Office of Solid Waste and EPA-540-R-11 -023
Emergency Response September 2011
(5203P) www.epa.gov/superfund/remedytech
www.clu-in.org/optimization
Streamlined Remediation System Evaluation
Intermountain Waste Oil Refinery
Bountiful, Utah
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STREAMLINED REMEDIATION SYSTEM EVALUATION
INTERMOUNTAIN WASTE OlL REFINERY
BOUNTIFUL, UTAH
Report of the Streamlined Remediation System Evaluation
Conference Call Conducted for the Intermountain Waste Oil Refinery
June 16,2011
Final Report
September 28, 2011
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EXECUTIVE SUMMARY
Optimization Background
EPA's working definition of optimization as of June 2011 is as follows:
"A systematic site review by a team of independent technical experts, at any phase of a cleanup
process, to identify opportunities to improve remedy protectiveness, effectiveness, and cost
efficiency, and to facilitate progress toward site completion. "
An optimization evaluation considers the goals of the remedy, available site data, site conceptual model,
remedy performance, protectiveness, cost-effectiveness, and closure strategy. A strong interest in
sustainability has also developed in the private sector and within Federal, State, and Municipal
governments. Consistent with this interest, optimization now routinely considers green remediation
during optimization evaluations. An optimization evaluation includes reviewing site documents,
interviewing site stakeholders, potentially visiting the site for one day, and compiling a report that
includes recommendations in the following categories:
• Protectiveness
• Cost-effectiveness
• Technical improvement
• Site closure
• Green remediation
The recommendations are intended to help the site team identify opportunities for improvements. In
many cases, further analysis of a recommendation, beyond that provided in this report, may be needed
prior to implementation of the recommendation. Note that the recommendations are based on an
independent evaluation, and represent the opinions of the evaluation team. These recommendations do
not constitute requirements for future action, but rather are provided for consideration by the Region and
other site stakeholders.
Site-Specific Background
The Intel-mountain Waste Oil Refinery (IWOR) is located at 995 South 500 West in the City of Bountiful,
Davis County, Utah. The site is approximately 2 acres. It is bordered on the north and east by residences
and on the south and west by commercial buildings along US-89 (500 West). The site is mostly flat with
a slightly lower elevation to the west. The buildings associated with the IWOR operations have been
demolished and the site has been redeveloped. The IWOR facility was a brick manufacturing facility
starting prior to 1950. In the 1950s an asphalt business was operated at the site. From 1957 to 1993 a
petroleum product hauling business was run at the site and during the 1970s an oil blending operation was
operated. Groundwater at the site was impacted with solvents, mainly trichloroethylene (TCE) and
petroleum hydrocarbons. TCE was commonly used in asphalt testing laboratories to separate aggregate
from bitumen.
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Summary of Conceptual Site Model (CSM)
The TCE source appears to have been surface dumping of TCE near the southeast corner of the former
laboratory building. Petroleum storage tanks, waste sludge and impacted soil were removed in 1993 and
2001; petroleum compounds are not a concern in groundwater. A narrow plume impacted by TCE and cis
1,2 DCE is interpreted to be present from the former source area to the west edge of the site. The highest
TCE concentration detected in April 2011 was 16.1 ug/L; however, the source area well is dry and no
longer available for sampling. The size of the TCE plume in excess of Maximum Contaminant Levels
(MCLs) is likely up to about 200 feet long and 50 feet wide. The cis-1,2 DCE plume is co-located with
the TCE plume but only has periodically had levels detected above the MCL.
PCE potentially from an off-site source was detected at a maximum level of 4.6 ug/L in April 2011. No
on-site PCE source was found during previous RI investigations. The occurrence of PCE at the site is
most likely the result of PCE in vapors migrating from a source somewhere west of the site. Passive
vapor sampling conducted in 2001 found several areas west of the site with elevated PCE and TCE vapor
levels but none to the upgradient (i.e., east side) of the site.
Site reports indicate that, based on groundwater sampling, all VOC impacts in groundwater are isolated to
the top of the water table to a maximum depth of less than 130 feet bgs. The presence of cis 1,2 DCE
above TCE levels indicates naturally occurring reductive dechlorination of the TCE source; however the
lack of vinyl chloride indicates that enhancement would likely be needed to achieve complete
dechlorination of TCE in the groundwater.
Summary of Findings
Source area TCE concentrations had decreased from 991 ug/L in 1992 to 160 ug/L in 2003, after which
the source area well was dry. The operation of a remediation system from 2004 to 2006, including pump
and treat (P&T) with vapor extraction, reduced TCE concentrations to below MCLs at locations that were
monitored. The capture zone of the formerly operated remedial system likely encompassed the VOC
plume. Treatment using granular activated carbon to remove VOCs from water and vapor operated
effectively with only one exceedance of a discharge standard. The annual site costs during system
operation were about $150,000.
The operation of the remediation system, including P&T at MW-02 and P&T plus vapor extraction at
MW-04, reduced concentrations to below MCLs at locations that were monitored. It is very likely that
pumping resulted in the contribution of a high percentage of clean water to the pumping wells (from
below and/or horizontally from outside the plume). Once the system was shut down natural flow
conditions returned and impacts from the source area likely migrated back to the shallow monitoring
wells, resulting in the rebound of TCE concentrations. The lack of groundwater monitoring in the source
area during and after system operation and the concentrations in the vapor collected just before system
shutdown indicate that a rebound of TCE levels in groundwater should not have been unexpected after
system shutdown.
Summary of Recommendations
Based on the TCE concentrations during the previous SVE pilot test and DPE system operations, coupled
with rebounds in TCE concentrations after those operations were discontinued, it is likely that elevated
levels of VOCs remain in the vadose zone in the suspected source area. The RSE-lite team recommends
sampling soil gas and shallow groundwater for VOCs at approximately three locations in the source area.
Assuming impacts are confirmed, DPE wells suited for soil vapor extraction of the intervals with elevated
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VOCs, and extraction of shallow ground-water, should be installed in the three locations. The RSE-lite
team recommends operation of a SVE system coupled with groundwater extraction (i.e., dual phase
extraction) using the three new wells, and perhaps SVE at existing well MW-7. The primary intent of
these wells is to remove remaining TCE source material from the unsaturated zone via SVE. However,
since it is assumed that groundwater in this area is more impacted than in other portions of the site, it also
makes sense to pump and treat groundwater for the purpose of mass removal. The actual extent of
groundwater capture during system operation should not be a significant focus, since concentrations of
TCE leaving the site are already so low. Rather, the focus of this system should be to remove remaining
TCE mass in the source area (vadose zone and groundwater) to an extent that MCLs for TCE in
groundwater near the source area are achieved or approached.
An exit strategy should be developed to indicate when it is possible to terminate active remediation at this
site. The RSE-lite team believes that additional active remediation is currently merited since there is
likely a remaining TCE source area that is technically feasible to address.
Based on the current and historic distribution of VOCs in groundwater the site, the relatively slow natural
groundwater flow velocity, and historic information on soil vapor concentrations (from passive vapor
surveys, the SVE tests, and the SVE system operation), it does not appear that upgradient VOC sources
are impacting the site. The well most impacted with PCE is the most downgradient well which is closest
to the potential off-site sources based on the 2001 passive vapor screening. Thus, previously proposed
upgradient monitoring wells are not recommended.
Enhancing reductive dechlorination (by injecting a carbon source such as emulsified oil) was suggested
previously, but the RSE-lite team does not believe that technology is a good fit at the site because of the
100 foot depth to groundwater and associated high cost of injection wells, the relatively low VOC
concentrations in groundwater, and most importantly, the fact that the vadose zone would not be
addressed.
in
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NOTICE
Work described herein was performed by Tetra Tech GEO for the U.S. Environmental Protection Agency
(U.S. E.P.A). Work conducted by Tetra Tech GEO, including preparation of this report, was performed
under Work Assignment #48 of EPA contract EP-W-07-078 with Tetra Tech EM, Inc., Chicago, Illinois.
Mention of trade names or commercial products does not constitute endorsement or recommendation for
use.
IV
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PREFACE
This report was prepared as part of a project conducted by the United States Environmental Protection
Agency Office of Superfund Remediation and Technology Innovation (U.S. EPA OSRTI) in support of
the "Action Plan for Ground Water Remedy Optimization" (OSWER 9283.1-25, August 25, 2004). The
objective of this project is to conduct Remediation System Evaluations (RSEs) at selected pump and treat
(P&T) systems that are jointly funded by EPA and the associated State agency. The project contacts are
as follows:
Organization
Key Contact
Contact Information
U.S. EPA Office of Superfund
Remediation and Technology
Innovation
(OSRTI)
Jennifer Hovis
USEPA Headquarters - Potomac Yard
2777 Crystal Drive
Arlington, VA 22202
phone: 703-603-8888
hovis.iennifer@epa.gov
Tetra Tech EM, Inc.
(Contractor to EPA)
Therese Gioia
Tetra Tech EM Inc.
1881 Campus Commons Drive, Suite 200
Reston,VA20191
phone: 815-923-2368
Therese.Gioia(o)tetratech.com
Tetra Tech GEO
(Contractor to Tetra Tech EM, Inc.)
Doug Sutton
Tetra Tech GEO
2 Paragon Way
Freehold, NJ 07728
phone: 732-409-0344
doug. sutton@tetratech. com
v
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TABLE OF CONTENTS
EXECUTIVE SUMMARY i
NOTICE iv
PREFACE v
TABLE OF CONTENTS vi
1.0 INTRODUCTION 1
1.1 PURPOSE 1
1.2 TEAM COMPOSITION 2
1.3 DOCUMENTS REVIEWED 2
1.4 PERSONS CONTACTED 2
1.5 BASIC SITE INFORMATION AND SCOPE OF REVIEW 3
1.5.1 LOCATION 3
1.5.2 SITE HISTORY, POTENTIAL SOURCES, AND RSE SCOPE 3
1.5.3 HYDROGEOLOGIC SETTING 4
1.5.4 POTENTIAL RECEPTORS 4
1.5.5 DESCRIPTION OF GROUNDWATER PLUME 5
2.0 SYSTEM DESCRIPTION 6
2.1 P&T SYSTEM 6
2.2 SVE SYSTEM 6
2.3 MONITORING PROGRAM 7
3.0 SYSTEM OBJECTIVES, PERFORMANCE, AND CLOSURE CRITERIA 8
3.1 CURRENT SYSTEM OBJECTIVES AND CLOSURE CRITERIA 8
3.2 TREATMENT PLANT OPERATION STANDARDS 8
4.0 FINDINGS 9
4.1 GENERAL FINDINGS 9
4.2 SUBSURFACE PERFORMANCE AND RESPONSE 9
4.2.1 GROUNDWATER FLOW AND PLUME CAPTURE 9
4.2.2 GROUND WATER CONTAMINANT CONCENTRATIONS 10
4.3 COMPONENT PERFORMANCE 10
4.3.1 GROUNDWATER EXTRACTION SYSTEM 10
4.3.2 GAC FOR WATER TREATMENT 11
4.3.3 GAC FOR VAPOR TREATMENT 11
4.3.4 SVE SYSTEM 11
4.4 COMPONENTS OR PROCESSES THAT ACCOUNT FOR MAJORITY OF ANNUAL COSTS 11
4.4.1 UTILITIES 12
4.4.2 OPERATORLABOR 12
4.4.3 PROJECT MANAGEMENT 13
4.4.4 CHEMICAL ANALYSIS 13
vi
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4.5 APPROXIMATE ENVIRONMENTAL FOOTPRINTS ASSOCIATED WITH REMEDY 13
4.6 RECURRING PROBLEMS OR ISSUES 14
4.7 REGULATORY COMPLIANCE 14
4.8 SAFETY RECORD 14
5.0 EFFECTIVENESS OF THE SYSTEM TO PROTECT HUMAN HEALTH AND THE
ENVIRONMENT 15
5.1 GROUND WATER 15
5.2 SURF ACE WATER 15
5.3 AIR 15
5.4 SOIL 15
5.5 WETLANDS AND SEDIMENTS 15
6.0 RECOMMENDATIONS 16
6.1 RECOMMENDATIONS TO IMPROVE EFFECTIVENESS 16
6.1.1 INVESTIGATE SITE SOURCE AREA AND INSTALL DUAL PHASE EXTRACTION
(DPE) POINTS WITH SCREENS AT IMPACTED DEPTHS 16
6.1.2 OPERATE DPE SYSTEM NEAR MW-7 TO REMOVE TCE MASS NEAR SOURCE
AREA 16
6.1.3 INSTITUTIONAL CONTROLS 18
6.2 RECOMMENDATIONS TO REDUCE COSTS 18
6.2.1 STOP MNA ANALYSIS 18
6.2.2 REDUCE SAMPLING FREQUENCY AT SELECT WELLS 18
6.2.3 Do NOT INSTALL Six OF SEVEN WELLS RECOMMENDED IN 2010 REMEDIAL
ACTION STATUS REPORT; CONSIDER OFF-SITE VAPOR SURVEY INSTEAD 19
6.3 RECOMMENDATIONS FOR TECHNICAL IMPROVEMENT 19
6.4 CONSIDERATIONS FOR GAINING SITE CLOSE Our 19
6.4.1 Do NOT CONSIDER ENHANCED REDUCTIVE DECHLORINATION 19
6.4.2 DEVELOP AN EXIT STRATEGY 20
6.5 RECOMMENDATIONS FOR ADDITIONAL GREEN PRACTICES 21
6.5.1 USE SMALLER SVE BLOWER THAN THE PREVIOUS SYSTEM 21
6.5.2 CONSIDERATIONS FOR RENEWABLE ENERGY AT THE SITE 21
Tables
Table 6.1 Cost Summary Table
Table 6.2 Green Remediation Summary Table
Attachments
Attachment A - Selected Figures from Existing Reports
Attachment B - Various Sources of Emissions Data Associated with Electricity
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1.0 INTRODUCTION
1.1 PURPOSE
During fiscal years 2000 and 2001 independent reviews called Remediation System Evaluations (RSEs)
were conducted at 20 operating Fund-lead pump and treat (P&T) sites (i.e., those sites with P&T systems
funded and managed by Superfund and the States). Due to the opportunities for system optimization that
arose from those RSEs, EPA OSRTI has incorporated RSEs into a larger post-construction complete
strategy for Fund-lead remedies as documented in OSWER Directive No. 9283.1-25, Action Plan for
Ground Water Remedy Optimization. A strong interest in sustainability has also developed in the private
sector and within Federal, State, and Municipal governments. Consistent with this interest, OSRTI has
developed a Green Remediation Primer (http://cluin.org/greenremediation/) and now as a pilot effort
considers green remediation during independent evaluations.
The RSE process involves a team of expert hydrogeologists and engineers that are independent of the site,
conducting a third-party evaluation of the operating remedy. It is a broad evaluation that considers the
goals of the remedy, site conceptual model, available site data, performance considerations,
protectiveness, cost-effectiveness, closure strategy, and sustainability. The evaluation includes reviewing
site documents, potentially visiting the site for one day, and compiling a report that includes
recommendations in the following categories:
• Protectiveness
• Cost-effectiveness
• Technical improvement
• Site closure
• Green remediation
The streamlined RSE process or RSE-lite is similar to the RSE process but does not include a site visit.
The recommendations are intended to help the site team identify opportunities for improvements. In
many cases, further analysis of a recommendation, beyond that provided in this report, may be needed
prior to implementation of the recommendation. Note that the recommendations are based on an
independent evaluation, and represent the opinions of the evaluation team. These recommendations do
not constitute requirements for future action, but rather are provided for consideration by the Region and
other site stakeholders.
The Intermountain Waste Oil Refinery was selected by EPA OSRTI based on a nomination from EPA
Region 8 and the State of Utah due to the rebound in contaminant concentrations since the initial active
remedial action was concluded in 2006.
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1.2 TEAM COMPOSITION
The RSE team consists of the following individuals:
Name
Peter Rich
Rob Greenwald
Affiliation
Tetra Tech GEO
Tetra Tech GEO
Phone
410-990-4607
732-409-0344
Email
peter. rich@tetratech. com
rob . greenwald@tetratech. com
In addition, Jennifer Hovis, Tracy Hopkins and Matt Charsky from EPA Headquarters participated in the
RSE-lite conference call. Kimberly White from EPA Region I was an observer on the call.
1.3 DOCUMENTS REVIEWED
The following documents were reviewed. The reader is directed to these documents for additional site
information that is not provided in this report.
• EPA Superfund Record of Decision, OU1 - November 2002
• Design Analysis for Treatability Study- March 2004
• Remedial Investigation Report, OU2- June 2004
• Treatability Study Technical Memorandum- July 2004
• EPA Superfund Record of Decision, OU2 - August 2004
• Update Fact Sheet, October 2006
• EPA Five-Year Review Report - September 2008
• Final Remedial Action Status Report, OU2- December 2010
• Annual Update to the Five-Year Review, January 2011
• January 2011 VOC and MNA Sample Results
• April 2011 VOC Sample Results
1.4 PERSONS CONTACTED
The following individuals associated with the site participated in the conference call:
Name
Lisa Lloyd
Andrew Schmidt
Tony Howes
Nathan Smith
Affiliation
U.S. EPA Region 8 (RPM)
U.S. EPA Region 8
(Hydrogeologist)
UtahDEQ
COM
Phone
303-312-6537
Email
Lloyd.Lisa@epamail.epa.go
V
Schmidt. Andrew@epamail.e
pa.gov
THOWES@utah.gov
SmithNT@cdm. com
DEQ= "Department of Environmental Quality'
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1.5 BASIC SITE INFORMATION AND SCOPE OF REVIEW
1.5.1 LOCATION
According to the 2008 Five Year Review and other site documents, the Intermountain Waste Oil Refinery
(IWOR) ("the site") is located at 995 South 500 West in the City of Bountiful, Davis County, Utah. The
site is approximately 2 acres. It is bordered on the north and east by residences and on the south and west
by commercial buildings along US-89 (500 West). The site is mostly flat with a slightly lower elevation
to the west. A site location map is included in Attachment A. The buildings associated with the IWOR
operations have been demolished and the site has been redeveloped.
1.5.2 SITE HISTORY, POTENTIAL SOURCES, ANDRSE SCOPE
According to the site documents, the IWOR facility was a brick manufacturing facility starting prior to
1950. In the 1950s an asphalt business was operated at the site. From 1957 to 1993 a petroleum product
hauling business was run at the site and during the 1970s an oil blending operation was occurring.
Groundwater at the site was impacted with solvents, mainly trichloroethylene (TCE) and petroleum
hydrocarbons. TCE was commonly used in asphalt testing laboratories to separate aggregate from
bitumen. The TCE source area appears to be near the former laboratory building location.
In 1992, studies by the property owner detected VOCs, specifically TCE (at 991 ug/L) and 1,1 DCA in
the original onsite well (later labeled MW-07) which is screened from 80 to 100 ft below ground surface.
The Utah DEQ sampled an onsite sump in January 1995 and detected toluene, PCA and TCE above
MCLs. In April 1996, Utah DEQ sampled the onsite well and detected TCE and 1,1 DCA above MCLs,
and sampled onsite soils and found one or more samples with ethylbenzene, trimethylbenzene, n-
butylbenzene, toluene and 1,2 DCA above the Superfund Chemical Data Matrix Cancer Risk Screening
Concentrations. Utah DEQ conducted an expanded site investigation in June 1998 and found TCE and
cis-1,2 DCE above MCLs in the onsite well. In August 2001 EPA conducted a removal action disposing
of the contents of numerous containers, above ground tanks and laboratory chemicals. EPA conducted an
RI from December 2001 to June 2004. The site was subdivided into:
• OU1- near surface soil and potential sources including tanks, drums and containers; and,
• OU2- the vadose zone and groundwater contamination.
Nine groundwater monitoring wells were installed as part of the RI.
The active OU-2 remedy operated from May 2004 to February 2006 and included pump and treat (P&T)
for groundwater from well MW-02 (at the leading edge of the plume just beyond the west site boundary)
and P&T combined with vapor extraction at MW-04 (approximately 50 feet downgradient of the original
onsite well MW-07). TCE concentrations in groundwater (measured monthly) dropped below MCLs at
MW-02 and MW-04 in December 2004 and June 2004 respectively, and remained below MCLs until
system operation was ceased in February 2006. MW-07 was dry for all sampling events after sampling on
March 2003 (160 ug/L TCE detected) and was not replaced for sampling during 2005/ 2006 when the
decisions to turn off the system and dismantle and remove the system (October 2006) were made. It is
noted that MW-08 was installed near MW-07 as part of the RI, but it is much deeper than MW-07 (MW-
08 is screened from 130 to 150 ft bgs) and MW-08 is not impacted by VOCs. TCE concentrations
increased at MW-04 after the P&T operations were discontinued. TCE was detected at a concentration of
16 ug/L in January 2008 at MW-04 and has typically been above the MCL since that time. MW-02 has
also had TCE levels at or just above the MCL during several monitoring events since 2008.
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This RSE-lite focuses on:
• performance of the active system during active operation;
• conceptual model(s) for the rebound of TCE (and cis 1,2 DCE) concentrations and the occurrence
of PCE detections at the site; and,
• options for future remediation to meet OU2 ROD objectives.
1.5.3 HYDROGEOLOGIC SETTING
Information in this section is primarily from site documents and does not include interpretation by the
RSE-lite team.
The site is located between the Wasatch Mountains to the east and the Oquirrh Mountains to the west
within the Basin and Range Physiographic Province. It is comprised of basin-fill deposits which were
eroded from the mountains and deposited during the Pre-Pleistocene and Pleistocene Epochs. The basin
fill is composed of alluvial and lacustrine deposits ranging from coarse to fine grained.
At the site, a one to two foot thick surface fill layer is underlain by a sandy clay layer to a depth of 10 feet
to 25 feet bgs. The clay layer is underlain by a mixture of sandy gravel and gravelly sands to 30 feet to 55
feet bgs followed by interbedded gravels, sands, silts and clays extending to 100 feet bgs. Sandy gravels
and gravelly sands extend from 100 feet bgs to at least 240 feet bgs. Groundwater is encountered at 100
feet to 110 feet bgs.
Wells at the site are considered completed in the shallow portion of the East Shore Aquifer (60 to 250 ft
bgs). The East Shore Aquifer also has intermediate (250 to 500 ft bgs) and deep (>500 ft bgs) portions.
The shallow East Shore aquifer is reported to be saline and not used for potable purposes in the area by
the site team.
At the site the shallow aquifer flow direction is generally just north of west, with a relatively flat
hydraulic gradient of approximately 0.0021 based on April 2011 water levels (MW-09U to MW-02). A
slug test at MW-02 indicated a hydraulic conductivity of 7.0X10-4 centimeters/second or about 2 ft/day.
Assuming an effective porosity of 0.10 to 0.25 for a gravel, sand and silt mixture the groundwater
velocity would range from 6 to 15 feet per year.
1.5.4 POTENTIAL RECEPTORS
Contaminant exposure pathways considered to be most significant at the site at the time of the ROD are
summarized as follows:
• Vapor intrusion of VOCs from contaminated soil into indoor air is a risk to structures above. The
OU1 ROD included a Land Use Control requiring any building constructed on the site to have
measures to eliminate vapor intrusion.
• There is a potential for the site groundwater to be used as drinking water. From the OU2 ROD-
"currently no one is using this portion of the aquifer for drinking water. However, the state of
Utah considers the groundwater a potential drinking water source. It is not possible to determine
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when the upper portion of the aquifer may be used for a drinking water source." There are water
supply wells in the area within 1000 feet of the site but they are screened at intervals deeper than
250 feet bgs. Deeper water supply wells in the area have been impacted by TCE and PCE but the
RSE team understands that the IWOR site is not suspected as a source of supply well impacts.
1.5.5 DESCRIPTION OF GROUNDWATER PLUME
The first figure in Attachment A illustrates the most recent VOC concentrations in groundwater (April
2011). A narrow plume impacted by TCE and cis 1,2 DCE is interpreted to be present from the former
source area well (MW-07) location just south and east of the former laboratory building to the west edge
of the site (MW-02). The highest TCE concentration detected in April 2011 was 16.1 ug/L at MW-04
(MW-07 is dry and no longer available for sampling, but historically it had higher concentrations of TCE
than are currently observed at MW-04). The size of the TCE plume in excess of MCLs is likely up to
about 200 feet long and 50 feet wide. The 1,2 DCE plume is co-located with the TCE plume but only
MW-04 has periodically had levels detected above the MCL.
PCE (potentially from an off-site source) was detected at 4.6 ug/L in April 2011 at MW-02, and was also
detected at levels below 1 ug/L at three other wells in the northwest portion of the site. No on-site PCE
source was found during previous RI investigations. The RSE-lite team believes that the occurrence of
PCE in MW-02 and other wells in the downgradient portion of the site is most likely the result of PCE in
vapors migrating from a source somewhere west of the site. Passive vapor sampling conducted in 2001
found several areas west of the site with elevated PCE and TCE vapor levels but none to the upgradient
(i.e., east side) of the site.
Site reports indicate that, based on groundwater sampling, all VOC impacts in groundwater are isolated to
the top of the water table to a maximum depth of less than 130 feet bgs. This is based on sampling results
at MW-08 which was installed with a screened depth of 130 ft bgs to 150 ft bgs (near MW-07) and has
not had detections of VOCs. The presence of cis 1,2 DCE above TCE levels indicates naturally occurring
reductive dechlorination of the TCE source; however the lack of vinyl chloride indicates that
enhancement by nutrient and perhaps bacterial introduction might be needed to achieve complete
dechlorination of TCE in the groundwater.
The operation of the remediation system, including P&T at MW-02 and P&T plus vapor extraction at
MW-04, reduced concentrations to below MCLs at locations that were monitored. However, the lack of
groundwater monitoring at MW-07 and the concentrations in the vapor collected just before system
shutdown indicate that a rebound of TCE levels in groundwater should not have been unexpected after
system shutdown. It is very likely that pumping at MW-02 and MW-04 resulted in the contribution of a
high percentage of clean water to the pumping wells (from below and/or horizontally from outside the
plume). Once the system was shut down natural flow conditions returned and impacts from the source
area likely migrated back to the shallow monitoring wells, resulting in the rebound of TCE
concentrations.
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2.0 SYSTEM DESCRIPTION
The previously operated remedy included P&T at downgradient well MW-02 and dual-phase
(groundwater and vapor) extraction from MW-04 about 50' downgradient of the original source area well
(MW-07). The systems began operation with treatability studies from May 2004 to September 2004.
The system operation continued until February 2006.
The treatability study included short tests of vapor extraction at MW-07 and MW-02 and air sparging at
MW-08 combined with vapor extraction at MW-07 as well as the selected remedy. The tests showed the
highest vapor concentrations at MW-07 . MW-07 vapor concentrations were up to approximately
129,000 ug/m3 versus highs of approximately 14,000 ug/m3 at MW-02 and 31,000 ug/m3 at MW-04. It
was decided that pumping at MW-02 and MW-04 with SVE at MW-04 would treat the area around MW-
07 without SVE at MW-07 or installation of a new groundwater pumping well in the immediate vicinity
of MW-07.
2.1 P&T SYSTEM
Groundwater was pumped from MW-04 and MW-02 from May 2004 to February 2006. MW-02 was
pumped at an average rate of 0.9 gpm (just above the design flow rate of 0.72 gpm to 0.88 gpm) and MW-
04 was pumped at an average rate of 2 gpm (below the design rate of 2.7 gpm to 3.3 gpm). Extraction
pumps were Grundfos Redi-Flo2 model with variable speed drive and a maximum 2 HP input.
Groundwater was treated using rented GAC equipment (likely two or three 200-pound drums in series)
with pre-filtering for sediment removal. Treated water was discharged to the storm sewer and had to meet
Utah Administrative Code R317-2 limits of 30 ug/1 for TCE, 70 ug/L for cis 1,2 DCE, and 3.3 ug/L for
PCE.
System influent concentrations were quite low, and averaged approximately 10 ug/L for total VOCs
during the 1.75 yr system operation yielding a total VOC mass removal during that time of about 0.23
pounds.
3 gal 3.785 L 10 ug 1kg 2.2 Ibs 1440 min
—2— x x x —-2- x x x 640 days = 0.23 Ibs
min gal L 10 ug kg day
2.2 SVE SYSTEM
The SVE system extracted from MW-04 only. The well is screened from 92.5 feet bgs to 117.5 bgs; this
typically provided 10 to 15 feet of exposed screen. The SVE system included a rented 25 HP blower with
a capacity of about 200 scfm at about 15 inches mercury (204 inches H2O). SVE tests showed influence
of about 1-inch H2O at 50 feet from an extraction well (MW-07 or MW-04) during the pilot test at flow
rates of 30 scfm and 3.5 inches mercury (47.6 inches H2O). The system was typically operated at 50 scfm
to 80 scfm at 54 to 150 inches H2O at the well head. Vapor was treated by rented GAC units (likely two
200-pound units in series) prior to discharge to the atmosphere.
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Influent vapor concentrations were typically about 2,000 ppbv or 10,000 ug/m3. At 60 scfm this equates
to a total VOC mass removal during the 1.75 year system operation of about 34 pounds.
60ft3 0.0283m3 10,000 ug 1kg 2.2 Ibs 1440 min ^, „ „ „ „
x x —— x —-E- x x x 640 days = 34.4 Ibs
min ft m 10 ug kg day
2.3 MONITORING PROGRAM
Process Monitoring
Volatile organic compounds (VOCs) in groundwater and soil vapor were sampled monthly at MW-04 and
groundwater was sampled monthly at MW-02 during system operation. Groundwater treatment system
effluent was sampled monthly for permit compliance; vapor was sampled to determine GAC change-out
frequency (monthly sampling frequency assumed). These were initially sent to a private lab to achieve
fast turnaround time, with subsequent transition to the CLP lab as operations stabilized.
Groundwater Monitoring
Groundwater is currently monitored quarterly at 9 locations (13 total samples because 2 locations have 3
depth intervals) with water levels measured and samples analyzed for VOCs. The shallow source area
well, MW-07 has not been sampled since March 2003 because it has been dry. A replacement well has
not been installed. The current quarterly monitoring schedule is a change that was implemented within
approximately the last year to provide as much information as possible for making decisions about what
do next. Previously (but after system shutoff) the groundwater monitoring was semi-annual rather than
quarterly. The VOC samples are sent to the CLP lab.
In addition, analysis of samples for methane, ethane, ethene, chloride, nitrate/nitrite, sulfate, ferrous iron,
alkalinity, dissolve oxygen, ORP and COD monitoring is completed quarterly at all monitoring wells.
These types of parameters are generally monitored to evaluate natural attenuation, and these samples for
"natural attenuation" parameters are sent to a private lab.
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3.0 SYSTEM OBJECTIVES, PERFORMANCE, AND
CLOSURE CRITERIA
3.1 CURRENT SYSTEM OBJECTIVES AND CLOSURE CRITERIA
The OU2 ROD for the IWOR Site identifies the following Remedial Action Objectives (RAOs):
• Restore the aquifer to beneficial use (drinking water standards) within a reasonable time frame
• Prevent exposure to contaminated ground water through ingestion of contaminated ground water
or inhalation of vapors during use
• Prevent the future contamination of ground water that is currently uncontaminated
The ROD lists the only COC as TCE; however PCE and cis 1,2 DCE have also been detected in samples
from site wells. Drinking water standards (MCLs) for these constituents are:
Contaminant of Concern
PCE
TCE
cis 1,2-DCE
Cleanup Criteria (jig/L)
5
5
70
We assume that State standards and Federal MCLs would also apply to other contaminants.
3.2 TREATMENT PLANT OPERATION STANDARDS
Treated groundwater was discharged to the storm sewer and was required to meet Utah Administrative
Code R317-2 limits of 30 ug/1 for TCE, 70 ug/L for cis 1,2 DCE, and 3.3 ug/L for PCE. The system met
these standards during operation except for a PCE exceedance in July 2005 of 5.6 ug/L.
The site documents and site team did not note a vapor discharge limit for the system. A limit, if any,
would likely have been many times higher than the actual emissions given the relatively low VOC
concentrations (as mentioned earlier, approximately 34 Ibs of VOCs were removed over 1.75 years,
which equates to approximately 0.05 Ibs/day which is lower than would typically be expected for an air
permit).
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4.0 FINDINGS
4.1 GENERAL F INDING s
The observations provided below are not intended to imply a deficiency in the work of the system
designers, system operators, or site managers but are offered as constructive suggestions in the best
interest of the EPA and the public. These observations have the benefit of being formulated based upon
operational data unavailable to the original designers. Furthermore, it is likely that site conditions and
general knowledge of ground water remediation have changed over time.
4.2 SUBSURFACE PERFORMANCE AND RESPONSE
4.2.1 GROUNDWATER FLOW AND PLUME CAPTURE
Groundwater flow under non-pumping conditions (see attached Figures for interpreted water levels
contours for April 2011 conditions) is just north of west with a relatively flat hydraulic gradient. The
RSE-lite team evaluated the site hydrogeology, water levels and potentiometric surface map and generally
agrees that when MW-04 and MW-02 were pumped the extent of capture likely encompassed the VOC
plume.
Comparing the extraction rate from MW-02 and MW-04 (combined 3 gpm) to the groundwater flow rate
yields an estimated capture zone width (963 ft) that is much wider than the estimated TCE plume width
(assumed to be less than 100 ft):
Q = Saturated Thickness x Width x Hydraulic Gradient x Hydraulic Conductivity
3 gpm = 578 ft3/day = 150ft x Xft x 0.002 ft/ft x 2 ft/day
X = 963 ft (many times wider than the plume)
In the above calculations, the saturated thickness is the approximate saturated thickness of the East Shore
aquifer shallow portion, the gradient is from the July 2010 contours from just upgradient of the source
area to the edge of the site near MW-02, and the hydraulic conductivity of 2 feet per day is from a slug
test at MW-02. It is difficult to know what the correct value for saturated thickness is for calculation
above, since the capture zone of the wells likely does not extend a full 150 ft below the water table.
However, using a smaller value for saturated thickness will result in a wider capture zone, so the saturated
thickness utilized above is conservative. Note that calculation above is a simplified analysis that does not
address the exact locations of the extraction wells and interference between extraction wells, but the level
of simplification is appropriate for this site. The RSE-lite team believes that detailed (e.g., numerical)
modeling that incorporates the specific locations of the extraction wells will not alter the general
conclusion that the extraction rate will capture water from a width much greater than the plume width,
and for this site more detailed modeling is not merited.
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Based on the hydraulic conductivity, hydraulic gradient, and an assumed porosity of 0.15 the groundwater
velocity in non-pumping conditions would be about 10 feet per year:
V = Hydraulic Conductivity x Hydraulic Gradient /porosity
2ft/dayX0.002ft/ftX 365days/yr/O.I5 = 9.73ft/yr
4.2.2 GROUND WATER CONTAMINANT CONCENTRATIONS
Initial sampling at MW-07 in May 1992 indicated 991 ug/L TCE. Samples analyzed in 1995 and 1998
had TCE concentrations of 750 ug/L and 870 ug/L respectively. The final sample taken at MW-07 in
March 2003 had 160 ug/L TCE (it has been dry since). No PCE was detected in the four samples
collected. No other well screened in the interval within 20 feet of the top of the water table has since been
installed in this suspected source area.
MW-04, fifty feet downgradient from MW-07, is the closest shallow interval well to this area. The
maximum TCE concentration at MW-04 prior to remedial system operation was 12 ug/L with no PCE
detections. TCE decreased to levels below lug/L during system operation while PCE increased to a
maximum of 17 ug/L, suggesting that pumping was drawing PCE in from a different source area. Since
system operation was terminated, the maximum TCE and PCE have been 32 ug/L and 1.3 ug/L,
respectively. In April 2011, TCE and PCE concentrations were 16.1 ug/L and 0.49 ug/L, respectively.
MW-02 is 190 feet downgradient of MW-07 and appears to be the approximate downgradient limit of the
current TCE plume. Prior to remedial system operation, the maximum TCE detected was 19 ug/L and
PCE was not detected. During operation, TCE decreased to levels below 1 ug/L while PCE was detected
up to 21 ug/L. Since system operation was terminated, the maximum TCE and PCE concentrations have
been 7.4 and 25 ug/L, respectively. In April 2011, TCE and PCE concentrations were 3.3 ug/L and 4.6
ug/L, respectively.
Cis-1,2 DCE is typically found with TCE detections; it has been above of the MCL of 70 in MW-04 two
times since the system operation was terminated. The cis-1,2 DCE detections indicate some naturally
occurring degradation of TCE but there is no indication that the degradation is progressing to vinyl
chloride and ethane/ethane.
The shallow sampling interval of MW-10, 40 feet to the northwest of MW-04 is the only other site well
that has had a VOC detected above cleanup criteria. The maximum TCE detected at MW-10 was 9.2
ug/L in the April 2011 sampling and the maximum PCE was 0.92 ug/L in April 2010.
4.3 COMPONENT PERFORMANCE
4.3.1 GROUNDWATER EXTRACTION SYSTEM
Both MW-02 and MW-04 were reported to be equipped with Grundfos Redi-Flo2 variable speed electric
pumps. These pumps have a maximum 2 HP input but based on the flow rate and depth to water they
likely operated at about 1HP and 1.5HP, respectively. The pumps apparently operated effectively. Well
yields were low as would be expected based on the hydraulic conductivity. Mass removal was minimal.
Extraction reduced groundwater concentrations in extraction wells to below cleanup criteria for TCE
during remedial system operation, likely because "clean water" (with respect to TCE) was pulled into the
wells from outside the plume. However, it is unknown what impact the pumping had on TCE
concentrations in the presumed main source area near MW-07.
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Based on the passive vapor survey done in May 2001 and the groundwater concentration trends, there are
likely PCE sources downgradient and side gradient from the IWOR site. Remedial groundwater
pumping, vapor extraction, and possibly natural vapor migration likely brought PCE impacts into the site
wells.
4.3.2
GAC FOR WATER TREATMENT
A treatment system is no longer present at the site. The GAC system was apparently generally effective
for water treatment with only one reported discharge exceedance. Sediment filters were used to prevent
fouling of the GAC. No GAC change-outs were reported.
4.3.3
GAC FOR VAPOR TREATMENT
A treatment system is no longer present at the site. GAC was used to treat vapors prior to discharge. The
system was apparently effective for treatment although effluent data were not provided. The Final
Remedial Action Status Report (RASR) indicates that the GAC units (1600 Ibs total) were changed out
once after 6 months of operation.
4.3.4
SVE SYSTEM
Long-term vapor extraction only took place at MW-04. Vapor mass removal was over 100 times greater
than mass removed from groundwater. Vapor concentrations were generally steady from October 2004
through the last sampling data of December 2005.
4.4 COMPONENTS OR PROCESSES THAT ACCOUNT FOR MAJORITY OF
ANNUAL COSTS
Based on costs for 22 weeks of O&M from October 2005 to February 2006 provided in Table 4-2 of the
Remedial Action Status Report (December 2010) and conversations with the site team, the RSE-lite team
estimates that annual costs for P&T operation, SVE operation, and groundwater monitoring (not
including treatment equipment rental) were approximately $155,700 per year as summarized in the
following table.
Item Description
Project Management
Routine system O&M labor
Electricity
GAC
GAC Disposal
Bag Filters including disposal
Laboratory - process water, process vapor and groundwater
Total
Approximate Annual Cost When
P&T/SVE was Operating*
$16,800
$43,200
$13,500
$4,800
$2,000
$3,400
$72,000
$155,700
*Items reported over 22 weeks scaled by 52/22; items reported over 5 months scaled by 12/5
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Based on costs provided in Table 4-2 and discussion in Section 4.3 of the Remedial Action Status
Report (December 2010) for the period after the system operation was terminated, the total costs
without system operation were approximately $71,000 over 4.5 years, or approximately $16,000
per year. Those costs include groundwater monitoring labor and analysis (approximately $11,000
per year), project management (approximately $4,200 per year) and work plans (less than $1,000
per year). Note that the recent annual costs per year for groundwater monitoring are greater than
the average cost per year over this 4.5 year period, because monitoring frequency was recently
increased from semi-annual to quarterly. The 2010 Remedial Action Status Report (Section 5.3)
indicates current events cost between $6,000 and $8,000 per event, which would indicate current
groundwater monitoring costs are between $24,000 and $32,000 per year.
The approximate costs summarized above are discussed in more detail below.
4.4.1 UTILITIES
Electricity costs for when the system operated are based on estimated electricity usage by the following
motors:
• Submersible pumps: two 2HP Grundfos Redi-Flo2 pumps operating continuously, at 75% load
for RW-4 and 50% load for RW-2
• Transfer pumps: assumed 2 HP each for two pumps, 75% load and operating 25% of the time
• SVE blower: 25 HP operating continuously at assumed 75% load
All motors are assumed to have operated at 75% efficiency. Based on these assumptions, the total
electricity usage is approximately 193,000 kWh per year, as per the following calculations.
RW2: 2 HP x 0.50 load x 0.75 kW/HP / 0.75 efficiency x 8760 hrs/yr = 8,760 kWh/yr
RW-4: 2 HP x 0.75 load x 0.75 kW/HP / 0.75 efficiency x 8760 hrs/yr = 13,140 kWh/yr
Transfer pumps: 4 HP x .25 x 0.75 load x 0.75 kW/HP / 0.75 efficiency x 8760 hrs/yr = 6,570 kWh/yr
SVE Blower: 25 HP x 0.75 load x 0.75 kW/HP / 0.75 efficiency x 8760 hrs/yr = 164,250 kWh/yr
Assuming an electricity rate of $0.07 per kWh, this translates to a cost of approximately $13,500 per year.
As indicated above, the SVE blower represented approximately 85% of the electrical usage during system
operation. Currently, there is no electrical usage because the system is not operating.
4.4.2 OPERATOR LABOR
When the system was operating a subcontractor based in Salt Lake City visited the site about twice per
month after the first few months. The costs were reported to be approximately $18,000 over 5 months, or
approximately $43,200 per year. There are no current operating labor costs because there is no system
operating.
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4.4.3 PROJECT MANAGEMENT
Based on the information provided, project management costs were reported to be approximately $7,000
over 5 months, or approximately $16,800 per year. Current project management for groundwater
monitoring efforts is approximately $4,200 per year. It is not clear if this includes reporting costs.
4.4.4 CHEMICAL ANALYSIS
During system operation, monthly groundwater and process sampling was conducted, as well as vapor
sampling via summa canisters. During system operation those costs were reported to be approximately
$30,000 over 5 months, or approximately $72,000 per year. Currently there is no process sampling and
groundwater sampling is now quarterly at 13 locations for VOC plus bioremediation parameters. The
average cost for monitoring (sampling and analysis) since system operation was terminated has been
approximately $11,000 per year, but current monitoring costs are likely higher than that average value
since monitoring is now quarterly whereas monitoring was semi-annual over much of that period. Thus,
current monitoring is more likely on the order of $20,000 per year. It is assumed the analysis for VOCs,
which is performed by the CLP lab, is of no cost to the project. The analysis for the MNA parameters at a
private lab might be on the order of $5,000 per year (rough estimate) with the balance of the cost
($15,000 per year) for quarterly activities sampling (labor, equipment, etc.).
4.5 APPROXIMATE ENVIRONMENTAL FOOTPRINTS ASSOCIATED WITH
REMEDY
The site remedial system has not operated since 2006 so the site currently has a minimal environmental
footprint associated with sampling of monitoring wells. During system operation the major contributor to
environmental footprints would have been the electricity usage (approximately 193,000 kWh/yr) which
was primarily associated with the SVE blower.
It is unclear what the appropriate conversion factors are for converting electricity usage to greenhouse gas
emissions and other air pollutant emissions because there is substantial variation and uncertainty in the
fuel blend used for electricity and the value of the conversion factors depending on the reference used.
According to the city website, the City of Bountiful provides some of its own power generation, some of
which is from hydroelectric sources. However the city also purchases power from other providers and the
fuel blend and emission factors for the electricity provided by these other sources is not known. The
emission factor for greenhouse gases from electricity generation from three different sources is provided
below (see Attachment B):
• City of Bountiful from eGRID (www.epa.gov/egrid)* - 252 Ibs of CO2 per MWh
• Northwest Power Pool (includes Utah) (www.epa.gov/egrid) - 902 Ibs of CO2 per MWh
• Utah (www.eia.gov Utah State Profile) - 1,849 Ibs of CO2 per MWh
* Note that this value is for the power generated by the City of Bountiful but would not
include the electricity purchased from other providers by the City of Bountiful and used
by City of Bountiful customers.
Given the wide uncertainty associated with the emission factor for electricity and the prevalent role of
electricity in the energy used by the remedy, the optimization team has not attempted to calculate the air
emission footprints for the previous remedy.
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The extracted water (approximately 3 gpm) discharged to the storm sewer would represent a minor use of
water associated with the previous remedy. There would have been other minor footprints associated
with transportation to and from the site, and for transporting samples. It is assumed that those footprints
would be minor versus the electricity footprints. There would have also been minor use of materials such
as the bag filters and the GAC.
4.6 RECURRING PROBLEMS OR ISSUES
No recurring problems or issues were reported by the site team.
4.7 REGULATORY COMPLIANCE
No remedial system is currently operating.
4.8 SAFETY RECORD
No health and safety issues were identified during the RSE-lite conference call.
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5.0 EFFECTIVENESS OF THE SYSTEM TO PROTECT HUMAN
HEALTH AND THE ENVIRONMENT
5.1 GROUND WATER
There are water supply wells within 1000 feet of the site but they are screened deeper than 250 feet bgs
and site VOC impacts have not been found below 130 feet bgs. The site team reports that shallow
groundwater is not suited for potable use because of high chloride; however, it is considered a potential
drinking water source by the state.
5.2 SURF ACE WATER
The nearest surface water to the site is Mill Creek approximately 1500 feet to the north. Artesian wells
and springs are reported about a half mile to the west of the site. The groundwater plume does not extend
to surface water bodies.
5.3 AIR
Vapor levels reported in the SVE extraction well (MW-04) and pilot test wells (MW-07 and MW-02)
were high enough to present a concern for vapor intrusion. The site has been redeveloped and the OU1
ROD required measures to prevent vapor intrusion into structures.
5.4 SOIL
Site surface soils have been remediated or the exposure pathway has been eliminated with concrete or
asphalt covers (since the OU2 ROD, the site has been redeveloped and the portion of the site in the
probable source area is paved). Subsurface soils may continue to be impacting groundwater, and the site
surface covers reduce infiltration.
5.5 WETLANDS AND SEDIMENTS
Please refer to Section 5.2.
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6.0 RECOMMENDATIONS
Cost estimates provided herein have levels of certainty comparable to those done for CERCLA Feasibility
Studies (-30%/+50%), and these cost estimates have been prepared in a manner generally consistent with
EPA 540-R-00-002, A Guide to Developing and Documenting Cost Estimates During the Feasibility
Study, July, 2000. The costs presented do not include potential costs associated with community or public
relations activities that may be conducted prior to field activities. The costs and sustainability impacts of
these recommendations are summarized in Tables 6-1 and 6-2.
6.1 RECOMMENDATIONS TO IMPROVE EFFECTIVENESS
6.1.1 INVESTIGATE SITE SOURCE AREA AND INSTALL DUAL PHASE EXTRACTION (DPE)
POINTS WITH SCREENS AT IMP ACTED DEPTHS
Based on the TCE concentrations during the previous SVE pilot test and DPE system operations, coupled
with rebounds in TCE concentrations after those operations were discontinued, it is likely that elevated
levels of VOCs remain in the vadose zone in the suspected source area near MW-07. MW-07 had the
highest TCE concentrations in groundwater at the site until March 2003, but MW-7 could not be sampled
after that because of low water levels. The RSE-lite Team recommends using a membrane interface
probe (MIP) or another method to actively sample soil gas and shallow groundwater for VOCs at
approximately three locations near MW-07 (see the second figure in Attachment A). Assuming impacts
are confirmed, DPE wells suited for soil vapor extraction of the intervals with elevated VOCs, and
extraction of shallow groundwater, should be installed in the three locations. A small number of DPE
wells in this limited area is suggested for the following reasons:
• sampling of existing wells indicates that the potential on-site TCE source area is likely limited to
the MW-07 area;
• remedial system operational experience indicates SVE radius of influence of at least 50 feet; and
• groundwater pumping at the proposed wells would be for mass removal purposes (in conjunction
with the extraction of vapors that would be the primary method for removing contaminant mass)
and not for groundwater capture.
The proposed investigation including well installation should cost about $75,000; including $30,000 for
the investigation plan and sampling and $45,000 for the drilling and well installation. An initial round of
sampling at these three new wells for VOCs vapor and groundwater might cost on the order of $5,000 for
sampling, analysis, and reporting.
6.1.2 OPERATE DPE SYSTEM NEAR MW-7 TO REMOVE TCE MASS NEAR SOURCE AREA
The RSE-lite team recommends operation of a SVE system coupled with groundwater extraction (i.e.,
dual phase extraction) using three new wells installed near MW-7 discussed in Section 6.1.1 (see second
figure in Attachment A for suggested locations of the new wells). MW-7 could also be considered for an
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extraction well in the SVE system. The primary intent of these wells is to remove remaining TCE source
material from the unsaturated zone via SVE. However, since it is assumed that groundwater in this area is
more impacted than in other portions of the site, it also makes sense to pump and treat groundwater for
the purpose of mass removal. The actual extent of groundwater capture during system operation should
not be a significant focus, since concentrations of TCE leaving the site are already so low. Rather, the
focus of this system should be to remove remaining TCE mass in the source area (vadose zone and
groundwater) to an extent that MCLs for TCE in groundwater near the source area are achieved or
approached.
The RSE-lite team does not believe extraction of groundwater or vapor should be conducted at MW-2 or
MW-4, for several reasons: 1) those wells are closer to the potential off-site PCE source, and pumping
from the suggested new wells are somewhat less likely to draw in PCE impacts from off-site; and 2) it
will be logistically more simple to keep air and water extraction in one small portion of the site.
SVE operation should continue until TCE concentrations are reduced to levels of about 200 ppbv (the
2004 SVE pilot test at MW-07 indicated TCE at 2,700 ppbv to 10,000 ppbv). The equilibrium soil vapor
concentration for 5 ug/1 TCE in groundwater at 15 degrees Celsius is 241 ppbv. Thus, a vapor
concentration of 200 ppbv will generally correspond to groundwater concentrations near the MCL or
below.
The new wells (drilled as part of recommendation 6.1.1) should be connected by underground piping to a
properly sized blower system with appropriate moisture separator and fail safes. It is suggested that the
equipment be purchased rather than rented. The blower should have a capacity of about 250 scfm at 60
inches H2O (Ametek Rotron DR858, 10HP or similar). The SVE emissions should be treated through
two 400 Ib GAC units in series. Well pumps should be installed in the three source area wells. A
reasonable pumping rate from the three new wells is likely on the order of 2 gpm total. The water should
be pumped through underground piping to a tank where condensate from the SVE system can also be
collected then the water would be pumped through sediment filters and two 200 Ib GAC units in series
prior to discharge to the storm sewer. We assume that an effluent tank will not be required.
In addition to the installation of the new wells discussed in Section 6.1.1, the likely capital costs for this
system would be approximately $132,000:
• About 100' piping: $5,000
• Blower unit with controls: $20,000
• 3 Submersible pumps installed: $18,000
• Conduit and wiring: $6,000
• 4 (2 spare) GAC for vapor: $6,000
• 4 (2 spare) GAC for water: $3,000
• Bag filters; $2,000
• Transfer tank and pump: $2,000
• Installation in an existing building or small shed: $25,000
• Design, Construction Management: $25,000
• Misc: $20,000
Annual operating costs for the proposed system (does not include current groundwater monitoring) are
roughly approximated to be $106,000 per year, as follows:
• a weekly system check @$500/wk= $26,000
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• monthly water process (3/month) and vapor (3/month) sampling = $15,000
• Approximate 15KW load power (maximum) = $9,000
• GAC including (2) 400 Ib vapor and (2) 200 Ib water units plus disposal $6,000
• Project management and reporting = $24,000
• Quarterly sampling of vapor and groundwater for VOCs at three new wells = $6,000
• Misc: $20,000
The quarterly sampling at the three new wells should not significantly add to labor since they will be part
of an operating system. It is assumed groundwater monitoring at other existing wells will remain at the
same frequency (quarterly) so those costs will not change from current costs.
6.1.3 INSTITUTIONAL CONTROLS
The RSE-lite team recommends that the site team further evaluate if institutional controls would be
appropriate to prevent human exposure to contaminated groundwater at the site. The site team has
indicated that the shallow groundwater is not used and not suitable for potable use due to inorganics. It
appears that there are other VOC sources in the area which could make long-term compliance with MCLs
difficult. While active remediation is recommended in Section 6.1.2 to address VOC impacts that likely
remain in the source area near MW-07, it is possible that VOC impacts near or at times just above the
MCL level may remain at the site.
6.2 RECOMMENDATIONS TO REDUCE COSTS
6.2.1 ST OP MNA ANALYSIS
Based on the analytical data, natural reductive dechlorination is not proceeding past DCE at the site and
enhanced reductive dechlorination is not a good fit for the site (see Section 6.4.2). Continuing analysis for
MNA parameters is not providing information useful for making decisions about remediation and it
should be terminated. It was estimated earlier that the analysis cost for these MNA parameters is likely
on the order of $5,000 per year. Labor costs would not change.
6.2.2 REDUCE SAMPLING FREQUENCY AT SELECT WELLS
The intermediate and deep intervals at MW-09 and MW-10 have not had a VOC detected above 0.5 ug/L
in 7 years of sampling. Vertical migration of the VOCs is not a concern at the site and sampling from
these wells should be eliminated or at a minimum reduced to an annual frequency. Other wells such as
MW-01 and MW-03 offer limited information for site remediation and the site team should consider
decreasing sampling frequency at additional select wells as more data is gathered. Assuming MNA
parameters are eliminated anyway (see Recommendation 6.2.1) this reduction in monitoring would not
reduce analysis costs (since the site does not incur costs for VOC analysis by the CLP lab). Labor will
likely be reduced slightly, so there would be some costs savings, but those savings would be minor and
are not quantified.
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6.2.3 Do NOT INSTALL Six OF SEVEN WELLS RECOMMENDED IN 2010 REMEDIAL
ACTION STATUS REPORT; CONSIDER OFF-SITE VAPOR SURVEY INSTEAD
The 2010 Remedial Action Status Report suggests the installation of up to seven new monitoring wells
(locations are indicated on the first figure in Attachment A). One of the seven proposed monitoring wells,
located about 75 feet west (down-gradient) of MW-02, could be useful to indicate potential VOC levels
from vapor and the down-gradient extent of the site plume in groundwater beyond MW-02. The RSE-lite
team does not suggest that the other six locations be added for the following reasons:
• Based on the current and historic distribution of VOCs in groundwater the site, the relatively slow
natural groundwater flow velocity, and historic information on soil vapor concentrations (from
passive vapor surveys, the SVE tests, and the SVE system operation), it does not appear that
upgradient VOC sources are impacting the site. The well most impacted with PCE is the most
downgradient well, MW-02 which is closest to the potential off-site sources based on the 2001
passive vapor screening. Thus, the three upgradient wells suggested in the 2010 report are not
likely to yield critical information.
• One of the suggested wells in the 2010 report is near the three new wells suggested in
recommendation 6.1.1, so that would be redundant.
• The other two wells suggested in the 2010 report (northeast of MW-10 and southwest of MW-4)
are likely not needed, since MW-4 and MW-2 are sufficient to monitor progress of the DPE
activities in Recommendation 6.1.2).
The removal of six of the up to seven proposed monitoring well may help avoid up to $90,000 in capital
costs, plus the added costs of monitoring those new wells. If an investigation is desired to delineate
potential PCE sources off-site, MIP or active soil gas sampling would be suggested, using the locations of
the passive vapor screening hits west of the site as a starting point. However, the RSE-lite team does not
believe this site should investigate off-site PCE sources (discussed further in Section 6.4.2).
6.3 RECOMMENDATIONS FOR TECHNICAL IMPROVEMENT
None.
6.4 CONSIDERATIONS FOR GAINING SITE CLOSE OUT
6.4.1 Do NOT CONSIDER ENHANCED REDUCTIVE DECHLORINATION
Enhancing reductive dechlorination (by injecting a carbon source such as emulsified oil) was suggested in
the 2010 Remedial Action Status Report, but the RSE-lite team does not believe that technology is a good
fit at the site because of the 100 foot depth to groundwater and associated high cost of injection wells, the
relatively low VOC concentrations in groundwater, and most importantly, the fact that the vadose zone
would not be addressed. The estimates provided in the Section 5.3 of the COM Final Remedial Action
Status Report are likely unrealistically optimistic regarding remedial costs and timeframe. A
bioremediation system including 4 injection wells in the source area would likely require approximately
$175,000 in capital costs:
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• (4) 120 foot deep wells: $60,000
• Inject 200 gallons Emulsified Oil per well diluted to 2%: $15,000
• Injection labor: $20,000
• Injection equipment: $20,000
• Bioaugmentation culture: $3,000
• Initial Performance Monitoring: $15,000
• Work plan/Design: $30,000
• Misc: $12,000
Extra monitoring costs and reporting costs would likely total at least $20,000 per year until closure.
Maintenance injections, if required might cost about $60,000 every two years.
This would be a good option at the site if the majority of VOC mass were in groundwater. Based on the
mass removal discussions in Section 2.1 and 2.2, the majority (likely »90%) of the VOC mass at the site
is present in the vadose zone. If the vadose zone is not addressed, the groundwater will be re-
contaminated. Therefore, SVE should be the main component of the remedy; and if SVE is required the
additional cost to install and run a low volume pump and treat system is minimal compared to the cost for
enhanced reductive dechlorination. Groundwater pumping also provides a more easily measured and
monitored remedy that is more appropriate for this site.
6.4.2 DEVELOP AN EXIT STRATEGY
An exit strategy should be developed to indicate when it is possible to terminate active remediation at this
site. The RSE-lite team believes that additional active remediation is currently merited since there is
likely a remaining TCE source area near MW-7 that is technically feasible to address. Once an attempt
has been made to address that source, several outcomes are possible:
• All VOCs may meet MCLs in groundwater, and the site can be closed after some period of
monitoring. The RSE-lite team assumes about three years of sampling would be needed after
shutting off the systems to show that a rebound does not occur.
• TCE in groundwater may meet MCLs but the active remedy may pull PCE from off-site sources
resulting in low PCE concentrations in groundwater that might exceed MCLs. If that occurs, a
reasonable exit strategy might allow for monitoring of continued attenuation of the PCE
concentrations in groundwater at the site after the active remedy for TCE is terminated, with no
further active remediation.
• TCE may remain on some portions of the site at levels slightly above MCLs, but at lower
concentrations than are currently observed and at concentrations that do not result in off-site TCE
impacts above MCLs in the future. At that point, a TI waiver for the remaining TCE
concentrations exceeding MCLs may be appropriate.
The exit strategy should be developed and documented in a site report as soon as possible, to serve as a
basis for the site team to make practical decisions regarding continued active remediation in the future.
The RSE-lite team estimates that development of the exit strategy for this site will cost approximately
$10,000 total for a draft and final document.
20
-------
6.5 RECOMMENDATIONS FOR ADDITIONAL GREEN PRACTICES
6.5.1 USE SMALLER SVE BLOWER THAN THE PREVIOUS SYSTEM
As mentioned earlier, approximately 85% of the electric use for the previous system was associated with
the 25 HP SVE blower. As described in Section 6.1.2, a 10 HP blower is recommended for SVE in a new
DPE system (for up to 3 wells) rather than the 25 HP unit used in the previous system. This will reduce
electrical usage on the order of 60% versus the previous system, with associated reductions in emissions
(as well as reduction in electricity cost). Since this blower represents a capital cost for another
recommendation, cost savings for electricity savings for using a small blower are not estimated.
6.5.2 CONSIDERATIONS FOR RENEWABLE ENERGY AT THE SITE
Due to the projected short-term operation of the proposed system and the redeveloped status of the site,
the RSE-lite team does not encourage consideration and investment into a renewable energy system for
the site. If the site team chooses to reduce the remedy footprint through the use of renewable energy, it
could consider green power purchasing through the local utility (if available) or through the purchase of
renewable energy certificates. Green power purchasing would increase costs (perhaps by approximately
$0.03 per kWh) but would avoid significant capital costs for renewable energy system design and
installation. Assuming a future system might use on the order of 80,000 kWh/yr (lower than the previous
system due to lower HP for the blower), so purchasing renewable energy certificates at $0.03 per kWh
might cost on the order of $2,400 per year.
21
-------
Table 6-1. Cost Summary Table
Recommendation
6.1.1 INVESTIGATE
SOURCE AREAS AND
INSTALL DPE WELLS
6.1.2 INSTALL AND
OPERATE DPE SYSTEM
6.1.3 INSTITUTIONAL
CONTROLS
6.2.1 STOP MNA ANALYSIS
6.2.2 REDUCE SAMPLING
FREQUENCY AT SELECT
WELLS
6.2.3 DO NOT INSTALL SIX
OF SEVEN PROPOSED WELLS
6.4. 1 DO NOT CONSIDER
ENHANCED REDUCTIVE
DECHLORINATION
6.4.2 DEVELOP AN EXIT
STRATEGY
6.5.1 USE SMALLER SVE
BLOWER
6.5.2 CONSIDERATIONS
FOR RENEWABLE ENERGY
AT THE SITE
Reason
Effectiveness
Effectiveness
Effectiveness
Cost Reduction
Cost Reduction
Cost Reduction
Site Closeout
Site Closeout
Green Practice
Green Practice
Additional
Capital Costs ($)
$80,000
$132,000
$0
$0
$0
($90,000)
$0
$10,000
Estimated
Change in
Annual Costs
($/yr)
$0
$106,000
$0
($5,000)
$0
$0
Estimated
Change in Life-
Cycle Costs
$*
$80,000
$556,000
$0
($20,000)
$0
($90,000)
Discounted
Estimated
Change in Life-
Cycle Costs
$**
$80,000
$537,874
$0
($19,145)
$0
($90,000)
Not quantified
$0
$10,000
$10.000
Former system has not operated since 2006, so savings is not quantified
$0 $2,400
$9,600
$9,190
Costs in parentheses imply cost reductions
* assumes 4 years of operation with a discount rate of 0% (i.e., no discounting)
** assumes 4 years of operation with a discount rate of 3%, no discounting in the first year (P/A= 3.829)
-------
Table 6-2. Green Remediation Summary Table
Recommendation
Reason
Green Remediation Effects
6.1.1 INVESTIGATE SOURCE AREAS
AND INSTALL DPE WELLS
Effectiveness
Increase in energy and materials
associated with well installation
6.1.2 INSTALL AND OPERATE DPE
SYSTEM
Effectiveness
Use of 10 HP blower rather than
previous 25 HP Blower may reduce
electricity up to ~ 60%.
6.1.3 INSTITUTIONAL CONTROLS
Effectiveness
Negligible increases or decreases in
remedy footprint
6.2.1 STOP MNA ANALYSIS
Cost reduction
Reduction in energy and materials
usage by laboratory associated with
sample analysis as well as shipping
6.2.2 REDUCE SAMPLING
FREQUENCY AT SELECT WELLS
Cost Reduction
Reduction in energy and materials
usage by laboratory associated with
sample analysis
6.2.3 DO NOT INSTALL SIX OF
SEVEN PROPOSED WELLS
Cost Reduction
Decrease in energy and materials
associated with well installation
6.4.1 DO NOT CONSIDER
ENHANCED REDUCTIVE
DECHLORINATION
Site Closeout
Decrease in energy and materials
associated with well installation and
emulsified oil injection.
6.4.2 DEVELOP AN EXIT STRATEGY
Site Closeout
Negligible increases or decreases in
remedy footprint
6.5.1 USE SMALLER SVE BLOWER
Green Practice
See 6.1.2.
6.5.2 CONSIDERATIONS FOR
RENEWABLE ENERGY AT THE SITE
Green Practice
Consider purchase of Renewable
Energy Certificates to offset
emission associated with electricity
-------
ATTACHMENT A
FIGURES FROM EXISTING REPORTS
-------
Treated GW Discharge Line
Buried 30" deep
Storm Sewer
Tie-In
Extracted GW Line
Buried 30" deep
%>--'' ''--"^Kprmer Above G/oujTd Bermed
, - - -Storage Tank Locations Impoundment
( ij Former UST and Dispense!
Lockedw,
Gate I
Groundwater Elevation Contours (April 2011)
Suggested New Well Locations
Existing Monitoring Well
Site Boundary
April 2011 Groundwater Elevation Contours
and Suggested New Monitoring Well Locations
IWOR, Bountiful, UT
DPE - Dual Phase Extraction
P&T - Pump and Treat
MW - Monitoring Well
-------
Storm Sewer
Tie-In
Treated GW Discharge Line
Buried 30" deep
Fo>mer UST and DlspBnseH -' Waste piles
Parking AresK Removed Concrete lT_I_u--^ Line Locati
/Sump
' ' ' I •' J
ig--'' '--Xprmer Above G/ouQd Bermed
'-> ,--Storage Tank Locations ""impoundment
Legend
Groundwater Elevation Contours (April 2011)
SugijbbUjd NBW Well Locations —
Existing Monitoring Well
Site Boundary
DPE - Dual Phase Extraction
P&T - Pump and Treat
MW-Monitoring Well
A
N
I Feet
Figure •S=T
April 2011 Groundwater Elevation Contours
and Suggested New Monitoring Well Locations
IWOR, Bountiful, UT
-------
ATTACHMENT B
VARIOUS SOURCES OF EMISSIONS DATA ASSOCIATED WITH ELECTRICITY
-------
Bountiful City Power - History
BOUNTIFUL CITY
Power
Power Internal Pages:
• Main Page
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Back
History
The city of Bountiful, Utah is located ten miles north of Salt Lake City. The
citizens of Bountiful first received electric services from a small, local power
company called "Bountiful Light and Power Company", which was organized on
July 3, 1907. The company was originally capitalized for $10,000. Most of the
principal stockholders lived in Bountiful, or the immediate area. The 2005 book
value of Bountiful City Light & Power was about $40,000,000.
A distribution system was constructed which served between 200-300 customers.
At that time, the officers of the Company conducted a study and determined that
it was cheaper to purchase power wholesale than to build a power plant.
Accordingly, a contract was signed with the Utah Light and Railway Company,
later known as the Utah Light and Traction Company, and presently as Utah
Power and Light (UP&L).
The old timers say that the Company failed to keep its distribution system in
good repair, and was subject to extensive public criticism, as well as pressure
from the Public Service Commission to improve its performance. They also recall
that electric service from the Company continued to deteriorate to a level that
prompted its customers to petition the city to intervene.
Dr. J.C. Stocks, who was mayor, headed up a citizen's task force to investigate
the complaint in about 1934. The investigation eventually lead to the City's
decision to own and operate its electric system, and better serve its citizens.
Then, as is the case now, the sources of power and energy were the most
challenging aspects of system operation. They realized that cost and reliability are
the two most important factors. Meanwhile, the City had negotiated a price for
the Company's distribution system, and obtained an option to assure the
purchase while the City arranged for financing. Revenue bonds in the amount of
$106,000 were issued by the City for construction of the power plant and the
purchase of the distribution system. The bonds were paid back through electric
revenues.
On May 22, 1935, Bountiful's own power plant produced its first electricity. During
that same year, the City Council approved three citizen appointments to serve on
the first Bountiful City Light and Power Commission. They were Mayor J.C.
Stocks, and Council representatives John S. Ledingham and Alfred G. Brown. One
of the first things they did as a Commission was investigate the condition of the
power plant. It was then recommended to employ an experienced person as
manager. Morton Fackrell served as the first manager for six months. The
Commission next appointed Samuel W. Hutchings, who served from 1935 to
1938. Since that time, five men have served as manager: John Ledingham,
Robert Nicol, Vaun Bethers, W. Berry Hutchings (twice), and Clifford C. Michaelis.
Berry Hutchings served as manager from 1950 to 1976. Vaun Bethers, the
Department Engineer, was appointed manager from 1976 to 1980. During that
time Mr. Hutchings served in a new position as Power Resource Manager. His
efforts helped Bountiful obtain licenses for the construction of hydro-electric
plants on Echo Dam, East Canyon Dam, Moon Lake and Lost Creek Dam. He was
http://www.bountifulutah.gov/PowerHistory.aspx[8/4/201111:39:17 AM]
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Bountiful City Power - History
also instrumental in Bountiful being awarded the license to take over the Weber
River hydro plant in Weber Canyon. However, after nearly ten years of court
litigation, Congress decided to re-license that plant to the previous operator.
Mr. Bethers left in 1980 and Mr. Hutchings was reappointed manager. He served
in that position until his retirement in 1983. At that time the City promoted from
within the department again, selecting Clifford C. Michaelis as manager. The job
title was then changed to Director.
The governing board for the Power Department is a Power Commission which is
appointed by the mayor and City Council. They work with the staff in making the
major decisions for the department and send their recommendations to the City
Council. The present members of the Power Commission are: Lowell Leishman
(Chairman), David Irvine, Fred Moss (City Council Representative), Richard
Foster, Ralph Mabey, John Cushing, and Jed Pitcher.
The Power Department offices were first located in a home at about 180 West
300 South, just east of the present power plant. After the discontinuation of the
Bamberger Railroad in 1952, the large warehouse building at 198 South 200 West
was owned by Muir-Roberts Produce Company. It was acquired by Bountiful
Power in 1964. The building has a historical marker near the front door denoting
the railroad connection. In 1978, a major addition was made to the office
building, which included ten truck bays and warehouse space on two levels. In
1998, major remodeling of the office spaces was done. In 1988 a six bay garage
was constructed to the west of the main building to house more equipment and
material.
The City-owned power plant was the first power resource, which at that time
consisted of three engines; two six-cylinder Buckeyes (approximately 110
kilowatts), and one three-cylinder Buckeye (approximately 60 kilowatts). As the
demand for more power rapidly increased, additional generating units were
installed. From 1955 to 1959, four Superior engines were added and only the
oldest Buckeye engine was left in place. In 1963 another addition was made to
the plant and a Cooper 2,500 kilowatt engine was added. In 1986 Bountiful built
a major addition to the plant to allow space for a 7,000 kilowatt Enterprise
engine. In 1995, the dispatch center was completely remodeled. In 2001 a gas
turbine was installed. At the present time, the power plant houses eight separate
turbo-charged generating units, and a gas turbine with an installed capacity of
19,000 kilowatts (if all nine were running at the same time). Today Bountiful City
Light and Power serves a population of about 43,000 and has over!6,000
metered customer accounts.
In the late 1940's, the cost of diesel fuel to operate the generating units
increased to the level where it was as economical to purchase power from UP&L
as to generate it; therefore, in 1948, an interconnection with the UP&L system
was made. Power was purchased from them for several years to supply the
needs of the system.
In 1953 Mountain Fuel Supply Company released an abundant supply of natural
gas at a cost substantially below the cost of purchasing power from UP&L. From
1954 to 1957, pressure from several groups tried to force the City out of the
power business. The manager, Berry Hutchings, and the Power Commission
convinced the City Fathers that natural gas, instead of diesel fuel to operate the
power plant generators would save the city millions of dollars. In 1957 another
electric revenue bond for $275,000 was issued to convert the existing four
generators to dual fuel (natural gas and diesel), upgrade the power plant, and
purchase four Superior engines.
The main use of the power plant today is for providing peaking power to meet
the needs of the city during high use periods, and for emergency power
purposes. It is idle when less expensive power can be purchased to meet the
needs of the City. However, in the winter months one engine is put on-line so
that the waste heat from it can be sent through pipes to heat the plant buildings
and the main office and warehouse building across the street. Bountiful also sells
some of its generated power to other utilities. The Power Plant presently supplies
less than 10% of the City's power needs.
In 1962 Bountiful was able to successfully contract with the Federal Government
to purchase hydroelectric power from the Colorado River Storage Project (CRSP).
It was an escalating contract which allowed for more power to be purchased each
year to keep up with increased city growth. At that time, that form of power was
more expensive than many other sources; but over the years it has become the
http://www.bountifulutah.gov/PowerHistory.aspx[8/4/201111:39:17 AM]
-------
Bountiful City Power - History
"low-cost"supply. The City's present contract is for 43,265 kilowatts per month
during the winter season, and 27,148 kilowatts per month during the summer
season. The first CRSP power generated at Flaming Gorge Dam was delivered in
1963. Another part of CRSP is power generated by the eight generators at Glen
Canyon Dam, which Bountiful started receiving in 1964. Today the Western Area
Power Administration (WAPA) is the marketing arm of the Federal Government
that was established to allocate those power sales. The City receives about 60
percent of its power from WAPA.
Bountiful City is also a participant in two coal-fired power plants: the
Intermountain Power Project (IPP), near Delta, Utah, and the San Juan Project in
New Mexico. A portion of the City's IPP power allocation is presently being sold to
six California cities (Anaheim, Burbank, Glendale, Los Angeles, Pasadena and
Riverside). Bountiful uses IPP power to cover about 14 percent of its present
load. The San Juan plant currently provides about 12 percent of the City's power
requirements.
Over the years, Bountiful has received authorization from the federal government
to build and operate hydroelectric facilities at various sites around Utah from the
Federal Energy Regulatory Commission (FERC). Bountiful has captured the energy
from those renewable resources to provide electricity to its citizens at the most
reasonable costs available, while preserving the integrity of the Utah
environment. The City was awarded the licenses to operate facilities at Echo Dam
and Pineview Dam. The Echo hydro plant was built in 1986. It consists of three
vertical turbines, which can generate a total of 4,500 kilowatts. Bountiful built its
own 26 mile transmission line to bring that power over the mountains to the city.
The Pineview hydro plant was built in 1991. It has one vertical turbine that
generates 1,800 kilowatts. Several other projects are currently being studied for
their feasibility.
In 1992 Bountiful Power purchased the former Colonial Lumber property on the
corner of 200 South and 200 West. The main building is being used for material
storage. Part of the land was used to build a new gas turbine in 2001. That unit
provides over 4,000 kilowatts.
Bountiful is a member of the Utah Associated Municipal Power System (UAMPS).
UAMPS serves 35 cities and 11 other agencies in Utah, Idaho, New Mexico and
Arizona. It serves as the power broker and helps make low-cost power available
to its members. About 20 percent of Bountiful's power is purchased through
UAMPS.
Over the years the Department has had a variety of experiences with bad
weather and the challenges of mother nature. East winds and snow had caused
the biggest problems until the floods of 1983. In May 1983 the City endured so
called "100 year floods", which came roaring down the canyons. A wall of water
smashed into the City's Northeast substation on 250 North and caused massive
destruction. Rebuilding the substation on higher ground at the same location took
a full year. Over the years, the infamous east winds have caused many
problems, but Bountiful's power crews worked through them all. Another notable
event took place in the fall of 1990, when the old wooden cooling tower at the
Power Plant caught fire (as it was being prepared for demolition) and burned to
the ground.
Although the main purpose of the Power Department has been to provide an
inexpensive source of power to city residents, much of the margin from the sale
of electricity is transferred to the City's General Fund and Capitol Improvement
Fund. Those funds aid in keeping the City's tax mill levy at a low level. Each year
money is transferred to those funds, which helps the City keep its equipment up
to date and to help pay for other projects. No tax dollars are used to finance the
power system operations.
The most important ingredients for the success of Bountiful City Light and Power
are the support of the citizens of Bountiful, the Bountiful City Council, the Power
Commission and the great dedication of the Power Department employees. Its
employees often work long hours during inclimate weather to restore power and
ensure that reliable power is delivered to the customers. Bountiful City Light and
Power continues to provide great service to its customers and looks forward to
the opportunities that the new century will bring.
http://www.bountifulutah.gov/PowerHistory.aspx[8/4/201111:39:17 AM]
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Bountiful City Power - History
Bountiful City Information Systems
Copyright 2011
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-------
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GHG Emission Factors I Reports I Notes
View Data
Electric Generating Company (EGC) Location (Operator) based Level Data
Company: Bountiful City City of
Parent Company:
Capacity (MW):
Net Generation (MWh):
Heat Input (MMBtu):
—1 1
Pollutant
Annual CO2
Annual SC>2
Annual NOX
Ozone Season NOX
Annual Hg
Annual CH4
Annual N2O
| Addltlolal EmlsslOTS Rates |
25.4
26,920.7
57,511.4
IB
Emissions Units
3,397.8 tons
0.22 tons
24.93 tons
13.17 tons
N/A
141.0 Ibs
15.2 Ibs
^^^^^^•^-^
Output Emission Rates Units Inpi
252.43 Ib/MWh
0.0166 Ib/MWh
1.8522 Ib/MWh
2.0840 Ib/MWh
N/A
5.24 Ib/GWh
0.56 Ib/GWh
Data Year: 2005
0 Location (Operator)-based
0 Owner-based
^^^
it Emission Rates Units
118.16 Ib/MMBtu
0.0078 Ib/MMBtu
0.8670 Ib/MMBtu
0.8631 Ib/MMBtu
N/A
N/A
N/A
eGRIDweb
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eGRID2007 Version 1.1 Year 2005 GHG Annual Output Emission Rates
Annual output emission rates for greenhouse gases (GHGs) can be used as default factors for estimating GHG emissions from electricity use when developing
a carbon footprint or emission inventory Annual non-baseload output emission rates should not be used for those purposes, but can be used to estimate GHG
emissions reductions from reductions in electricity use.
eGRID
subregion
acronym
AKGD
AKMS
AZNM
CAMX
ERCT
FRCC
HIMS
HIOA
MROE
MROW
NEWE
NWPP
NYCW
NYLI
NYUP
RFCE
RFCM
RFCW
RMPA
SPNO
SPSO
SRMV
SRMW
SRSO
SRTV
SRVC
eGRID subregion name
ASCC Alaska Grid
ASCC Miscellaneous
WECC Southwest
WECC California
ERCOT All
FRCC All
HICC Miscellaneous
HICC Oahu
MRO East
MRO West
NPCC New England
WECC Northwest
NPCC NYC/Westchester
NPCC Long Island
NPCC Upstate NY
RFC East
RFC Michigan
RFC West
WECC Rockies
SPP North
SPP South
SERC Mississippi Valley
SERC Midwest
SERC South
SERC Tennessee Valley
SERC Virginia/Carolina
Annual output emission rates
Carbon dioxide Methane Nitrous oxide
(CO2) (CH4) (N2O)
(Ib/MWh) (Ib/GWh) (Ib/GWh)
1,232.36 25.60 6.51
498.86 20.75 4.08
1,311.05 17.45 17.94
724.12 30.24 8.08
1,324.35 18.65 15.11
1,318.57 45.92 16.94
1,514.92 314.68 46.88
1,811.98 109.47 23.62
1,834.72 27.59 30.36
1,821.84 28.00 30.71
927.68 86.49 17.01
902.24 19.13 14.90
815.45 36.02 5.46
1,536.80 115.41 18.09
720.80 24.82 11.19
1,139.07 30.27 18.71
1,563.28 33.93 27.17
1,537.82 18.23 25.71
1,883.08 22.88 28.75
1 ,960.94 23.82 32.09
1,658.14 24.98 22.61
1,019.74 24.31 11.71
1,830.51 21.15 30.50
1,489.54 26.27 25.47
1,510.44 20.05 25.64
1,134.88 23.77 19.79
Annual non-baseload output emission rates
Carbon dioxide Methane Nitrous oxide
(CO2) (CH4) (N2O)
(Ib/MWh) (Ib/GWh) (Ib/GWh)
1,473.43 36.41 8.24
1,457.11 60.47 11.87
1,201.44 20.80 8.50
1 ,083.02 39.24 5.55
1,118.86 20.15 5.68
1,353.72 48.16 12.95
1,674.15 338.44 51.42
1,855.10 120.11 20.79
1,828.63 28.82 25.20
2,158.79 45.57 35.22
1,314.53 77.47 16.02
1,333.64 49.28 18.73
1 ,525.05 56.80 9.08
1,509.85 60.32 10.78
1,514.11 45.30 18.41
1,790.50 41.61 24.36
1,663.15 29.40 26.24
1,992.86 24.49 31.72
1,617.71 22.42 20.14
2,169.74 31.18 31.99
1,379.05 24.40 12.04
1,257.10 29.50 9.82
2,101.16 25.66 32.92
1,697.22 35.20 26.41
1 ,998.36 28.25 32.86
1,781.28 40.09 27.46
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Table 1. 2009 Summary Statistics
Item Val
Utah
NERC Region(s)
Net Summer Capacity (megawatts)
Electric Utilities
Independent Power Producers & Combined Heat and Power
Electric Utilities
Independent Power Producers & Combined Heat and Power
Emissions (thousand metric tons)
Sulfur Dioxide
Nitrogen Oxide
Carbon Dioxide
Sulfur Dioxide (Ibs/MWh)
Nitrogen Oxide (Ibs/MWh)
Carbon Dioxide (Ibs/MWh)
Full Service Provider Sales (megawatthours)
Average Retail Price (cents/kWh)
ue U.S. Rank
WECC
Coal
7,418 39
6,581 32
838 43
43,542,946 34
40,991,819 27
2,551,126 43
30 35
68 13
36,518 25
1.5 38
3.5 5
1,849 11
27,586,700 37
27,586,700 36
1,092,589 22
6.77 45
MWh = Megawatthours.
kWh = Kilowatthours.
Sources: U.S. Energy Information Administration, FormEIA-860, "Annual Electric Generator Report." U.S. Energy Information Administration, Form EIA-861, "Annual Electric Power Industry
Report." U.S. Energy Information Administration, Form EIA-923, "Power Plant Operations Report" and predecessor forms.
Table 2. Ten Largest Plants by Generating Capacity, 2009
_, , Primary Energy Source or
Plant T i, i
1 ecnnology
U1
1.
2.
3.
4.
5.
6.
8.
9.
10
tab
Hunter Coal
Lake Side Power Plant Gas
Bonanza Coal
KUCC Coal
West Valley Generation Project Gas
Net Summer
Operating Company Capacity
(MW)
Los Angeles City of 1 ,800
PacifiCorp 1,320
PacifiCorp 895
PacifiCorp 557
PacifiCorp 540
Deseret Generation & Iran Coop 458
PacifiCorp 348
Kennecott Utah Copper Corporation 207
Milford Wind Corridor Phase I LLC 204
CER Generation LLC 1 89
MW = Megawatt.
Source: U.S. Energy Information Administration, Form EIA-860, "Annual Electric Generator Report."
265
State Electricity Profiles 2009
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Table 3. Top Five Retailers of Electricity, with End Use Sectors, 2009
(Megawatthours)
Type of
Entity All Sectors Resid
Provider
Utah
l.PacifiCorp Investor-Owned 22,097,825
2 Provo Citv Corn Public 761 759
3
4
5
T
P
City of St George Public 595,622
City of Murray Public 423 943
City of Logan Public 397,961
3tal Sales Top Five Providers 24277110
srcent of Total State Sales 88
ential Commercial Industrial Transportation
6,495,687 7,971,632 7,598,164 32,342
238,205 390,489 133,065
265,162 106,452 224,008
116,691 258,739 48,513
96,476 168,188 133,297
7,212,221 8,895,500 8,137,047 32,342
83 87 95 100
- (dash) = Data not available.
Source: U.S. Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report."
Table 4. Electric Power Net Summer Capacity by Primary Energy Source and Industry Sector, 1999 and 2003 Through 2009
(Megawatts)
Energy Source
1999
2003
2004
2005
2006
2007
2008
2009
Percentage Share
1999
2009
Utah
Coal
Petroleum
Natural Gas
Hydroelectric
Other Renewables
Pumped Storage
Independent Power Producers and Combined Heat and
Power
Coal
Petroleum
Natural Gas
Other Gases2
Hydroelectric
Other Renewables1
Other3
Total Electric Industry
Coal
Petroleum
Natural Gas
Other Gases2
Hydroelectric
Other Renewables1
Pumped Storage
Other3
4,463
44
296
265
35
131
54
19
4
48
4
1
5,233
4,517
63
300
48
269
36
.
-
4,461
46
782
252
33
223
144
3
72
-
2
i
5,797
4,606
49
854
-
254
34
-
-
4,645
38
796
252
23
436
181
195
-
2
1
57
6,190
4,826
38
991
-
254
24
-
57
4,645
35
1,098
253
23
475
246
225
-
2
i
6,528
4,891
35
1,323
-
255
24
-
-
4,645
35
1,257
253
23
500
246
215
-
2
4
32
6,712
4,891
35
1,473
-
255
27
-
32
4,645
25
1,755
253
33
412
226
179
-
2
5
7,122
4,871
25
1,934
-
255
38
-
-
4,645
25
1,542
253
34
633
226
381
-
2
23
7,132
4,871
25
1,923
-
256
57
-
-
4,645
25
1,624
253
34
838
226
378
-
2
231
7,418
4,871
25
2,002
-
256
265
-
-
85.3
0.8
5.7
5.1
0.7
2.5
1.0
0.4
0.1
0.9
0.1
*
100.0
86.3
1.2
5.7
0.9
5.1
0.7
.
-
62.6
0.3
21.9
3.4
0.5
11.3
3.0
5.1
-
*
3.1
100.0
65.7
0.3
27.0
-
3.4
3.6
-
-
1 Other Renewables includes wood, black liquor, other wood waste, municipal solid waste, landfill gas, sludge waste, agriculture byproducts, other biomass, geothermal, solar thermal,
photovoltaic energy, and wind.
2 Other gases includes blast furnace gas, propane gas, and other manufactured and waste gases derived from fossil fuels.
3 Other includes batteries, chemicals, hydrogen, pitch, purchased steam, sulfur, tire-derived fuels and miscellaneous technologies.
* = Value is less than half of the smallest unit of measure (e.g., for values with no decimals, the smallest unit is 1 and values under 0.5 are shown as *).
- (dash) = Data not available.
Source: U.S. Energy Information Administration, Form EIA-860, "Annual Electric Generator Report."
State Electricity Profiles 2009
266
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Table 5. Electric Power Net Generation by Primary Energy Source and Industry Sector, 1999 and 2003 Through 2009
(Megawatthours)
Energy Source
1999
2003
2004
2005
2006
2007
2008
2009
Percentage
Share
1999
2009
Utah
Electric Utilities
Coal
Petroleum
Natural Gas
Hydroelectric
Other Renewables1
Independent Power Producers and
Combined Heat and Power
Coal
Petroleum
Natural Gas
Other Gases2
Hydroelectric
Other Renewables1
Other3
Coal
Petroleum
Natural Gas
Other Gases2
Hydroelectric
Other Renewables1
Other3
36,071,421
34,125,014
29,023
515,127
1,246,727
155,530
713,207
408,767
1,641
94,930
191,285
8,415
8,169
36,784,628
34,533,781
30,664
610,057
191,285
1,255,142
163,699
37,544,892
35,579,158
31,386
1,322,984
412,899
198,465
478,774
399,490
1,480
60,123
-
8,440
5,083
4,158
38,023,666
35,978,648
32,866
1,383,107
-
421,339
203,548
4,158
37,165,917
35,634,374
32,567
864,181
439,919
194,876
1,046,060
983,480
34
45,669
-
9,929
3,821
3,126
38,211,977
36,617,854
32,601
909,850
-
449,848
198,697
3,126
36,695,193
34,824,862
40,245
874,505
770,779
184,802
1,469,938
1,145,543
664
302,996
-
13,684
3,948
3,102
38,165,131
35,970,405
40,909
1,177,501
-
784,463
188,750
3,102
39,590,509
35,667,551
29,619
2,965,072
737,659
190,608
1,672,815
1,187,999
32,507
423,478
-
9,124
14,868
4,838
41,263,324
36,855,550
62,126
3,388,550
-
746,783
205,476
4,838
43,319,965
35,910,192
38,828
6,673,998
533,021
163,925
2,052,610
1,260,602
319
750,220
-
5,761
31,030
4,679
45,372,575
37,170,794
39,147
7,424,218
-
538,782
194,955
4,679
44,424,071
36,761,964
43,612
6,705,185
659,033
254,277
2,154,691
1,258,402
-
661,122
35,788
9,051
47,585
142,743
46,578,763
38,020,367
43,612
7,366,307
35,788
668,084
301,862
142,743
40,991,819
34,284,061
36,057
5,565,584
826,996
279,121
2,551,126
1,242,065
-
878,458
27,933
8,261
207,415
186,994
43,542,946
35,526,126
36,057
6,444,042
27,933
835,257
486,536
186,994
98.1
92.8
0.1
1.4
3.4
0.4
1.9
1.1
*
0.3
0.5
*
*
100.0
93.9
0.1
1.7
0.5
3.4
0.4
94.1
78.7
0.1
12.8
1.9
0.6
5.9
2.9
-
2.0
0.1
*
0.5
0.4
100.0
81.6
0.1
14.8
0.1
1.9
1.1
0.4
1 Other Renewables includes biogenic municipal solid waste, wood, black liquor, other wood waste, landfill gas, sludge waste, agriculture byproducts, other biomass, geothermal, solar thermal,
photovoltaic energy, and wind.
2 Other gases includes blast furnace gas, propane gas, and other manufactured and waste gases derived from fossil fuels.
3 Other includes non-biogenic municipal solid waste, batteries, chemicals, hydrogen, pitch, purchased steam, sulfur, tire-derived fuels and miscellaneous technologies.
* = Value is less than half of the smallest unit of measure (e.g., for values with no decimals, the smallest unit is 1 and values under 0.5 are shown as *).
- (dash) = Data not available.
Note: Totals may not equal sum of components because of independent rounding.
Source: U.S. Energy Information Administration, Form EIA-923, "Power Plant Operations Report" and predecessor forms.
267
State Electricity Profiles 2009
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Table 6. Electric Power Delivered Fuel Prices and Quality for Coal, Petroleum, and Natural Gas, 1999 and 2003 Through 2009
Fuel, Quality
1999
2003
2004
2005
2006
2007
2008
2009
Utah
Coal (cents per million Btu)
Average heat value (Btu per pound)
Average sulfur Content (percent)
Petroleum (cents per million Btu)
Average heat value (Btu per gallon)
Average sulfur Content (percent)
Natural Gas (cents per million Btu)
Average heat value (Btu per cubic foot)
103
11,620
0.46
298
104,081
3.09
254
1,043
W
11,025
0.55
722
139,493
0.23
W
1,062
W
10,718
0.52
924
139,512
0.23
W
1,049
W
10,786
0.52
1,291
139,752
0.26
W
1,047
W
10,981
0.58
1,525
139,660
0.25
W
1,052
W
11,156
0.58
1,753
139,376
0.25
W
1,051
W
11,060
0.53
2,217
138,979
0.30
W
1,036
W
10,965
0.56
1,413
139,467
0.31
366
1,043
1 Petroleum includes petroleum liquids and petroleum coke.
Btu = British thermal unit.
W = Withheld to avoid disclosure of individual company data.
Note: Due to different reporting requirements between the Form EIA-923 and historical FERC Form 423, the receipts data from 2008 and on are not directly comparable to prior years. There may
be a notable increase in fuel receipts beginning with 2008. For more information, please see the Technical Notes in the Electric Power Annual.
Sources: U.S. Energy Information Administration, Form EIA-423, " Monthly Cost and Quality of Fuels for Electric Plants Report." Federal Energy Regulatory Commission, FERC Form 423,
"Monthly Cost and Quality of Fuels for Electric Plants." U.S. Energy Information Administration, Form EIA-923, "Power Plant Operations Report."
Table 7. Electric Power Industry Emissions Estimates, 1999 and 2003 Through 2009
(Thousand Metric Tons)
Emission Type 1999 2003 2004 2(
Utah
Sulfur Dioxide
Coal 28 32 34
Petroleum * * *
Other Gases *
Other1 * * *
Total 28 32 34
Coal 67 64 65
Natural Gas 3 2 1
Other Renewables2 -R -R -R
Other1 * * *
Total 70 66 66
Coal 32 081 R 33 904R 34 906R
Petroleum 24 26 26
Natural Gas 462 784 528
Geothermal 455
Other1 57E 54 57
Total 32 627E 34 773E 35 522E
105 2006 2007 2008 2009
31 34 25 22 30
31 34 25 22 30
62 68 67 62 66
11321
64 69 70 65 68
35,528E 35,1 06E 35,503E 36,1 06E 33,576
31 56 31 33 27
701 1,631 3,321 3,182 2,855
55477
58 56 46 54 52
36,324E 36,853E 38,906E 39,381 E 36,518
1 Other includes non-biogenic municipal solid waste, tire-derived fuels, and miscellaneous technologies.
2 Other Renewables includes biogenic municipal solid waste, wood, black liquor, other wood waste, landfill gas, sludge waste, agriculture byproducts, and other biomass.
R = Revised.
* = Value is less than half of the smallest unit of measure (e.g., for values with no decimals, the smallest unit is 1 and values under 0.5 are shown as *).
- (dash) = Data not available.
Note: CO2 emissions for the historical years 1998 - 2008 have been revised due to changes in emission factors.
Sources: Calculations made by the Electric Power Systems and Reliability Team; Office of Electricity, Renewables, and Uranium Statistics; U. S. Energy Information Administration.
State Electricity Profiles 2009
268
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Table 8. Retail Sales, Revenue, and Average Retail Prices by Sector, 1999 and 2003 Through 2009
Sector
1999
2003
2004
2005
2006
2007
2008
2009
Percentage Share
1999
2009
Utah
Retail Sales (thousand megawatthours)
Residential
Commercial
Industrial
Other
Transportation
All Sectors
Residential
Commercial
Industrial
Other
Transportation
All Sectors
Average Retail Prices (cents/kWh)
Residential
Commercial
Industrial
Other
Transportation
All Sectors
6,236
7,282
7,568
792
NA
21,879
391
385
254
33
NA
1,064
6.27
5.29
3.36
4.21
NA
4.86
7,166
9,024
7,646
NA
25
23,860
494
504
290
NA
1
1,290
6.90
5.59
3.79
NA
6.01
5.41
7,325
9,345
7,816
NA
25
24,512
528
551
314
NA
2
1,395
7.21
5.90
4.01
NA
6.57
5.69
7,567
9,417
7,989
NA
28
25,000
569
571
339
NA
2
1,481
7.52
6.07
4.24
NA
7.20
5.92
8,232
9,749
8,356
NA
29
26,366
625
599
352
NA
2
1,578
7.59
6.15
4.21
NA
7.19
5.99
8,752
10,241
8,759
NA
34
27,785
714
669
396
NA
3
1,782
8.15
6.54
4.52
NA
7.44
6.41
8,786
10,286
9,086
NA
33
28,192
725
686
417
NA
3
1,830
8.26
6.66
4.59
NA
7.85
6.49
8,725
10,235
8,594
NA
32
27,587
740
712
414
NA
3
1,868
8.48
6.96
4.81
NA
8.31
6.77
28.5
33.3
34.6
3.6
100.0
36.8
36.2
23.9
3.1
--
100.0
-
-
--
31.6
37.1
31.2
-
0.1
100.0
39.6
38.1
22.1
0.1
100.0
-
-
--
kWh = Kilowatthours.
NA = Not available.
— = Not applicable.
Source: U.S. Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report."
Table 9. Retail Electricity Sales Statistics, 2009
Item
Full Service Providers
Investor-
Owned
Public
Federal
Cooperative
Facility
Other Providers
Energy
Delivery
Total
Utah
Number of Entities
Number of Retail Customers
Retail Sales (thousand megawatthours)
Percentage of Retail Sales
Revenue from Retail Sales (million dollars)
Percentage of Revenue
Average Retail Price (cents/kWh)
1
787,551
22,098
80.10
1,453
77.76
6.57
40
228,120
4,373
15.85
343
18.37
7.85
1
10
61
0.22
2
0.09
2.75
9
43,729
1,055
3.82
71
3.77
6.69
NA
NA
NA
--
NA
--
NA
NA
NA
NA
--
NA
--
NA
NA
NA
NA
--
NA
--
NA
51
1,059,410
27,587
100.00
1,868
100.00
6.77
kWh = Kilowatthours.
NA = Not available.
— = Not applicable.
Notes: Data are shown for All Sectors. Full Service Providers sell bundled electricity services (e.g., both energy and delivery) to end users. Full Service Providers may purchase electricity from
others (such as independent Power Producers or other full service providers) prior to delivery. Other Providers sell either the energy or the delivery services, but not both. Sales volumes and
customer counts shown for Other Providers refer to delivered electricity, which is a joint activity of both energy and delivery providers; for clarity, they are reported only in the Energy column in
this table. The revenue shown under Other Providers represents the revenue realized from the sale of the energy and the delivery services distinctly. "Public" entities include municipalities, State
power agencies, and municipal marketing authorities. Federal entities are either owned or financed by the Federal Government. "Cooperatives" are electric utilities legally established to be owned
by and operated for the benefit of those using its services. The cooperative will generate, transmit and/or distribute supplies of electric energy to a specified area not being serviced by another
utility. "Non-utility" sales represent direct electricity transactions from independent generators to end use consumers. Totals may not equal sum of components because of independent rounding.
Source: U.S. Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report."
269
State Electricity Profiles 2009
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Table 10. Supply and Disposition of Electricity, 1999 and 2003 Through 2009
(Million Kilowatthours)
Category
1999
2003
2004
2005
2006
2007
2008
2009
Utah
Combined Heat and Power, Electric
Industrial and Commercial Generation Subtotal
Total Net Generation
Retail Sales
Full Service Providers
Total Electric Industry Retail Sales
Direct Use
Net Interstate Trade1
Net Trade Index (ratio)2
36071
409
8
36,488
26
270
296
36,785
36,785
21,879
21879
327
1,586
12992
36 785E
155
37 545
447
9
38,002
22
22
38,024
6
38,029
23,860
23860
360
1,522
12,286
38 029E
148
37 166
406
37,579
21
612
633
38,212
15
38,227
24,512
24512
361
1,861
11 494
38 227E
143
36695
706
7
37,408
20
737
757
38,165
41
38,206
25,000
25000
742
1
2,135
10328
38,2 06E
137
39591
829
11
40,430
28
805
833
41,263
15
41,279
26,366
26366
967
1
2,323
11622
41,2 79E
139
43320
1 096
11
44,427
45
901
946
45,373
22
45,394
27,785
27785
73E
38
2 680"
14 8191*
45 394E
1 481*
44424
976
-2
45,398
6
1 175
1,180
46,579
12
46,591
28,192
28192
if
55
2627"
15 702R
46 591E
151E
40992
1 325
10
42,327
3
1 213
1,216
43,543
8
43,551
27,587
27587
1,093
43
2322
12506
43,551
140
1 Net Interstate Trade = Total Supply - (Total Electric Industry Retail Sales + Direct Use + Total International Exports (if applies) + Estimated Losses).
2 Net Trade Index is the sum of Total Supply / (Total Disposition - Net Interstate Trade).
R = Revised.
- (dash) = Data not available.
Notes: Totals may not equal sum of components because of independent rounding. Estimated Losses are reported at the utility level, and then allocated to States based on the utility's retail sales
by State. Reported losses may include electricity unaccounted for by the utility. Direct use is commercial or industrial use of electricity that (1) is self-generated (2) is produced by either the same
entity that consumes the power or an affiliate, and (3) is used in direct support of a service or industrial process located within the same facility or group of facilities that houses the generating
equipment. Direct use is exclusive of station use. Beginning with publication year 2010, Total disposition has been reorganized to include Net Interstate Trade. Therefore, Total Disposition
equals Total Supply.
Sources: U.S. Energy Information Administration, Form EIA-923, "Power Plant Operations Report" and predecessor forms. U.S. Energy Information Administration, Form EIA-860, "Annual
Electric Generator Report." U.S. Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report." DOE, Office of Electricity Delivery and Energy Reliability, Form
OE-781R, "Annual Report of International Electric Export/Import Data," predecessor forms, and National Energy Borad of Canada.
State Electricity Profiles 2009
270
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