HomeMy WebLinkAboutD_HEX_Decision_Additional_Exhibits_2001091
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BEFORE THE HEARING EXAMINER FOR THE CITY OF RENTON
RE: Puget Sound Energize Eastside
Conditional Use Permit
LUA18-000055, CU-H, SME
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FINDINGS OF FACT, CONCLUSIONS OF
LAW AND FINAL DECISION
Summary
Puget Sound Energy (“PSE”) has applied for a conditional use permit and a shoreline exemption for
the upgrade of 4 miles of two existing 115 kV transmission lines into two 230 kV transmission lines
beginning at the Talbot Hill substation, continuing north along the existing PSE transmission line
corridor to the northern City limits. The permit applications are approved subject to conditions.
The most time intensive and significant issue by far for this proposal was pipeline safety. This Decision
contains a detailed assessment of many of the public concerns raised over pipeline safety, because th e
record does not contain such an applicant or staff response to many of the safety comments submitted
for conditional use permit review. The assessment of pipeline safety is addressed at Finding of Fact
(“FOF”) 5A, pages 4-17 of this Decision. The cities responsible for the environmental review of the
project wisely hired qualified independent professionals to evaluate the safety risks of the project.
Contrary to the opinion of some project opponents, the safety analysis prepared for the project was
objective, credible and competently produced given the limitations in available data and information
on pipeline operations. Several project commentators, at least two of which appear to be engineers,
provided highly detailed and well-sourced critiques of the safety analysis produced by the city
consultants. Most of the pipeline safety comments had already been duplicated in prior stages of
environmental review conducted by the City of Bellevue. The Final Environmental Impact Statement
(“FEIS”) contains responses to many of these duplicated comments. However, several issues had not
been addressed. FOF 5A provides a detailed response to both ensure that safety impacts are adequately
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addressed and to provide a final1 opportunity for City and Applicant response through the
reconsideration process should project opponents find that their concerns still have not been fully
addressed.
Perhaps the second most significant issue associated with the proposal is the need for the project. The
Coalition of Eastside Neighborhoods for Sensible Energy (“CENSE”) brought the need for the proposal
to the forefront by well organized and extensive documentation, qualified professionals, talented
presenters and a large number of concerned citizens living throughout the Eastside. PSE “opened the
door” on the issue by explaining why it needed to upgrade its project, i.e. to meet future electrical
demand and to avoid blackouts. For this reason, CENSE was allowed to make its argument that there
is no need and that alternative energy sources should be more effectively utilized. CENSE’s
participation in the process has clearly been in the public interest and has served the public good by
bringing important energy issues into public debate. However, CENSE’s need issues are not pertinent
to the review criteria of the conditional use permit under review. Conditional use permit review is
focused upon land use impacts such as traffic, noise and impacts to environmental resources such as
streams and wetlands. PSE’s business plan and its affect on utility rates is not a land use impact. To the
extent that those issues could be framed as land use impacts, they are found to be adequately addressed
under the jurisdiction of the Washington State Utilities and Transportation Commission (“UTC”). The
UTC has direct oversight and regulatory authority over the type of issues raised by CENSE, i.e. efficient
use of energy resources and consideration of alternative energy sources in a manner that assures least
cost to utility rate payers. The relevancy of CENSE’s need issue is resolved in Conclusion of Law No.
8, pages 37-40 of this decision.
The other impacts of the proposal have largely been thoroughly addressed in the FEIS prepared for the
project as augmented by an EIS Consistency Analysis, Ex. 2. Those impacts are summarized in FOF
5B-P, p. 17-33 of this Decision.
Testimony
A summary of testimony, not a part of this decision, is appended as Appendix A.
1 At least one commentator was critical of the fact that in the Bellevue permitting review process there was no
opportunity for cross-examination of witnesses. No requests for cross-examination were made in this proceeding, so
any objections based upon cross-examination rights should be considered waived. However, in at least some types of
contested land use proceedings such as administrative appeals, hearing participants have a due process right to cross -
examine technical experts. See Chrobuck v. Snohomish County, 78 Wn.2d 858, 870 (1971). In the Renton PSE
hearing it would not have been feasible to grant the several dozen hearing participants the right to cross -examine all
City and PSE experts. The detailed assessment of pipeline safety of this Decision in conju nction with the
reconsideration process is intended to provide an avenue to question the reports of the technical experts in lieu of the
cross-examination process. In this respect, City and Applicant experts are expected to provide a response to any
motions for reconsideration filed on pipeline safety. However, all reconsideration motions, responses and replies
cannot contain any new evidence, as that would violate the one -hearing rule imposed by the Regulatory Reform Act,
specifically the limitation imposed by RCW 36.70B.050. See the Reconsideration section of this Decision at p. 40 for
reconsideration procedures.
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Exhibits
Exhibits 1-18 identified at page 2 of the January 8, 2020 staff report. The following documents were
entered into the record during the January 8, 2020 hearing:
Exhibit 19 City PowerPoint
Exhibit 20 Google Maps
Exhibit 21 COR Maps
Exhibit 22 PSE Brief/Witness Statements
Exhibit 23 CENSE Notebook
Exhibit 24 CENSE PowerPoint
Findings of Fact
Procedural:
1. Applicant. Brad Strauch, Puget Sound Energy, PO Box 97034, EST-3, Bellevue, WA 98009-
9734
2. Hearing. The hearing on the application was held in the Renton City Council Chambers at 5:00
pm on January 8, 2020.
3. Project Description. The Applicant is requesting Hearing Examiner Conditional Use Permit
approval and a Shoreline Exemption for the upgrade of 4 miles of two existing 115 kV transmission
lines with two 230 kV transmission lines beginning at the Talbot Hill substation, continuing north along
the existing PSE transmission line corridor to the northern City limits. The proposed upgrade would
require the replacement of approximately 144 existing wood and steel poles (H-frame designs) with
approximately 41 steel monopoles of either single-circuit or double-circuit design. The height of the
proposed poles would vary by location but are estimated at an average height of between 85 and 95
feet. Within the Talbot Hill substation, additional breakers and associated controls will be added to
accommodate the new lines.
The Applicant requests approval of a shoreline exemption for the transmission line crossing of the
Cedar River. The project would include the replacement of aerial wire across the Cedar River, which
is classified as a Shoreline of the State. The project proposes the replacement of poles outside of the
200-foot shoreline jurisdiction and the aerial wire crossing would not require any disturbances within
the shoreline jurisdiction.
4. Environmental Review. The proposed transmission line upgrades will be installed through the
cities of Bellevue, Redmond, Newcastle and Renton through the existing PSE transmission corridor,
totaling 16-18 miles for the upgrade area. The City of Bellevue has assumed lead agency status over
the environmental review of the entire upgrade project to meet the requirements of the State
Environmental Policy Act (“SEPA”), Chapter 43.21C RCW. Bellevue required an environmental
impact statement (“EIS”) to assess project impacts throughout all four affected cities. The four cities
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along with Kirkland were all involved in preparation of the EIS and are referred throughout this
decision as the “EIS team” along with its consultants. The EIS was prepared in two phases, with Phase
1 issued in January 2016 addressing multiple design options and Phase 2 issued in May 2017 focusing
on the preferred option. A final EIS (“FEIS”) was issued May 2018.
5. Adverse Impacts. There are no significant adverse impacts associated with the proposal.
Pertinent impacts are more specifically addressed as follows;
A. Pipeline Safety. The proposal will not materially increase the risk of unintentional pipeline
release along the co-located Olympic Pipeline.
Pipeline safety is the greatest impact of concern and took up the most time to address in
preparation of this Decision. Several commentators, at least one of whom has an
engineering background, provided extensive comment on their safety concerns regarding
co-location of the Olympic Pipeline system, which runs parallel to the proposed
transmission lines for 1,200 feet in the City of Renton. See Rogers hearing testimony.
A risk assessment prepared by a contractor hired and supervised by the EIS team for the
Phase 2 EIS determined that the proposal would not increase the risk of pipeline
unintentional releases. EDM Services, Inc., a firm specializing in pipeline safety, prepared
the risk analysis. See Phase 2 EIS, p. 1-29. As shall be discussed, the EDM report2 found
that the proposed initial operation of the two transmission lines at 115kv and 230kv would
create a nominal increase in the risk of unintentional release. In response, PSE revised its
proposal to only operate both lines at 230kv. According to the risk study, operating at 230kv
would result in no increase over baseline pipeline incidents, which presumably would result
in no increase in risk caused by PSE’s proposal.
The potential increase in pipeline incidents caused by operating the lines at 115kv/230kv is
instructive on the impact of the proposed transmission line over pipeline safety. The
increase in risk over current conditions by the 115kv/230kv proposal would result in a 1 in
51 million increase in risk to a total risk of one in 4.5 million in the chance that a person
living within proximity of the pipeline would be killed by an unintentional pipeline release.
See Figure 3.9-12 Phase 2 EIS. This represents a 9% increase over current conditions. In
terms of “societal risk” as identified in page 3-9-42 of the Phase 2 EIS, there is a one in 2
million probability of an event resulting in 17 fatalities occurring in any 1-year time period,
and a one in 60,000 probability of an event resulting in a single fatality occurring in any 1-
year period with the proposal. This represent an 8% increase in risk over current conditions.
These societal risks are above the thresholds for negligible impacts, and below the
thresholds for intolerable impacts as used by Santa Barbara County and the California
Department of Education for school siting purposes. By comparison, the annual risk of
2 References in this Decision to the “EDM report” pertain to the May 2017 study by EDM entitled “Energize Eastside
EIS Pipeline Safety Technical Report,” attached as Appendix I-5 to the Phase 2 EIS.
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being struck by lightning is one in one million and being killed in a vehicle accident is one
in 47,718.
The only source of added risk of pipeline release attributable to the 115kv/230kv line in the
EDM report was AC interference. AC interference denotes an induced current along the
pipeline caused by an electric field generated by the proposed transmission lines. At certain
levels, this induced current can increase the rate of pipeline corrosion, which in turn can
result in unintentional pipeline releases. This AC interference was the only risk factor for
pipeline leak that EDM considered to change3 as a result of the colocation of the proposed
transmission lines in its risk factor analysis. Compare Figure 9.2.5-1 with Figure 9.3.5-1 of
EDM Report. EDM assumed in its risk analysis that corrosion leak incidents would be
increased by 50% for the currently existing transmission line over baseline conditions and
would increase by 100% for the proposed 115/230kv line arrangement, based upon the fact
that the 115/230kv line would induce a greater current density. See EDM report, p. 80 and
83. The EDM report also acknowledged that AC interference can increase pipeline voltage,
which can injure or kill people who touch the pipeline at high voltages.
The EDM study used the results of an AC interference study prepared by a PSE consultant
to address the added risk of AC interference. The AC interference study was prepared by
Det Norske Veritas (U.S.A.), Inc. (“DNV”)4. From prior studies, DNV determined that an
induced current under 20 amperes per square meter will not increase corrosion. Industry
recognized standards also set 15v as the limit for safe induced voltage. The amount of
current induced by transmission lines is in part influenced by pole location and
configuration. DNV determined that all induced currents and voltages would be less than
the 20-ampere corrosion threshold and 15v voltage threshold when the two transmission
lines proposed by PSE are both operated at 230kv and the poles are located and configured
as recommended by DNV.
PSE had originally proposed to operate its two transmission lines at 115kv for one line and
230kv for the other line for the initial stages of operation but agreed to operate both lines at
230kv to avoid the corrosion and voltage risks identified in the DNV study. In the absence
of any increase in corrosion risk under 230kv/230kv conditions, employing the
methodology of the EDM study, there would be no increase in pipeline release incidents by
the proposed co-location of the transmission lines since there would be no addition to risk
3 The “change” is a change to the baseline data used in the EDM report. The baseline data of the report, as detailed in
Section 5 of the report, was based upon pipeline leaks reported to the United States Department of Transportation for
the years 2010 through 2015 for refined petroleum product pipeline releases. See Figure 5.2-1. The releases were
broken into several categories, such as equipment failure, incorrect operation and external corrosion. The only
“change” to this baseline data was the addition of AC interference incidents to the external corrosion category.
4 References to the “DNV Report” in this Decision are to DNV’s December 2016 report entitled “AC Interference
Analysis – 230 Kv Transmission Line Collocated With Olympic Pipelines Opl16 & Opl20 .” The report was not
actually entered into the record by the Applicant or City. However, it was extensively referenced by the project
opponents contesting pipeline safety as well as within the EDM report. For these reasons, the DNV report is
considered to be part of the record.
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caused by AC interference. In fact, the risks under the EDM analysis would be lower for
the proposal since the currently existing transmission line creates AC interference whereas
the proposed transmission lines will not. From this information it must be concluded that
according to the methodology of the EDM risk assessment, operating the lines at
230kv/230kv will not increase risk of pipeline release.
EDM did a separate analysis for construction impacts, assuming that construction impacts
would increase release rate by 50%. That analysis concluded that the risk in creating 17
fatalities was one in 428 million and the maximum increased risk in individual fatality is
one in 58 million, both of which are below the Santa Barbara County and the California
Department of Education acceptable risk thresholds for school siting purposes. See EDM
report, p. 91 and 102.
It is recognized that despite the extensive numerical analysis that underlies the EDM study
and its reliance upon industry data, its core conclusions rely upon assumptions based
entirely upon unsupported professional judgment. These assumptions are (1) the only
significant impact attributable to the proposal beyond that already factored into the baseline
data is AC interference; and (2) AC interference results in a 50% increase in corrosion
release for current conditions above the baseline data and a 100% increase in corrosion
release above baseline data for the proposed 115kv/230kv transmission line configuration.
EDM provides no reasons, data or studies for these assumptions. Nonetheless, project
opponents have not provided any compelling evidence or argument to the contrary and there
is no reason to doubt EDM’s competence or objectivity in making these judgement calls.
The preponderance of evidence in the record establishes that these judgment calls provide
for an accurate assessment of pipeline safety risk.
Given the nominal or potentially even reduced fatality risk associated with the project, in
conjunction with the extensive mitigation recommended by the EIS team as formulated by
its independent consultants, it is determined that the proposal will not create any significant
impacts to adjoining properties by virtue of pipeline safety impacts.
The EDM risk analysis was subject to extensive criticism by several project opponents, at
least a couple of whom appear to have engineering backgrounds and some experience in
pipe corrosion issues. Most of the concerns raised by those commentators were addressed
in the FEIS comment response section of the FEIS, Appendix K. However, some were not.
The major issues raised in the public comment letters are addressed below.
i. EDM/DNV Credibility. At least one commentator has challenged the credibility of
PSE, Olympic Pipeline and utilities in general based upon specific instances of past
conduct by PSE and utilities in general. The EDM report was prepared by a qualified
consultant with expertise in pipeline safety that was hired by the EIS team. See Phase
2 EIS, p. 1-29. DNV was retained by the PSE, but its study was subject to peer review
by Stantec Consulting Services Inc., which was hired and supervised by the EIS
team. Based on Stantec's experience and industry standards, it was Stantec’s opinion
that the technical approach used by DNV to achieve an optimal transmission line
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route and powerline conductor configuration to minimize the AC interference risks
on the Olympic Pipeline system is consistent with industry practice. See FEIS, p. 4.9‐
37. There is no reason to dispute the impartiality or competence of EDM or Stantec.
Although their services were paid for by PSE, their contractual responsibility for
preparing a competent and impartial report was to the EIS team. The EIS team had
no interest other than to protect the public from pipeline hazards in hiring and
supervising EDM and Stantec.
As further noted by the EIS team at p. k-591 of the Phase 2 EIS:
For specialized analysis related to electrical transmission and pipeline
safety, the EIS Consultant Team has involved engineers, scientists, and
scholars in appropriate fields. To evaluate changes in pipeline safety risk
that would occur as a result of the Energize Eastside project, EDM Services,
a firm specializing in pipeline risk and system safety, was retained to
conduct a probabilistic pipeline risk assessment. The EIS Consultant Team
also retained Stantec Consulting Services, Inc. (Stantec) to perform an
independent, technical review of the AC Interference Study prepared by
DNV GL. Based on Stantec's experience and industry standards, it is their
opinion that the technical approach used in the analysis is consistent with
industry practice.
One project opponent identified that DNV had been fired by the State of Michigan
for a conflict of interest and appearance of improper influence. See Elworth letter,
Ex. 6, p. 22. Mr. Elworth did not identify the circumstances of the Michigan
situation and there is no suggestion in the record of any actual bias in DNV’s work
for Michigan or any error in its judgment or analysis. The Michigan situation, to the
extent disclosed in this administrative record, does not present grounds for
discounting the work of DNV given that its work was subject to peer review by
Stantec.
ii. AC Corrosion Threshold. The DNV report correctly concluded that AC interference
would not increase corrosion on the Olympic pipeline so long as the induced current
on the pipeline was less than 20 amperes per square meter.
As previously identified, the EDM risk analysis was based upon the conclusion that
AC interference was the only source of increased leak risk created by the proposal
beyond baseline data. The risk of AC interference, in turn was based upon the DNV
report. The DNV report identified that AC interference did not increase corrosion
so long as induced current on the pipeline does not exceed 20 amperes per square
meter. In a letter 38b of Ex. 6, Todd Anderson asserted that the 20-ampere threshold
is based upon a standard that hasn’t been adopted by any jurisdiction, whereas the
European Union has a standard setting a threshold of 3 amperes per square meter.
Since AC interference is the primary source of added safety risk created by the
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proposal and assessment of that risk is dependent upon the corrosion threshold, an
accurate corrosion threshold is critical to an accurate assessment of pipeline safety.
From the source material presented by Mr. Anderson, it is clear that his
understanding of the European Union standard is based upon a typographical error
in a pipe corrosion technical article that intended to reference the standard as 30
ampere per square meter as opposed to 3 amperes per square meter.
Mr. Anderson cites the basis for his assertion that the European standard is 3
amperes per square meter from the following reference in page 7 of the article
(admitted into Ex. 6), Strategy For Eliminating Risks Of Corrosion And
Overprotection For Buried Modern Pipelines, by Fumio Kajiyama:
ISO 155891 prescribes for the AC corrosion risk and CP as follows: If the
a.c. current density on a 100 mm 2 bare surface (e.g. an external test probe)
is higher than 3 A/m 2 (or less, in certain conditions), there is a high risk
of corrosion. Risk of corrosion is mainly related to the level of a.c. current
density compared to the level of CP current density. If the a.c. current
density is too high, the a.c. corrosion cannot be prevented by CP.
(emphasis added).
The reference to 3 A/m2 is contradicted by other portions of the article. On the same
page, the article cites to a 1992 study that sets 30 A/m2 as the threshold. Page 10 of
the article again identifies 30 A/m2 as the threshold, citing to ISO 155891, the same
standard referenced in the quote above for the alleged 3 A/m2 threshold standard.
ISO 1558915 (the 2003 version as cited in the article) itself nowhere sets a threshold
of 3 A/m2. Instead, a "NOTE" at p. 33 of the standard identifies that there's a high
risk of corrosion above 30 A/m2. The ISO standard otherwise does not set a
threshold for AC induced current corrosion.
The DNV report derived its 20 A/m2 threshold from the results of an investigation
of a corrosion failure incident in Germany in 1986, where it was learned for the first
time that AC interference could corrode pipelines. The results of that investigation
revealed that corrosion could occur at current densities of 20 A/m2, that corrosion
may or may not occur at 20-100 A/m2 and that corrosion did occur for current
densities exceeding 100 A/m2. See DNV report, p. 10. The findings of the
5 ISO 155891 was not admitted as an exhibit. However, Mr. Anderson asserts that the 3 A/m2 is a standard adopted
by the European Union (EU). In the Volume 4 EIS comment responses, EDM stated it was not aware of any adopted
European Union A.C. interference risk standard, which was apparently a reference to Mr. Anderson’s assertion that
the 3 A/m2 had been adopted by the EU. If Mr. Anderson was co rrect in his assertion, the Examiner can take judicial
notice of adopted EU standards. If ISO 155891 has not been adopted by the European Union or any other governmental
entity, judicial notice could not be taken but Mr. Anderson’s argument that the standard should be applied would also
be rejected.
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investigation were adopted into a 2010 report published by National Institute of
Corrosion Engineers (NACE) TG 327 International Report entitled “AC Corrosion
State of-the-Art: Corrosion Rate, Mechanism, and Mitigation Requirements”. DNV
relied upon this NACE standard to assess the AC interference created by the
proposal.
Mr. Anderson didn’t find the NACE standard used by DNV compelling, because it
has not been adopted by the American National Standards Institute or the
Department of Defense. Mr. Anderson also noted that the NACE website labels the
standard as inactive. See Letter 38b of Ex. 6. However, as noted in p. K-619 of the
FEIS, Stantec determined that the standards and references used in the DNV-GL
report are those used in the industry. Stantec noted that the 30 A/m2 corrosion
threshold is the standard used in Europe and the direction North America is also
moving to in a new NACE AC Corrosion Criteria Draft standard that is in the
process of being approved.
From the information above, it is clear that there is no 3 A/m2 corrosion threshold
standard adopted in Europe and that DNV’s use of 30 A/m2 instead of 20 A/m2 was
a very conservative application of AC interference standards.
iii. Pipeline Incident Baseline. EDM’s risk analysis was based upon pipe incident rates
collected by the United States Department of Transportation (“USDOT”) for US
refined petroleum pipelines for the period between January 2010 and December
2015, which involved 805 unintentional pipeline leaks over a total of 379,086 miles
that were reported pursuant to the mandates of federal regulations, specifically 49
CFR 195.50. See EDM Report, Table 5.2-1. As previously discussed, EDM
augmented this data with the increased risk associated with AC interference from co-
located transmission lines. As augmented, the baseline data is found to provide an
accurate and appropriate bases for assessing increased pipeline incident risk created
by the proposal.
In Letter 76, p. 36 of Ex. 6, Todd Anderson asserts that the baseline data is not
appropriate because it only covers a six-year period, doesn’t distinguish between
new and old pipes and doesn’t distinguish between incidents involving pipelines co-
located with transmission lines and those that are not. As identified at Footnote 34
of the EDM report, the six-year timeframe was based upon the parameters of the
data base made available by USDOT.
The limited number of years involved in the baseline data is appropriate given the
evolving safety standards applicable to pipeline safety. USDOT creates a new data
base when there is a change in operator reporting requirements to ensure that all data
contained within the database is consistent. As noted at p. 3.9-18 of the Phase 2 EIS,
use of the relatively current data also assures that review of incidents is limited to
those governed by current safety standards, which are designed to prevent
occurrences that happened prior to 2010. As noted at p. k-212 of the FEIS, as a result
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of the 1999 Bellingham release6 and other pipeline incidents, the National
Transportation Safety Board (NTSB) made a number of recommendations that
resulted in new pipeline regulations requiring improvements in pipeline integrity
management. Due to this new federal legislation, the State of Washington passed
the Underground Utilities Damage Prevention Act in 2011 that increased
requirements for pipeline operators operating in the State of Washington. Further,
even though the data base only covers six years of US pipelines, the pipeline data
covers 379,086 miles of pipe data as shown in Table 3.9-2 of the Phase 2 EIS, which
the Phase 2 EIS concludes “provides a large and appropriate sample size for
conducting a risk assessment”. See p. 3.9-18, Phase 2 EIS.
As to the age of the pipelines and the number of lines co-located with transmission
lines, as noted in the EDM report, that type of information isn’t available from the
USDOT baseline data. As previously noted, EDM accounted for the AC interference
by increasing the baseline external corrosion incidents by 50% for the existing
transmission line and 100% for the proposed 115kv/230kv line. No increase in risk
was assigned to the 230kv/230kv configuration because no AC interference was
found to occur under this configuration as determined in the DNV report.
EDM made no adjustment to the USDOT baseline data for the age of the PSE line,
but Mr. Anderson did not provide any bases for concluding that disparity in pipeline
age would be statistically significant. Instead, Mr. Anderson asserted that the
information was available in the industry and PSE simply chose to avoid using that
data since it would not serve its purposes. This contention misses the point that PSE
did not put the baseline data together. That task was done by EDM under the
supervision of the EIS team at the expense of PSE.
As previously noted, EDM has no reason to bias its results and EDM was qualified
to do its analysis. Given that EDM found the baseline data it used to be sufficiently
accurate for its statistical analysis and the absence of any compelling evidence it
was deficient, the data is found to be appropriate and accurate for assessing pipeline
safety risk.
iv. Stress Corrosion. As outlined above, the EDM risk analysis was premised on the
professional opinion that the only modification to operational baseline data necessary
to account for the impacts of the proposal was the incorporation of AC interference
impacts. In Letter 36b, Ex. 6, Todd Anderson devotes a significant amount of his
analysis to highlight the absence of any accommodation for stress corrosion in the
EDM risk analysis. Unfortunately, Mr. Anderson doesn’t provide any clear
explanation of what stress corrosion is or present any evidence or explanation as to
6 The Bellingham incident was a release of 237,000 gallons of gasoline from an Olympic pipeline in Bellingham,
Washington on June 10, 1999 that resulted in a pool fire within a creek that killed three people. See Phase 2 DEIS,
Appendix I-1.
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how the proposal would increase stress corrosion. In reviewing prior comments from
Mr. Anderson on the same subject, the EIS team noted the following in its Volume
4 EIS response to his stress corrosion concerns:
Regarding stress corrosion, the EIS Consultant Team could not find
information to suggest a direct relationship between topography (e.g., hilly
or flat land) or fault conditions and stress corrosion cracking occurrences
on pipelines. Stress corrosion cracking is a form of corrosion that
occasionally occurs as a result of the combined influence of pipeline stress
due to its pressurized contents and a corrosive medium. Due to the higher
pipeline temperatures, pipeline incidents attributed to stress corrosion
cracking are more common on natural gas pipelines than on hazardous
liquid pipelines (for additional information, see U.S. Department of
Transportation's 'Fact Sheet: Stress Corrosion Cracking' at:
https://primis.phmsa.dot.gov/comm/FactSheets/FSStressCorrosion.htmRef
er).
FEIS, v. 4, p. k-644
The EIS consultant team also noted at p. k-632 that AC interference and AC
corrosion do not cause stress corrosion cracking and that a Japanese article cited by
Mr. Anderson in his written comments (referenced in Finding of Fact No. 5Aii
above) was only referring to stress cracking caused by cathodic over-protection.
Given the lack of evidence and clarity in Mr. Anderson’s concerns and the absence
of any evidence or reasonable inference in the record that the proposed transmission
lines would have any impact on stress corrosion cracking, stress corrosion serves as
no bases to overturn the professional judgment of EDM that the proposal will not
increase the risk of unintentional pipeline releases.
v. Holiday Current. The DNV estimates of induced current density from AC
interference take into account the high current densities associated with small
holidays (coating flaws).
Brian Elworth asserted in his Ex. 6 correspondence that the DNV analysis didn’t
take into consideration the fact that current density at small holidays can be
magnified as much as 10,000 times, thus greatly exceeding the 20 A/m2 corrosion
threshold applied in the DNV analysis. It is determined that the impacts of small
holidays have already been factored into the DNV analysis and that the presence of
small holidays on the Olympic pipelines will not undermine the accuracy of the
DNV analysis.
Page 11 of the DNV report identifies the formula used by DNV to estimate induced
current density on the Olympic pipeline. As is readily seen in the formula, holiday
diameter is factored into the formula. As revealed in the accompanying text, DNV
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factored in the presence of one-centimeter holidays into the formula. DNV
referenced research that has found that holidays of one to three centimeters in
diameter create the highest corrosion rates. Addressing the one to three centimeter
holidays, DNV noted at Page 10 that “[h]oliday testing during installation of the
pipeline should catch all holidays of this magnitude, but in general smaller holidays
could be missed; so the smallest, or one square centimeter, is considered in
calculation of AC current density.” The fact that DNV has taken small holiday size
into account in its induced current estimation was confirmed by the v4 FEIS
comment responses, which noted at page k-502:
In their analysis, DNV GL considered the current density on a worst case
one square centimeter coating holiday and the measured soil resistivity,
along with the induced AC potential from the model, which is consistent
with industry practice and very conservatively high for the age of the
Olympic pipelines. Thus, the small coating holiday is already used in this
calculation and the final number for current density.
It is also significant that DNV field tested its formula and found that it accurately
estimates induced current density. DNV applied its induced current formula to
existing conditions and then compared the modelled results to readings of current
density under existing conditions. The results of the modeling closely mirrored field
conditions. See Figure 8, p. 11 of DNV report. Given that the formula used by DNV
to estimate induced current density takes holiday size into consideration and that its
results are field tested as accurate, the evidence is clear that DNV induced current
estimates accurately account for small holiday size.
vi. Spacing/Amperage Guidelines. The spacing between transmission lines and power
lines, the amperage of the power lines and the width of the transmission corridor, has
been properly taken into account in assessing pipeline safety risk.
Sue Stronk in a letter in Ex. 6 identified industry guidelines that recommend a 25-
foot separation between parallel pipelines, a 50-foot separation between
transmission lines and pipelines and the transmission line corridors to be 120 to 150
feet in width. CENSE expressed similar concerns in Ex. 23. Actual spacing for the
proposed transmission line involves a corridor width of only 100 feet, minimum
spacing between pipeline and transmission lines of 13 feet and 14-foot separation
between power lines.
Along similar lines, Barbara Braun writes in Ex. 6 that a 2015 report from DNV
identifies the association of a high corrosion risk with pipelines that are closer than
100 feet to powerlines, with powerlines having currents greater than 1,000 amps
(PSE proposes approximately 1,500 amps) and colocation distances between
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powerlines and pipelines of more than 5,000 feet (PSE’s line will be collocated with
the pipeline for several miles).
The standards cited by Ms. Stronk are not mandatory, but rather are what should
govern the configuration of new transmission line corridors when there is a
reasonable opportunity to meet the standards. Those conditions are not present here,
as the transmission line corridor goes through a heavily developed area where
numerous residences and other properties would have to be removed in order to
expand and/or realign the transmission corridor. In its report, EDM has taken into
consideration all the mitigation necessary to ensure that spacing of the pipeline from
the proposed transmission line facilities doesn’t increase unintentional pipeline
release for factors such as minimum arc separation for lightning and separation
necessary for construction. Project opponents have not identified any other
compelling factors in need of additional mitigation to compensate for the nonideal
separation conditions present in the existing transmission line.
The high-risk factors identified by Ms. Braun have similarly been adequately
incorporated into EDM’s pipeline risk assessment. As noted by the EIS response
team at p. k-499 of the FEIS in addressing the same comments made by Ms. Braun
in a prior comment letter:
The risk ranking referenced by this commenter attempts to assist with
identifying the susceptibility of a pipeline to AC interference based on
several factors. Once identified as a potential risk, a detailed study
including modeling is required to determine the actual AC interference
levels the pipeline would be exposed to, to quantify the actual risks, and to
design required mitigation. The pipelines were identified as requiring a
detailed study, which was completed by DNV GL as part of the AC
Interference Study completed for the project.
vii. Earthquake Damage. The foundation depths for the proposed transmission poles
do not increase the risks of unintentional pipeline release due to earthquake damage.
PSE proposes to maintain a minimum of 13-foot separation between the
transmission poles and the pipeline in order to place the poles outside the maximum
arc distance as recommended in the DNV report. In Renton, the proposed pole
foundations are proposed to have depths of 13 to 46 feet. As noted by Todd
Anderson in one of his letters, a major earthquake could cause the foundation of a
downed pole to hit the pipeline and rupture it.
The concept of a pole foundation moving laterally in an earthquake to rupture the
pipeline has not been directly addressed by the EIS team or its consultants.
However, as noted at p. 309 of the FEIS, the American Society of Engineers found
that standards applicable to utility poles for wind/ice and broken wire forces exceed
those that apply to buildings to protect against earthquakes. The FEIS at p. 341 also
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noted that PSE calculations showed that the poles will in any event meet
International Building Code seismic requirements. The EIS team also noted at p. k-
386, v4 of the FEIS that the risk of downed power lines will be lower with the new
transmission poles given the anticipated upgrades to PSE’s infrastructure under the
project, including the use of steel versus wood poles and newer standards not
applicable during the installation of the existing poles. Perhaps, most important, P.
k-182 of the FEIS further notes that PSE retained a Washington licensed
geotechnical engineer to evaluate seismic hazards and compare the design of the
project facilities to withstand probable seismically induced ground shaking at each
location. It is anticipated that the poles would withstand such conditions and would
not fall as a result of an earthquake or other natural forces, including extreme
weather. On a final relevant point, it must also be recognized that the Renton
segment of the transmission line is outside the Seattle fault and no new poles are
proposed within any liquefaction hazard areas. See FEIS, Section 4.11.5.8.
However, the Renton segment intersects an identified landslide hazard area that
according to the FEIS has received geotechnical evaluation and appropriate design
measures by a Washington State licensed geotechnical engineer.
From the comments made by the EIS team as outlined above, it is clear that the
transmission poles have been designed to withstand earthquake events and that they
will not be located within any earthquake hazard area. However, earthquakes could
still trigger landslides in the project area and it’s not clear from the record whether
the proximity of the pipeline was factored into the applicable regulations or
geotechnical analysis (the geotechnical report for the Renton segment was not
submitted into the record).
Overall, the fact that the EIS team did not find any cause for concern over Mr.
Anderson’s earthquake concern is sufficiently compelling to find no significant risk
of rupture due to seismic activity Other than identifying the pole depth exceeds
pipeline separation distance, Mr. Anderson provided no evidence that there was any
material chance that a pole foundation could damage a pipeline in an earthquake.
Relying upon simple common sense, which appears to be the entire basis of Mr.
Anderson’s position, it appears that if an earthquake or landslide is strong enough
to upend a foundation more than 13 feet deep, that earthquake or landslide will be
rupturing the pipeline independently of the foundation in any event. These
circumstances, in conjunction with the fact that the poles are designed to withstand
earthquakes and are located outside of seismic fault and liquefaction areas provides
substantial evidence and establishes more likely than not that the foundation depths
for the proposed transmission poles do not increase the risks of unintentional
pipeline release due to earthquake damage.
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viii. Size of Pool Fire. The pool fire modeled in the EDM report appropriately identifies
a worst-case scenario for purposes of assessing pipeline safety risk.
The FEIS pipeline risk analysis identifies that the most likely source of injury and
fatality from an unintentional pipeline release is a pool fire. Accurately modeling
the size of such a fire in highly populated areas such as Renton, therefore, is essential
to accurately assessing the number of persons that could be killed or injured in a risk
analysis. Section 7.1 of the EDM report models a pool fire for a “worst-case”
maximum release volume of 8,861 barrels (or 372,162 gallons). See v4 EIS, p. k322.
The assumptions used in the pool size modeling were questioned by numerous
project opponents, who noted that the modeling assumed flat terrain with no water
bodies. Without citation, Todd Anderson asserts in his Ex. 6 comments that only 1%
of the transmission corridor is flat. He also provided anecdotal evidence of a
waterline release in Bellevue that resulted in a water dispersion far more extensive
than that presented in the EDM model. CENSE points out that a hill near the Sierra
Elementary school undermines the accuracy of the pool fire assumptions. See Ex.
23, p. 13.
As detailed at v4 FEIS, p. k322, to estimate a reasonable “worst-case” or maximum
release volume, the risk assessment used USDOT hazardous liquid pipeline release
data, filtered to include only refined petroleum product releases in order to be as
directly applicable to the Olympic Pipeline system as possible, and then normalized
the data to the pipe diameter of the Olympic pipelines. The risk assessment used the
average of the largest spill size range (6,000 to 12,000 barrels) to arrive at an average
"maximum" spill size of 8,861 barrels (or 372,162 gallons). The risk assessment also
considered the maximum population density in estimating societal risk.
Project opponents present some compelling arguments on the deficiencies of the
“worst case” pool fire modelled by EDM. As is evident from the preceding
discussion, EDM’s presentation of “worst-case” conditions isn’t actually worst-
case, but “reasonable” worst case which assesses risks based upon the severe end of
the range of possible outcomes to unintentional pipeline releases. However, in the
professional assessment of acceptable risk, project opponents have not demonstrated
or even contended that in using reasonable worst-case analysis as opposed to the
worst possible outcome, EDM has failed to use proper risk assessment methodology.
There is nothing in the record to remotely suggest that a ”reasonable” worst case
analysis approach is not required when evaluating whether a proposal meets
acceptable risk levels such as those set by the California Department of Education,
which were employed in the EDM risk assessment. In point of fact, absent any
evidence to the contrary, it is reasonable to conclude that the risk levels created by
the professionals who set the California Department of Education were based upon
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the expectation that risk assessment would be based upon the methodology of
standard industry practices.
As identified at Finding of Fact 5Ai above, EDM is a firm specializing in pipeline
safety. EDM was hired by and subject to the supervision of the EIS team, not PSE.
EDM used CANARY software, specifically designed to model pool fires, to model
the size of a reasonable “worst-case” pool fire. The pool fire was based on the largest
releases that can be reasonably expected to occur from an unintentional release.
Project opponents gave examples of how the pool fire could be worse, but none
provided any evidence that the EDM risk assessment failed to meet industry
standards. For these reasons, it is concluded that the EDM modelled pool fire serves
as an accurate and appropriate bases for assessing pipe safety risk.
ix. Leak Detection. The general effectiveness (or lack thereof) of leak detection is
already factored into the EDM risk analysis and the EDM conclusion that the
proposal doesn’t appreciably increase pipeline safety risk.
Mr. Elworth and Mr. Anderson both questioned the effectiveness of Olympic’s leak
detection system, pointing out that the size of an unintentional pipeline spill is
directly linked to how quickly it is detected. As noted in a quote by Mr. Anderson
in one of his letters in Ex. 6: “According to a Reuters review of PHMSA data, since
2010, there have been at least 466 incidents in which a pipeline carrying crude oil
or refined products has leaked. Of those, only 105, or 22%, were identified by an
advanced detection system.” Mr. Ellsworth identifies that hearing materials suggest
that pipeline inspections only happen every five years and that corrosion leaks can
easily occur between inspections given corrosion rates of one millimeter per year
and the pipe depth of 0.250 inches. See Ex. 6.
There may very well be deficiencies in leak detection as identified by Mr. Anderson
and Mr. Elworth, but these deficiencies have already been factored into the baseline
data used for the rate study. See EDM study, Section 5. The baseline data is based
upon all reported leaks from refined petroleum product pipelines to the United States
Department of Transportation as required by 49 CRF 195.50. These leaks occurred
under the state and federally mandated leak detection systems of pipeline companies
throughout the United States from 2010 through 2015. Although Olympic Pipeline
has had its past problems with leak detection as identified by Mr. Anderson, there’s
nothing in the record to suggest that Olympic’s current leak detection system and
operation is any less effective than those of the other companies reporting pipeline
incidents for baseline data.
x. Lightning. The proposal adequately mitigates against lightning damage it may cause
to the pipeline.
In an Ex. 6 comment letter Brian Elworth succinctly expresses concern over
lightning damage as follows: The replacement of the insulting [sic] wood
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transmission line support structure with tall conductive metal towers, essentially
lightning rods grounded near the hazardous liquid pipeline, while removing the
lightning dissipating natural tree canopy is a gross breach of safety common sense.
Mr. Elworth’s concerns on lightning strikes has been fully addressed in the DNV
and associated Stantec review by implementing a minimum 13-foot separation (arc
distance) between transmission lines and pipelines, along with field verification
required to assure that the separation is sufficient to prevent lightning arcing. As
noted by the EIS team in v.4 FEIS, p. k-509:
As long as the pipeline is outside of the maximum calculated arcing distance
[13 feet], then the risk has been mitigated. The Canadian Energy Pipeline
Association (CEPA) published a report called A/C Interference Guideline
Final Report, which summarizes the use of the Sunde equation to calculate
the lightning arcing distance and a regression formula developed in
Canadian Electricity Association (CEA) report 239T817 to assess the arcing
distance due to a lightning initiated power arc (i.e., from powerline fault
current). The DNV report only uses the Sunde equation for this assessment,
while Stantec recommended that they also consider the CEA regression
formula. This recommendation is included as a mitigation measure in Section
4.9.8 of the Final EIS. Based on the DNV GL recommendations, PSE revised
the design from that presented in the Phase 2 Draft EIS to ensure that all
poles would be at least 13 feet from the pipelines, because this was the
maximum calculated arc distance necessary to prevent arcing between the
poles and the pipelines, based on soil conditions in the corridor. If the
modeled conditions are correct, there would be no risk of arcing damage.
However, soil conditions are quite variable; therefore, actual arc distances
could vary. Actual arc distances will be measured at each pole once the poles
are installed. Where necessary, pole grounds would be installed to provide
adequate separation from the pipelines. See Final EIS Section 4.9.8,
Mitigation Measures.
B. Visual and Aesthetic Impacts: As mitigated and conditioned, the Visual and Aesthetic
impacts of the project will not be significant.
The visual and aesthetic impacts of the project are related to several factors including the
appearance and form of the utility infrastructure itself; the impact on scenic views; and tree
removal. The EIS team characterized the existing aesthetic environme nt through an
assessment of the visual character in the built and natural environment, the effected
population, and the existing visual quality (FEIS, Appendix C, page C-6). Most views of
the project will be within a ¼ mile, most often when the view of the project is in the
foreground and the viewer is likely to experience the full scale of the project from close
proximity (FEIS, Appendix C, page C-3). The methodology used by the EIS team applied
parameters it entitled Natural Harmony, Built Order and Utility Coherence in the existing
and built out conditions. The most desirable features for each of these parameters included
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undisturbed natural areas; planned urban areas; and the presence of the least feasible
number of small poles with few wires, which are consistent in height, and form and blend
into the surrounding environment.
For purposes of defining significant impact, the EIS team defined impacts with respect to
the general aesthetic environment and to scenic views. The most important aspect with
respect to aesthetic impact was the degree of contrast between the project and the existing
aesthetic environment. A substantial contrast, especially where viewer sensitivity is high,
was considered a significant aesthetic impact. Significant impacts to scenic views were
defined when the area with the scenic view is impacted and that impact includes many
sensitive viewers such as residential viewers, viewers from parks and trails and/or outdoor
facilities. The other important consideration is the degree of the additional obstruction of
scenic views compared to the existing view (FEIS Section 4.2.3.4, page 4.2-7 and Appendix
C, page C-24). The FEIS found “impacts to the scenic views and the aesthetic environment
in the Renton Segment would be less than significant” (FEIS Section 4.2.5.9). The rationale
is that there is a low contrast between the existing PSE facilities and the new project
facilities that would replace them with respect to use, form and function. The siting of the
new project in the existing right of way location accomplishes the mitigation goal of
decreasing the visual impact (FEIS, Appendix J, page J1-68).
The FEIS acknowledges that tree removal has the potential to create large visual impacts;
that the project height and scale may make it a dominant visual feature in the built
environment given it is much higher than the surrounding built features and different in
character from the surrounding uses; and that the project at build out could involve
significant changes from the existing character of the use over short distances in areas with
higher viewer sensitivity (FEIS, Appendix C, page C-9). It is these impacts the project must
minimize or mitigate to the extent feasible. The most significant areas of potential visual
and aesthetic impacts are related to the utility infrastructure itself and the loss of trees.
i. Compatibility of Utility Infrastructure. The Renton section of the project is
surrounded by a variety of uses including institutional and single-family residential
areas, sometimes in areas of high visibility (FEIS, Appendix C, page C-15). However,
of the 185 adjacent parcels, 42% of the corridor is currently vacant. The Renton
segment goes through several established single and multi-family residential
neighborhoods. Sunset (Renton Highlands) is one of the City’s older developed areas
and is comprised of commercial and residential uses; it is currently being redeveloped
with new multi-family, parks, library, and commercial land uses. Several parks are
along the corridor, including May Creek Greenway, Honey Creek Greenway, and the
Cedar River Natural Zone (Exhibit 3, Finding of Fact No. 19d). The FEIS also
identified areas of high potential scenic view impacts in Renton between SR 169 and
SR 900 (FEIS, Appendix C, page C-22).
As noted by the staff report, and as a feature of the chosen alignment, the project will
be located within an existing PSE right of way that contains existing electrical utility
facilities. This use in this location has been established since the 1920s and early
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1930s. All existing uses surrounding the project alignment were built around the
existing utility corridor. The utility corridor is part of the existing character of the
adjacent neighborhoods, which house many tall vertical structures including light
poles, street lights, electrical lines (including Seattle City Light’s existing lattice
tower 230kV transmission lines), communication towers, buildings, and trees
(including Douglas fir, which have a mature height of 70 ft to over 300 ft) (Exhibit
3, Finding of Fact No. 19d).
The project design will involve increasing the height of poles from around 55 feet for
the existing poles to up to 118 feet for the new poles (FEIS, Appendix C, page C-20).
The heights of the proposed poles would be increased to an average height of between
85 and 95 feet under the project proposal. However, there are 70% fewer poles
proposed in the after condition (Exhibit 3, Finding of Fact No. 19a). The transmission
line replacement would reduce the number of poles within the corridor from 144 to
41 poles. The proposed poles would be setback from the edge of the existing
easement area to provide adequate spacing between the poles and the edge of the
easement, and therefore create a sufficient setback to buildings and structures
(Exhibit 3, Finding of Fact No. 19b). This reduction in the number of poles within
the existing utility right of way could potentially improve the visual character of the
area, at least at the ground level.
Several members of the public expressed concern about the visual impacts of the new
utility infrastructure including concerns that the poles would “industrialize the
corridor” and are “looming” (Exhibit 6, Public Comments #8 DeMund and #18
Braun); would be much higher than the existing uses (Exhibit 6, Public Comment #9
CENSIE); and would be out of character for the neighborhood (Exhibit 6, Public
Comments #27 Pipkin, #67 Cieszlak, #72 Willis and Weir – comment submitted at
the hearing). Mitigation for these impacts needs to be evaluated from the ground level
and at the level of the poles and wires.
ii. Ground Level Mitigation. Ground treatment for mitigation of the utility infrastructure
includes screening and visual enhancement. Screening can be accomplished by
fencing and landscaping.
a. Landscaping. Vegetation in a transmission line corridor that has an operational
voltage of more than 200 kV must be managed in compliance with federal
requirements, resulting in limitations with regard to the type and scope of
landscaping that is allowable. Vegetation management standards vary depending
upon the location of vegetation management in relation to transmission wires.
Consistent with federal standards, vegetation in the wire zone (i.e., 10-ft outside
wires) must have a mature height of no greater than 15 feet, unless the local
topography is sufficient to allow a 20-foot vertical clearance between the power
lines and the mature height of trees under the power lines. Trees can be taller
outside the wire zone, but no more than 25-feet in height within the Managed
Right of Way (Exhibit 3, Finding of Fact No. 19h, FEIS, Appendix E, page E-1,
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FEIS page 4.4-4, FEIS Appendix E, page E-6 and FEIS Appendix J, page J1-
73). The deep ravine cut by the Cedar River allows retention of taller trees under
the upgraded transmission lines.
According to the submitted Vegetation Replacement Letter (Exhibit 8), PSE
proposes to mitigate impacts to trees that are necessary to meet federal
transmission line operational standards. To mitigate for loss of significant trees
in the transmission corridor, PSE is proposing mitigation ratios that would
exceed the City’s adopted tree replacement standards as proposed in the
submitted Vegetation Replacement Letter (Exhibit 8).
The Applicant is proposing to work with individual property owners to restore
areas impacted during construction to its previous, or an improved, state. PSE
proposes to work with affected property owners to replace trees in the most
effective manner that meets the permit conditions. (Exhibit 3, Finding of Fact
No. 19h).
All applicable codes and standards will be followed during design and
construction, including electrical, stormwater and erosion control, tree protection,
and noise codes. A condition of approval will require the Applicant to submit a
final Landscape and Tree Replacement Plan to the Current Planning Project
Manager at the time of Construction Permit review for review and approval prior
to construction permit issuance. Maintenance of vegetation within the
transmission line corridor, shall be required to comply with the City’s property
maintenance regulations as outlined under RMC 1-3-3.
b. Artwork. Several FEIS Mitigation measures deal with the siting, form and
materials of the proposed project. One of these measures includes specifying
poles with an aesthetic treatment, such as paint or a self-weathering finish, to
reduce contrast with the surrounding environment (FIES, Appendix M, page M-
20 and FEIS Table 4.2-3, page 4.2-53). The Applicant submitted renderings
including photo simulations of the different pole finishes (Exhibit 31) along the
project corridor. To further enhance the visual environment and to reduce the
visual impact, a mitigation measure was added to the EIS Consistency Analysis
(December 13, 2019, Exhibit 2) requiring that poles visible to the public be
treated with artwork (Exhibit 3, Finding of Fact No. 19d). The proposed concept
of adding artwork to the transmission line poles was approved by the City of
Renton Arts Commission on November 5, 2019. A condition of approval will
require that individual art wraps for the transmission line poles be submitted to
the Current Planning Project Manager for review and approval prior to the
issuance of a Construction Permit. This artwork shall be installed prior to the
energizing of the transmission lines.
c. Light and Glare. As the FEIS notes, loss of vegetation could also “result in less
screening of existing light sources, such as streetlights or lights from buildings”
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(FEIS, Appendix J, page J1-75). The FEIS suggest an appropriate response would
be to ask other utility providers and owners of now visible adjacent buildings with
exterior lighting to provide shielding on the existing lighting. To the extent
practically feasible and consistent with utility regulations and safe practices, the
Applicant shall configure its tree replacement in a manner that minimizes
increased light exposure caused by the proposal.
iii. Above Ground Level Mitigation. With respect to above ground level visual impacts of
the utility infrastructure, other than providing artwork and appropriate coloration, the
other potential mitigation area is restricting the proliferation of co-located
telecommunications facilities, to the extent feasible under state and federal law.
a. Co-Location of Telecommunication Facilities. Todd Anderson (Exhibit 6, Public
Comment #76a & b), expressed concerns regarding the taller poles and the
potential for increased use for co-located telecommunications infrastructure.
Specifically, Mr. Anderson stated he was concerned that the new poles would be
used to site new 5G antennas on every pole, a technology that he states requires
a 100-fold increase in the number of antennas over 4G technology. Furthermore,
Mr. Anderson is concerned that new federal laws will mean the City of Renton
will have no local control over the aesthetics of these telecommunication
facilities.
It should be noted that the project results in 70% fewer poles than in the existing
condition, from 144 down to 41 poles. The City of Renton requires
telecommunication facilities to blend into the existing characteristics of the site
to the extent feasible, including non-reflective neutral paint to match the colors in
the immediate vicinity (RMC 4-4-140(F)(3)). In this case, that would mean to
match the tower the facilities are located upon. Any independent towers must
meet stealth tower standards and be disguised as or on faux trees, flagpoles, sports
field lights or freestanding signs (RMC 4-4-140(I)), while small cell (5G)
facilities will also require concealment (RMC 4-4-140(J)). The Renton standards
comply with Federal regulatory requirements.
Two adopted FEIS mitigation measures specifically address telecommunications
facilities. The first limits the number of telecommunication facilities that could
be installed on the 230kV poles to the number currently installed in the corridor
and proposed to be installed as part of the FEIS. The second FEIS mitigation
measure requires the re-installation of telecommunication facilities to be in the
same approximate locations as they were previously and to comply with the
requirements of Chapter 80.54 RCW, Chapter 480-54 WAC, and local
jurisdiction regulations. See Ex. 2, Environmental Consistency Analysis, p. 3-16.
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The impact of co-location of telecommunications facilities is adequately
mitigated by the adopted FEIS mitigation measures.
C. Loss of Trees. The proposal will not create significant tree loss impacts.
Impacts related to the loss of trees will be mitigated to the extent feasible. Many members of
the public expressed concern over the potential loss of trees, many of which are old growth,
up to 250 years old, and located in critical areas or their buffers7. The FEIS states there is
little vegetation along the Renton Segment with the exception of near Honey Creek and the
Cedar River. Tree removal will be required in the Honey Creek ravine but not in the Cedar
River Valley, though tree removal impacts to a tributary of the Cedar River are indicated
(FEIS, pages 4.2-22 and 4.2-44). There are 574 trees in the study area in Renton. Of these,
367 are significant trees pursuant to RMC 4-11-200 and seven are landmark trees pursuant
to RZC 21.78)8. Approximately 339 (57%) of the total trees in the segment will be removed,
including up to 242 significant trees. This is, overall, 5-10 trees per acre with five of them,
on average, being significant trees. 47 of the total removed trees are within critical habitats
buffers (22 trees from stream buffers and 25 trees from wetlands buffers (FEIS Figures 4.4-
4, 4.4-5, 4.4-6, 4.4-7, 4.4-8, Section 4.4.5.8, page 4.4-22 and Ex. 2, page 2-4 and 2-5). These
trees are all within the existing utility corridor. No City of Renton designated Landmark trees
will be removed (Ex. 2, page 2-15).
The FEIS states that all trees with a mature height of over 15-feet will be removed within a
67-92-foot wide corridor, depending on whether the pole configuration is monopoles or dual
poles (FEIS, Appendix E, page E-1-2). All trees with a mature height over 25-feet will be
removed within the Managed Right of Way (FEIS page 4.4-4, FEIS Appendix E, page E-6
and FEIS Appendix J, page J1-73). The FEIS and Tree inventory Reports analyzed the impact
on trees for most of the project, but specifically did not analyze the effects of tree removal in
Renton (FEIS, Appendix E, pages E-6-8).
The City of Renton requires tree retention at ratios dependent upon the underlying zone. The
Environmental Consistency Analysis includes a mitigation measure that requires trees to be
retained in accordance with the City’s Tree Retention standards (Page 3-6). However, no tree
retention is required for this project based on the City’s tree retention formulas (RMC 4-4-
130(H)) (Ex. 13). Mitigation required in the Environmental Consistency Analysis includes
compliance with the Vegetation Replacement Approach letter (Ex. 8). Additionally, the
Applicant has provided a Mitigation Plan which will include replanting of trees (Ex. 9 and
PSE Renton Mitigation Plan, The Watershed Company, January 2018). Mitigation will
happen on both private property and within the corridor. The Applicant will be required to
7 See Exhibit 6, Public Comments #1, 3, 7-18, 20-24, 26, 31-39, 45, 68, 72 and the hearing testimony of Gillespie,
Weir, and Ossenkop.
8 City of Renton Tree Inventory, Puget Sound Energy – Energize Eastside Project, The Watershed Company, May
2016.
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submit a Final Tree Retention and Replacement Plan at the time of construction permit
review (Ex. 2, Pages 3-7 and 3-8).
With respect to the impact of tree removal on visual and aesthetics, the Environmental
Consistency Analysis contains several mitigation measures which require the retention or
replacement of trees to the greatest extent possible; the limiting of disturbance to what is
necessary for safety and maintenance of the transmission facilities with replanting of
vegetation that would be compatible with vegetation clearance requirements to prevent future
vegetation removal and maintenance in the future; the avoidance of removal of mature trees
in all construction areas, where possible; and the provision of mitigation monitoring for all
trees removed from critical areas (Ex. 2). A condition of approval will require project site
disturbance and tree replacement per the Vegetation Replacement Approach letter (Exhibit
8). As noted above in Finding of Fact No. 5Bii Ground Level Mitigation: Landscaping a
condition of approval will require the Applicant to submit a final Landscape and Tree
Replacement Plan to the Current Planning Project Manager at the time of Construction
Permit review for review and approval prior to construction permit issuance. Maintenance of
vegetation within the transmission line corridor, shall be required to comply with the City’s
property maintenance regulations as outlined under RMC 1-3-3.
D. Geologically and Seismically Hazardous Areas. As mitigated, no impacts from
geologically hazardous areas or seismic hazards are anticipated.
The only portion of the proposal that appears to involve construction in a geologically
hazardous area is within a landslide hazard area near the Honey Creek Open space. The
Renton segment of the project is outside of the Seattle Fault zone but still at risk of ground
shaking hazards in the northern portion of the Renton segment. In addition, the Honey Creek
landslide area could be triggered by a seismic event. Seismic risk is considered low in the
Renton segment of the project.
Though construction and operation of the project cannot completely avoid impacts to
geological areas, mitigation has been proposed to limit the impact of potential geological and
seismic events on the construction and operation of the project. The City of Renton allows
the overbuilding or replacement of existing utility systems in geologically hazardous areas if
the work does not increase the footprint of the structure or line by 10% and occurs within the
existing right of way or easement boundary (RMC 4-3-050). The project segment in Renton
is located entirely within the existing utility corridor and will involve the replacement of
existing poles. Most of the existing poles (70%) will be removed and not replaced as the
project allows for significantly fewer poles than in the existing condition. As mitigation, the
conditions of approval require geotechnical review of all proposed facilities to ensure that
the project meets Renton geologically hazardous area standards.
Implementation of NESC standards overseen by a Washington-licensed geotechnical
engineer will ensure that the geotechnical design of the new poles minimizes the seismic and
landslide hazards present. Since the project portion in Renton is not within the Seattle Fault,
the project is not anticipated to increase seismic risks as it will meet the most recent National
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Electrical Safety Code design standards (FEIS, Chapter 4, Section 4.11.5.8). See Finding of
Fact No. 5Avii for additional discussion on seismic risks.
Best management practices (BMP) are required by the Renton Municipal Code (RMC 4-3-
050) and include the use of appropriate shoring during construction; the use of erosion and
runoff control measures (retention of vegetation where feasible, replanting, the use of ground
cover, etc.); the conduction of settlement and vibration monitoring during construction to
identify potential adverse conditions to critical areas and local facilities; and compliance with
the Renton critical areas codes (FEIS, Appendix M, page M-13). The Energize Eastside
Environmental Consistency Analysis also provided 21 mitigation measures related to the
topic. A condition of approval will require the Applicant to comply with the mitigation
measures set forth in the EIS Consistency Analysis / EIS Addendum, dated December 13,
2019 (Exhibit 2).
E. Streams and Wetlands. All impacts to streams and wetlands will be fully mitigated.
The Renton section of the project crosses four stream segments: Cedar River, Honey Creek,
Ginger River and an unnamed tributary of the Cedar River. Wetlands and the Zone 2
Wellhead Protection Areas are also in the project area.
The project is designed to avoid and minimize impacts to critical areas by utilizing the
existing transmission line corridor, limiting disturbance and implementing best management
practices (BMPs) when working in critical areas, and installing transmission lines between
poles with minimal site disturbance. No new poles are proposed in wetlands, streams or
stream buffers, flood hazard areas, or seismic hazard areas. New poles are proposed in habitat
conservation areas and wellhead protection areas.
The project proposes to impact a single wetland buffer for the placement of a utility pole.
The impacted wetland is a Category III slope wetland. Two existing poles will be removed
from and replaced outside of wetland and stream buffers resulting in a net increase of only
68 sf of permanent wetland buffer impact.
Vegetation community conversion impacts in wetland and stream buffers total 18,786 sf.
19,235 sf of temporary disturbance will occur. A total of 18 trees would be removed from
the Honey Dew Creek buffer and 11 trees would be removed within the Ginger Creek buffer
within the Lower Cedar River sub basin. No impacts are proposed within the 200-foot
shoreline jurisdiction of the Cedar River. Vegetation conversion impacts are also proposed
in wellhead protection areas. Post-construction, all disturbed areas will be re-vegetated, if
necessary, and left to return to their natural state, in accordance with the submitted mitigation
plans (Ex. 10).
The Critical Areas Mitigation plan provides for mitigation ratios for permanent impacts at a
ratio of 1:1. The mitigation of conversion buffer impacts will be a ratio of 0.5:1, which results
in a total of 9,500 sf of wetland buffer enhancement. Proposed mitigati on activities include
invasive species removal and installation of native small trees, shrubs, and groundcover
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plants (Ex. 10). In the Honey Creek buffer, snag creation will mitigate for some impacts to
habitat occurring within the May Creek sub-basin. Best Management Practices (BMPs) will
be used to minimize impacts resulting from pole replacement activities. No permanent
impacts to the wetland or streams and their buffers are anticipated. As mitigated, the impact
to the wetland buffer is adequately alleviated. Impacts to groundwater resources are
anticipated to be minimal and adequately addressed through the City’s regulations and the
application of best management practices.
F. Plants and Animals. Impacts to protected plants and animals are not anticipated to be
significant.
In addition to salmonid species, the Critical Areas Report (Ex. 9) noted the presence of
several priority species including a pileated woodpecker, a bald eagle, and an active ospreys’
nest. The habitat in the study area is limited to forested patches in topographically low
(ravine) areas associated with Honey Creek and the Cedar River. Impacts to plants and
animals will occur during construction, mainly due to the loss of trees. For a discussion on
trees, see Finding of Fact No. 5C. During operation, there will be temporary and minor
disturbances to habitat due to tree trimming and maintenance activities. Though their
presence is noted in the Critical Areas Report, plants and animals (except trees) are not
mentioned in the staff report. Several mitigation measures will help to protect plants and
animals, including several that are related to minimizing impacts to streams, wetlands and
other water resources (Ex. 2). Additionally, the Applicant has provided a vegetation
replacement program (Ex. 8). A condition of approval will require compliance with the
Vegetation Replacement program. As mitigated, impacts to plants and animals should be
minimized or avoided.
G. Climate Change/Greenhouse Gas Emissions. No significant impacts from Greenhouse
Gases are anticipated.
The City of Renton does not have regulations that specifically limit greenhouse gas
emissions. The State of Washington has a reporting threshold of 10,000 metric tons of carbon
dioxide (CO2e) in a given year for project level long-term (operational) impacts to greenhouse
gases. The project would result in emissions of sulfur hexafluoride (SF6) from the Richards
Creek and Talbot Hill substations and 7.5 metric tons of CO2e per year in sequestration losses
from the loss of trees. However, the losses are well below the Washington State reporting
threshold (FEIS, Chapter 4, Section 4.5.7.9). In addition, the Applicant will mitigate for the
loss of trees with tree replacement that exceeds City standards: the project plans to remove
a total of 212 regulated trees and 122 non-regulated (non-significant or landmark trees) and
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replace them with 284 new trees (Ex. 8). With emissions below the reporting threshold, the
impact from greenhouse gas emissions is considered less than significant.
H. Land Use and Housing. The proposal is compatible with and will not adversely affect
Renton land use patterns.
The project passes through 11 zoning districts and several neighborhoods as well as
Shoreline High Intensity and Urban Conservancy Environments along the Cedar River. The
predominant use adjacent to the project is residential. The King County Assessor describes
the mix of uses as 49% residential, 17% vacant, and 9% each industrial and institutional (Ex.
23, Section 9). The utility use is a permitted use in all zones with approval of a conditional
use permit. The Renton segment of the project will be located entirely within an existing
utility corridor. As noted in the Environmental Consistency Analysis (Ex. 2), the proposal is
consistent with City of Renton land use plans and will not impact future land use patterns
(Page 2-16). It will also not remove or impact existing housing beyond landscape impacts.
No poles will be placed in the shoreline (Ex 3). As noted in the Staff Report, the proposal is
consistent with the City of Renton Comprehensive Plan (See Ex. 3, Finding of Fact 15 and
16 adopted herein as if set forth in full).
In its testimony, CENSE notes impacts to land use and housing that are both financial and
aesthetic. For a discussion of the visual impacts, see Finding of Fact No. 5B. CENSE notes
the removal of mature landscaping could have a negative impact on property values (Ex. 23,
Section 9). As described in Findings of Fact No. 5B Visual Impacts and 5C Loss of trees, the
impact on landscaping will be mitigated to the extent feasible. All landscaping impacts,
though on the scale of decades for trees to mature, will be temporary.
CENSE also argues that properties next to high voltage transmission lines sell for less than
homes that are not adjacent to this use. The Phase 1 EIS relied on a study prepared by the
Electric Power Research Institute to answer this question. The study was an overview study
summarizing the results from 50 similar studies. The results of the study were inconclusive
as property values were found to decrease, stay the same or even increase. The EPRI study
found there was evidence that transmission lines have the potential to decrease nearby
property values by about 3-6%, with lots directly adjacent to the right of way tending to
benefit. The loss of property value was most significant in higher end properties. The effect
on sales prices was difficult to determine as no clear pattern emerged, except that the effects
of a transmission line on sales prices of properties diminish over time and all but disappear
in five years (Phase 1 EIS, Chapter 10, Section 10.7.1.4).
The Phase I EIS does not identify whether any of the studies apply to the impacts of upgrades
to existing power lines as they do for this project. Clearly, the impacts of an existing line on
the value of a new home or a new transmission line on an existing home would be
significantly greater than an upgrade to an existing line as is considered for PSE project. The
Renton segment of the project is located entirely within an existing electrical transmission
line corridor that has been in place since the 1920s with upgrades in the 1960s. Given the
minor effect that transmission lines have on property values overall and the relatively minor
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change in transmission corridor specific to this project, impacts to property values are not
considered significant.
I. Transportation. The proposed transmission line upgrade is located within the existing
utility corridor. Because adjacent land uses and roads already integrate with the transmission
lines, once operational, the upgraded transmission lines would not disrupt vehicles or
pedestrians in the surrounding areas (Ex. 3, Finding of Fact No. 19f).
Temporary construction impacts may occur during project construction. Construction
vehicle access to pole replacement sites would be made from existing roads or newly
constructed temporary access roads. The project in Renton is located entirely within an
established and developed utility corridor with maintenance and access routes in place. The
proposed pole locations would be near existing accessible routes to minimize impacts to
traffic from project construction. The proposed transmission line upgrade does not require
the construction of walls, fences or screening vegetation, which further ensures that the
existing uses and circulation would not be disrupted.
Access to adjacent land uses would be maintained during construction. Informal recreational
activities occur throughout the project area. There are both formal and informal recreation
trails within and across several segments of the existing PSE transmission line corridor,
which is generally viewed as a green belt. Post-construction, neighboring properties will
have the same uses and circulation patterns as currently exist.
Conditions of approval will require the Applicant to submit a pedestrian and vehicular traffic
control plan at the time of Construction Permit for review and approval by the Plan Review
Section prior to the issuance of a Construction Permit and to provide a plan for any closures
to City Parks and/or trails. The park and trail closure plan will also be submitted to the
Community Services division for review and approval prior to the issuance of a Construction
Permit.
The PSE easement bisects the City as a whole. The City needs to provide an interconnected
transportation grid and prevent dead end streets. Therefore, public roads will need to extend
through the corridor. To permit the construction of future City public street connections as a
result of future development, a condition of approval will require future public road
transportation connections within the transmission line corridor to be permitted when needed
to accommodate future development to the extent that PSE’s easement does not preclude
said connections. No other transportation impacts are anticipated.
J. Noise. The proposed transmission line replacement will not result in any significant noise
impacts when completed and in use. Chapter 9 of the Phase I EIS contains an analysis of
potential operational and construction-related noise impacts. With respect to operational
impacts, the Phase I EIS states:
“Potential operational impacts from overhead transmission lines associated with any of
the transmission line alternatives would occur from corona discharge. The maximum
corona noise produced from 230 kV lines at ground level during wet weather conditions
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[is] a relatively low noise level that would not be noticeable in most suburban
environments. . . Background ambient noise levels in suburban residential areas of King
County fall between 40 and 50 dBA during nighttime hours. Even in rural areas, corona
noise from 230 kV transmission lines would be unlikely to impact sensitive uses.
Consequently, audible corona noise would be a negligible operational noise impact…”
(Phase 1 EIS, Section 9.6.3.1).
The proposed transmission line replacement may have temporary construction-related noise
impacts on surrounding neighbors. Temporary construction impacts (consistent with the
limited durations described above) would terminate once construction is complete.
No significant excavation is required, and installation would not create significant noise.
Noise-generating activity during pole installation would occur for a relatively short period
of time and is likely to fall within the bounds of typical construction noise. The City requires
best management practices to minimize impacts from noise. (See RMC 4-4-060(J)(5-6)).
Some of the areas along the Renton segment are possible candidate locations for the use of
helicopters because of the complex terrain in the area. It is important to note that using a
helicopter is the last option utilized by a contractor due to costs and additional FAA
permitting (Ex. 3, Finding of Fact No. 19g). The use of helicopters is most likely for the
crossing over the Cedar River.
No noise impacts from the operational phase are anticipated. Noise from construction will
be temporary in nature and adequately mitigated.
K. Parking. No new parking spaces are proposed or necessary for the transmission line upgrade.
Parking for construction vehicles is proposed to be provided within the existing transmission
line corridor or adjacent street parking during active construction. In addition, it is possible
that recreation sites or facilities may be used for temporary construction staging. PSE
proposed to work with the City of Renton to identify suitable locations for construction
staging that would result in minimal impacts to parking. Such suitable locations may include
overflow parking areas or parts of the site that are underutilized. In order to ensure that
adequate parking is provided during project construction, a condition of approval will require
the Applicant to provide a construction staging and parking plan to the Current Planning
project manager for review and approval prior to the issuance of Construction Permits.
L. Historic and Cultural Resources. Historical and cultural resources in the Renton segment
include one archeological site, 117 individual historic inventory properties and one historic
district. No impacts to the archeological site are anticipated given all proposed pole
replacements will be located away from the site. Five of the 117 individual historic inventory
properties are eligible for the National Register of Historic Places (NRHP); however, the
transmission corridor predates each of these (Ex. 2, page 2-18). Poles would be located
within the existing transmission corridor, resulting in little change from existing conditions,
with the possible exception of visual impacts. For a discussion of the visual impacts, see
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Finding of Fact No. 5B. Historic and cultural resource impacts were considered during the
design of the proposal. Design details for pole types and placement were created to reduce
impacts on historic and cultural resources.
The most significant potential historic property is the electrical transmission system itself
including the corridor, H-poles and the Talbot Hill substation (Phase 2 EIS, Section 3.7.2.1).
The other significant historical resource in the Renton segment is the Mt. Olivet Cemetery.
This cemetery has been in use since 1875, though it was not officially platted until 1891
(Phase 2 EIS, Section 3.7.2.7). Significant individuals here include notable members of the
Native American community and local pioneers. This cemetery in its modern form is likely
to have been built on a former Native American cemetery. There may be unmarked graves
beyond the current dedicated boundaries of the cemetery. This cemetery is not a listed
historical resource and is therefore not protected as an historical archeological resource.
However, it is still a protected cemetery pursuant to Chapters 68.60 RCW and 68.50 RCW.
Graves outside of the boundaries of the cemetery are protected under Chapters 68.60.010
RCW and 27.44 RCW. The nearest poles to the Mt. Olivet Cemetery will be approximately
750 feet and 900 feet southeast of the cemetery.
There are many regulatory requirements designed to protect Historic and Cultural resources.
The Environmental Consistency Analysis lists nine required regulatory mitigation measures
in this category (Ex. 1, Section 3.9). The Applicant will be required to work with the
Washington State Department of Archeological and Historic Preservation, affected tribes,
King County and all appropriate stakeholders to identify and protect historic and cultural
resources. As mitigated, impacts to historic and cultural resources will be avoided or
minimized to the extent feasible.
M. Recreation. The proposal will not adversely affect recreational resources. Recreational uses
will remain accessible. There will be both visual impacts and a loss of trees which could
affect the recreational experience. However, both types of impacts will be mitigated to the
extend feasible.
There are many recreational opportunities within the Renton segment of the project. The City
of Renton does not have regulations that require mitigation of project-related impacts to
recreational resources. Impacts to recreation sites in the Renton segment are anticipated to
be minimal because vegetation clearing and changes to poles and wires would not affect the
use of these sites (Ex. 2, page 2-18). Impacts to recreational areas may be visual and aesthetic.
For a discussion of visual and aesthetic impacts, see Finding of Fact No. 5B. For a discussion
regarding Loss of Trees, see Finding of Fact No. 5C. Recreation sites might be temporarily
closed during maintenance (FEIS, Chapter 4, Section 4.6.5.1). No recreation sites will be
permanently lost or substantially altered.
Three pairs of H-frames are located within the Sierra Heights Park. These would be replaced
by two 95-foot tall poles and two 50-foot tall poles at each pole site. The PSE corridor crosses
a portion of the Sierra Heights Elementary School campus. However, the school’s sports
fields are separated from the transmission line corridor by a forested area. The poles will not
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likely be visible from the school. The Honey Creek Open Space will see four H-frame poles
(two sets) replaced with two approximately 95-foot tall poles. Though the poles are taller,
there are fewer of them than in the existing condition. The vegetation in the deep ravine that
houses Honey Creek will be unchanged. However, 40-50 trees will be removed from the top
of the slopes, which will be visible to users on the trail. In the Cedar River Natural Zone, two
H-frames will be replaced with a single 100-foot tall monopole. Two poles will be located in
the natural area. Like at Honey Creek, the poles will be taller but there will be fewer of them
than in the existing condition. In this area 50-55 trees will be removed. Also, as in the case
of Honey Creek, only vegetation near the top of the slopes will be removed. No trees will be
removed from Riverview Park. Trail users will see the loss of trees and the new poles.
However, use of the trail will be unchanged.
N. Environmental Health: Electromagnetic Fields. The electromagnetic fields of the
proposal will not adversely affect public health.
Existing magnetic fields in the study area for the Renton segment are already associated with
PSE transmission lines and substations. The FEIS evaluated electromagnetic impacts for the
area immediately under and adjacent to the transmission lines, including areas within 250
feet from the centerline of the transmission line corridor (FEIS, Chapter 4, page 4.8-1).
Neither the City of Renton nor the State of Washington has adopted EMF guidelines or
standards for electric transmission lines. Exposure guidelines have been adopted by the
International Commission on Non-Ionizing Radiation Protection (ICNIRP), the American
Council of Governmental Industrial Hygienists (ACGIH) and the Institute of Electrical and
Electronics Engineers (IEEE) (FEIS, Chapter 4, Section 4.8.1, Page 4.8-5). Each agency has
different guidelines for safe exposure by the general public. These range from 1,000
milligauss (mG) to 9,040 mG over a 24-hour period of exposure. Given the operation period
(assumed 2027-2028), under existing conditions the maximum exposure in Renton is
between 177-219 mG in the worst-case scenario (FEIS, Chapter 4, Table 4.8-2). Because the
poles will be higher, relative to the existing circumstance, the exposure in Renton will
decrease from existing conditions to a maximum worst-case exposure of 34.5 mG (FEIS,
Chapter 4, Section 4.8.5.8). Therefore, no negative health impacts from electromagnetic
fields are anticipated.
Conclusions of Law
1. Authority. Hearing examiner conditional use permits qualify as Type III review pursuant to
RMC 4-8-080(G). As outlined in RMC 4-8-080(G), the Hearing Examiner is authorized to hold
hearings and issue final decisions on Type III applications subject to closed record appeal to the Renton
City Council. Shoreline exemptions qualify as Type I review pursuant to RMC 4-8-080(G). RMC 4-
8-080(C)(2) requires consolidated permits to each be processed under “the highest-number procedure”.
The Type III review is the “highest-number procedure” and therefore must be employed for the
conditional use and shoreline exemption review.
2. Zoning/Comprehensive Plan Designations. The project site is located within multiple zoning
designations, including: Commercial Arterial (CA), Commercial Office Residential (COR), Center
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Village (CV), Light Industrial (IL), Residential-1 (R-1), Residential-10 (R-10), Residential-14 (R-14),
Residential-4 (R-4), Residential-6 (R-6), Residential-8 (R-8), Resource Conservation (RC), and
Residential Multi-Family (RM-F).
3. EIS Adequacy. Several project opponents argued at hearing that the FEIS is inadequate because
PSE is only applying for a portion of the proposal as described in the FEIS. Specifically, project
opponents assert that PSE has only applied for the southern portion of the transmission corridor that
links the Talbot substation to the proposed Richards Creek substation as opposed to the transmission
line assessed in the FEIS which ran from the Talbot station all the way to the Sammamish substation.
The hearing examiner has no jurisdiction to address the adequacy of the EIS. Further, there is no
reasonable basis to conclude that PSE will not follow through on constructing the entire proposal.
The SEPA rules authorize administrative appeals of the adequacy of EISs. WAC 197-11-680(3)
authorizes cities to adopt administrative appeal procedures for the adequacy of EISs and importantly
only authorizes one such appeal of the SEPA Responsible Official’s approval of the adequacy of an
EIS. As identified at p. FS-II of the FEIS, Carol Hellend from the Development Services Department
of the City of Bellevue served as the SEPA responsible official. As she testified at the Renton
conditional use permit hearing, the City of Bellevue has not elected to adopt an administrative appeal
process for the decision of the SEPA responsible official to approve or deny the adequacy of an EIS.
In the absence of available administrative appeal, the only forum for appealing the adequacy of the
FEIS is judicial. Ms. Hellend testified that such a judicial appeal has been filed against the City of
Bellevue. It might be the case, although unlikely9, that Renton’s administrative SEPA appeals process
could have been used to challenge the adequacy of the FEIS as it applies to PSE’s conditional use
permit application for Renton, but whether that appeal was available is a moot point because no timely
administrative appeal was filed.
In the absence of an administrative appeal the examiner has no authority to address the adequacy of the
FEIS. Approval of an FEIS is a separate decision made by the SEPA Responsible Official. See WAC
197-11-460. The validity of that decision cannot be attacked in another permit review absent a timely
appeal. See Wenatchee Sportsmen Ass’n v. Chelan County, 141 Wn.2d 169, 182 (2000), and Habitat
Watch v. Skagit County, 155 Wn.2d 397 (2005).
As opposed to arguing that the EIS is inadequate, the position could be taken that a decision can’t be
issued on the conditional use permit yet because environmental review hasn’t been completed on what
PSE is in fact proposing. WAC 197-11-070(1) prohibits the issuance of a land use decision prior to
issuance of a determination of non-significance or FEIS for the proposal. If PSE has sufficiently
changed its proposal such that it no longer bears any material resemblance to what was assessed in the
FEIS, then one could take the position that the proposal subject to the conditional use permit application
hasn’t been subject to any environmental review and hence no conditional use permit decision can be
9It’s unlikely that Renton’s appeal process could be used to challenge the adequacy decision of Bellevue’s SEPA responsible
official. It’s unclear if Renton even has an appeal process for EIS adequacy. RMC 4-9-070M adopted WAC 197-11-680 by
reference, which gives the City the option of adopting an administrative SEPA appeal process. However, the RMC doesn’t
appear to anywhere expressly elect to exercise that option.
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issued. However, that isn’t the situation here. For one, there is no evidence that PSE will not follow
through on the complete transmission line between the Talbot and Sammamish substations. PSE is a
few years behind schedule in applying for the transmission lines north of the Richards Creek substation,
but delays in project implementation are hardly unique and, in any event, PSE is also behind schedule
in its application for the transmission line through Renton.
More pertinent for purposes of Renton’s review of the project is whether limiting the project between
the Talbot and Richards Creek substations reduces the accuracy or utility of the environmental review
provided by the FEIS. As noted in Richard Aramburu’s materials, the EIS team concluded that the
project could still operate and provide added power to the Eastside if the new transmission line was
limited to the corridor between the Talbot and Richards Creek substations. A close review of the
environmental impacts assessed by the FEIS doesn’t reveal any change in environmental impacts to
Renton residents that would be caused by cutting the proposal short at the Richards Creek substation.
The design and configuration of the transmission line would remain the same and the extensive amount
of colocation between pipeline and transmission line north of the Renton segment doesn’t suggest any
change in AC interference impacts within Renton.
4. Review Criteria/Finding of Compliance with Shoreline Exemption Criteria. A conditional use
is required for the proposed expansion because “large utilities” are only authorized in all zoning
districts by RMC 4-2-060O upon approval of a conditional use permit. RMC 4-11-210 specifically
includes 230kv transmission lines in its definition of large utilities. Conditional use criteria are
governed by RMC 4-9-030(D). The Applicant also requests approval of a shoreline exemption for its
proposed crossing of the Cedar River. RMC 4-9-190C.3 governs the criteria for shoreline exemptions
and the proposal satisfies that criteria for the reasons identified in Finding No. 18 of the staff report.
Applicable conditional use standards are quoted below in italics and applied through corresponding
conclusions of law.
Conditional Use Permit
RMC 4-9-030(D)(1): The proposed use shall be compatible with the general goals, objectives, policies
and standards of the Comprehensive Plan, the zoning regulations and any other plans, programs, maps
or ordinances of the City of Renton.
5. The criterion is met. The proposal complies with applicable zoning regulations, the
comprehensive plan and all other pertinent applicable ordinances for the reasons identified in Finding
No. 15, 16 and 17 of the staff report.
A comment letter from Seco Development (Ex. 6), notes that staff only checks off the comprehensive
plan policies and doesn’t identify why the policies are met. The policies and goal cited in the staff
report, specifically Goal U-O, Policy U-67 and Policy U-68, in total encourage the availability of safe,
adequate and efficient electrical infrastructure within existing utility corridors when possible while
concurrently minimizing adverse impact on the environment and adjacent land uses. The proposal
meets all of these parameters. Seco identifies two additional policies, specifically U-1 and U-8, which
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require utility services to be consistent with Comprehensive Plan growth projections and to encourage
the use of new technology to increase the quality and efficiency of utility services.
As noted in the Seco letter, the staff report doesn’t provide any analysis as to why the comprehensive
plan goals and policies are met, but the reasons are fairly self-evident from the record. For the reasons
identified in Finding of Fact No. 5 of this decision, the proposal minimizes impacts to the
environmental and adjacent land uses and is overall safe. The proposal is limited to an existing corridor
as encouraged by Policy U-68. As to efficient use of utility services, the UTC ensures efficient use of
utility resources as outlined in Conclusion of Law No. 8 of this decision. Finally, on the issue of meeting
Renton growth targets, the preponderance of evidence and substantial evidence in the record establishes
that the proposed upgrade will meet Renton’s future power needs. Section 1.3 of the Phase I EIS
identifies power demand analysis conducted by PSE that has been verified by EIS team peer review as
accurate. As identified in Conclusion of Law No. 8, PSE is required to put together an Integrated
Resource Plan that shows how the power company will meet projected demand in an efficient manner.
On the other side, CENSE has presented a significant amount of evidence that the proposed upgrades
are not necessary to meet projected demand. There is no evidence and no reasonable inference that can
be made from the evidence in the record that the upgrades will not be enough to meet future City of
Renton demand.
In addressing utility efficiency and quality, Policy U-8 encourages the use of new technology. The
Seco letter points out that the Richards Creek substation, to be placed in Renton, embraces such new
technology and that Renton has not benefitted from any similar facility. As far as can be ascertained
from the record, the Richards Creek substation is the only significant new PSE facility as part of the
overall Energize project that doesn’t have a similar counterpart in the Renton segment. The Richards
Creek substation is located in a central part of the new corridor, which suggests this was simply the
most logical place to put the structure from an engineering standpoint, as opposed to any
accommodation made to the City of Bellevue. The Phase I EIS explores alternative forms of energy
technology and concludes that the proposal under consideration best meets the development objectives
of PSE. As outlined in Conclusion of Law No. 8, PSE must also consider strategies including new
technologies to assure that utility rates are kept to a minimum. Given all these considerations, it is
concluded that new technology has and will be considered in project design as required by Policy U-8.
RMC 4-9-030(D)(2): Appropriate Location: The proposed location shall not result in the detrimental
overconcentration of a particular use within the City or within the immediate area of the proposed use.
The proposed location shall be suited for the proposed use.
6. The criterion is met. The project is located entirely within the existing electrical transmission
corridor. The transmission line replacement would reduce the number of poles within the corridor by
over 70% from 144 to 41 poles. The proposed poles would be setback from the edge of the existing
easement area to provide adequate spacing between the poles and the edge of the easement, and
therefore creating a sufficient setback to buildings and structures. The proposal to upgrade the
transmission line within PSE’s existing electrical transmission line corridor would not result in a
detrimental overconcentration of a particular use within the City or within the immediate area. The
majority of the utility corridor does not currently house other electrical utilities. Thus, the proposed
project does not over concentrate the particular land use, which is already an existing utility corridor.
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The utility corridor is part of the existing character of the area. By selecting this route through Renton,
PSE limits new impacts and ensures consistency with the existing uses, which already accommodate a
utility corridor. This criterion is satisfied.
RMC 4-9-030(D)(3): Effect on Adjacent Properties: The proposed use at the proposed location shall
not result in substantial or undue adverse effects on adjacent property.
7. As determined in Finding of Fact No. 5, there are no significant adverse impacts associated
with the proposal, so it will not result in substantial or undue adverse effects on adjacent property.
8. Project Need Not Relevant. The need for the transmission corridor upgrade is not relevant to
the criterion above, or in the alternative, is adequately addressed by the oversight and regulatory
authority of the Utilities and Transportation Commission.
A major concern for many hearing participants is the need for the proposal. Numerous project
opponents, in particular CENSE, believe that the power needs of the Eastside will not increase in any
appreciable manner to necessitate a transmission line upgrade (Ex 23, page 16). Project opponents also
believe that PSE should be looking to other forms of energy, such as solar and wind, to augment its
transmission grid supply so that the upgrades are not necessary.
The only criterion that could remotely require demonstration of need for the project is that quoted
above. Authorizing unnecessary transmission line upgrades could result in higher electrical rates for
Renton residents, which arguably qualifies as a substantial or undue adverse impact on adjacent
properties under the criterion quoted above. The failure to effectively use renewable energy sources
such as solar and wind likely could result in environmental impacts, but these impacts would be highly
attenuated and there is nothing to reasonably suggest that the environmental impacts of PSE’s business
plan will affect “adjacent property” beyond the environmental impacts already exhaustively addressed
in this permit review process.
Potential rate increases are not the type of impacts contemplated within the scope of “adverse impacts”
contemplated in RMC 4-9-030(D)(3). Rate increases are not land use impacts within the purview of
zoning regulations. As noted within the purpose clause of the conditional use chapter,
“[c]onditional Use Permits allow for review of certain uses with special characteristics that
may not generally be appropriate within a zoning district, but may be permitted subject to
conditions and mitigation measures that protect public health, safety and welfare and ensure
compatibility with other uses in the district.”
In short, conditional uses are uses that can’t be permitted outright within a particular zoning district
without an assessment of its impacts and compatibility on adjoining uses. It’s important to note that
conditional uses are uses that would otherwise be authorized within a specific zone if it weren’t
otherwise for these impact issues. Utility rate increases have nothing to do with the suitability of a
proposed use within a particular zone. Compatibility is assessed on impacts that are considered when
placing a use within any zone, which are traditionally based upon land use impacts such as noise, light,
trip generation and the bulk and height of structures. The feasibility of a business plan and the wisdom
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of its choices is not a factor considered in land use permit review, unless those choices result in
environmental as opposed to economic impacts.
Even if rate increases caused by unnecessary need were pertinent to Renton’s conditional use review
process, those rate increases have been effectively and appropriately minimized by the oversight of the
Washington State Utilities and Transportation Commission (UTC). RCW 80.01.040(3) empowers the
UTC to
“[r]egulate in the public interest, as provided by the public service laws, the rates, services,
facilities, and practices of all persons engaging within this state in the business of supplying
any utility service or commodity to the public for compensation.”
Pursuant to this authority, the UTC adopted WAC 480-100-238, which requires electric utilities to
adopt an integrated resource plan (“IRP”), the purpose of which is to help meet an electric utilities
responsibility to meet future demand “with a least cost mix of energy supply resources and
conservation.” See WAC 480-100-238(1). The plan must forecast demand, assess the availability and
feasibility of energy resources and adopt a capital facilities plan “that is designated to meet current and
projected future needs at the lowest reasonable cost to the utility and its ratepayers .” See WAC 480-
100-238(3)(f). The plan serves as a tool in UTC evaluation and approval of PSE electrical rates. See
WAC 480-100-238(6). The IRP is subject to a public hearing before the UTC as well as a public
participation process. See WAC 480-100-238(5). A new IRP is required every two years. See WAC
480-100-238(5). The 2015 IRP includes the Energize Eastside project.
Through tools such as the IRP, the UTC is able to fulfill its mandate to ensure that capital
improvements. As summarized in Section 2.2.2.4 of the Phase 2 EIS:
PSE has a legal obligation to deliver safe, dependable power, and an obligation to do so at a
reasonable cost. PSE continually balances these obligations in determining the best solutions
to solve problems facing the electric system. The Washington Utilities and Transportation
Commission (UTC) also has an obligation to review all PSE projects to determine if the solution
is reasonable and prudent. After a project is complete and before the costs are allowed to be
placed into the rate base, PSE must prove to the UTC that the cost to build a project is prudent
and reasonable to ratepayers. This means PSE must research and compare costs and benefits
of multiple alternatives that can accomplish the desired objectives. This is not a simple lowest
project cost test; it is a holistic review and analysis of factors such as projected duration of
solution, risk to the electric system associated with the type of solution (e.g., is the solution an
untested technology), and impacts to the community, as well as the dollar cost of the project.
PSE has completed some of this evaluation already and will continue to evaluate costs through
the design and permitting phase of the project.
In short, if the proposal is not needed, the UTC won’t pass the costs of the proposal to adjacent property.
From the process outlined above, it is determined that the UTC review process adequately ensures that
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adjacent property owners will not be adversely affected by rate hikes caused by any unneeded portions
of the PSE proposal.
RMC 4-9-030(D)(4): Compatibility: The proposed use shall be compatible with the scale and
character of the neighborhood.
9. The Renton section of the project is surrounded by a variety of uses including recreational,
institutional, commercial, industrial and residential areas, sometimes in areas of high visibility. As
noted by the staff report, and as a feature of the chosen alignment, the project will be located within an
existing PSE right of way that contains existing electrical utility facilities. This use in this location has
been established since the 1920s and early 1930s. All existing uses surrounding the project alignment
were built around the existing utility corridor. The utility corridor is part of the existing character of
the adjacent neighborhoods, which house many tall vertical structures including light poles, street
lights, electrical lines (including Seattle City Light’s existing lattice tower 230kV transmission lines),
communication towers, buildings, and trees (including Douglas fir, which have a mature height of 70
ft to over 300 ft) (Exhibit 3, Finding of Fact No. 19d). See also Finding of Fact No. 5Bi.
The project design will involve increasing the height of poles from around 55 feet for the existing poles
to up to 118 feet for the new poles (FEIS, Appendix C, page C-20). The heights of the proposed poles
would be increased to an average height of between 85 and 95 feet under the project proposal. However,
there are 70% fewer poles proposed in the after condition (Exhibit 3, Finding of Fact No. 19a). The
transmission line replacement would reduce the number of poles within the corridor from 144 to 41
poles. The proposed poles would be setback from the edge of the existing easement area to provide
adequate spacing between the poles and the edge of the easement, and therefore creating a sufficient
setback to buildings and structures (Exhibit 3, Finding of Fact No. 19b). This reduction in the number
of poles within the existing utility right of way could potentially improve the visual character of the
area, at least at the ground level. The project, given its location within an existing, long established
utility corridor, is determined to be compatible with the scale and character of the neighborhood.
RMC 4-9-030(D)(5): Parking: Adequate parking is, or will be made, available.
10. As described in Finding of Fact No. 5K, no new parking spaces are proposed for the
transmission line upgrade. Parking for construction vehicles is proposed to be provided within the
existing transmission line corridor or adjacent street parking during active construction. In addition, it
is possible that recreation sites or facilities may be used for temporary construction staging. PSE
proposed to work with the City of Renton to identify suitable locations for construction staging that
would result in minimal impacts to parking. In order to ensure that adequate parking is provided during
project construction, a condition of approval will require the Applicant to provide a construction
staging and parking plan to the Current Planning project manager for review and approval prior to the
issuance of Construction Permits.
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RMC 4-9-030(D)(6): Traffic: The use shall ensure safe movement for vehicles and pedestrians and
shall mitigate potential effects on the surrounding area.
11. The proposed transmission line upgrade is located within the existing utility corridor. Because
adjacent land uses and roads already integrate with the transmission lines, once operational, the
upgraded transmission lines would not disrupt vehicles or pedestrians in the surrounding areas (Ex. 3,
Finding of Fact No. 19f).
Conditions of approval will require the Applicant to submit a pedestrian and vehicular traffic control
plan at the time of Construction Permit for review and approval by the Plan Review Section prior to
the issuance of a Construction Permit and to provide a plan for any closures to City Parks and/or trails.
The park and trail closure plan will also be submitted to the Community Services division for review
and approval prior to the issuance of a Construction Permit.
The PSE easement bisects the City as a whole. The City needs to provide an interconnected
transportation grid and prevent dead end streets. Therefore, public roads will need to extend through
the corridor. To permit the construction of future City public street connections as a result of future
development, a condition of approval will require future public road transportation connections within
the transmission line corridor to be permitted when needed to accommodate future development to the
extent that PSE’s easement does not preclude said connections. No other transportation impacts are
anticipated. (See also Finding of Fact No. 5I).
RMC 4-9-030(D)(7): Noise, Light and Glare: Potential noise, light and glare impacts from the
proposed use shall be evaluated and mitigated.
12. As described in Finding of Fact No. 5J, the proposed transmission line replacement will not
result in any significant noise impacts when completed and in use. No noise impacts from the
operational phase are anticipated. Noise from construction will be temporary in nature and adequately
mitigated.
Loss of vegetation could also “result in less screening of existing light sources, such as streetlights or
lights from buildings” (FEIS, Appendix J, page J1-75). The FEIS suggest an appropriate response
would be to ask other utility providers and owners of now visible adjacent buildings with exterior
lighting to provide shielding on the existing lighting. To the extent practically feasible and consistent
with utility regulations and safe practices, the Applicant shall configure its tree replacement in a manner
that minimizes increased light exposure caused by the proposal (See Finding of Fact No. 5Biic). No
significant impacts from light and glare are anticipated. This criterion is satisfied.
RMC 4-9-030(D)(8): Landscaping: Landscaping shall be provided in all areas not occupied by
buildings, paving, or critical areas. Additional landscaping may be required to buffer adjacent
properties from potentially adverse effects of the proposed use.
13. Landscaping will be provided to buffer properties from potentially adverse effects. As described
in Finding of Fact No. 5Biia, vegetation in a transmission line corridor that has an operational voltage
of more than 200 kV must be managed in compliance with federal requirements, resulting in limitations
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with regard to the type and scope of landscaping that is allowable. Vegetation management standards
vary depending upon the location of vegetation management in relation to transmission wires.
According to the submitted Vegetation Replacement Letter (Exhibit 8), the Applicant proposes to
mitigate impacts to trees that are necessary to meet federal transmission line operational standards. To
mitigate for loss of significant trees in the transmission corridor, the Applicant is proposing mitigation
ratios that would exceed the City’s adopted tree replacement standards as proposed in the submitted
Vegetation Replacement Letter (Exhibit 8).
A condition of approval will require the Applicant to submit a final Landscape and Tree Replacement
Plan to the Current Planning Project Manager at the time of Construction Permit review for review and
approval prior to construction permit issuance. Maintenance of vegetation within the transmission line
corridor, shall be required to comply with the City’s property maintenance regulations as outlined under
RMC 1-3-3. As conditioned, this criterion is satisfied.
DECISION
As conditioned, the conditional use permit and shoreline exemption applications satisfy all applicable
review criteria for the reasons identified in the findings and conclusions of this decision. For that reason,
the conditional use permit and shoreline exemption applications are approved, subject to the following
conditions:
1. The Applicant shall comply with the mitigation measures set forth in the EIS Consistency
Analysis / EIS Addendum, dated December 13, 2019 (Exhibit 2), except for Condition J3 as
modified by Condition No. 10 below.
2. Any project site disturbance and tree replacement shall occur as proposed in the Vegetation
Replacement Approach letter (Exhibit 8).
3. Individual art wraps for the transmission line poles shall be submitted to the Current Planning
Project Manager for review and approval prior to the issuance of a Construction Permit.
Artwork shall be installed prior to the energizing of the transmission lines.
4. A construction staging and parking plan shall be submitted to the Current Planning project
manager for review and approval prior to the issuance of Construction Permits.
5. A pedestrian and vehicular traffic control plan shall be submitted at the time of Construction
Permit for review and approval by the Plan Review Section prior to the issuance of a
Construction Permit.
6. A plan shall be submitted for any closures to City Parks and/or trails. The park and trail closure
plan shall be submitted to the Community Services division for review and approval prior to
the issuance of a Construction Permit.
7. A final Landscape and Tree Replacement Plan shall be submitted to the Current Planning
Project Manager at the time of Construction Permit review for review and approval prior to
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construction permit issuance. Maintenance of vegetation within the transmission line corridor,
shall be required to comply with the City’s property maintenance regulations as outlined under
RMC 1-3-3.
8. Future public road transportation connections within the transmission line corridor shall be
permitted when needed to accommodate future development to the extent that PSE’s easement
does not preclude said connections.
9. In its tree replacement plan, the Applicant shall coordinate with adjoining property owners to
the extent practically feasible and consistent with utility regulations and safe practices to
minimize additional light spillage upon the property owners that may result from the clearing
done for the proposal.
10. Individual art wraps for the transmission line poles shall be submitted to the Current Planning
Project Manager for review and approval prior to the issuance of a Construction Permit. PSE
will install art wraps at up to 12 transmission line pole locations (including those previously
discussed and identified by the City at the Renton Technical College and on publicly visible
PSE-owned property). Artwork shall be installed prior to the energizing of the transmission line,
or as otherwise approved by the Current Planning Project Manager, but at no point will art
installation delay the transmission lines from being energized. The Current Planning Manager
may require a cash security bond for completion of the artwork if it is not installed prior to
energizing.
11. The proposed transmission lines shall both be operated at 230kv at all times when not shut down
entirely, except as necessary to respond to emergency situations10.
DATED this 6th day of February 2020.
City of Renton Hearing Examiner
Appeal Right and Valuation Notices
RMC 4-8-080(G) classifies the application(s) subject to this decision as Type III application(s)
subject to closed record appeal to the City of Renton City Council. Appeals of the hearing examiner’s
decision must be filed with the Renton City Clerk within fourteen (14) calendar days from the
10 The record does not identify whether in some circumstances the transmission lines will have to b e operated at less than
230kv for maintenance or other reasons and also what corrosion impacts may occur when operating at lower levels for only
short periods of time. If this condition is not feasible for PSE, it should request reconsideration with alternative language that
ensures that temporary operation at less than 230kv does not materially increase corrosion via AC interference. One potential
resolution would be a condition authorizing operations pursuant to an addendum to the DNV report subject to St antec peer
review that identifies under what conditions operating at less than 230kv would not materially increase corrosion risk.
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issuance of the decision as outlined in RMC 4-8-110C2. The appeal deadline for this Decision is
5:00 pm, February 25, 2020. All appeals must be received by the City Clerk’s Office by this deadline
and be accompanied by the applicable appeal fee.
Affected property owners may request a change in valuation for property tax purposes
notwithstanding any program of revaluation.
Reconsideration
Motions for reconsideration must be filed with the Renton City Clerk by the 5:00 pm February 25,
2020 appeal deadline. All motions for reconsideration shall be posted at the City of Renton website
at
https://edocs.rentonwa.gov/Documents/Browse.aspx?id=8095664&dbid=0&repo=CityofRenton
(or go to: Rentonwa.gov – “How do I” – Contact – Hearing Examiner – Decisions – Land Use
Decisions – 2020 – Puget Sound Energy Energize Eastside folder). Motions for reconsideration
will not be mailed to hearing participants and it is their responsibility to check the website if they
wish to respond to any such motions. Responses to the motions from hearing participants shall be
filed with the City Clerk’s Office by 5:00 pm March 6, 2020 and will be posted on the website
posting the motions for reconsideration. Replies from those who filed the motions for
reconsideration shall be due by 5:00 pm March 11, 2020. All motions for reconsideration must be
based upon evidence already admitted into the administrative record as exhibits or testimony. NO
NEW EVIDENCE IS ALLOWED.
CITY OF RENTON
DEPARTMENT OF COMMUNITY AND ECONOMIC DEVELOPMENT
HEARING EXAMINER DECISION
EXHIBITS
Project Name:
Puget Sound Energy Energize Eastside
Project Number:
LUA18-000055, CU-H, SME
Date of Report
January 8, 2020
Staff Contact
Jill Ding
Senior Planner
Project Contact/Applicant
Marissa Gifford
HDR
929 108th Ave NE, Suite 1300
Bellevue, WA 98004-4361
Project Location
From PSE's Talbot Hill
Substation (2400 S Puget
Dr. continuing north along
the existing PSE
transmission line corridor
to the northern City limits
The following exhibits are included with the Hearing Examiner Decision:
Exhibits 1-2: As shown in the Environmental Review Committee (ERC) Report
Exhibits 3-18: As shown in the Staff Report to the Hearing Examiner
Exhibit 19: Staff PowerPoint
Exhibit 20: Google Earth, https://www.google.com/earth/
Exhibit 21: COR Maps, http://rp.rentonwa.gov/Html5Public/Index.html?viewer=CORMaps
Exhibit 22: PSE Memorandum
Exhibit 23: Cense Brief Presentation
Exhibit 24: Cense PowerPoint
Puget Sound Energy
Energize Eastside
Public Hearing
Date
Names/Titles
January 8, 2020
Jill Ding, Senior Planner
99640
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PUGET SOUND ENERGY’S HEARING
MEMORANDUM - 1
719 Second Avenue Suite 1150
Seattle, WA 98104
(206) 623 -9372
The Honorable Phil Olbrechts
BEFORE THE HEARING EXAMINER
FOR THE CITY OF RENTON, WASHINGTON
In re: Renton Land Use Matter
LUA18-000055
Puget Sound Energy, Inc.
Energize Eastside Conditional Use Permit
File
PUGET SOUND ENERGY, INC.’S
HEARING MEMORANDUM
Applicant Puget Sound Energy, Inc. (“PSE”) presents this Hearing Memorandum
in support of its application for a Conditional Use Permit (“CUP”) to upgrade and operate
approximately 4 miles of two 115 kV transmission lines in the cit y of Renton (“City” or
“Renton ”) with two 230 kV transmission lines (“Project”) in an existing utility corridor.
The Project is a critical component of an approximately 16-mile electric system upgrade
required to bring PSE’s system into compliance with federally-required planning criteria
by increasing transmission reliability on the Eastside, including Renton.
The Renton PSE upgrade is part of the larger Energize Eastside Project that would
also occur in the cities of Bellevue, Redmond, and Newcastle, and in unincorporated King
County.1 The Project in Renton would replace approximately 144 existing wood and steel
1 The City of Bellevue Hearing Examiner recently approved a conditional use
permit required to build the Richards Creek substation and the south segment of the
Energize Eastside Project. See City of Bellevue Hearing Examiner, Findings of Fact,
Conclusions and Decision on the Conditional Use Permit Application for the South
BEFORE the HEARING EXAMINER for the CITY OF RENTON, WASHINGTON
In Re
Puget Sound Energy, Inc
“Energize Eastside” Talbot Hill Substation (2400 S Puget Dr.) continuing
north along the existing PSE transmission line corridor
to the northern City limits
Project File Number - PR18-000049
Land Use File Number - LUA18-000055, CU-H, SME
Coalition of Eastside Neighborboods for Sensible Energy
Renton Public Hearing
January 8, 2020