For all other releases (e.g., mechanical
puncture, leak, or other), no changes to the reported spill volume have been made.
Figure 5.2.1-1 – Spill Size Distribution, U.S. Refined Petroleum Product Pipeline Releases, Normalized
to 18-inch Diameter Pipe, January 2010 through December 201549
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
1 11 21 31 41 51 61 71 81 91 101 111 121 131 141 151 161 171 181 191Spill Size, barrelsNumber of Releases
2010 thru 2015 U.S. Refined Petroleum Pipeline
Spill Size Distribution
Normalized to 18‐inch Pipe
The normalized average spill size from these releases was 484 barrels (20,300 gallons). The
largest normalized reported unintentional release was 12,000 barrels (504,000 gallons). As noted,
48 One of the OPL pipelines under study is 16‐inches in outside diameter, the other is 20‐inches in outside
diameter. An average 18‐inch diameter has been used for both lines in this study.
49 For this Report, we have used an average pipe diameter of 18‐inches for both the OPL 16‐inch and 20‐
inch diameter pipelines. This includes all releases which occurred along the pipeline right‐of way and all
releases which occurred on the pipeline operator controlled property, which migrated beyond the property
boundary. Releases which occurred on the pipeline operator controlled property and totally contained on
the operator’s property, have not been included.
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the majority of these releases were relatively small, with a small portion having rather significant
spill volumes.
These data are also summarized in tabular form in Table 5.2.1‐1. These data will be used later in
the individual and societal risk assessments.
Table 5.2.1-1– Spill Size Distribution, U.S. Refined Petroleum Product Pipeline Releases, Normalized to 18-inch
Diameter Pipe, January 2010 through December 201550
Spill Size Range
Barrels
Average Spill Size Distribution
1 Barrel or Less 0.5 Barrels 27 Percent
2 to 9 Barrels 4.3 Barrels 21 Percent
10 to 99 Barrels 36 Barrels 22 Percent
100 to 999 Barrels 416 Barrels 21 Percent
1,000 to 5,000 Barrels 2,603 Barrels 6 Percent
6,000 to 12,000 Barrels 8,861 Barrels 3 Percent
5.2.2 Olympic Pipeline Leak History
The PHMSA incident data file for hazardous liquid pipeline releases was reviewed to identify the
frequency of releases from OPL’s two pipelines that share the HVAC overhead power line
corridor. Between January 1, 2010 and December 31, 2015, there were five (5) reported releases
on the OPL system. These releases varied in size from 0.2 to 7.5 barrels. All of the releases
occurred at valve stations and the releases were entirely contained within OPL property; there
were no reported releases along the pipeline right‐of‐way.
Three (3) of the releases occurred on the 20‐inch diameter Allen to Renton pipe segment, at Allen
Station, near Mount Vernon. One (1) release occurred at Renton Station on the Renton to Seattle
pipe segment. One (1) release occurred at Ferndale on the Ferndale to Allen segment. There
were no reported injuries, fires, or explosions. These releases are summarized in the table below.
50 This includes all releases which occurred along the pipeline right‐of way and all releases which occurred
on the pipeline operator controlled property, which migrated beyond the property boundary. Releases
which occurred on the pipeline operator controlled property and totally contained on the operator’s
property, have not been included.
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Table 5.2.2-1– OPL Reported Releases, January 1010 through December 2015
Date
Release
Volume
(barrels)
Location Item Involved
9/19/2011 0.29 MP 7 Block Valve Instrumentation Connection Failure
3/31/2012 1.96 Allen Station Threaded Connection/Coupling Failure
4/1/2012 0.97 Allen Station Instrumentation (Pressure Gauge) on Pig Launcher
7/20/2014 0.19 Renton Station
Scraper Trap O‐Ring Connection Failure on Pig Trap
Door
11/10/2014 7.49 Allen Station Threaded Connection Failure
Assuming a four hundred (400) mile OPL pipeline system, the resulting frequency of unintentional
release was 2.0833 incidents per 1,000 mile years over this six (6) year period; this is essentially
the same frequency of unintentional release (2.1235 incidents per 1,000 miles years) for the
roughly 60,000 miles of U.S. refined petroleum product pipelines over this same period. The
average spill size was 2.2 barrels, significantly less than the national overage of 94.5 barrels. It
should also be noted that all of the released refined petroleum product was entirely contained on
OPL controlled property; there were no reported releases during this period that occurred along
the pipeline right‐of‐way or were not entirely contained on OPL controlled property.
5.3 Population Density
Societal risk is dependent on the number of exposed individuals. In the societal risk analysis
presented later in this Report, population densities were used to determine the number of
exposed individuals. These data were obtained by analyzing census data; the following data were
provided by Environmental Science Associates for the HVAC overhead power line corridor which
would be shared with the OPL pipeline(s).
Minimum Population Density – 568 persons per square mile
Average Population Density ‐ 3,228 persons per square mile
Maximum Population Density ‐ 23,169 persons per square mile
The societal risk analysis will present the likelihood of various release scenarios for each of these
population densities.
5.4 Potential Hazards of Collocated Overhead HVAC Lines and Hazardous Liquid
Pipelines
Previously, in Section 1.1.5, the existing OPL procedures that address the OPL identified hazards
posed by the collocation of overhead HVAC transmission lines and hazardous liquid pipelines,
were presented. In this section, these, and other risks which will be used in the analysis will be
discussed.
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When overhead HVAC lines are collocated with a hazardous liquid pipeline(s), the following
potential hazards can be presented.
Fault Conditions – When a ground fault occurs on a HVAC transmission line, it can cause high
electrical current to travel through the soil and onto a pipeline. Under fault conditions,
elevated potentials can lead to coating damage or direct arcing to the pipeline.51 These
situations can cause pipe external corrosion coating damage, damage to the pipe wall, and
through wall pipe failures.
Touch and Step Potential – Touch potential is the voltage a person may be exposed to when
contacting a pipe or electrically continuous appurtenance (e.g., cathodic protection test
station, access stile, valve, etc.); this can be a concern during both normal steady state
inductive and fault conductive/inductive conditions. High touch or step potentials can pose a
safety hazard to a person in contact with the pipeline, or pipeline appurtenance. The current
industry threshold is 15 volts. At touch potentials greater than this value, personnel may be
subject to safety risks posed by electrical shock.
Pipeline Integrity – During steady state operation, an overhead HVAC line can induce
interference that can contribute to accelerated external corrosion damage to a pipeline.
According to the A.C. Corrosion State of the Art: Corrosion Rate, Mechanism, and Mitigation
Requirements, published by the National Association of Corrosion Engineers (NACE),
“In 1986, a corrosion failure on a high‐pressure gas pipeline in Germany was attributed to AC
corrosion. This failure initiated field and laboratory investigations that indicated induced AC‐
enhanced corrosion can occur on coated steel pipelines, even when protection criteria are
met. In addition, the investigations ascertained that above a minimum AC density, typically
accepted levels of cathodic protection would not control AC‐enhanced corrosion. The
German AC corrosion investigators’ conclusions can be summarized as follows:
a. AC‐induced corrosion does not occur at AC densities less than 20 amp/meter2 (1.9
amps/foot2).
b. AC corrosion may or may not occur (is unpredictable) for AC densities between 20 to
100 amp/meter2 (1.9 to 9.3 amps/foot2).
c. AC corrosion occurs at current densities greater than 100 amp/meter2 (9.3
amps/foot2).”
Encroachment and Construction Hazards – The construction of facilities near an active
hazardous liquid pipeline can increase the risk that the line will be hit or damaged by the
construction activity. Increased pipe stresses due to surcharge loading can also be imposed by
equipment operating over, or near, the pipeline.
51 Det Norske Veritas, Criteria for Pipelines Co‐Existing with Electric Power Lines, October 2015. Prepared
for INGAA Foundation, Inc.
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5.5 Pipeline Incidents Caused By Close Proximity to Electrical Utilities
Unfortunately, national data, similar to that presented earlier from the PHMSA database is not
available to directly quantify the increased risk of unintentional release that may be posed by the
collocation of overhead HVAC lines and hazardous liquid pipeline(s). In order to estimate the
increased risk, the following data would be required:
Total length of collocated hazardous liquid pipelines and overhead HVAC lines.
Total number of unintentional releases, injuries, and fatalities, by cause, for all such collocated
facilities.
These data, combined with that presented in Section 5.2, would enable a comparison of pipelines
which are collocated with overhead HVAC lines and those which were not collocated.
In the absence of any such data, the PHMSA incident report database for the period from January
2010 through December 2015 has been reviewed. We attempted to identify all releases that may
have been caused by a pipeline’s close proximity to electrical utility facilities. Unfortunately, the
external corrosion caused releases do not include data to identify releases caused by A.C. interference
with cathodic protection systems; nor do the excavation damage caused releases identify construction
related specifically to overhead power line or other electrical utility construction. However, the
following observations are noteworthy; they help put the additional pipeline risk posed by ground
faults due to the collocation of overhead HVAC lines and hazardous liquid pipelines into perspective.
Of the 2,362 reported hazardous liquid pipeline incidents from January 2010 through
December 2015. Fifteen (15, or 0.6 percent) were reported as being caused by an indication
of “stray current” on the incident report.
Based on the incident reports, it does not appear that any of the seven (7) fatalities were a
result of collocated pipelines and overhead HVAC lines.
Based on a review of the OPL incident reports, there do not appear to be any OPL releases
that were caused by the pipelines being collocated with the existing overhead HVAC lines.
There were six (6), or 0.25 percent of the 2,363 hazardous liquid pipeline incidents from
January 2010 through December 2015 that may have been caused due to their close proximity
to electrical utilities. These incidents were identified by reviewing all incidents caused by
“other outside force damage”, where “electrical arcing from other equipment or facility” was
marked on the PHMSA Form F 7000 Accident Report. (These six incidents are summarized in
the following subsections of this Report.)
5.5.1 Chevron Pipe Line Company June 11, 2010 Incident
According to the PHMSA Failure Investigation Report, “A large electrical charge was introduced to
a fence directly over Chevron’s pipeline. The charge jumped from a metal fence post to Chevron’s
pipeline causing an ~ 1” hole in the fence post and an ~1/2” hole near the 12:00 position on the
pipe. The leak occurred near a small creek that runs through a high density populated area. The
crude followed the creek to a pond where most of it was captured.”
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This event caused a reported 800 barrel (33,600 gallon) crude oil spill (778 barrels, or 32,700
gallons, were reported as recovered) and $32 million in clean‐up costs, repairs, remediation, lost
product, private property damage, emergency response, and settlements. The site was located
adjacent to a Rocky Mountain Power Electrical Transition Station (ETS), near Red Butte Creek,
near Salt Lake City, Utah. An ETS is where a high voltage above grade transmission line transitions
to below grade buried cable.
According to the PHMSA report, the bottom of the fence post was within three (3) inches of the
top of the pipeline. (There were no one‐call laws in place at the time of fence construction,
around 1980.) The cause of the “large electrical charge” was determined to be a ground fault that
sent a very large surge of electricity through the fence. (It was later discovered that the fence was
connected to the ETS station grounding grid.)
Figure 5.5.1-1 Photograph from PHMSA report showing hole in pipe wall caused by electrical fault.
5.5.2 Oneok NGL Pipeline August 8, 2011 Incident
The accident report filed by the pipeline operator reported the incident cause as, “A 34 kV
electrical wire came down off the utility pole struck the ground and the 106E pipeline cased
crossing vent pipe initiating a small grass fire. The downed powerline arced a hole in the 106E
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pipeline, casing for road crossing and vent stack on casing. The 14# natural gasoline product
releasing from the pipeline made its way to the surface and became ignited by the grass fire.”
Electrical arcing was noted on the incident report. This incident resulted in a 3.26 barrel (137
gallon) natural gas liquid spill. The total estimated damage from this incident was $411,000.
5.5.3 Crimson Pipeline September 8, 2013 Incident
The accident report filed by the pipeline operator reported the incident cause as, “the cause
appears to be third party damage related to a nearby power pole grounding rod.” Electrical
arcing was noted on the incident report. This incident resulted in a 100 barrel (420 gallon) crude
oil spill. The total estimated damage from this incident was $3.1 million.
5.5.4 Buckeye Partners LP March 14, 2014 Incident
The accident report filed by the pipeline operator reported the incident cause as, “A power line
was reported down to the Kankakee, Illinois fire department by a passing motorist on Route 113
in Kankakee, Illinois. The power line fell directly on top of where the Buckeye 162 pipeline crosses
Route 113… draft report of metallurgical analysis by same third party has stated the cause to be
local melting of the pipe walls. The energy source for the melting was a high current arc that
originated from a downed electrical power distribution line...” This incident resulted in a 25 barrel
(1,020 gallon) refined petroleum product (transmix) spill. 16.6 barrels (697 gallons) were
recovered. The total estimated damage from this incident was $2.0 million.
5.5.5 Marathon Pipeline (MPL) February 17, 2015 Incident
The accident report filed by the pipeline operator reported the incident cause as, “The leak was
caused by an electrical arc from a grounding rod in the electric company's grounding system to
MPL's jet fuel pipeline, resulting in an electrical arc burn breach to the pipe and release of jet
fuel.” This incident resulted in a 160 barrel (6,720 gallon) refined petroleum product spill. 112
barrels (4,700 gallons) were recovered. The total estimated damage from this incident was $2.5
million.
5.5.6 Kinder Morgan September 9, 2015 Incident
The accident report filed by the pipeline operator reported the incident cause as, “severe weather
caused a center point high voltage line cross member to fall, draping lines over a high voltage
12.47 kV three phase distribution line. The electrical energy from the lightning was transferred
through the poles steel guide wire and into the ground where it arced to the LCRC 12" pipeline.
This arc caused a small hole in the pipe that caused the leak.” 180 barrels (7,560 gallons) was
recovered. The total estimated damage from this incident was $80,000.
5.6 A.C. Interference Analysis, Proposed 115/230 kV Project (Willow 2)
Puget Sound Energy, the project proponent, retained Det Norske Veritas to perform an analysis of
potential A.C. interference with the existing OPL 16‐inch and 20‐inch pipelines. Their findings are
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presented in the final report, entitled, A.C. Interference Analysis – 230 kV Transmission Line
Collocated with Olympic Pipelines OPL16 and OPL 20, (A.C. Interference Study) dated December
13, 2016. The A.C. Interference Study utilized the Elsyca Inductive and Resistive Interference
Simulator (IRIS) software to predict the steady state electrical interference and resistive fault
effects of the proposed overhead HVAC transmission lines on the existing 16‐inch and 20‐inch
diameter OPL refined petroleum product pipelines.
In the evaluation of the proposed project and project alternatives, the study conservatively used
the winter peak electrical loads. The study evaluated both the proposed 115/230 kV circuit
voltage and the future 230/230kV circuit voltage.
5.6.1 Soil Resistivity
Det Norske Veritas collected soil resistivity measurements at 32 locations along the right‐of‐way.
The results are summarized below at a depth of 5‐feet.
Minimum Resistivity – 66 ohm‐meters
Average Resistivity – 1,005 (OPL 20‐inch) and 1,013 (OPL 16‐inch) ohm‐meters
Maximum Resistivity – 4,021 ohm‐meters
5.6.2 Model and Simulation Validation
The A.C. Interference Study included a comparison of modeled to actual A.C. interference for the
existing 115 kV transmission line (Willow 1). In general, the measured A.C. potentials were fairly
low – a maximum of 4.08 volts for the 16‐inch line and 5.63 volts for the 20‐inch line. (The
common industry threshold is 15 volts, which can pose a safety threat to personnel.)
It should be noted that these measurements were not taken at the winter peak electrical loads;
the operating parameters of the transmission line (e.g., phase conductor load and phase balance)
have a significant impact on the induced A.C. potentials. Other factors that affect the measured
values include: geometry of transmission lines, pipeline proximity, soil resistivity, external pipe
corrosion coating type and condition, depth of cover, pipe diameter, angle between the pipeline
and overhead HVAC transmission line, phase conductor spacing and distance above the ground,
etc.
These field measurements were compared to modeled results to validate the model. The
modeled results were in general conformance with the actual measured results, considering the
range in values for the various factors noted above. The actual field measurements and the
simulated results are presented graphically on the following figures for the 16‐inch and 20‐inch
OPL pipelines.
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Figure 5.6.2-1 OPL 16-inch Modeled versus Actual A.C. Potentials
Figure 5.6.2-2 OPL 20-inch Modeled versus Actual A.C. Potentials
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5.6.3 Predicted Results for Proposed 115/230 kV Project (Willow 2)
Structure (Pole) Type Sensitivity Study
A sensitivity study was performed to analyze various pole configurations. For the Willow 2 route,
the C2 structure was modeled along the corridor, except for a short segment, where low profile
structures are proposed. The location of where the low profile poles were analyzed is depicted in
Figure 5.6.3‐1. (It should be noted that the low profile poles would normally result in higher
levels of A.C. interference on the pipelines due to the low pole configuration; as a result, their
proposed use was limited.) The sensitivity study results are presented in Table 5.6.3‐1 below for
winter peak loading.
Table 5.6.3-1 Willow 2 Sensitivity Study Results, Winter Peak Loading
Structure Type Load Scenario
Maximum Induced A.C.
Potential52
(volts)
Maximum Theoretical A.C. Current
Density53
(amps per square meter)
OPL 16‐inch OPL 20‐inch54 OPL 16‐inch OPL 20‐inch
Low Profile 115/230 kV 10 ‐ 47 ‐
Low Profile 230/230 kV 11 ‐ 52 ‐
C2 115/230 kV 22 24 74 47
C2 230/230 kV 18 18 83 71
Optimized Structure (Pole) Configuration
Due to the complexities along the right‐of‐way, the same pole configuration cannot be used along
the entire corridor. The A.C. Interference Study analyzed an optimized configuration of
transmission structures along the corridor. This configuration is presented in Figure 5.6.3‐1.
52 The common industry threshold is 15 volts, which can pose a safety threat to personnel.
53 As noted previously, A.C. induced corrosion does not occur at AC densities less than 20 amp/meter2. A.C.
corrosion may or may not occur (is unpredictable) for AC densities between 20 to 100 amp/meter2. AC
corrosion occurs at current densities greater than 100 amp/meter2.
54 The OPL 20‐inch line is not located within the corridor where the low profile structures are proposed.
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Figure 5.6.3-1 Willow 2 Transmission Line Route Depicting Modeled Structures
(C1, C2, Low Profile, and C16)55
55 This Figure has been taken from A.C. Interference Analysis – 230 kV Transmission line Collocated with
Olympic Pipelines OLP16 and OPL20, dated December 13, 2016, prepared by Det Norske Veritas, Inc.
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Estimated Induced A.C. Voltage (Touch Potential)
The simulated induced A.C. voltage results for the OPL 16‐inch line are presented in the figure
which follows for the proposed 115/230 kV and potential future 230/230 kV installations. This
figure depicts the results for the optimized pole structure configurations, presented above. As
noted, at peak winter loads, the predicted induced A.C. voltage would slightly exceed the 15 volt
threshold for potential personal injury near the substation (node 100 to 110) for the proposed
115/230 kV installation.
Figure 5.6.3-2 Induced A.C. Voltage, OPL 16-inch, Willow 2 Transmission Line Route56
56 This Figure has been taken from A.C. Interference Analysis – 230 kV Transmission line Collocated with
Olympic Pipelines OLP16 and OPL20, dated December 13, 2016, prepared by Det Norske Veritas, Inc.
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The simulated induced A.C. voltage results for the OPL 20‐inch line are presented in the figure
which follows for the proposed 115/230 kV and potential future 230/230 kV installations. This
figure depicts the results for the optimized pole structure configurations. As noted, at peak
winter loads, the predicted induced A.C. voltage would slightly exceed the 15 volt threshold for
personal injury near the node 150; the touch voltage threshold would be exceeded for both the
proposed 115/230 kV and future 230/230 kV installations.
Figure 5.6.3-3 Induced A.C. Voltage, OPL 20-inch, Willow 2 Transmission Line Route57
57 This Figure has been taken from A.C. Interference Analysis – 230 kV Transmission line Collocated with
Olympic Pipelines OLP16 and OPL20, dated December 13, 2016, prepared by Det Norske Veritas, Inc.
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Estimated A.C. Current Density
The simulated A.C. current densities for the OPL 16‐inch line are presented in the figure which
follows for the proposed 115/230 kV and future 230/230 kV installations. This figure depicts the
results for the optimized pole structure configurations. As noted, at peak winter loads, the
predicted A.C. current for the proposed 115/230 kV installation exceeds the 20 amps per square
meter threshold near node 90. Both the proposed 115/230 kV and future 230/230 kV
installations exceed this threshold from about not 130 to node 140. (Between A.C. current
densities of 20 and 100 amps per square meter, A.C. corrosion may or may not occur; A.C.
corrosion does occur above 100 amps per square meter.)
Figure 5.6.3-4 Induced A.C. Voltage, OPL 16-inch, Willow 2 Transmission Line Route58
58 This Figure has been taken from A.C. Interference Analysis – 230 kV Transmission line Collocated with
Olympic Pipelines OLP16 and OPL20, dated December 13, 2016, prepared by Det Norske Veritas, Inc.
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The simulated A.C. current densities for the OPL 20‐inch line are presented in the figure which
follows for the proposed 115/230 kV and future 230/230 kV installations. This figure depicts the
results for the optimized pole structure configurations. As noted, at peak winter loads, the
predicted A.C. current density for the proposed 115/230 kV installation and the future 230/230 kV
installation exceed the 10 amps per square meter threshold near node 140. (Between A.C.
current densities of 20 and 100 amps per square meter, A.C. corrosion may or may not occur; A.C.
corrosion does occur above 100 amps per square meter.)
Figure 5.6.3-5 Induced A.C. Voltage, OPL 20-inch, Willow 2 Transmission Line Route59
Estimated Coating Stress Voltage – Structure (Pole) and Shield Wire Sensitivity
The A.C. Interference Analysis report noted that, “several sensitivity studies were performed with
regards to the fault analysis whereby the effects of fault currents, shield wire configurations, and
pole configurations were evaluated to determine the pipelines’ susceptibility to damage, resulting
from a fault incident. For each fault sensitivity study, a single line‐to‐ground fault was considered
at multiple locations south along the collocation. The resulting coating stress voltage (voltage
across the coating) on the pipeline was compared for the C1, C2, C3, and Low Profile pole
configurations, which showed for the same magnitude of fault current, the C2 and C3 pole
configurations resulted in the same coating stress voltages. Thus for the resistive fault simulation,
as the C2 and C3 poles were both single pole configurations, the coating stress voltage was the
59 This Figure has been taken from A.C. Interference Analysis – 230 kV Transmission line Collocated with
Olympic Pipelines OLP16 and OPL20, dated December 13, 2016, prepared by Det Norske Veritas, Inc.
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same in each case. Based upon these results, a separate fault sensitivity study was not performed
for the C16 structures, as the coating stress voltages were expected to be similar to the C2 and C3
structures. For the Low profile structures, as they are comprised of two poles, the resulting
coating stress voltage is different, considering the same fault current.
A fault current value of 25 kA was used in this study, which is based on the maximum transmission
system fault current that could be experienced in the portions of the corridor where the pipelines
are collocated. The scenarios that were analyzed to arrive at 25 kA include a bus fault at the
Sammamish, the proposed Richards Creek, and Talbot Hill substations. The Olympic Pipelines first
enter the PSE transmission corridor approximately 3 miles north of the Talbot Hill substation,
which was accounted for in the calculation of fault current present at that location. Using a fault
current of 25 kA the sensitivity studies were analyzed with no shield wire, an Alumoweld shield
wire, and an Optical Ground Wire (OPGW). The same four poles were considered for the C1, C2,
and C3 studies where the two closest poles north and south of the substation were faulted in the
analysis. For each case, the maximum coating stress voltage and maximum arcing distance were
calculated…”
As noted in the following table, when a shield wire is used, the coating stress voltages decrease
dramatically, as the primary function of the shield wire is to provide a low resistance path to carry
the majority of the fault current to ground. In the absence of a shield wire, the total fault current
returns to ground at a single location, possibly at one of the OPL pipelines.
Table 5.6.3-2 Coating Stress Voltages Resulting from 25 kA Fault Current
Fault
Scenario
Pole
Number
Structure (Pole)
Type
Coating Stress Voltage (volts)
No Shield Wire Alumoweld OPGW
FC1 16 C1 18,840 3,219 2,833
FC2 48 C1 55,170 7,902 5,970
FC3 179 C2/C3 44,850 6,297 3,447
FC4 46 C2/C3 20,010 2,826 1,517
FC5 100 Low Profile ‐ 2,595 1,637
FC6 106 Low Profile ‐ 1,931 2,097
FC7 108 Low Profile ‐ 2,560 2,428
Based on the type and thickness of the exterior corrosion coating on the OPL pipelines, the Report
estimated the coating breakdown voltage at 10,825 volts. As noted above, provided a shield wire
is used, the predicted coating stress voltage is less than the coating breakdown voltage. The
applicant has committed to using an OPGW shield wire.
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Estimated Arcing Distance – Structure (Pole) Type and Shield Wire Sensitivity
As noted previously, a phase to ground fault on a HVAC transmission line can result in large
currents in the soil. These faults are typically caused by lightning, phase insulator failure,
conductor failure, other failure which allows the conductor to touch the ground, or transformer
failure. These high currents can cause arc damage to the pipe, resulting in pipe wall damage or
through wall pipe containment failures.
The A.C. Interference Study analyzed potential faults and developed predicted maximum return
to ground currents and resulting arcing distances for a variety of pole configurations and shield
wires. The maximum soil resistivity values were used in the analysis, as they result in the
maximum arcing distance (worst case). As noted previously, the actual soil resistivity along the
corridor ranged from 66 to 4,021 ohm‐meters, with an average of 1,012 meters; a soil resistivity
of 4,021 ohm‐meters was used in the analysis with a fault current of 25 kV.
Table 5.6.3-3 Arc Distances
Structure (Pole) Type Shield Wire
Maximum Return
Current to Ground
(amps)
Maximum Arcing
Distance (feet)
C1 and C2/C3 None 25,000 42
C1 and C2/C3 Alumoweld 3,805 17
C1 and C2/C3 OPGW 2,207 13
Low Profile Alumoweld 1,109 10
Low Profile OPGW 602 7
As noted in the above table, the OPGW shield wire provides the lowest return current to ground
values and shortest arcing distances. The applicant has committed to the installation of an OPGW
shield wire.
The A.C. Interference Study also analyzed the arc distances using the actual range of soil
resistivity. Assuming a fault current of 25 kV and an OPGW shield wire, the resulting arc distances
ranged from 4 to 13‐feet. Due to the variation is soil resistivity and imprecision in pipe location,
the A.C. Interference Study recommended the following:
Distances between the pipeline and transmission line pole grounds should be field verified by
the transmission line and pipeline operators.
If the transmission line pole grounds are found to be within 13 feet of the pipeline, arc
shielding protection should be installed, consisting of a single zinc ribbon extending a
minimum of 25 feet past the transmission line pole grounds in both directions. The zinc
ribbon should be connected to the pipeline through a single direct‐current decoupler (DCD).
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5.7 A.C. Interference Analysis, Existing 115 kV Corridor
Puget Sound Energy retained Det Norske Veritas (U.S.A.), Inc. to perform an analysis of potential
A.C. Interference for the existing 115 kV corridor. The results of this analysis are presented in a
MS PowerPoint Slide Deck entitled, Puget Sound Energy A.C. Interference Analysis Existing
Corridor. (The soil resistivity data and model validation were presented earlier, in Sections 5.6.1
and 5.6.2 of this report.)
In the evaluation of the existing corridor, the study conservatively used the peak winter electrical
loads presented below.
Table 5.7-1 Loading Scenarios (Peak Winter Loads)
Loading Scenario
South North
Talbot Hill –
Lakeside #2
Talbot Hill –
Lakeside #1
Sammamish‐
Lakeside Creek #2
Sammamish –
Lakeside #1
115 kV
Actual
Winter 2013‐14
618 618 402 161
115 kV
Predicted
Winter 2027‐28
884 889 136 110
5.7.1 Estimated Induced A.C. Voltage (Touch Potential)
The simulated induced A.C. voltage results for the OPL 16‐inch and 20‐inch lines are presented in
the figures which follow for the existing corridor. As noted, at peak winter loads, the predicted
induced A.C. voltage would be less than the 15 volt threshold. As a result, a touch potential
hazard will not be posed to personnel.
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Figure 5.7.1-1 Induced A.C. Voltage, OPL 16-inch, Existing Corridor60
60 This Figure has been taken from Puget Sound Energy, A.C. Interference Analysis, Existing Corridor, dated
February 2, 2017, prepared by Det Norske Veritas, Inc.
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Figure 5.7.1-2 Induced A.C. Voltage, OPL 20-inch, Existing Corridor61
5.7.2 Estimated A.C. Current Density
The simulated A.C. current densities for the OPL 16‐inch line are presented in the figure which
follows for the existing 115 kV installation. As noted, at peak winter loads, the predicted A.C.
current density would exceed the 20 amps per square meter threshold near nodes 75 and 135.
The highest anticipated current density would be 35 amps per square meter. (Between A.C.
current densities of 20 and 100 amps per square meter, A.C. corrosion may or may not occur.
A.C. corrosion does occur above 100 amps per square meter; it does not occur below 20 amps per
square meter.)
61 This Figure has been taken from Puget Sound Energy, A.C. Interference Analysis, Existing Corridor, dated
February 2, 2017, prepared by Det Norske Veritas, Inc.
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Figure 5.7.2-1 Induced A.C. Voltage, OPL 16-inch, Existing Corridor62
The simulated A.C. current densities for the OPL 20‐inch line are presented in the figure which
follows for the existing 115 kV installation. As noted, at peak winter loads, the predicted A.C.
current density would slightly exceed the 20 amps per square meter threshold near nodes 100
and 145. The highest anticipated current density would be 25 amps per square meter. (Between
A.C. current densities of 20 and 100 amps per square meter, A.C. corrosion may or may not occur.
A.C. corrosion does occur above 100 amps per square meter; it does not occur below 20 amps per
square meter.)
62 This Figure has been taken from Puget Sound Energy, A.C. Interference Analysis, Existing Corridor, dated
February 2, 2017, prepared by Det Norske Veritas, Inc.
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Figure 5.7.2-2 Induced A.C. Voltage, OPL 20-inch, Existing Corridor63
5.7.3 Estimated Coating Stress Voltage
OPL did not provided data to the applicant regarding the estimated coating stress voltage for the
existing 115 kV corridor.
5.7.4 Estimated Arcing Distance
OPL did not provided data to the applicant regarding the estimated arcing distances the existing
115 kV corridor.
63 This Figure has been taken from Puget Sound Energy, A.C. Interference Analysis, Existing Corridor, dated
February 2, 2017, prepared by Det Norske Veritas, Inc.
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6.0 Qualitative Aggregate Risk Assessment
Unfortunately, the baseline data presented in the prior section does not include an inventory of
pipelines that are collocated with overhead HVAC line(s), nor do the incident data reports identify
incidents which occurred where the pipeline was collocated with overhead HVAC line(s). As a
result, using these baseline data, it is impossible to directly develop and quantify the difference in
risk which may exist between the subject collocated OPL pipeline segments and those that are not
collocated with HVAC overhead transmission line(s).
It is difficult to estimate the potential extent of human injury because there are so many variables
affecting the size of a fire or explosion that could result from an unintentional release of refined
petroleum product: rate of infiltration into the soil, rate of vapor cloud formation, size of the
vapor cloud within the combustible range (controlled by weather, including wind and
temperature, release rate, product spilled, etc.), concentration of vapors (varying with wind and
topographic conditions), degree of vapor cloud confinement, etc. (These conditions will be
evaluated later in the Report, when Individual and Societal Risks are presented.)
As noted in the Baseline Data presented previously, refined petroleum product pipeline releases
seldom cause personal injuries or death. In fact, there were no fatalities on the U.S. regulated
refined petroleum product pipeline systems from 2010 through 2015. However, such incidents
can and do occur (e.g., Bellingham, Washington incident of June 10, 1999 and San Bernardino
incident of May 25, 1989). In this section, the likelihood of fatalities will be estimated using these
historical baseline data presented in the preceding section. The results provide a means of
framing the risk posed by the OPL pipelines.
Using the U.S. hazardous liquid and refined petroleum product pipeline baseline data compiled in
the previous section, the anticipated frequencies of unintentional releases, fires and fatalities
from the existing OPL 16‐inch and 20‐inch diameter pipelines have been estimated. The
qualitative aggregate risk estimates are based on the following criteria:
24.8 total miles of 16‐inch and 20‐inch OPL Pipeline64
Baseline Incident Rate for Releases from Refined Petroleum Product Pipeline Systems –
0.5144 incidents per 1,000 mile years
Conditional Probability of Ignition – 2.5 percent
64 The length of pipeline that is collocated with the transmission line between Sammamish Substation and
Talbot Hill Substation is 68,122 linear feet for one pipeline (20‐inch diameter pipeline) and 62,906 linear
feet (16‐inch diameter pipeline).
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Table 6.0-1 Qualitative Aggregate Risk Assessment Results – 24.8 Miles of OPL Pipelines
Unintentional Release Resulting In
Anticipated
Frequency
Incidents per
1,000 mile
years
Anticipated Number
of Incidents per
Year65
Likelihood of Annual
Occurrence
Spill Volume Distribution, Normalized to 18‐inch Diameter
Reportable Release of Any Volume 0.5144 0.0128 1 in 78
Pipeline Release of 1 Barrel or Less 0.1389 0.0034 1 in 290
Pipeline Release of 2 to 9 Barrels 0.1080 0.0027 1 in 373
Pipeline Release of 10 to 99 Barrels 0.1132 0.0028 1 in 356
Pipeline Release of 100 to 999 Barrels 0.1080 0.0027 1 in 373
Pipeline Release of 1,000 to 5,000 Barrels 0.0309 0.0008 1 in 1,300
Pipeline Release of 6,000 to 12,000 Barrels 0.0154 0.0004 1 in 2,620
Fire and Fatality
Fire 0.0129 0.0003 1 in 3,135
General Public Fatality66 0.0035 0.0001 1 in 11,520
It should be noted that these historical data do not differentiate between various population
densities. For example, a release in an urban area is likely to cause more significant impacts to
humans than a release in a rural, undeveloped area. For the more sparsely populated areas of the
OPL pipeline, the fatality figures shown above likely overstate the risk to the public; while in the
more densely populated areas, they likely understate the risk, due to the more likely public
exposure resulting from the greater population density. In Sections 9.0 (Individual Risk
Assessment) and 10.0 (Societal Risk Assessment) of this Report, the actual environment will be
considered; these analyses will consider population density, pipe contents, pipe diameter, actual
operating conditions and the proximity to the public67.
65 Assumes 28.4 miles of collocated pipelines with the overhead high voltage alternating current (HVAC)
electrical transmission line between Sammamish Substation and Talbot Hill.
66 This value is based on the total number of fatalities that occurred on U.S. Regulated Hazardous Liquid
Pipelines from January 2010 through December 2015.
67 It should be noted that the Individual Risk assessment will not consider population density due to the
definition of Individual Risk.
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7.0 Release Modeling Results
In this section, various pipeline release scenarios are presented. The releases were modeled
using CANARY, by Quest, version 4.4 software. For vapor cloud explosion modeling, this software
uses the Baker‐Strehlow model to determine peak side‐on over‐pressures as a function of
distance from a release. The CANARY software also provides a means for evaluating pool fires.
Thousands of possible data combinations could be used to evaluate individual releases. However,
in order to make a reasonable determination of likely releases, the following assumptions and
data inputs were used.
Table 7.0-1 Release Modeling Input
Parameter Model Input
Pipe Diameter 18‐inches68
Normal Operating Pressure 650 psig69
Average Flow Rate 6,650 Barrels per Hour70 (BPH)
Pipe Contents Temperature 70 degrees F
Wind Speed 2 meters per second (4.5 miles per hour)
Stability Class
D ‐ Pasquill‐Gifford atmospheric stability is classified by the letters A through F.
Stability can be determined by three main factors: wind speed, solar insulation,
and general cloudiness. In general, the most unstable (turbulent) atmosphere is
characterized by stability class A. Stability A occurs during strong solar radiation
and moderate winds. This combination allows for rapid fluctuations in the air and
thus greater mixing of the released gas with time. Stability D is characterized by
fully overcast or partial cloud cover during daytime or nighttime, and covers all
wind speeds. The atmospheric turbulence is not as great during D conditions, so
the gas will not mix as quickly with the surrounding atmosphere. Stability F
generally occurs during the early morning hours before sunrise (no solar
radiation) and under low winds. This combination allows for an atmosphere
which appears calm or still and thus restricts the ability to actively mix with the
released gas. A stability classification of “D” is generally considered to represent
average conditions.
Relative Humidity 70%
Air and Surface Temperature 70 degrees F
Spill Surface Soil
68 One of the OPL pipelines is 16‐inches in diameter; the other is 20‐inches in diameter. An average 18‐inch
pipe diameter has been used to model both of these lines.
69 As presented in Section 1.1, the normal operating pressure of the 16‐inch OPL line is 500 to 800 psig; the
normal operating pressure of the 20‐inch OPL line is 300 to 500 psig.
70 As presented in Section 1.1, the normal flow rate of the 16‐inch OPL line is 5,400 BPH; the normal flow
rate of the 20‐inch OPS line is 7,900 BPH.
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Parameter Model Input
Fuel Reactivity
Medium ‐ Most hydrocarbons have medium reactivity, as defined by the Baker‐
Strehlow method. Low reactivity fluids include methane, natural gas (98+%
methane), and carbon monoxide. High reactivity fluids include hydrogen,
acetylene, ethylene oxide, and propylene oxide.
Obstacle Density
Low
This parameter describes the general level of obstruction in the area including
and surrounding the confined (or semi‐confined) volume. Low density occurs in
open areas or in areas containing widely spaced obstacles. High density occurs in
areas of many obstacles, such as tightly‐packed process areas or multi‐layered
pipe racks.
Low obstacle density is appropriate due to the low building density and open
space within the pipeline corridor. Normally, the vapor cloud would be located
at ground level, near the release; these surroundings are relatively open along
the entire pipeline alignment (low obstacle density).
Flame Expansion
3 D ‐ This parameter defines the number of dimensions available for flame
expansion. Open areas are 3‐D, and produce the smallest levels of overpressure.
2.5‐D expansions are used to describe areas that quickly transition from 2‐D to 3‐
D. Examples include compressor sheds and the volume under elevated fan‐type
heat exchangers. 2‐D expansions occur within areas bounded on top and bottom,
such as pipe racks, offshore platforms, and some process units. 1‐D expansion
may occur within long confined volumes such as hallways or drainage pipes, and
produce the highest overpressures.
Reflection Factor
2 ‐ This factor is used to include the effects of ground reflection when an
explosion is located near grade. A value of 2 is recommended for ground level
explosions.
7.1 Pool Fires
For a buried refined petroleum product pipeline, the greatest risk to the public is posed by pool
fires. When a release occurs, the pipe contents are released into the soil. Depending on the
release rate, soil conditions, ground water level, and other factors, the released material may
come to the surface. Depending on local terrain, it may flow for some distance away from the
location of the release. If an ignition source is present, the accumulated pool could catch fire,
creating a public safety risk.
For this corridor, the majority of the alignment is within relatively open area, with a soil surface.
The CANARY software contains an algorithm that predicts the size of the pool for a given spill
volume. This model is a shallow inverted cone. The cone is filled as the fluid flows into the pool,
and mass is lost as it evaporates, seeps into the soil, etc. The pool fire model assumes that the
depth of fluid is sufficient to sustain burning long enough to establish a flame and result in the
impacts being modeled. Naturally, there are literally thousands of possible scenarios based on
the actual local site conditions. In this study, we have used the CANARY software algorithm to
predict the pool size. The resulting pool fire impacts are presented in Tables 7.1‐1, 7.1‐2 and 7.1‐
3 below. These data are presented separately for gasoline, jet fuel and diesel fuel.
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The following radiant heat flux mortality endpoints were used in the individual and societal risk
analyses:
12,000 Btu/ft2‐hr (37.7 kW/m2) – 100% mortality after 30 second exposure.
8,000 Btu/ft2‐hr (25.1 kW/m2) – 50% mortality after 30 second exposure.
5,000 Btu/ft2‐hr (15.7 kW/m2) – 1% mortality after 30 second exposure.
Table 7.1-1 Pool Fire Impacts - Gasoline
Release
Volume
(barrels)
Distance from Center of Pool Fire (feet)
Pool
Diameter
(feet)
12,000 Btu/ ft2‐hr 8,000 Btu/ ft2‐hr 5,000 Btu/ ft2‐hr
Downwind Crosswind Downwind Crosswind Downwind Crosswind
0.5 4.4 1.4 6.2 2.0 8.5 3.0 2
4.3 12.2 5.6 16.4 8.2 21.6 12.2 6
36 24.3 15.1 31.1 21.0 40.2 29.4 16
416 38.5 29.2 45.8 36.3 58.0 48.0 37
2,603 61.9 50.0 69.9 57.7 86.2 73.3 81
8,861 83.4 70.4 91.5 77.7 112.7 98.0 124
Table 7.1-2 Pool Fire Impacts – Jet Fuel
Release
Volume
(barrels)
Distance from Center of Pool Fire (feet)
Pool
Diameter
(feet)
12,000 Btu/ ft2‐hr 8,000 Btu/ ft2‐hr 5,000 Btu/ ft2‐hr
Downwind Crosswind Downwind Crosswind Downwind Crosswind
0.5 4.0 1.4 5.5 1.9 7.5 2.9 2
4.3 9.9 4.8 13.3 6.9 17.8 10.4 6
36 20.0 12.6 25.8 17.6 33.2 24.6 16
416 34.5 25.1 40.1 31.0 48.0 39.4 37
2,603 57.2 45.4 61.4 49.6 69.8 58.1 81
8,861 79.0 72.0 82.9 70.0 91.5 78.2 124
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Table 7.1-3 Pool Fire Impacts – Diesel Fuel
Release
Volume
(barrels)
Distance from Center of Pool Fire (feet)
Pool
Diameter
(feet)
12,000 Btu/ ft2‐hr 8,000 Btu/ ft2‐hr 5,000 Btu/ ft2‐hr
Downwind Crosswind Downwind Crosswind Downwind Crosswind
0.5 3.4 1.2 4.7 1.8 6.4 2.7 2
4.3 8.1 4.0 10.8 5.8 14.6 8.8 6
36 16.6 10.4 20.3 14.0 25.2 18.9 16
416 29.9 21.4 33.4 25.0 38.6 30.4 37
2,603 53.0 45.0 55.3 29.2 60.0 47.9 81
8,861 N/A
71 N/A 80 73 86.0 73.5 124
Figure 7.1‐1 presents an aerial depiction of a typical pool fire and the resulting isopleths. The
inner, yellow circle is the pool of fluid. The orange oval outer perimeter represents the outer
boundary of the 12,000 Btu/ ft2‐hr isopleth. The blue oval outer perimeter represents the outer
boundary of the 8,000 Btu/ ft2‐hr isopleth. And the green oval outer perimeter represents the
boundary of the 5,000 Btu/ ft2‐hr.
For the societal risk analysis (Section 10.0), the combined yellow and orange shaded areas
represent the area subjected to the 12,000 Btu/ ft2‐hr heat flux. The blue shaded area depicts the
area subjected to the 8,000 Btu/ ft2‐hr heat flux. And the green shaded area comprises the area
subjected to the 5,000 Btu/ ft2‐hr heat flux.
71 This diesel fuel pool fire does not produce a 12,000 Btu/ ft2‐hr isopleth. The flame drag allows it to
radiate downward in the area just downwind of the pool. The smoke from a diesel fire is also heavier, and
the fire is very smoky; as a result, the average surface heat flux is smaller, resulting in a “cooler” fire and
this heat flux level is not reached.
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Figure 7.1-1 Typical Pool Fire Radiant Heat Flux
7.2 Explosions
The potential impacts to humans as a result of explosions was presented earlier in Section 4.2 of
this Report. Gasoline, jet fuel, and diesel fuel generally do not explode, unless the vapor cloud is
confined in some manner. In this case, the pipeline is located in relatively open areas.
The potential releases from each of the refined petroleum products was modeled using CANARY
software. The resulting peak overpressure level was 0.38 psi, due to the relatively open
environment (medium fuel reactivity and low obstacle density). This overpressure level is not
high enough to pose potentially fatal risks to the public. However, it could cause glass breakage.
For reference, the explosion modeling endpoints often used are presented in the following table.
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Table 7.2-1– Explosion Modeling Endpoints (CDE 2007)
Mortality Rate Outdoor Exposure (psi) Indoor Exposure72 (psi)
99% Mortality 72 13
50% Mortality 13 5.7
1% Mortality 2.4 2.4
As noted in the California Department of Education, Guidance Protocol for School Site Pipeline
Risk Assessment, “Under uncommon circumstances a vapor cloud explosion (VCE) could occur
when a flammable vapor cloud ignites. These events are unlikely, based on historical experience,
with the petroleum liquids covered here (LEES 1996). Impacts for VCEs are expressed in terms of
a shock wave, overpressure (pounds per square inch or psi) above atmospheric pressure. Because
the density of crude oil and petroleum product vapors is greater than air, the ALOHA VCE module
for evaporating pools (puddles) was used to examine various pool sizes of the gasoline surrogate,
n‐hexane, for VCE explosion impacts. For an uncongested setting, an overpressure of 1.45 psi (1%
mortality) was not encountered for pool sizes between 0 and 600 feet for the conditions
modeled.” (CDE 2007)
It should also be noted that between January 2010 and December 2015 there were no reported
explosions in the PHMSA incident database for refined petroleum product pipelines.
7.3 Flash Fires
Flash fires can occur when a vapor cloud is formed, with some portion of the vapor cloud within
the combustible range, and the ignition is delayed. In a flash fire, the portion of the vapor cloud
within the combustible range burns very quickly, reducing the potential impact to humans. For
gasoline, diesel fuel, and jet fuel, the potential for extensive vapor migration is limited somewhat
by the relatively low evaporation rates from the liquid pools.
The California Department of Education, Guidance Protocol for School Site Pipeline Risk
Assessment, includes an analysis of various size circular hexane pools. In all cases, the diameter
of the vapor cloud within the combustible range is smaller than the diameter of the pool. (The
diameter of the vapor cloud within the combustible range varies from 60 to 80% of the pool
diameter.)73
Since the duration of a refined petroleum flash fire is relatively short and the size of the fire is
smaller than the pool diameter, we have assumed that one hundred percent (100%) of the fires
72 An indoor exposure would be applicable to those individuals located indoors (e.g., inside their home,
business, school, etc.). An outdoor exposure applies to those located outdoors.
73 Since the 100% mortality impacts are larger than the pool size for pool fires, while the portion of the
vapor cloud within the combustible range is smaller than the pool size, it is conservative to assume that one
hundred percent (100%) of the fires are pool fires.
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are pool fires. This is conservative since in all pool fire cases, the 12,000 Btu/ ft2‐hr isopleth
extends beyond the pool boundary, whereas the flash fire boundary is smaller than the pool.
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8.0 Conditional Probabilities
8.1 Pipeline Contents
We have averaged the OPL reported shipment percentages of the various commodities for each
pipeline presented in Section 1.1. The resulting conditional probabilities of pipe contents at the
time of an unintentional release have been used in the individual and societal risk assessments.
Diesel – 29 percent
Jet Fuel – 20 percent
Gasoline – 51 percent
8.2 Pipeline Operability
We have conservatively assumed that the pipelines would be operational one‐hundred percent
(100%) of the time.
8.3 Pool Fire Spill Volumes
In order to create a hydraulic model and analyze the potential release volumes from the two
existing OPL pipelines, the following minimum data would be required:
Pipeline profile,
Location and means of actuation of block valves,
Pipeline supervisory control and data acquisition system performance parameters,
Leak detection system performance parameters, etc.
OPL did not provide these data for security reasons. As a result, for pool fire consequence analysis,
the actual reported refined petroleum product pipeline unintentional release volumes which occurred
from January 2010 through 2015 have been used. These data were then normalized to an 18‐inch
diameter pipeline, as discussed in Section 5.2.1. The resulting conditional probabilities for various spill
sizes resulting from an unintentional release have been used in the individual and societal risk
assessments.
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Figure 8.3-1 Pool Fire Conditional Spill Volumes74
Spill Size Conditional Probability
0.5 Barrels 27 Percent
4.3 Barrels 21 Percent
36 Barrels 22 Percent
416 Barrels 21 Percent
2,603 Barrels 6 Percent
8,861 Barrels 3 Percent
8.4 Fire and Explosion
The 2010 through 2015 U.S. Hazardous Liquid Pipeline release data have been analyzed to
develop the following data points.
Of the 2,362 releases from the U.S. Hazardous Liquid Pipeline database are considered, from
all components (e.g., crude oil, highly volatile liquid, refined petroleum products, etc.),
including those which occurred within, and were entirely contained on, the pipeline
operator’s controller property, and those which occurred along the right‐of‐way, from January
2010 through December 2015, 79 (3.3 percent, 3.3%) ignited after release.
Of the 805 refined petroleum product pipeline releases, 20 (2.5 percent, 2.5%) ignited after
release.
Of the 195 refined petroleum product pipeline system releases which occurred along the
pipeline right‐of‐way, or occurred on pipeline operator controlled property and extended
beyond the property boundary, 4 (2.1 percent, 2.1%) ignited after release.
Of all 195 refined petroleum product pipeline releases which occurred along the pipeline
right‐of‐way, or occurred on pipeline operator controlled property and extended beyond the
property boundary, none resulted in an explosion.
Based on the data outlined above, the following conditional probabilities have been used in the
individual and societal risk assessments:
Percentage of OPL pipeline releases which would be ignited – 2.5 percent (2.5 %)
Percentage of OPL pipeline ignited releases that would result in a fire – 100 percent (100%)
Percentage of OPL pipeline ignited releases that would result in an explosion – 0.0 percent
(0.0 %)
Since the duration of a refined petroleum flash fire is relatively short and the size of the fire is
smaller than the pool diameter (CDE 2007), we have assumed that one hundred percent (100%)
of the fires are pool fires.
74 These data were presented previously, in Section 5.2.1 of this Report.
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8.5 Likelihood of Fatal Injuries
The following radiant heat flux exposure mortality end points have been used in the individual
and societal risk assessments:
12,000 Btu/f2t‐hr (37.7 kW/m2) – 100% mortality
8,000 Btu/ft2‐hr (25.1 kW/m2) – 50% mortality
5,000 Btu/ft2‐hr (15.7 kW/m2) – 1% mortality
8.6 Other Primary Assumptions
The following primary assumptions have been made in performing the analyses.
Assumptions Common to Individual and Societal Risk Analyses
The pool fire modeling assumed that the depth of fluid is sufficient to sustain burning long
enough to establish a flame and result in fatalities.
Pool fires were assumed to be created after every release, one hundred percent (100%) of the
time.
The pool was assumed to form directly over the release, including one hundred percent
(100%) of the unintentional release spill volumes. This results in the largest volume of fluid
within the pool. (Refined petroleum product would normally evaporate, be diluted, infiltrate
into the ground, cling to vegetation, etc. as it flows away from the release site, reducing the
pool volume.)
Individual Risk Analysis Assumptions
The risk level has been determined for the maximally exposed individual; in other words, it
assumes that a person is present continuously – 24 hours per day, 365 days per year.
The risk analysis assumed that the wind direction was perpendicular to the pipeline, resulting
in the greatest downwind distance to potentially harmful impacts.
Societal Risk Analysis Assumptions
The risk level has been determined for a maximally exposed population, exposed 100% of the
time. If the exposure was less, the likelihood of each scenario would be reduced
proportionately. For example, in residential areas, the population density is normally reduced
during work hours; in commercial areas, the population density is reduced during the night.
Individuals are also protected from radiant heat flux when inside structures, unless the
structures themselves should catch fire; but in these situations, there is often time for
individuals to seek safety. For reference, the California Department of Education uses 0.16
(16%) as the conditional probability of occupancy and 0.25 (25% for outdoor exposures) for
public school site citing.
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Population density was used to determine the number of individuals exposed to each release.
The individuals were assumed to be spread uniformly throughout the area. (See Section 5.3
of this Report.)
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9.0 Individual Risk Assessment
As discussed previously, individual risk (IR) is most commonly defined as the frequency that an
individual may be expected to sustain a given level of harm from the realization of specific
hazards, at a specific location, within a specified time interval. Individual risk is typically
measured as the probability of a fatality per year. The risk level is typically determined for the
maximally exposed individual; in other words, it assumes that a person is present continuously –
24 hours per day, 365 days per year. The likelihood is most often expressed numerically, using
one of the values shown in Table 9.0‐1 below. The values shown on each row may be used
interchangeably.
Table 9.0-1 Individual Risk Numerical Values
Annual Likelihood of
Fatality Numerical Equivalent Scientific Notation Shorthand
1 in 100 1.0 x 10‐2 1.0 E‐2 10‐2
1 in 1,000 1.0 x 10‐3 1.0 E‐3 10‐3
1 in 10,000 1.0 x 10‐4 1.0 E‐4 10‐4
1 in 100,000 1.0 x 10‐5 1.0 E‐5 10‐5
1 in 1,000,000 1.0 x 10‐6 1.0 E‐6 10‐6
1 in 10,000,000 1.0 x 10‐7 1.0 E‐7 10‐7
In the following subsections, the individual risk will be presented for the two (2) OPL pipelines:
Where they are not collocated with an overhead HVAC line,
Where they are collocated within the existing overhead HVAC corridor (No Action
Alternative), and
Where they would be collocated within the proposed overhead HVAC corridor (Alternative 1).
Where only one pipeline is present, the likelihood of a release would be one‐half the stated
values.
The individual risks are presented graphically. These figures present risk transects, which show
the annual risk of fatality resulting from a pipeline release as a function of the distance from the
center of the pool which could form after an unintentional release; the location of this pool would
depend on local terrain and other factors. It should also be noted that the highest risks are posed
directly over the center of the pool fire.
9.1 Two OPL Pipelines Not Collocated within Overhead HVAC Corridor
In this section, the individual risk posed along the pipeline corridor will be presented. These
results are useful for evaluating the risk to the public only; this excludes the risks posed to OPL
personnel and OPL’s contractors.
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The baseline incident rate of 0.5144 incidents per 1,000 mile years was developed in Section 5.2
of this report. As discussed previously, the PHMSA pipeline incident database includes releases
from all hazardous liquid pipelines; it does not distinguish between pipelines collocated or not
collocated with overhead HVAC transmission line facilities. As a result, it was not possible to
determine separate incident rates for collocated and non‐collocated facilities from these data.
For the two pipelines, the resulting baseline incident rate is 1.0288 incidents per 1,000 mile years
(2 pipelines x 0.5144 incidents per 1,000 mile years = 1.0288 incidents per 1,000 mile years).
The individual risk maximum annual probability of fatality from two (2) OPL pipelines is 1.77 x 10‐7
(1 in 5.7 million). The estimated maximum downwind distance to potentially fatal impacts,
measured from the center of the pool fire is 113 feet. The maximum individual risk is presented
in the figure below, as a function of the distance from the middle of the pool fire. Where only one
line is present, the individual risk would be one‐half (1/2) these values.
Figure 9.2-1 Individual Risk Transect, Two OPL Pipelines Not Collocated within Overhead HVAC
Corridor
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It should be noted that the individual risk results are below the threshold of 1.0 x 10‐6 (1 in 1.0
million.)75
9.2 Two OPL pipelines Collocated with Existing 115 kV Line (No Action
Alternative)
Puget Sound Energy retained Det Norske Veritas (U.S.A.), Inc. to perform an analysis of potential
A.C. Interference for the existing 115 kV corridor. The results of this analysis are presented in a
MS PowerPoint Slide Deck entitled, Puget Sound Energy A.C. Interference Analysis Existing
Corridor. The baseline data used in this analysis were presented previously, in Section 5.7 of this
Report. In this section, the individual risk posed by the two (2) pipelines where they are
collocated within the existing 115 kV corridor will be presented.
9.2.1 Induced A.C. Voltage
There are no segments of the existing corridor which are anticipated to yield induced A.C.
voltages that exceed the 15 volt threshold. As a result, there is not a touch potential (electrical
shock) posed to personnel that may touch the pipeline or pipeline appurtenances (e.g., cathodic
protection test leads, etc.) This would not result in an increased frequency of unintentional
pipeline releases. (See Figures 5.7.1‐1 and 5.7.1‐2, presented earlier.)
9.2.2 A.C. Current Density
There are two (2) short segments where the estimated A.C. current density would exceed the 20
amps per square meter de minimus value. (A.C. current densities below 20 amps per square
meter do not cause A.C. corrosion.) The estimated current densities for the OPL 16‐inch pipeline,
during peak winter voltages are expected to be 34 amps per square meter for the actual 2013‐14
peak winter load and 35 amps per square meter at the anticipated 2027‐28 peak winter load. For
the OPL 20‐inch pipeline, the estimated current densities are expected to be 25 amps per square
meter for the actual 2013‐14 peak winter load and 22 amps per square meter for the anticipated
2027‐28 peak winter load. (When A.C. current densities are between 20 and 100 amps per square
meter, A.C. corrosion may or may not occur.)
For this analysis, we have made the following assumptions:
The likelihood of an external corrosion caused leak would increase fifty percent (50%) for the
anticipated A.C. current densities of 22 to 35 amps per square meter.
Based on the data presented in Figures 5.7.2‐1 and 5.7.2‐2, we have conservatively estimated
that the A.C. current density may exceed 20 amps per square meter for ten percent (10%) of
the length of the OPL 16‐inch line and five percent (5%) of the OPL 20‐inch line; we have used
an average 7.5% of the length for the societal risk analysis. For the individual risk analysis, we
have assumed that the individual was located at the maximally exposed location (e.g., highest
A.C. current density).
75 See Section 3.2 of this Report for a discussion of individual risk criteria.
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We have conservatively assumed that the system would operate at peak winter voltages one
hundred percent (100%) of the time.
Using these assumptions for the maximum exposed individual (individual risk), the predicted
frequency of external corrosion caused releases for the No Action Alternative would be 0.1701
incidents per 1,000 mile years for each pipeline, compared to the baseline of 0.1134 incidents per
1,000 mile years, as calculated below.
0.1134 + [0.1134 x 0.5 x 1.00 (100% at peak winter)] = 0.1701
Using these assumptions for societal risk, based on the average over a given area, the predicted
frequency of external corrosion caused releases for the No Action Alternative would be 0.1177
incidents per 1,000 mile years for each pipeline, compared to the baseline of 0.1134 incidents per
1,000 mile years to, as calculated below.
0.1134 + [0.1134 x 0.5 x 0.075 (percentage of length) x 1.00 (100% at peak winter)] = 0.1177
It should be noted that 49 CFR 195.577 (a) requires, “For pipelines exposed to stray currents, you
must have a program to identify, test for, and minimize the detrimental effects of such currents.”
This is a Federal regulatory requirement imposed on OPL.
9.2.3 Coating Stress Voltage Resulting from Fault
We do not have data available for the estimated coating stress voltages for the OPL pipelines
within the existing 115 kV corridor. The Applicant has stated that the coating stress voltages for
the proposed 115/230 kV corridor will be less than or equal to the existing 115 kV corridor coating
stress voltages.
In order to estimate the most conservative incremental risk from the proposed 115/230 kV
project, we have assumed that the coating stress voltages and resulting coating stress voltage
caused pipeline releases for the existing 115 kV corridor are the same as those for the proposed
115/230 kV project. However, the proposed project may actually reduce the likelihood of
unintentional pipeline releases caused by coating stress voltage due to the proposed installation
of a shield wire.
9.2.4 Arc Distance Resulting from Fault
We do not have data available for the estimated arc distances for the OPL pipelines within the
existing 115 kV corridor. The Applicant has stated that the arc distances for the proposed
115/230 kV corridor will be less than or equal to the existing 115 kV corridor arc distances.
In order to estimate the most conservative incremental risk from the proposed 115/230 kV
project, we have assumed that the ground fault arc distances and ground fault arc caused
frequency of unintentional releases for the existing 115 kV corridor are the same those for the
proposed 115/230 kV project. However, the proposed project may actually reduce the likelihood
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of unintentional pipeline releases due to electrical arcs; any risk reduction has not been included
in our findings.
9.2.5 Estimated Frequency of Unintentional Releases
Using the data summarized above, the estimated frequency of unintentional releases from the
OPL pipelines where they are collocated with the existing 115 kV line are as follows:
Individual Risk Maximum Exposure ‐ is 0.5869 incidents per 1,000 mile years per pipeline, or
1.1738 incidents per 1,000 mile years for the two OPL pipelines.
Societal Risk Average Exposure ‐ is 0.5193 incidents per 1,000 mile years per pipeline, or
1.0386 incidents per 1,000 mile years for the two OPL pipelines.
Figure 9.2.5-1 Frequency of Unintentional Releases Existing 115 KV Corridor
Cause
Individual Risk Frequency
(incidents per 1,000 mile years)
Societal Risk Frequency
(incidents per 1,000 mile years)
Equipment Failure 0.1266 0.1266
Incorrect Operation 0.0396 0.0396
External Corrosion 0.1701 0.1177
Outside Force/Excavation 0.1002 0.1002
Material Failure 0.0871 0.0871
Internal Corrosion 0.0106 0.0106
Natural Force 0.0211 0.0211
Other 0.0316 0.0164
Total 0.5869 0.5193
9.3 Two OPL Pipelines Collocated with 115/230 kV Lines (Alternative 1)
The results of the A.C. Interference Analysis – 230 kV Transmission Line Collocated with Olympic
Pipelines OPL 16 and OPL 20 are summarized in Section 5.6 of this Report. In this section, the
individual risk posed by the 2 pipelines where they would be collocated within the 115/230 kV
corridor will be presented.
9.3.1 Induced A.C. Voltage
There are short segments of the corridor which could yield induced A.C. voltages that exceed the
15 volt threshold; these areas would result in potential safety (electrical shock) hazards to
personnel that may touch the pipeline or pipeline appurtenances (e.g., cathodic protection test
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leads, etc.). They would not result in an increased frequency of unintentional pipeline releases.
(See Figures 5.6.3‐2 and 5.6.3‐3, presented earlier.)
9.3.2 A.C. Current Density
There are two areas where the estimated A.C. current density would exceed the 20 amps per
square meter de minimus value. (A.C. current densities below 20 amps per square meter do not
cause A.C. corrosion.) The estimated A.C. current densities at these locations range from 25 to 70
amps per square meter. When A.C. current densities are between 20 and 100 amps per square
meter, A.C. corrosion may or may not occur.
For this analysis, we have made the following assumptions:
The likelihood of an external corrosion caused leak would increase one hundred percent
(100%) when A.C. current densities are between 25 and 70 amps per square meter. (This
current density is higher than that presented in Section 9.2.2 for the existing 115 kV corridor.)
Based on the data presented in Figures 5.6.3‐4 and 5.6.3‐5, we have conservatively estimated
that the A.C. current density may exceed 20 amps per square meter for ten percent (10%) of
the length of the OPL 16‐inch line and five percent (5%) of the OPL 20‐inch line; we have used
an average 7.5% of the length for the societal risk analysis76. For the individual risk analysis,
we have assumed that the individual was located at the maximally exposed location (e.g.,
highest A.C. current density).
We have conservatively assumed that the system would operate at peak winter voltages one
hundred percent (100%) of the time.
Using these assumptions for the maximum exposed individual, for individual risk, the predicted
frequency of external corrosion caused releases for Alternative 1 would be 0.2268 incidents per
1,000 mile years for each pipeline, compared to the baseline of 0.1134 incidents per 1,000 mile
years, as calculated below.
0.1134 + [0.1134 x 1.00 (100% at peak winter)] = 0.2268
Using these assumptions for societal risk, the predicted frequency of external corrosion caused
releases for Alternative 1 would be 0.1219 incidents per 1,000 mile years for each pipeline,
compared to the baseline of 0.1134 incidents per 1,000 mile years, as calculated below.
0.1134 + [0.1134 x 0.075 (percentage of length) x 1.00 (100% at peak winter)] = 0.1219
It should be noted that 49 CFR 195.577 (a) requires, “For pipelines exposed to stray currents, you
must have a program to identify, test for, and minimize the detrimental effects of such currents.”
This is a Federal regulatory requirement imposed on OPL.
76 Societal risk is based on the area exposed to the potential risk and the number of exposed individuals.
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9.3.3 Coating Stress Voltage Resulting from Fault
The applicant has committed to the use of an OPGW shield wire. Using this shield wire, at the
maximum 25 kA fault current, the estimated coating stress voltage would range from 1,517 to
5,970 volts. The estimated coating breakdown voltage of the pipeline external coating is 10,825
volts. As a result, coating degradation is not anticipated along the corridor provided an OPGW
shield wire is used.
9.3.4 Arc Distance Resulting from Fault77
The applicant has committed to the use of an OPGW shield wire. Using this shield wire, at the
maximum 25 kA fault current, the estimated arc distance ranges from 4 to 13‐feet. This would
pose a potential pipeline risk at transmission structure ground locations, where the electrical
ground might be located less than 13‐feet from the pipeline. It should be noted that this risk is
not posed along the entire length of the corridor. In other words, the only affected segments of
the pipeline would be that portion within the arc distance of the grounding rod (4 to 13‐feet).
The existing 115 kV line structures (poles) are spaced at 450 to 725‐foot intervals. In general, the
proposed 230 kV structures (poles) would be spaced at generally the same spacing as the existing
structures, except in some cases where the spacing will be slightly greater. If one conservatively
assumes that the OPL 16‐inch line is 5‐feet from all of the grounding rods and that the OPL 20‐
inch line is 5‐feet from the 16‐inch line, then at each grounding rod there would be 24‐feet of the
16‐inch and 17‐ feet of the 20‐inch pipeline within 13‐feet of the grounding rod. This condition is
depicted in Figure 9.3.4‐1 below.
77 49 CFR 195.401 (b) (1) requires, “Non Integrity Management Repairs, Whenever an operator discovers
any condition that could adversely affect the safe operation of its pipeline system, it must correct the
condition within a reasonable time. However, if the condition is of such a nature that it presents an
immediate hazard to persons or property, the operator may not operate the affected part of the system
until it has corrected the unsafe condition.”
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Figure 9.3.4-1 Assumed Pipe Configuration at All Grounding Rods
Assuming an average 500 foot pole spacing, 4.1 percent (4.1 %) of the pipelines would be located
within 13‐feet of a grounding rod.
( 24 ‐ feet + 17 ‐ feet ) ÷ ( 2 × 500 ‐ feet ) = 0.041 x 100 = 4.1 percent
Of the 2,362 hazardous liquid pipeline incidents between January 2010 and December 2015, there
were 129 (5.5%) that were noted as being caused by “other”. Of these 129 incidents, there were
only 6 (4.7%) that may have been caused by arcing relating to high voltage electrical facilities.
For the purposes of this analysis, we have conservatively assumed that the frequency of “other”
caused releases would increase one hundred percent (100%) for the portion of the pipeline within
the worst case arc distance to a grounding rod.
Using these assumptions for the maximum individual risk exposure, the predicted frequency of
“other” caused releases for Alternative 1 would be 0.0316 incidents per 1,000 mile years for each
pipeline, compared to the baseline of 0.0158 incidents per 1,000 mile years, as calculated below.
0.0158 + [0.0158 x 1.00 (100% at peak winter)] = 0.0316
Using these data and assumptions for societal risk, the predicted frequency of “other” caused
releases for Alternative 1 would be 0.0164 incidents per 1,000 mile years for each pipeline,
compared to the baseline of 0.0158 incidents per 1,000 mile years, as calculated below:
0.0158 + [0.0158 x 0.041 (percentage of length) x 1.00 (100% at peak winter)] = 0.0164
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We believe that this result is conservative, for the following reasons:
The assumed pipeline distances from the grounding rods is likely conservative.
The assumed one hundred percent (100%) increase of “other” caused incidents is likely
conservative.
The worst case arc distance of 13‐feet has been conservatively used.
The results for the worst case peak winter loading have been used, for 100% of the time.
A ground fault condition only occurs when there is a fault on the electrical transmission
system; it is a very infrequent hazard.
As noted previously, there were only six (6) hazardous liquid pipeline incidents between
January 2010 and December 2015 that may have been caused by electrical arcing. These
incidents represent only 0.25 percent (0.25%) of the total 2,363 hazardous liquid pipeline
releases during this time period.
These results do not reflect the implementation of measures to mitigate potential arc damage
to the pipeline. The A.C. Interference Study recommended mitigation to address potential
ground fault issues where the pipeline(s) is within the arc distance to a pole structure
grounding rod. OPL has verbally committed to mitigating any potential impacts. However,
they have not committed to implementing the specific measures included in the A.C.
Interference Study; OPL committed to implementing mitigation on a case by case basis in
order to maximize the effectiveness of the mitigation.
There is a Federal regulation requiring OPL to address any known potential unsafe condition
(49 CFR 195.401).
9.3.5 Frequency of Unintentional Releases
Using the data summarized above, the resulting estimated frequency of unintentional releases
are as follows:
Individual Risk Maximum Exposure ‐ is 0.6436 incidents per 1,000 mile years per pipeline, or
1.2872 incidents per 1,000 mile years for the two OPL pipelines.
Societal Risk Average Exposure ‐ is 0.5235 incidents per 1,000 mile years per pipeline, or
1.0470 incidents per 1,000 mile years for the two OPL pipelines.
The frequency of unintentional releases by cause are presented below for a single pipeline where
it would be collocated with the proposed 115/230 kV lines.
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Figure 9.3.5-1 Frequency of Unintentional Releases Proposed 115/230 kV Corridor
Cause
Individual Risk Frequency
(incidents per 1,000 mile years)
Societal Risk Frequency
(incidents per 1,000 mile years)
Equipment Failure 0.1266 0.1266
Incorrect Operation 0.0396 0.0396
External Corrosion 0.2268 0.1219
Outside Force/Excavation 0.1002 0.1002
Material Failure 0.0871 0.0871
Internal Corrosion 0.0106 0.0106
Natural Force 0.0211 0.0211
Other 0.0316 0.0164
Total 0.6436 0.5235
9.3.6 Operational Individual Risk
The individual risk maximum annual probability of fatality from two (2) OPL pipelines is 2.21 x 10‐7
(1 in 4.5 million). The estimated maximum downwind distance to potentially fatal impacts,
measured from the center of the pool fire is 113 feet. The maximum individual risk is presented
in the figure below, as a function of the distance from the middle of the pool fire. Where only one
line is present, the individual risk would be one‐half (1/2) these values. These results are useful
for evaluating the risk to the public only; this excludes the risks posed to OPL personnel and OPL’s
contractors.
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Figure 9.3.6-1 Individual Risk Transect, Maximum Exposure, Two OPL Pipelines Collocated within
Proposed 115/230 kV Overhead HVAC Corridor
The increased individual risk for the proposed 115/230 kV project over that posed by the existing
115 kV system is presented by the orange line in the figure above. The maximum additional
individual risk annual probability of fatality from two (2) OPL pipelines is 1.95 x 10‐8 (1 in 51
million).
It is important to note that we did not have coating stress voltage and ground fault arc data
available for the OPL pipelines where they are collocated with the existing 115 kV lines. In order
to estimate the most conservative incremental risk from the proposed 115/230 kV project, we
have assumed that the likelihood or coating stress voltage and ground fault arc caused
unintentional releases for the existing 115 kV corridor are the same those for the proposed
115/230 kV project. However, the proposed project may actually reduce the risk of these
unintentional pipeline releases.
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9.3.7 Construction Individual Risk
As discussed previously, during construction of the proposed facilities, the existing OPL 16‐inch
and 20‐inch pipelines will be exposed to an increased risk of being damaged by construction
activities (e.g., excavation) and/or overstressed by surcharge loading from construction
equipment. The existing OPL procedures to prevent third party damage have been presented in
Section 1.1.5 of this Report. Risk mitigation measures have been presented in Section 11.0.
As presented in Table 5.2‐2, outside force/excavation caused 20% of the refined petroleum
product releases from January 2010 through December 2015. With the current OPL procedures
and the proposed spacing of the structures (poles), the increased risk posed to the pipeline during
construction is relatively low. For the purposes of this Study, we have made the following
assumptions:
Average structure (pole) spacing of 500‐feet,
Potential impact radius of 25‐feet for each structure (5% of corridor), and
Fifty percent (50%) increase in outside force/excavation risk during construction of the 230 kV
facilities.
Using these assumptions for the maximum individual risk exposure, the predicted frequency of
“outside force/excavation” caused releases during construction of Alternative 1 would be 0.1503
incidents per 1,000 mile years for each pipeline, compared to the baseline of 0.1002 incidents per
1,000 mile years, as calculated below.
0.1002 + [0.1002 x 0.50 (50% risk increase)] = 0.1503
Using these data and assumptions for societal risk, the predicted frequency of “outside
force/excavation” caused releases during construction of Alternative 1 would be 0.1027 incidents
per 1,000 mile years for each pipeline, compared to the baseline of 0.1002 incidents per 1,000
mile years, as calculated below:
0.1002 + [0.1002 x 0.05 (percentage of length) x 0.50 (50% risk increase)] = 0.1027
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Figure 9.3.7-1 Frequency of Unintentional Releases Existing 115 KV Corridor during Construction of
Proposed 115/230 kV Project
Cause
Individual Risk Frequency
(incidents per 1,000 mile years)
Societal Risk Frequency
(incidents per 1,000 mile years)
Equipment Failure 0.1266 0.1266
Incorrect Operation 0.0396 0.0396
External Corrosion 0.1701 0.1177
Outside Force/Excavation 0.1503 0.1027
Material Failure 0.0871 0.0871
Internal Corrosion 0.0106 0.0106
Natural Force 0.0211 0.0211
Other78 0.0316 0.0164
Total 0.6370 0.5218
Using the data summarized above, the resulting estimated frequency of unintentional releases
from the OPL pipelines where they are collocated with the existing 115 kV line are as follows:
Individual Risk Maximum Exposure ‐ 0.6370 incidents per 1,000 mile years per pipeline, or
1.2740 incidents per 1,000 mile years for the two OPL pipelines.
Societal Risk Average Exposure ‐ 0.5218 incidents per 1,000 mile years per pipeline, or 1.0436
incidents per 1,000 mile years for the two OPL pipelines.
During construction of the proposed project, the individual risk maximum annual probability of
fatality from two (2) OPL pipelines is 2.19 x 10‐7 (1 in 4.6 million). The estimated maximum
downwind distance to potentially fatal impacts, measured from the center of the pool fire is 113
feet. The maximum individual risk is presented in the figure below, as a function of the distance
from the middle of the pool fire. Where only one line is present, the individual risk would be one‐
half (1/2) these values.
78 Coating stress voltage and arc distance data is not available for the existing 115 kV corridor. The “other”
incident cause data depicted has been taken from the 115/230 kV proposed project.
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Figure 9.3.7-1 Individual Risk Transect, Maximum Exposure, Two OPL Pipelines Collocated within
Proposed 115 kV Overhead HVAC Corridor during Construction of Proposed 115/230 kV Project
The maximum increased individual risk during the construction of the proposed 115/230 kV
project over that posed by the existing 115 kV system is presented by the orange line in the figure
above. The maximum additional individual risk annual probability of fatality from two (2) OPL
pipelines is 1.72 x 10‐8 (1 in 58 million).
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10.0 Societal Risk Assessment
As noted previously, societal risk is the probability that a specified number of people would be
affected by a given event. The generally accepted number of casualties is higher for lower
probability events and much lower for more probable events, as discussed previously in Section
3.3 of this document.
In order to determine the number of persons exposed to the potential hazard, population density
has been used. The individuals were assumed to be spread uniformly throughout the area. The
analysis also conservatively assumed that the population would be exposed one hundred percent
(100%) of the time. If one assumed that the population were exposed fifty percent (50%) of the
time, then the likelihood would be one‐half (1/2) the values presented for each scenario.
All of the societal results presented herein are based on one (1) mile of the two (2) OPL pipelines
(two miles total pipeline length). If the length were increased, the change in probability for each
scenario would be proportional. In other words, if one were considering a two (2) mile length of
the two (2) pipelines (four miles total pipeline length), then the likelihood of each scenario would
be two (2) times as likely. On the other hand, if one were considering a one (1) mile length of only
one (1) pipeline (one mile total pipeline length), then the likelihood of each scenario would be
one‐half (1/2) as likely.
It is important to note that we did not have coating stress voltage and ground fault arc data
available for the OPL pipelines where they are collocated with the existing 115 kV lines. In order
to estimate the most conservative incremental risk from the proposed 115/230 kV project, we
have assumed that the likelihood of coating stress voltage and ground fault arc caused
unintentional releases for the existing 115 kV corridor are the same as those for the proposed
115/230 kV project. However, the proposed project may actually reduce the risk of these
unintentional pipeline releases.
10.1 Two OPL Pipelines Not Collocated within Overhead HVAC Corridor
10.1.1 Maximum Population Density
The societal risk results are presented in Figure 10.1.1‐1 for the maximum population density of
23,169 persons per square mile, for a one (1) mile length of the two (2) OPL pipelines (two miles
total pipeline length), over a one (1) year time period.
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1.00E-11
1.00E-10
1.00E-09
1.00E-08
1.00E-07
1.00E-06
1.00E-05
1.00E-04
1.00E-03
1.00E-02
1 10 100 1000Annual Likelihood of IncidentNumber of Fatalities
Societal Risk Results, Two OPL Lines Not Collocated with
Overhead HVAC
One Mile, Two OPL Pipelines UK R2P2, 2001
Netherlands CDE and SBCO Intolerable
CDE and SBCO Negligible
Figure 10.1.1-1 – Societal Risk Results, One Mile of Two OPL Lines Not Collocated with Overhead
HVAC, Maximum Population Density
As depicted in Figure 10.1.1‐1, there are scenarios that could result in multiple fatalities. The
annual probability of these incidents are presented in the following table.
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Table 10.1.1-2 Societal Risk Results, One Mile of Two OPL Lines Not Collocates with Overhead HVAC,
Maximum Population Density
Number of Fatalities Probability Annual Likelihood
17 3.94 x 10‐7 1 in 2.54 million
15 5.48 x 10‐7 1 in 1.83 million
9 1.33 x 10‐6 1 in 749,000
8 1.56 x 10‐6 1 in 642,000
7 1.87 x 10‐6 1 in 536,000
5 2.31 x 10‐6 1 in 432,000
4 5.07 x 10‐6 1 in 197,000
3 6.15 x 10‐6 1 in 163,000
2 7.72 x 10‐6 1 in 130,000
1 1.34 x 10‐5 1 in 74,800
These results are above the thresholds for negligible impacts which are used by Santa Barbara
County and the California Department of Education for public school siting. But they are
approximately one order of magnitude below (roughly one tenth of) these entities’ intolerable
level. It should be noted however, that there are no known societal risk criteria for the proposed
project. (See also Sections 3.2 and 3.3 of this Report.)
10.1.2 Average Population Density
The societal risk results are presented in Figure 10.1.2‐1 for the average population density of
3,228 persons per square mile, for a one (1) mile length of the two (2) OPL pipelines (two miles
total pipeline length), over a one (1) year time period.
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1.00E-11
1.00E-10
1.00E-09
1.00E-08
1.00E-07
1.00E-06
1.00E-05
1.00E-04
1.00E-03
1.00E-02
1 10 100 1000Annual Likelihood of IncidentNumber of Fatalities
Societal Risk Results, Two OPL Lines Not Collocated with
Overhead HVAC
One Mile, Two OPL Pipelines UK R2P2, 2001
Netherlands CDE and SBCO Intolerable
CDE and SBCO Negligible
Figure 10.1.2-1 – Societal Risk Results, One Mile of Two OPL Lines Not Collocated with Overhead
HVAC, Average Population Density
As depicted in Figure 10.1.2‐1, there were incidents where either one (1) or two (2) individuals
could be fatally injured. The probability is as follows:
Two (2) fatalities ‐ The societal risk annual probability is 5.48 x 10‐7 (1 in 1.83 million).
One (1) or more fatalities79 ‐ The societal risk annual probability is 4.52 x 10‐6 (1 in 221,000).
These results are below the thresholds for negligible impacts which are used by Santa Barbara
County and the California Department of Education for public school siting; they are more than
two orders of magnitude below (less than one‐one‐hundredth of) these entities’ intolerable level.
79 The predicted maximum is two (2) fatalities for this scenario.
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However, there are no known societal risk criteria for the proposed project. (See also Sections 3.2
and 3.3 of this Report.)
10.1.3 Minimum Population Density
When the minimum population density of 568 persons per square mile was considered, the
number of persons exposed to each incident was below that which resulted in a single fatality.
The highest mortality for any of the releases scenarios was 0.4; there were two scenarios which
resulted in 0.4 fatalities:
8,863 barrel jet fuel pool fire, annual probability of 1.54 x 10‐7 (1 in 6.5 million)
8,863 barrel gasoline pool fire, annual probability of 3.94 x 10‐7 (1 in 2.5 million)
10.2 Two OPL Pipelines Collocated with 115/230 kV Lines (Alternative 1)
10.2.1 Maximum Population Density
The societal risk results are presented in Figure 10.2.1‐1 for the maximum population density of
23,169 persons per square mile, for a one (1) mile length of the two (2) OPL pipelines (two miles
total pipeline length), over a one (1) year time period for the proposed 115/230 kV project.
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Figure 10.2.1-1 – Societal Risk Results, One Mile of Two OPL Lines Collocated with 115/230 kV
Overhead HVAC, Maximum Population Density
As depicted in Figure 10.2.1‐1, there are scenarios that could result in multiple fatalities. The
annual probability of these incidents are presented in the following table.
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Table 10.2.1-1 Societal Risk Results, One Mile of Two OPL Lines Collocated with 115/230 kV Overhead HVAC,
Maximum Population Density
Number of Fatalities
Two OPL Lines Collocated with
Proposed 115/230 kV Overhead
HVAC
Annual Likelihood
Additional Risk of Proposed
Project versus No Action
Alternative
Annual Likelihood
17 4.92 x 10‐7
1 in 2.03 million
3.95 x 10‐9
1 in 253 million
15 6.85 x 10‐7
1 in 1.46 million
5.50 x 10‐9
1 in 182 million
9 1.67 x 10‐6
1 in 599,000
1.34 x 10‐8
1 in 74.6 million
8 1.95 x 10‐6
1 in 513,000
1.56 x 10‐8
1 in 63.9 million
7 2.34 x 10‐6
1 in 428,000
1.87 x 10‐8
1 in 53.4 million
5 2.90 x 10‐6
1 in 345,000
2.32 x 10‐8
1 in 43.0 million
4 6.34 x 10‐6
1 in 158,000
5.09 x 10‐8
1 in 19.7 million
3 7.69 x 10‐6
1 in 130,000
6.17 x 10‐8
1 in 16.2 million
2 9.65 x 10‐6
1 in 104,000
7.75 x 10‐8
1 in 12.9 million
1 1.67 x 10‐5
1 in 60,000
1.34 x 10‐7
1 in 7.45 million
These additional risk posed by the proposed 115/230 kV project are less than the thresholds for
negligible impacts which are used by Santa Barbara County and the California Department of
Education for public school siting. It should be noted however, that there are no known societal
risk criteria for the proposed project. (See also Sections 3.2 and 3.3 of this Report.)
10.2.2 Average Population Density
The societal risk results for the proposed 115/230 kV project are presented in Figure 10.2.2‐1 for
the average population density of 3,228 persons per square mile, for a one (1) mile length of the
two (2) OPL pipelines (two miles total pipeline length), over a one (1) year time period.
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Figure 10.2.2-1 – Societal Risk Results, One Mile of Two OPL Lines Collocated with 115/230 kV
Overhead HVAC, Average Population Density
As depicted in Figure 10.2.2‐1, there were incidents where either one (1) or two (2) individuals
could be fatally injured.
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Table 10.2.2-1 Societal Risk Results, One Mile of Two OPL Lines Collocated with 115/230 kV Overhead HVAC,
Average Population Density
Number of Fatalities
Two OPL Lines Collocated with
Proposed 115/230 kV Overhead
HVAC
Annual Likelihood
Additional Risk of Proposed
Project versus No Action
Alternative
Annual Likelihood
2 6.85 x 10‐7
1 in 1.46 million
5.50 x 10‐9
1 in 182 million
1 5.66 x 10‐6
1 in 177,000
4.54 x 10‐8
1 in 22.0 million
These results are below the thresholds for negligible impacts which are used by Santa Barbara
County and the California Department of Education for public school siting; they are more than
two orders of magnitude below (less than one‐one‐hundredth of) these entities’ intolerable level.
However, there are no known societal risk criteria for the proposed project. (See also Sections 3.2
and 3.3 of this Report.)
10.2.3 Minimum Population Density
When the minimum population density of 568 persons per square mile was considered, the
number of persons exposed to each incident was below that which resulted in a single fatality.
The highest mortality for any of the releases scenarios was 0.4; there were two scenarios which
resulted in 0.4 fatalities:
8,863 barrel jet fuel pool fire, annual probability of 1.93 x 10‐7 (1 in 5.18 million)
8,863 barrel gasoline pool fire, annual probability of 4.92 x 10‐7 (1 in 2.03 million
10.2.4 Construction Societal Risk
Maximum Population Density
The societal risk results during construction of the proposed 115/230 kV project are presented in
Figure 10.3.1‐1 for the maximum population density of 23,169 persons per square mile, for a one
(1) mile length of the two (2) OPL pipelines (two miles total pipeline length), over a one (1) year
time period80.
80 Coating stress voltage and arc distance data is not available for the existing 115 kV corridor. The “other”
incident cause data has been taken from the 115/230 kV proposed project.
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Figure 10.3.1-1 – Societal Risk Results during Construction of Proposed 115/230 kV Project, One Mile
of Two OPL Lines Collocated with 115/230 kV Overhead HVAC, Maximum Population Density
As depicted in Figure 10.3.1‐1, there are scenarios that could result in multiple fatalities. The
annual probability of these incidents are presented in the following table:
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Table 10.3.1-1 Societal Risk Results During Construction of Proposed 115/230 kV Project, One Mile of Two OPL
Lines Collocated with 115/230 kV Overhead HVAC, Maximum Population Density
Number of Fatalities
Two OPL Lines In Existing 115 kV
Overhead HVAC During
Construction of Proposed
115/230 kV Project
Annual Likelihood
Additional Risk During
Construction versus No Action
Alternative
Annual Likelihood
17 4.87 x 10‐7
1 in 2.05 million
2.33 x 10‐9
1 in 428 million
15 6.78 x 10‐7
1 in 1.47 million
3.25 x 10‐9
1 in 308 million
9 1.65 x 10‐6
1 in 605,000
7.92 x 10‐9
1 in 126 million
8 1.93 x 10‐6
1 in 518,000
9.25 x 10‐9
1 in 108 million
7 2.31 x 10‐6
1 in 432,000
1.11 x 10‐8
1 in 90.3 million
5 2.87 x 10‐6
1 in 349,000
1.37 x 10‐8
1 in 72.8 million
4 6.28 x 10‐6
1 in 159,000
3.01 x 10‐8
1 in 33.2 million
3 7.62 x 10‐6
1 in 131,000
3.65 x 10‐8
1 in 27.4 million
2 9.56 x 10‐6
1 in 105,000
4.58 x 10‐8
1 in 21.8 million
1 1.66 x 10‐5
1 in 60,000
7.94 x 10‐8
1 in 12.6 million
These additional risk posed during construction of the proposed 115/230 kV project are less than
the thresholds for negligible impacts which are used by Santa Barbara County and the California
Department of Education for public school siting. It should be noted however, that there are no
known societal risk criteria for the proposed project. (See also Sections 3.2 and 3.3 of this
Report.)
Average Population Density
The societal risks during construction of the proposed 115/230 kV project are presented in Figure
10.3.2‐1 for the average population density of 3,228 persons per square mile, for a one (1) mile
length of the two (2) OPL pipelines (two miles total pipeline length), over a one (1) year time
period.
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Figure 10.3.2-1 – Societal Risk Results during Construction of Proposed 115/230 kV Project, One Mile
of Two OPL Lines Collocated with 115/230 kV Overhead HVAC, Average Population Density
As depicted in Figure 10.3.2‐1, there were incidents where either one (1) or two (2) individuals
could be fatally injured.
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Table 10.3.2-1 Societal Risk Results, One Mile of Two OPL Lines Collocated with 115/230 kV Overhead HVAC,
Average Population Density
Number of Fatalities
Two OPL Lines Collocated with
Proposed 115/230 kV Overhead
HVAC
Annual Likelihood
Additional Risk of Proposed
Project versus No Action
Alternative
Annual Likelihood
2 6.78 x 10‐7
1 in 1.47 million
3.25 x 10‐9
1 in 308 million
1 5.60 x 10‐6
1 in 179,000
2.68 x 10‐8
1 in 37.3 million
These results are below the thresholds for negligible impacts which are used by Santa Barbara
County and the California Department of Education for public school siting; they are more than
two orders of magnitude below (less than one‐one‐hundredth of) these entities’ intolerable level.
However, there are no known societal risk criteria for the proposed project. (See also Sections 3.2
and 3.3 of this Report.)
Minimum Population Density
When the minimum population density of 568 persons per square mile was considered, the
number of persons exposed to each incident was below that which resulted in a single fatality.
The highest mortality for any of the releases scenarios was 0.4; there were two scenarios which
resulted in 0.4 fatalities.
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11.0 Risk Reduction Measures
The proposed project could increase the likelihood and possibly the severity of unintentional
releases from the OPL pipelines. In this section, several measures are presented which could be
implemented to reduce this increased risk.
11.1 Surcharge Loading
The application of loads to the soil surface (surcharge loads) can induce stresses on the underlying
substructures, including pipelines. These stresses can over‐stress the pipe, causing ovality,
through wall bending, pipe wall buckling, side wall crushing, fatigue, etc. which can result in an
unintentional release.
During the construction of the proposed project, surcharge loads will be imposed on the existing
OPL pipelines. In order to reduce the increased risk of unintentional release, the following
measure could be imposed on the applicant.
Surcharge Loading Risk Reduction Measure – The Applicant shall analyze, or cause to be
analyzed, all surcharge loads which will be imposed on the existing OPL pipeline(s) from heavy
equipment, crane matts, etc. in accordance with the following:
49 CFR 195, Transportation of Hazardous Liquid by Pipeline,
American Petroleum Institute Recommended Practice 1102, Steel Pipelines Crossing Railroads
and Highways, and
American Lifelines Alliance, Guidelines for the Design of Buried Steel Pipe.
11.2 Third Party Damage
During construction of the proposed project, excavations and soil disturbance will be required
around and near the existing OPL pipeline(s). During these activities, the OPL pipeline(s) could be
damaged. This damage could result in an immediate, or subsequent release, similar to those
which occurred in Bellingham, Washington, Walnut Creek, California, and San Bernardino,
California. (See Section 1.4 of this Report for a summary of these incidents.) In order to reduce
the increased risk of unintentional release, the following measure could be imposed on the
applicant.
Third Party Damage Risk Reduction Measure – The Applicant shall implement the following
measures during construction of the proposed project. These measures are in addition to those
required by State and Federal regulations and those included in OPL’s operations and
maintenance procedures.
The Applicant shall insure that OPL line marking personnel mark the entire length of any
pipeline that is within 50‐feet of any excavation or ground disturbance below original grade.
It is not acceptable to mark only the location of angle points (points of intersection).
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The Applicant shall excavate, expose, and positively identify the existing OPL pipeline(s) using
soft dig methods (e.g., hand excavation, vacuum excavation, etc.) whenever the pipeline(s)
are within 25‐feet of any proposed excavation or ground disturbance below original grade.
An OPL employee, trained in the observation of excavations and pipeline locating, shall be on‐
site at all times an excavation being made, or the ground is being disturbed below the original
grade.
11.3 Electrical Interference
The A.C. Interference Study presented an analysis of the potential hazards which could impact the
existing OPL pipeline(s). Based on the results of this study, we recommend the following risk
reduction measures.
Induced A.C. Voltage Risk Reduction Measure – After the proposed 230 kV system has been
commissioned, touch voltage testing should be conducted to insure that touch voltage potentials
at all above grade facilities are less than 15 volts. The tests should be conducted during periods
when the electrical system is operating at, or near, winter peak loading. Mitigation should be
implemented should touch voltages exceed 15 volts. This will help insure that pipeline operators
are not injured.
A.C. Current Density Risk Reduction Measure – In areas where the predicted A.C. current density
will exceed 20 amps per square meter, testing should be conducted to insure that A.C. current
densities do not exceed 20 amps per square meter. The tests should be conducted during periods
when the electrical system is operating at, or near, winter peak loading. Where A.C. current
densities exceed the 20 amps per square meter threshold, mitigation measures should be
implemented to insure that A.C. corrosion does not occur.
Fault Arcing Risk Reduction Measure – In areas where the pipeline is within 13‐feet of a
grounding rod, mitigation measures should be implemented to prevent ground fault arcing to the
pipeline.
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12.0 References
12.1 Acronyms
AC – Alternating Current
ALARP ‐ As Low as Reasonably Practicable
ANSI ‐ American National Standards Institute
API ‐ American Petroleum Institute
API 5L X52 – Pipe manufactured in accordance with API Standard 5L, Specification for Line Pipe,
with a specified minimum yield strength of 52,000 psi
ASME ‐ American Society of Mechanical Engineers
ASTM ‐ American Society for Testing and Materials
BPH – Barrels per Hour
CFR ‐ Code of Federal Regulations
CWA ‐ Clean Water Act
EIS – Environmental Empact Statement
ERW – Electric Resistance Welded
HLPSA ‐ Hazardous Liquid Pipeline Safety Act
HVAC – High Voltage Alternative Current
IR – Individual Risk
MSS ‐ Manufacturers Standardization Society of the Valve and Fittings Industry
NFPA – National Fire Protection Association
NTSB – National Transportation Safety Board
OPL – Olympic Pipeline Company
OPS – Office of Pipeline Safety
PHMSA ‐ The Pipeline and Hazardous Materials Safety Administration
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PLDS ‐ Pipeline Leak Detection System
PLL ‐ Probable Loss of Life
PPM – Parts per Million
PSI – Pounds per Square Inch
RCW – Revised Code of Washington
RSPA ‐ Research and Special Programs Administration
SMYS – Specified Minimum Yield Strength
SPCC ‐ Oil Spill Prevention Control & Countermeasures
USA ‐ Unusually Sensitive Areas
USC – United States Code
USDOT ‐ United States Department of Transportation
WAC – Washington Administrative Code
12.2 Definitions
Aggregate Risk ‐ Aggregate risk, or probable loss of life (PLL), is one risk measure used to evaluate
projects. Aggregate risk is the total anticipated frequency of a particular consequence,
normally fatalities, that could be anticipated over a given time period, for all project
components being analyzed. Aggregate risk is a type of risk integral; it is the summation
of risk, as expressed by the product of the anticipated consequences and their respective
likelihood. The integral is summed over all of the potential events that might occur for all
of the project components, over the entire project length.
ALARP approach. Generally, risks within a band of risk levels are considered tolerable only if risk
reduction is impractical or if its cost is grossly disproportionate to the risk improvement
gained. The underlying concept is to maximize the expected utility of an investment, but
not expose anyone to an excessive increase in risk.
Barrels – A measure of volume equal to 42 U.S. gallons.
Bright Line Threshold ‐ A bright‐line rule (or bright‐line test) is a clearly defined rule or standard,
composed of objective factors, which leaves little or no room for varying interpretation.
The purpose of a bright‐line rule is to produce predictable and consistent results in its
application. The term "bright‐line" in this sense generally occurs in a legal context.
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Bright‐line rules are usually standards established by courts in legal precedent or by
legislatures in statutory provisions.
De Manifestus ‐ ALARP (as low as reasonably practical) principle states that there is a level of risk
that is intolerable, sometimes called the de manifestus risk level. Above this level risks
cannot be justified.
De Minimus ‐ Latin term for "of minimum importance" or "trifling." Essentially it refers to
something or a difference that is so little, small, minuscule, or tiny that the law does not
refer to it and will not consider it. In a million dollar deal, a $10 mistake is de minimus.
Flammability Limit ‐ Flammable liquid only burns in its gaseous state. If the ratio of fuel to air is
greater than the upper flammability limit, the mixture is too rich to burn; if it is less than
the lower flammability limit, the mixture is to lean to burn. (The mixture will only burn in
gaseous state, between the upper and lower flammability limit.)
Flash Fire – A flash fire is a rapidly burning gas or vapor cloud of short duration. The duration lasts
until all vapor and oxygen in the cloud is consumed. The duration of the flash fire at any
point in the space depends on the concentration of the flammable vapor in air and the
specific vapor substance involved. (CDE 2005)
Incidents per 1,000 mile years ‐ This unit provides a means of predicting the number of incidents
for a given length of line, over a given period of time. For example, if one considered an
incident rate of 1.0 incidents per 1,000 miles years, one would expect one incident per
year on a 1,000 mile pipeline. Using this unit, frequencies of occurrence can be calculated
for any combination of pipeline length and time interval.
Individual Risk ‐ Individual risk (IR) is most commonly defined as the frequency that an individual
may be expected to sustain a given level of harm from the realization of specific hazards,
at a specific location, within a specified time interval. Individual risk is typically measured
as the probability of a fatality per year. The risk level is typically determined for the
maximally exposed individual; in other words, it assumes that a person is present
continuously – 24 hours per day, 365 days per year.
Isopleth – A line connecting points at which a given variable has a specified value. In this context,
the line connections points of a specified heat flux value.
Pasquill‐Gifford Atmospheric Stability – This is classified by the letters A through F. Stability can
be determined by three main factors: wind speed, solar insulation, and general
cloudiness. In general, the most unstable (turbulent) atmosphere is characterized by
stability class A. Stability A occurs during strong solar radiation and moderate winds. This
combination allows for rapid fluctuations in the air and thus greater mixing of the
released gas with time. Stability D is characterized by fully overcast or partial cloud cover
during daytime or nighttime, and covers all wind speeds. The atmospheric turbulence is
not as great during D conditions, so the gas will not mix as quickly with the surrounding
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atmosphere. Stability F generally occurs during the early morning hours before sunrise
(no solar radiation) and under low winds. This combination allows for an atmosphere
which appears calm or still and thus restricts the ability to actively mix with the released
gas. A stability classification of “D” is generally considered to represent average
conditions.
Pool Fire – A pool fire would typically follow a vapor flash fire for a liquid product release. If
ignition occurs early, the main impact if from the pool fire. The fire burns the evaporated
vapor from the pool surface. The fire would continue until all the liquid in the pool was
consumed or the fire was extinguished. (CDE 2005)
Refined Petroleum Products – For the purposes of this Report, these products include: gasolines,
diesel, and jet fuel.
Societal Risk ‐ Societal risk is the probability that a specified number of people will be affected by
a given event. The accepted number of casualties is relatively high for lower probability
events and much lower for more probable events.
12.3 Reference Documents
American Petroleum Institute (API 752). Management of Hazards Associated with Location of
Process Plant Buildings.
California Department of Education (CDE 2007 and CDE 2005). February 2007. Guidance Protocol
for School Site Pipeline Risk Analysis.
Det Norske Veritas (Veritas 2017). Puget Sound Energy A.C. Interference Analysis, Existing
Corridor.
Det Norske Veritas (Veritas 2016). A.C. Interference Analysis – 230 kV Transmission line
Collocated with Olympic Pipelines OLP16 and OPL20.
Health and Safety Executive (HSE 2000). Report on a Study of International Pipeline Accidents,
Contract Research Report 294/2000. United Kingdom.
Mannan, Dr. Sam. (LEES). Lee’s Loss Prevention in the Process Industries. Third Edition.
Marszal, Edward M. (Marszal 2001). 2001. Tolerable Risk Guidelines.
National Transportation Safety Board (NTSB 2002). Pipeline Rupture and Subsequent Fire in
Bellingham, Washington, June 10, 1999. Pipeline Accident Report NTSB/PAR‐02/02.
Washington, D.C.
National Transportation Safety Board (NTSB 2003). Pipeline Rupture and Subsequent Fire near
Carlsbad, New Mexico, August 19, 2000. Pipeline Accident Report NTSB/PAR‐03/01.
Washington, D.C.
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National Transportation Safety Board (NTSB 2011). Pacific Gas and Electric Company Natural Gas
Transmission Pipeline Rupture and Fire, San Bruno, California, September 9, 2010.
Pipeline Accident Report NTSB/PAR‐11/01. Washington, D.C.
Northwest Gas Association v. WUTC, 141 Wn. App. 98, 168 P.3d 443, 2007. Rev. denied, 163
Wn.2d 1049, 2008.
Office of the State Fire Marshal, Pipeline Failure Investigation Report, November 9, 2004.
California.
Payne, Brian L. el al. EDM Services, Inc. 1993. California Hazardous Liquid Pipeline Risk
Assessment, Prepared for California State Fire Marshal, March.
Presidential/Congressional Commission on Risk Assessment and Risk Management (Commission
1997). 1997. Framework for Environmental Health Risk Management.
Quest Consultants, CANARY. (QUEST 2003) CANARY by Quest User’s Manual. 2003.
Santa Barbara County Planning and Development (SBCO 2008). October 2008. Environmental
Thresholds and Guidelines Manual.
United States Department of Transportation (USDOT), Bureau of Transportation Statistics.
Various Years. National Transportation Statistics.
West, Kim. 2016. Personal communication. Email from Kim West, Project Engineer (Olympic
Pipeline) to Karmen Martin (ESA). August 5, 2016 at 4:32 PM with attachment.