Ordinance No. 1235 (19)STAFF REPORT
STAFF REPORT
PUBLIC WORKS, WATER & DEVELOPMENT
DEPARTMENT
DATE: December 15, 2015
RE(77EIVED
Q v a 7 2015
CITY AUNIhiISTRATION
SERVICE�
TO: Honorable Mayor and City Council
FROM: Samuel Kevin Wilson, Director of Public Works, Water &
Development Services
RE: Approval of an Ordinance Amending the Zoning Code to Regulate
Distributed Generation within the City of Vernon and to Correct a
Typographical Error in the Billboard Zoning Requirements and adopt
a Negative Declaration pursuant to the California Environmental
Quality Act
RECOMMENDATION
A. Adopt an ordinance amending the City of Vernon's Zoning ordinance to 1) Define
Distributed Generation, 2) Establish regulations regarding Distributed Generation and 3)
Correct a typographical error in Section 26.8.3-4(c); and
B. Adopt a Negative Declaration finding that there is no substantial evidence, in light of the
whole record before the City, that the project may have a significant effect on the
environment within the meaning of the California Environmental Quality Act (CEQA).
BACKGROUND
The Public Works, Water and Development Services Department has been advised by the Vernon
Gas and Electric Department that it would like to have an amendment made to the Vernon Zoning
ordinance to require that a person to obtain a conditional use permit before allowing Distributed
Generation to be place on a parcel of land within the City. Additionally City staff is recommending
that a modification be made to the billboard regulations of the zoning ordinance to correct a
typographical error. Section 26.6.6 of the City Code sets forth the process to amend the zoning
ordinance.
Distributed Generation
The City of Vernon Gas and Electric Department initiated a study of the potential impacts
Distributed Generation (DG) may have on the City's operations and the environment. Distributed
Generation generally refers to the production of electricity through non-traditional generating
plants including but not limited to, photovoltaic (PV) facilities, diesel and natural gas fueled
facilities, wind generators, biomass -fueled facilities, fuel cells, water -powered energy systems;
combined heat and power facility, energy storage devices, micro -turbines and waste burning
power facilities.
The City of Vernon's electric utility customer base has shown an interest in constructing DG
facilities to offset electricity provided by the City. This desire to install DG stems from both a
wish to reduce power costs and to create electricity onsite in a more sustainable manner. Power
Engineers was retained by the Vernon Gas and Electric Department to conduct an impact study.
The study consisted of. 1) A Physical Distribution System Impact Analysis, 2) An Environmental
Impact Analysis, 3) A Safety Assessment and 4) A Financial Impact Analysis. Attached herewith
is a copy of the study.
The study concluded that the City's existing electrical distribution system can generally support
DG, but limited DG can be connected to any of Leonis 7 kilovolt (kV) distribution circuits until
the feeder circuit breakers are replaced with higher interrupting current rating. However,
allowing DG up to 5% of the City's peak load would result in operating revenue losses of up to
$6,474,580 depending upon the mix of DGs permitted and that a restructuring of current electric
rates would be required to recover fixed costs. Furthermore, the study found that existing
regulations will provide adequate safety protection related to hazardous materials and electric
safety that may be associated with solar PV, fuel cells and fossil -fuel DG projects, however a
more in-depth analysis is required to fully understand the environmental impacts of other types
of DG.
Ultimately the City will have to determine the maximum amount of DG that will be permitted in
the City. The Solar rights act has made it clear cities should not inhibit the use of solar power
generation. As such the Power Engineer, Inc. study concluded that Solar PV DGs up to 1.0 MW
should be permitted without the need for a conditional Use Permit.
In addition, emergency backup generators are sometimes required to be installed in certain
facilities to provide a backup power source in case electricity is lost at a site. Public facilities
such as fire stations, city halls, hospitals, police stations, water well sites as well as private
developments where hazardous materials are stored or used quite often require a separate source
of electricity as a backup in case the primary source is interrupted to insure that critical
operations and safeguards are maintained during a power outage. The purpose of the backup
systems is not to provide an alternate source of electricity during normal operating conditions
and therefore should not be considered Distributed Generation.
City Staff is therefore recommending that the City's zoning ordinance be amended to clearly
show that DG facilities, with the exception of solar photovoltaic up to 1.0 MW and emergency
generators, require a Conditional Use Permit. It is recommended that the Section 26.2.4 be
amended to add a definition for Distributed Generation and that Section 26.4.1-7 (b)(4) be added
2
to the code to require a Conditional Use Permit for Distributed Generation both to read as
follows:
Add the following definition to Section 26.2.4:
Distributed Generation shall mean, a decentralized power generating facilities interconnected to
the City's distribution system and used exclusively to meet the customer's load requirements at
the site to offset power consumption normally provided by the City and may include, but not
limited to, solar photovoltaic (PV) facilities, diesel and natural gas fueled facilities, wind
generators, biomass -fueled facilities, fuel cells, water -powered energy systems; combined heat
and power facility, energy storage devices, micro -turbines and waste burning power facilities
Add Section 26.4.1-7 (b)(4) to read as flows:
(4) Distributed Generation. With the exception of solar panels generating up to one (1) MW of
energy on a Lot and emergency generators that only provide power backup when a buildings
electric utility service is interrupted, no distributed generation shall be permitted on a parcel of
land except with a Conditional Use Permit. The City reserves the right to limit the amount of
distributed generation to be interconnected to the distribution system.
Billboards
It has been noted that when the City adopted its latest zoning standards earlier this year for
billboards that section 26.8.3-4(c) contained a typographical error. This section specifies location
requirements for billboards that are within 200 feet of the edge of the 1-710 freeway fight of way
and that are designed primarily to be viewed from the freeway. Subsection (1) of 26.8.3-4(c)
deals specifically with Digital signs and while subsection (2) of 26.8.3-4(c) deals specifically
with Static signs. However section 26.8.3-4(c) mistakenly only references digital signs.
Therefore the words "or Static" should be inserted after the word Digital in section 26.8.3-4(c) to
read as follows:
(c) Outdoor Advertising Structures with Digital or Static Displays that are located within two
hundred (200) feet of the edge of the Right-of-way of the I-710 freeway and are designed
to be primarily viewed from the I-710 freeway are subject to the following standards:
(1) An Outdoor Advertising Structure with a Digital Display that is located within two
hundred (200) feet of the edge of the Right-of-way of the 1-710 freeway and
designed primarily to be viewed from the 1-710 freeway shall not be located within
five hundred (500) feet of another Outdoor Advertising Structure with a Static
Display located on the same side of the freeway or within one thousand (1,000) feet
of another Outdoor Advertising Structure with a Digital Display located on the
same side of the freeway and designed to be oriented toward the freeway; and
(2) An Outdoor Advertising Structure with a Static Display that is located within two
hundred (200) feet of the edge of the Right-of-way of the 1-710 freeway and
designed primarily to be viewed from the 1-710 freeway shall not be located within
five hundred (500) feet of any other Outdoor Advertising Structure located on the
same side of the freeway and designed to be oriented toward the freeway.
CEQA ANALYSIS
An initial study has been conducted for the project in compliance with the California
Environmental Quality Act (CEQA). As shown by the initial study, no potentially significant
impacts are expected to result from the proposed zoning changes and there is no substantial
evidence, in light of the whole record before the City, that the project may have a significant effect
on the environment. The Director of Public Works, Water & Development Services has
recommended that a Notice of Intent be provided and issued pursuant to CEQA Guidelines section
15072 and a Negative Declaration be adopted in compliance with CEQA Guidelines section 15070
et seq.
RECOMMENDATION
It is therefore recommended that a negative Declaration be adopted and that the City's zoning
ordinance be amended as follows:
Add the following definition to Section 26.2.4:
Distributed Generation shall mean, a decentralized power generating facilities interconnected to
the City power generating facility and used exclusively to meet the customer's load requirements
at the site to offset power consumption normally provided by the City and may include, but not
be limited to solar photovoltaic (PV) facilities, diesel and natural gas fueled facilities, wind
generators, biomass -fueled facilities, fuel cells, water -powered energy systems, combined heat
and power facility, energy storage devices, micro -turbines and waste burning power facilities.
Add Section 26.4.1-7 (b)(4) to read as follows:
(4) Distributed Generation. With the exception of solar panels generating up to one (1) MW of
energy on a Lot and emergency generators that only provide power backup when a buildings
electric utility service is interrupted, no distributed generation shall be permitted on a parcel of
land except with a Conditional Use Permit. The City reserves the right to limit the amount of
distributed generation to be interconnected to the distribution system.
Amend Section 26.8.3-4(c) to read as follows:
(c) Outdoor Advertising Structures with Digital or Static Displays that are located within two
hundred (200) feet of the edge of the Right-of-way of the I-710 freeway and are designed
to be primarily viewed from the I-710 freeway are subject to the following standards:
(1) An Outdoor Advertising Structure with a Digital Display that is located within two
hundred (200) feet of the edge of the Right-of-way of the I-710 freeway and
designed primarily to be viewed from the I-710 freeway shall not be located within
five hundred (500) feet of another Outdoor Advertising Structure with a Static
Display located on the same side of the freeway or within one thousand (1,000) feet
of another Outdoor Advertising Structure with a Digital Display located on the
same side of the freeway and designed to be oriented toward the freeway; and
(2) An Outdoor Advertising Structure with a Static Display that is located within two
hundred (200) feet of the edge of the Right-of-way of the I-710 freeway and
designed primarily to be viewed from the 1-710 freeway shall not be located within
five hundred (500) feet of any other Outdoor Advertising Structure located on the
same side of the freeway and designed to be oriented toward the freeway.
Attachment(s): Power Engineers Distributed Generation Impact Study
The "Power Engineers Distributed Generation Impact Study" referenced in this staff report is
available for public inspection at the City Clerk counter located at City Hall, 4305 Santa Fe
Avenue, Vernon, CA 90058. If you have any questions or concerns, please contact the Office of
the City Clerk at cityolerk(cci.vernon.ca.us or at (323) 583-8811 extension 546.
CITY OF VERNON
DISTRIBUTED GENERATION IMPACT
STUDY
June 23, 2015
CITY OF VERNON
Distributed Generation Impact Study
Overall impacts Report
Revision 0 - Final
PROJECT NUMBER:
135853
PROJECT CONTACT.•
DevBiAa, P.E., PMP
EMAIL•
DLv,BiHa@powereng.com
PHONE:
(714) 5072732
POWER ENGINEERS, INC.
Distributed Generation Impact Study
Distributed Generation Impacts Study
PREPARED FOR. -
CITY OF VERNON
PREPARED BY
DEV BIRLA, P.E., PMP— 714.507.2732
dev.birla@powereng.com
POWER ENGINEERS, INC.
Distributed Generation Impact Study
TABLE OF CONTENTS
EXECUTIVESUMMARY..................................................................................................................I
1.0
PROJECT INTRODUCTION....................................................................................5
2.0
PHYSICAL DISTRIBUTION SYSTEM IMPACTS ................................................ 6
2.1
INTRODUCTION OF PHYSICAL DISTRIBUTION SYSTEM IMPACTS ................................... 6
2.2
DATA AND ASSUMPTIONS.............................................................................................. 6
2.3
ANALYSIS.......................................................................................................................7
2.3.1
Reverse Power Study..................................................................................................... 7
2.3.2
Overload Study.............................................................................................................. 8
2.3.3
Voltage Limit Study....................................................................................................... 9
2.3.4
Voltage Flicker Study..................................................................................................10
2.3.5
Short Circuit Study......................................................................................................11
2.3.6
Analysis of 66 kV System............................................................................................13
2.4
RESULTS SUMMARY.....................................................................................................
13
2.5
CONCLUSIONS..............................................................................................................
14
2.5.1
Recommended Limits for DG......................................................................................15
3.0
ENVIRONMENTAL IMPACTS AND INITIAL STUDY.....................................16
3.1
INTRODUCTION FOR ENVIRONMENTAL AND INITIAL STUDY .......................................
16
3.2
INITIAL ENVIRONMENTAL SCREENING........................................................................
16
3.2.1
Wind.............................................................................................................................19
3.2.2
Biomass........................................................................................................................19
3.2.3
Carpet -waste Burning Facility.....................................................................................19
3.2.4
Fuel Cells.....................................................................................................................
20
3.2.5
Fossil-fueled.................................................................................................................20
3.2.6
Solar PV.......................................................................................................................
22
3.2.7
Environmental Summary and Conclusion...................................................................22
4.0
SAFETY ASSESSMENT..........................................................................................
24
4.1
INTRODUCTION OF SAFETY ASSESSMENT....................................................................24
4.2
ELECTRICAL HAZARD SUMMARY................................................................................
24
4.3
EXISTING ELECTRICAL DISTRIBUTION SYSTEM...........................................................25
4.4
INDUSTRY STANDARDS................................................................................................
26
4.4.1
IEEE 1547....................................................................................................................26
4.4.2
UL 1741.......................................................................................................................27
4.4.3
CPUC Rule 21 Revision..............................................................................................
28
4.5
ISLANDING...................................................................................................................
28
4.5.1
Background..................................................................................................................28
4.5.2
Management.................................................................................................................29
4.5.3
Work Practices.............................................................................................................29
4.5.4
Documentation.............................................................................................................30
4.6
GROUNDING.................................................................................................................
30
4.6.1
Background..................................................................................................................30
4.6.2
Management.................................................................................................................31
4.6.3
Work Practices.............................................................................................................31
4.7
PROTECTIVE RELAYING...............................................................................................
31
4.7.1
Background..................................................................................................................31
4.7.2
Management.................................................................................................................32
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4.8 MONITORING, INFORMATION EXCHANGE AND CONTROL ........................................... 33
4.9 GENERAL INTERCONNECTION GUIDELINES AND INTERCONNECTION AGREEMENT .... 34
4.9.1 Background..................................................................................................................34
4.9.2 Review and Comments................................................................................................ 34
5.0 FISCAL IMPACTS OF DISTRIBUTED GENERATION....................................38
5.1
INTRODUCTION OF FINANCIAL IMPACTS......................................................................38
5.1.1
Distributed Generation Impacts...................................................................................
38
5.2
TEN YEARS FINANCIAL FORECAST..............................................................................
39
5.2.1
DG Limits on the System, Net Metering and DG State Regulations and Legislation.
40
5.3
RATE STRATEGY..........................................................................................................
46
5.3.1
Comply with City Council Policy and Regulations.....................................................47
5.3.2
Financial Stability........................................................................................................48
5.3.3
Equity and Fairness......................................................................................................48
5.3.4
Renewable Energy and Conservation..........................................................................
48
5.3.5
Maintain Competiveness and High Value Services while Accomplishing Changes
throughGradualism.....................................................................................................48
5.3.6
Engage Stakeholders and Communication..................................................................49
5.3.7
Accommodating Growth..............................................................................................49
5.4
RATE DESIGN...............................................................................................................
56
5.4.1
Rate Design Revenue Adequacy Conclusions.............................................................68
6.0
INTEGRATED IMPACTS.......................................................................................
70
6.1
PHYSICAL DISTRIBUTION SYSTEM IMPACTS................................................................70
6.2
ENVIRONMENTAL IMPACTS AND INITIAL STUDY.........................................................
71
6.3
SAFETY ASSESSMENT — HAZARD ANALYSIS...............................................................
72
�. 6.4
ELECTRICAL HAZARD SUMMARY................................................................................
72
6.5
HAZARDOUS MATERIALS ANALYSIS...........................................................................
73
6.5.1
Short -Term Construction Impacts................................................................................
73
6.5.2
Discussion on Current Cup Process.............................................................................74
6.6
RATE PAYERS IMPACTS................................................................................................74
7.0 RECOMMENDATIONS...........................................................................................76
7.1 OVERALL PROJECT RECOMMENDATIONS: ................................................................... 76
7.2 PHYSICAL DISTRIBUTION SYSTEM IMPACTS................................................................76
7.2.1 Recommended Limits for DG......................................................................................76
7.3 ENVIRONMENTAL IMPACTS AND INITIAL STUDY.........................................................77
7.4 SAFETY ASSESSMENT...................................................................................................77
7.5 RATEPAYERS IMPACTS RECOMMENDATIONS.............................................................. 78
8.0 REFERENCES...........................................................................................................79
FIGURES
FIGURE 5-1: VERNON DG ADOPTION PROJECTIONS AND AGGREGATE CUSTOMER DEMANDS
(NCP).........................................................................................................................43
FIGURE 5-2: REVENUE REDUCTIONS, AVOIDED COSTS AND OPERATING LOSSES FOR THE BASE
CASEDG....................................................................................................................44
FIGURE 5-3: RATE MAKING PROCESS............................................................................................. 50
FIGURE5-4: COST OF SERVICE....................................................................................................... 50
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FIGURE 5-5:
TEST YEAR REVENUE REQUIREMENT PROCESS.........................................................51
FIGURE 5-6:
FIXED AND VARIABLE COSTS AND REVENUES COMPARISON....................................55
FIGURE 5-7:
UNIT COSTS FOR D CURRENT, PROPOSED AND COS RATES ......................................
59
FIGURE 5-8:
UNIT COSTS FOR GS-1 CURRENT, PROPOSED AND COS RATES................................60
FIGURE 5-9:
UNIT COSTS FOR GS-2 CURRENT, PROPOSED AND COS RATES................................61
FIGURE 5-10:
UNIT COSTS FOR TOU-G CURRENT, PROPOSED AND COS RATES ............................
62
FIGURE 5-1 1:
UNIT COSTS FOR TOU-G CURRENT, PROPOSED AND COS RATES BY SEASON .........
63
FIGURE 5-12:
UNIT COSTS FOR TOU-V CURRENT, PROPOSED AND COS RATES ............................
65
FIGURE 5-13:
UNIT COSTS FOR TOU-V CURRENT, PROPOSED AND COS RATES BY SEASON .........
66
FIGURE 5-14:
UNIT COSTS FOR TOU-PA CURRENT, PROPOSED AND COS RATES ..........................
68
FIGURE 5-15:
PROGRESSION OF FIXED COST RECOVERY FROM CURRENT RATES TO PHASE 3 ......68
TABLES
TABLE 2-1:
REVERSE POWER DG LIMITS........................................................................................7
TABLE 2-2:
OVERLOAD DG LIMITS.................................................................................................
8
TABLE 2-3:
VOLTAGE LIMIT DG LIMITS.......................................................................................
10
TABLE 2-4:
DG LIMITS BY SUBSTATION/VOLTAGE......................................................................
12
TABLE 2-5:
DG LIMITS BY 7 KV FEEDER......................................................................................
13
TABLE 2-6:
DG LIMITS BY 16 KV FEEDER....................................................................................
14
TABLE 2-7:
DG LIMITS BY SUBSTATION/VOLTAGE......................................................................
14
TABLE 3-1:
POTENTIAL ENVIRONMENTAL IMPACTS SUMMARY ...................................................
17
TABLE 3.2:
2007 FOSSIL FUEL EMISSION STANDARDS.................................................................21
TABLE 5-1:
NET METERING REQUIREMENTS FOR VERNON IN FY 2015.......................................41
TABLE 5-2:
REVENUE REQUIREMENTS FOR VERNON....................................................................42
TABLE 5-3:
10-YEAR AVERAGE REVENUE REQUIREMENT FORECAST FIXED AND VARIABLE COST
STRUCTURE................................................................................................................42
TABLE 5-4:
ANNUAL FINANCIAL IMPACTS FOR MAXIMUM DG PENETRATION (E.G., 5% OF NCP)
....................................................................................................................................
45
TABLE 5-5:
TEST YEAR REVENUE REQUIREMENT........................................................................
52
TABLE 5-6:
BASE RATE TEST YEAR REVENUE REQUIREMENT.....................................................
52
TABLE 5-7:
UNBUNDLED BASE RATE TY REVENUE REQUIREMENT ............................................
54
TABLE 5-8:
CLASSIFICATIONS OF BASE RATE TY REVENUE REQUIREMENT ...............................
55
TABLE 5-9:
COMPARISON OF REVENUES AND REVENUE REQUIREMENTS....................................56
TABLE 5-10:
VERNON BASE RATE PHASE IN AND COS..................................................................57
TABLE 5-1 1:
VERNON BASE RATE PHASE IN AND COS..................................................................
57
TABLE 5-12:
CURRENT AND PROPOSED BASE RATES: RESIDENTIAL .............................................
58
TABLE 5-13:
CURRENT AND PROPOSED BASE RATES: GS-1...........................................................
59
TABLE 5-13:
CURRENT AND PROPOSED BASE RATES: GS-2...........................................................60
TABLE 5-15:
CURRENT AND PROPOSED BASE RATES: TOU-G.......................................................61
TABLE 5-16:
CURRENT AND PROPOSED BASE RATES: TOU-V.......................................................
64
TABLE 5-17:
CURRENT AND PROPOSED BASE RATES: TOU-PA.....................................................67
APPENDICES
APPENDIX A DG STUDY -ETAP MODELS....................................................................................A-1
APPENDIXB CEQA CHECKLIST.................................................................................................... B-1
APPENDIX C ACOUSTICAL ASSESSMENT...................................................................................... C-1
APPENDIX D HAZARDOUS MATERIALS ASSESSMENT...................................................................D-1
APPENDIX E VERNON GAS AND ELECTRIC DEPARTMENT RATE STRATEGY ................................ E-1
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ACRONYMS
$/kWh
dollars per kilowatt hour
°C
degrees Celsius
A
Amps
AB
Assembly Bill
ACM
asbestos containing materials
ACSR
aluminum conductor, steel reinforced
AEPSO
Area Electric Power System Operator
ANSI
American National Standards Institute
AQMP
Air Quality Management Plan
Area EPS
Area Electric Power System
BWP
Burbank Water and Power
CalRecycle
California's Department of Resources Recycling and Recovery
CCR
California Code of Regulations
CEQA
California Environmental Quality Act
CO
carbon monoxide
COS
cost of service
CPUC
California Public Utility Commission
CUP
Conditional Use Permit
DER
Distributed Energy Resource
DG
distributed generation
DR
distributed resources
EIR
Environmental Impact Report
EMS
Energy Management System
ESA
Environmental Site Assessment
FY
under fiscal year
GS-2
General Service-2
IEEE
Institute of Electrical and Electronic Engineers, Inc.
IS
Initial Study
ISE
interconnection system equipment
kA
kiloamperes
kcmil
circular mils
kV
kilovolt
kW
kilowatts
kWh
kilowatt-hour
LBP
and lead -based paint
Local EPS
Local Electric Power System
MIC
Monitoring, Information Exchange and Control
MVA
megavolt ampere
MW
megawatts
N/A
Not Applicable
NCP
non -coincident peak
NewGen
NewGen Strategies and Solutions, LLC
NOx
nitrogen oxides
NREL
National Renewable Energy Laboratory
O&M
operations and maintenance
PA
Power Agriculture class
PBC
Public Benefits Charge
PCC
Point of Common Coupling
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PM 10
particulate matter less than 10 micrometers in diameter
PM2.5
particulate matter less than 2.5 micrometers in diameter
POWER
POWER Engineers, Inc.
PV
photovoltaic
ROGs
reactive organic gases
RPU
Riverside Public Utilities
SCAB
South Coast Air Basin
SCAQMD
South Coast Air Quality Management District
SCE
Southern California Edison
SDG&E
San Diego Gas and Electric
SIWG
Smart Inverter Working Group
Sox
sulfur oxides
TOU-V
Time of Use — V
TY
Test Year
UL
UL LLC
VAR
reactive power
Vernon
City of Vernon
VOCS
volatile organic compounds
W/m2
Wind Power Density
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EXECUTIVE SUMMARY
The City of Vernon (Vernon) has been receiving more frequent requests from its customers to install
power generation systems at their facilities. These systems are referred to as distributed generation
(DG). DGs could include, but are not limited to, solar photovoltaic (PV) facilities, diesel and natural
gas fueled facilities, wind generators, biomass -fueled facilities, fuel cells, and carpet -waste burning
power facilities. In order to understand the potential impacts of allowing DG, Vernon issued a request
for a proposal for a Distributed Generation Impact Study. This study would assess DG impacts on
electric distribution system, the environment, public safety, and potential negative fiscal impacts.
POWER Engineers, Inc. (POWER) was selected to perform this study.
POWER performed an assessment of the impacts of DG on the following areas: physical and
operational impacts on distribution system, the environment, public safety, and fiscal impacts on rate
payers. In addition, POWER evaluated the current mandatory requirement of a Conditional Use
Permit (CUP) for all DGs regardless of the size and type of DG. Based on the analysis of each area,
POWER performed an integrated assessment and recommends an optimal level of DGs without
causing significant impacts. POWER also reviewed the current electric rates to evaluate potential
financial impacts associated with allowing increased levels of DGs on the distribution system and
recommends restructuring of electric rates for long-term financial security and stability.
The POWER team (POWER, NewGen Strategies and Solutions LLC, Scientific Resources
Associated and RBF) worked with the Vernon staff for several months, collecting extensive data and
information to fully understand each area at depth. Data collection and review included, but was not
limited to:
• Distribution System Features and Engineering Data — Starting from ETAP System model,
information of maximum and minimum loads of 10 distribution circuits, relay protection and
other features of distribution system.
• Financial Data - Financial reports of revenues requirements, operation and maintenance
(O&M) and capital expenses including city transfers, current financial policies and practices
and electric rates.
• Environmental and Safety Data - Applicable Environmental and CUP policies and
requirements for distributed generation, the Safety Element of Vernon General Plan and DG
Interconnection application requirements and guidelines.
The POWER team analyzed these data, conducted independent research where necessary (such as
latest net metering law and state legislation Assembly Bill (AB) 327, air quality and climate change
regulations), conducted field reconnaissance as much as possible and prepared draft technical reports.
POWER team also prepared a Cost of Service Study which was added later to the scope in order to
incorporate the latest financial information; analyzed the financial impact of recommended DG
levels; and identified the rates necessary for the short- and long-term financial security of Vernon.
Physical Distribution System Impacts Analysis — Analysis started from review of data from 10
distribution circuits and interpolated to the complete distribution system. Five different electrical
studies (reverse power, overload, voltage limit, voltage flicker and short-circuit) were performed on
each circuit under a number of various scenarios including both rotating machine and non —rotating
/inverter based generation. It is apparent from the analysis that although DGs could have impacts on
the Vernon distribution system, the amount of DG the physical system can absorb is very high and
will not be a limiting factor in the policy on how much DG can be permitted within Vernon. Based on
the analysis, it can range from 140 megawatts (MW) to a full peak load of 190 MW (if it is physically
practical to connect DGs with the distribution circuits), depending upon the types of DGs and at what
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point the power can start flowing into Southern California Edison (SCE) system at the point of
�. interconnection.
Environmental Impact Anal — The Comprehensive Zoning Ordinance of the City of Vernon
§26.4.1-3(b) and General Plan (Section 2.2) currently requires a CUP for generating facilities, power
plants and cogeneration facilities. The CUP process requires a comprehensive review under the
California Environmental Quality Act (CEQA) and allows Vernon to include project -specific
conditions. Vernon is considering streamlining the process of allowing DG facilities in Vernon,
provided that this streamlining does not result in adverse environmental impacts. The environmental
analysis focused on potential environmental impacts from exempting DG facilities from the CUP
requirements, allowing these facilities to be constructed and operated without environmental review
and without project -specific conditions. The analysis indicates that combustion engines (including
microturbines) could have the potential to result in cumulative air quality impacts. Additionally,
biomass and the carpet -waste burning facilities could also have impacts related to odor and noise. The
CUP requirements should be maintained for these facilities.
Exempting solar PV systems from the CUP requirements would result in less than significant
environmental impacts. Though fuel cells would also likely have less than significant environmental
impacts, this technology is evolving. Retaining the CUP requirement for this type of DG is prudent to
allow Vernon to get more information about the specific project, perform its due diligence, and
include project -specific conditions if deemed necessary. Vernon could revisit this requirement when
the design and operations of fuel cells become more standardized. Meteorological conditions (low
wind speeds) in Vernon are such that there is no potential for practical wind power generation.
Exemption will streamline the process for solar PVs and is consistent with other neighboring utilities.
The CUP requirement should be maintained for all other types of DGs including microturbines, fuel
cells, conventional combustion gas turbines, biomass and potential carpet waste burning plants.
L' Safety Assessment — The safety assessment was divided into two subareas: electrical safety hazard
analysis and hazardous materials assessment. Electrical safety hazard analysis builds upon the
distribution system impact study and concludes that DGs pose a potential electrical safety hazard due
to back feed into distribution system for line workers and the public in general. But these potential
safety hazards are manageable with reasonable efforts such as: adopting prudent operating and
maintenance procedures, e.g., requirements for DG's to comply with industry standards Institute of
Electrical and Electronic Engineers, Inc. (IEEE) 1547 and UA 1741 and monitoring of DGs. Three
areas of concern identified were: islanding, grounding and protective relaying. Management
approaches for areas of concern aim to reduce the impacts to less than significant. Approaches to
monitoring DG, as well as suggestions for Vernon's interconnection agreement and guidelines, are
also included.
The Environmental Checklist Form from the CEQA Statues and Guidelines criteria was used to
determine short-term and long-term hazardous materials impacts. Solar PVs will have no short-term
and long-term impacts. Non -solar DGs could have short- and long-term impacts, but compliance of
all applicable federal, state and local regulation by DG owners and monitoring by highly trained
Vernon safety staff will reduce those impacts to no different than what currently exists in day-to-day
operations.
Financial Impact Analysis — It is evident that although DGs have impacts on all areas, financial
impacts are going to outweigh other areas and will be a limiting factor of how much and what optimal
level of DGs can be permitted without significant impacts on rate payers. Compliance with the
current net metering law and AB 327 requires Vernon to permit up to 5% of customer peak loads (the
sum of non -coincident peak load of each class of customers) for renewable distributed generation.
Using 2014 system data for peak loads, the 5% limit is 9,924 kilowatts (kW) and will vary each
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subsequent year based on customer class peak demands. At full subscription, the 5% requirement is
�. estimated to result in annual operating revenue loss ranging from $3,125,852 to $6,474,580,
depending upon the mix of solar PV and conventional fossil fuel DG, if allowed. These operating
revenue losses equate to a rate increase from 1.4% to 3.0% for non-DG customers to ensure Vernon
remains financially stable recovering all costs. Currently, 2,000 kW of solar PV installations are in
the pipe line (planned or under construction) which results in an estimated operating revenue loss of
$484,000 per year. This level of operating losses equates to a rate increase of 0.3% for other non-DG
customers to fully recover the costs to operate the electric system.
IN.,.,.-
In conclusion, the results of this Distributed Generation Impact Study indicate that:
• The existing distribution system can generally support DG up to a full peak load 190 MW,
but no DG can be connected to any of Leonis 7 kilovolt (kV) distribution circuits until the
feeder circuit breaker is replaced with higher interrupting current rating.
• As required by net metering law and AB 327, allowing DG up to 5% of peak loads (non -
coincident peak load of each class of customers); 9,924 kW based on the 2014 peak load
results estimated operating revenue loss ranging from $3,125,852 to $6,474,580 depending
upon the mix of DGs permitted.
• Restructuring of current electric rates is required to recover fixed costs via the increased
demand charge and to gradually realign the rates overtime with the Cost of Service study as
much as possible.
• Solar PV projects up to 1.0 MW can be exempted from the CUP requirements without
significant environmental impacts. The CUP requirement should be maintained for the other
types of DGs evaluated in the study and solar PV projects above 1.0 MW.
• Existing regulations will provide adequate safety protection related to hazardous materials
that may be associated with solar PV, fuel cells and fossil -fuel DG projects. Electric safety
hazards are manageable by adopting prudent operating and maintenance procedures,
interconnections agreement requirements, and guidelines and requirements of compliance of
DGs with industry standards such as IEEE Std.1547 and UA 1741.
Recommendations:
• Adopt and comply with current net metering law and AB 327 requirements to define the
maximum and types of DGs. Currently, the limit is 5% of customer peak loads and translates
into 9,924 kW of renewable DGs. All other non-renewable and conventional fossil fuel,
including natural gas fired microturbines, are not included in this limit and should be
evaluated on a case -by -case basis. Evaluate potential carpet -waste burning plants based on a
complete Environmental Impact Report, including the financial impacts on Vernon.
• Permit solar PV DGs up to 1.0 MW without CUP process and continue CUP process for all
other types of DGs both renewable and non-renewable. Modify and update CUP language
regarding diesel engines strictly used as a back-up and stand by generators, to clarify that
those are exempt from the CUP.
• All 7 kV circuit breakers at the Leonis substation should be replaced with higher interrupting
current rating as soon as practical and before any DG is connected to 7 kV circuits.
• Adopt the recommended Rate Strategy with the framework for long-term financial integrity
of Vernon including:
a. Improving the amounts of cash reserves (e.g., days of cash on hand).
b. Gradually realign the rates overtime with the Cost of Service as much as possible.
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c. Adopt the restructured rates to recover additional fixed costs via the increased
L demand charges and introduce a facilities charge (i.e., distribution demand) in
addition to current power supply demand charge.
M
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1.0 PROJECT INTRODUCTION
The public's growing desire for renewable generation as an environmental friendly power supply
option has drastically changed perspective of the customers, utility service offerings, pricing and day-
to-day utility operations. We are in a period of change with potential opportunities of distributed
generation (DG) and associated risks. The city of Vernon (Vernon) has recognized this challenge and
issued a Request for Proposal in June 2014 to study the impacts of DG and to provide
recommendation for DG penetration levels without significant impacts.
POWER was selected to perform this study in September 2014 and utilized an integrated assessment
of four distinct but related areas:
• Physical and operational impacts on the Vernon distribution system.
• Environmental impacts and California Environmental Quality Act (CEQA) initial study.
• Public safety impacts and city in general.
• Potential loss of revenue and negative impact on the rate payers.
Based on the analysis of each area, POWER Engineers, Inc. (POWER) performed an integrated
assessment and has recommended the optimal level of DG without causing significant system
upgrades and negative impact on the rate payers.
Although other neighboring utilities face similar challenges, Vernon's electric system is unique due to
the nature of its load (commercial and industrial with only 125 residential customers) and small
geographical service area (only 5.2 square miles). The high load factor for the commercial and
industrial customer base has an impact on the cost and rate making analysis of DG penetration. Large
industrial and commercial loads create non -typical challenges for electric system operation and
protection. The small geographical service area and dense loading results in shorter than typical
distribution circuits with multiple circuits on the same pole and have potential constraints for
interconnection of DG with the distribution system.
The state regulation to comply with Renewable Portfolio Standards and 33% of renewable energy by
2020 has resulted in rate increases for most utilities in California, including in Vernon. Any further
rate increases may be difficult for customers to accept, and rate structuring could be met with
suspicion. The current net metering laws and state regulations on DG play an important role in the
analysis and results of the analysis.
Vernon's Environmental and Safety Element of the Vernon General Plan are instrumental in
determining environmental impacts and safety assessment of DG.
The approach to managing DG on the Vernon system has been carefully tailored to the unique charter
of Vernon's distribution system, environmental/safety codes, and great capability of safety staff to
handle incidents on routine basis. This report has relied heavily on the provided financial data and
current fiscal policies and practices as much as possible, with recommendations wherever deemed
necessary.
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2.0 PHYSICAL DISTRIBUTION SYSTEM IMPACTS
2.1 Introduction of Physical Distribution System Impacts
This portion of the study examines the physical and operational impacts of adding DG to the system
at three voltages: 7 kilovolts (kV), 16 kV, and 66 kV.
Ten circuits across the three voltage levels were selected by Vernon for POWER to analyze. Vernon
specified six feeders at 7 kV, three feeders at 16 kV, and one 66 kV line, comprising approximately
15% of Vernon's electric system. These feeders provide a representative sample of the system
including a variety of long and short feeders as well as lightly and heavily loaded feeders. The
analysis performed generalizes the results of these representative feeders to provide general
recommendations for the system as a whole.
The addition of DG to a distribution system has both benefits and drawbacks to the physical and
electrical system that should be considered. Appropriately sized and placed DG can help maintain
feeder voltage and reduce conductor loading and losses. However, particularly with higher DG
penetration, other concerns such as changing power flow direction, exceeding equipment ratings and
power quality concerns can arise. Several of the driving aspects in DG penetration limits are
examined in this analysis.
2.2 Data and Assumptions
Vernon provided POWER with up-to-date ETAP models of their 66 kV system as well as individual
7 kV and 16 kV ETAP models for Vernon specified feeders. Circuit maps containing general feeder
location, individual feeder continuous and peak loading, and conductor lengths and types were
provided by Vernon.
Two loading scenarios were used for analysis: peak loading and minimum loading. The peak feeder
loading information from the circuit maps was used to model the peak loading scenario within ETAP
by scaling the modeled load to the peak values proportionally across all loads. Vernon also provided
feeder loading data pulled every fifteen minutes from September 9, 2014 to October 21, 2014. The
minimum loading experienced by each feeder during this time frame was used to model the minimum
loading scenarios within ETAP using the same proportional scaling approach.
As part of the analysis to determine the maximum DG values for the system, a variety of generators
and inverters were modeled within each 7 kV, 16 kV, and 66 kV ETAP model. Generally, generation
was placed at multiple locations on the feeders, both as distributed and as a lumped equivalent. This
lumped equivalent, placed at the "worst case" location on the feeder as defined for that specific
analysis, produces the most impact and was used for all final analysis. The generators used ETAP
library reactance for a typical round -rotor generator. The inverters were modeled using typical PV
array and inverter data from the ETAP library.
The generators and inverters were modeled with power factor control, operating at unity power factor.
Rule 21 of the California Energy Commission and California Public Utilities Commission is
scheduled to change in the future and inverter based DG, such as PV, will have to include reactive
power support, but still will not be allowed to actively regulate voltage. Because of the relatively
short lines in the City of Vernon's system, the reduced impact to voltage resulting from the change in
Rule 21 is not expected to increase the allowable inverter based DG limits compared to what is
included in this analysis.
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2.3 Analysis
Five unique studies were analyzed to determine approximate DG limits. The five studies included a
reverse power study, an overload study, a voltage limit study, a voltage flicker study, and a short
circuit study. These studies were completed independently of one another to identify which would
drive the primary system impacts of the electrical systems. A reactive power (VAR) study was not
specifically performed since the addition of generation at unity power factor should shift the feeder
power factor closer towards unity. However, consideration for the possibility of voltage changes and
loading challenges were included in those respective studies.
A detailed discussion of each performed analysis with results is included in the subsections below.
Refer to Tables 2-1 through 2-4 for the calculated DG limits determined from the five individual
studies. The conclusion section summarizes the driving factors and general recommendations
considering all of these analyses.
Detailed reports of ETAP results for each analysis are included in Appendix A of this document.
These reports include the base case (existing system) under both minimum and maximum loads, as
well as the results of the maximum DG values as reported in this document. For simplicity in review,
pertinent results are summarized in the following sections.
2.3.1 Reverse Power Study
The reverse power study was performed to determine the DG value which resulted in current flowing
in the opposite direction of normal power flow through the feeder breaker, back into the substation.
The minimum feeder loading scenarios were used for the analysis, which results in the lowest level of
generation which may cause power to flow in the reverse direction.
`- To determine the most restricted DG location, lumped DG was placed at three locations along each
feeder: after the underground getaway cable, approximately halfway down the feeder, and near the
end of the feeder. Analysis showed that lumping DG at the beginning of the feeder, after the
underground getaway cable, resulted in the smallest amount of DG to produce a reverse power
condition and was thus considered the limiting case. DG power factors were held at unity, and
voltages held at nominal. Refer to Table 2-1 for the results of the reverse power study.
TABLE 2.1: REVERSE POWER DG LIMITS
Feeder 2 - 7 kV* 0.24 MW*
Feeder 11 - 7 kV 0.40 MW
Feeder 19 - 7 kV 0.95 MW
Feeder 21 - 7 kV 0.64 MW
Feeder 63 - 7 kV
1.00 MW
Feeder 66 - 7 kV
0.64 MW
Norris -16 kV*
1.30 MW*
Davis -16 kV**
0.10 MW**
Kaeser -16 kV
3.10 MW
Notes: kV = kilovolts; MW = megawatts
'Most restrictive feeder at given voltage level
-16 kV Davis feeder has near 0 MW minimum measured load
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Generally, the values shown in Table 2-1 are similar to the minimum loading levels of the feeder. The
\.• results show that the most restrictive feeders are Feeder 2 at 7 kV with 0.24 megawatts (MW) of DG
resulting in a reverse power scenario, and the Davis feeder at 16 kV with 0.10 MW of DG resulting in
a reverse power scenario. The 16 kV Davis feeder had two short periods of very light loading,
resulting in this low limit.
The reverse power scenario alone does not create a significant system impact. A few aspects need to
be considered to account for the system behavior if the reverse power limits are exceeded, including
relay settings. Vernon's feeder overcurrent elements are non -directional, however pickups are in
excess of the conductor limits, and therefore will not operate for reverse power flow scenarios.
From a safety standpoint, Vernon's operational/maintenance policy should contain measures to
maintain line personnel safety during scenarios where the feeder is disconnected from the distribution
substation. If DG is not disconnected from the feeder upon loss of substation breaker opening, a
possibility for dangerous voltage or current on the feeder may be present. Anti-islanding schemes
may be required to support protection from these scenarios.
Institute of Electrical and Electronic Engineers, Inc. (IEEE) Std. 1547.7-2013 indicates that rotating
machine DG should not exceed 1 /3 of the minimum load on a feeder, and that PV (inverter based) DG
should not exceed the minimum load on the feeder due to concerns with islanding scenarios. In cases
where these guidelines are exceeded, protection can be achieved by transfer trip schemes for larger
DG facilities, or requirements for curtailment of large DG facilities during minimum loading
scenarios (such as nights and/or weekends). A further discussion on this aspect is included in the
safety impact analysis portion of the project.
2.3.2 Overload Study
The objective of the overload study was to determine the largest amount of DG that can be placed
along a feeder without overloading existing Vernon conductors or other equipment. The analysis was
performed with minimum loading to prevent overloads on the circuit when power flows back up the
circuit and into the substation. All analysis was performed with connections to the main branch
conductor of the feeder and did not consider the effects of being placed on a smaller conductor such
as a tap. Individual DG locations would need to be considered on a project -by -project basis to
determine effects on the smaller tap conductors.
To determine the most restrictive DG location, lumped DG was placed at three locations along each
feeder: after the underground getaway cable, approximately halfway down the feeder, and near the
end of the feeder. Analysis showed that lumping DG after the underground getaway cable resulted in
the smallest amount of DG to overload the existing main branch conductors and was thus considered
the limiting case. Refer to the Table 2 for the results of the conductor overload study.
TABLE 2.2: OVERLOAD DG LIMITS
Feeder 11 - 7 kV` 3.8 MW*
Feeder 19 - 7 kV 5.0 MW
Feeder 21- 7 kV 4.6 MW
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TABLE 2-2: OVERLOAD DG LIMITS
Feeder 66 — 7 kV 4.b MW
Norris —16 kV 14.1 MW
Davis —16 kV* 12.8 MW*
Kaeser-16 kV 16 MW
Notes: kV = kilovolts; MW = megawatts
*Most restrictive feeder at given voltage level
The results shown in Table 2-2 indicate that the most restrictive feeders are Feeder 11 at 7 kV with
3.8 MW of DG resulting in a conductor overload scenario, and Davis at 16 kV with 12.8 MW of DG
resulting in a conductor overload scenario.
Conductor overloads generally can only be resolved by increasing conductor size from the point of
DG back to the substation. Due to heavily loaded and complex structures, along with construction
limitations, it is expected that exceeding the overload ratings could require significant physical
system improvements.
It should be noted that while this analysis focused on conductor overloads, there are many other
pieces of equipment (switches, breakers, etc.) along the branch that could require review, analysis,
and/or replacement if the overload ratings are exceeded. Existing line switch capacity ratings not
provided and the DG limits reported in Table 2 do not take them into account. However, Vernon
believes that their switches have ratings of 600 Amps (A) or greater, which is typical industry design.
If Vernon's line switches are all at this rating, there will be no concerns with the switches. Excluding
possible concerns with line switches, the conductor rating was reached before these other pieces of
substation equipment became limiting factors. If any line switches have ratings below the continuous
circuit rating provided on the feeder one -line drawings, lower limits may be required.
Similarly, the analysis was performed by connecting the DG to the main feeder conductor. This
analysis does not include considerations for possible upgrades to distribution transformers at the
interconnection point, or the conductor ratings for short taps that feed these transformers. Small tap
sections and transformers may require upgrades for very large DG interconnections.
2.3.3 Voltage Limit Study
The purpose of performing a voltage limit study was to determine the amount of additional DG that
would result in a 5% voltage change along the feeder. Due to variations in nominal system voltage in
the provided ETAP models, this 5% criterion was used in lieu of a typical 0.95 to 1.05 per unit
nominal voltage. This limit was applied both to the voltage at the connection bus as well as voltage
drop along the feeder (except where existing modeled voltage drops were in excess of 5%).
To determine the most restricted DG location, lumped DG was placed at three locations along each
feeder: after the underground getaway cable, approximately halfway down the feeder, and near the
end of the feeder. The percent voltage change, as a result of adding the lumped DG, was monitored at
the same three locations. Analysis showed that lumping DG at the end of the feeder and monitoring
the percent voltage change at the end of the feeder resulted in the smallest amount of DG to cause the
5% voltage change and was thus considered the limiting case. Refer to Table 2-3 for the results of the
voltage limit study.
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TABLE 2-3: VOLTAGE LIMIT DG LIMITS
Feeder 2 - 7 kV 9.5 MW
Feeder 11 - 7 kV 7.5 MW
Feeder 19 - 7 kV* 2.6 MW*
Feeder 21- 7 kV
5.6 MW
Feeder 63 - 7 kV
9.5 MW
Feeder 66 - 7 kV
13 MW
Norris -16 kV
22 MW
Davis -16 kV
23 MW
Kaeser-16 kV*
14 MW*
Notes: kV = kilovolts; MW = megawatts
"Most restrictive feeder at given voltage level
The results shown in Table 2-3 indicate the most restrictive feeders are Feeder 19 at 7 kV with 2.6
MW of DG resulting in a 5% voltage increase at the end of the feeder, and Kaeser at 16 kV with 14
MW of DG resulting in a 5% voltage increase at the end of the feeder. Feeder 19 represented a long
heavily loaded feeder that experiences significant voltage drop (nearly 10% at the end of feeder).
Feeder 19 has limited forms of voltage regulation and thus, the resulting calculated DG limit of 2.6
MW is smaller than the other 7 kV feeders. However, DG boosts voltage, so the voltage rise from the
DG may be beneficial when the feeder is loaded.
These limits are based on a lumped generator at one location (at the end of the feeder). A more
distributed level of DG may result in lower voltage increases along the feeder. However, the values
calculated in the "worst case" analysis indicate that other system limits (specifically conductor
overload) would prevent these voltage limits from being reached.
In practicality, DG will not be lumped at a single location but distributed along a feeder. Optimally
placed DG can help support voltage regulation along a long heavily loaded feeder. Typically this
voltage support is best seen near the ends of feeders where voltages are lowest. Placing DG along
these long heavily loaded feeders will boost the voltage at the point of connection as well as slightly
reduce line losses.
2.3.4 Voltage Flicker Study
Photovoltaic (PV) solar generation is a likely form of DG for Vernon based on low environmental
impact and Vernon's geographical location. However, PV generation can be obscured by clouds and
cause a decrease in generation and thus voltage for a short period of time, typically referred to as
flicker. Flicker is a result of multiple significant voltage dips experienced over a short period of time,
which can be visually observed in the resulting output of lights. To fully understand the effects clouds
can cause upon generation, a simplified voltage flicker study was performed with the objective of
determining the percent voltage drop required to cause irritation. PV is considered the worst form of
generation that will produce flicker as voltage dips are inconsistent, unpredictable, and rapid
(compared to traditional generation).
As a result of clouds, it typically takes several seconds between most voltage dips with photovoltaic
generation systems. Analysis was performed for flicker between 1 and 15 voltage dips per minute
based on conservative industry data provided by EPRI and other industry sources. Realistic dips will
usually occur at slower rates over minutes, but partly cloudy days can cause greater deviation. Based
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on IEEE Std. 141-1993 Figure 3-8, flicker at one dip per minute allows for a 2% voltage drop before
`. irritation, whereas flicker at 15 dips per minute only allows for a 1% voltage drop before irritation.
IEC/TR 61000-3-7:2008 (adopted as IEEE Std. 1453.1-2012) has similar, but less conservative, limits
for voltage dips; however, these limits are applied to low voltage systems only.
Based on industry data compiled by EPRI, shorter duration between dips correspond to smaller
percent generation dip for the plant, compared to larger percent generation dips for slower frequency
dips. The values range from approximately 25% generation loss for 15 dips per minute to
approximately 50% generation loss for one dip per minute. Loss of over 80% of generation will
typically take over 10 minutes at which point flicker is not a concern. Based on analysis it was
determined that the quicker rate of dips (15 dips per minute) had more of an impact due to the stricter
1% voltage drop criteria. Results of the analysis were based on the 25% generation loss resulting in
1% voltage drop from 15 dips per minute criteria, which is generally conservative.
To determine the most restricted DG location, lumped PV DG was placed at three locations along
each feeder: after the underground getaway cable, approximately halfway down the feeder, and near
the end of the feeder. The DG values were increased to a value where an immediate 25% generation
loss produced a 1% voltage drop anywhere on the feeder. Analysis showed that lumping DG at the
end of the feeder resulted in the smallest amount of DG and was thus considered the limiting case.
For feeders at each 7 kV and 16 kV voltage levels, the overall 5% voltage deviation limit was
exceeded before a DG value large enough to cause an irritation was reached. Similarly, the main
conductors would be overloaded before the flicker limit could be reached. The results of the flicker
study are shown in Tables 2-5 and 2-6 as Not Applicable (N/A) as the PV generation levels necessary
to create flicker are well in excess of the voltage and thermal limits.
2.3.5 Short Circuit Study
�. The short circuit study was performed to determine the allowable amount of DG that can be placed on
a feeder without exceeding short circuit ratings of equipment on the distribution system. After
reviewing various equipment ratings, it was determined that the limiting factor was the existing feeder
circuit breaker interrupting ratings, which were then used as the short circuit analysis limits.
Reclosing is not an issue as reclosing has 10 second open intervals and DG isolates within two
seconds per IEEE Std. 1547.
Vernon provided POWER with station one -line diagrams which contained circuit breaker interrupting
ratings as either kiloamperes (kA) or megavolt ampere (MVA) ratings for each 7 kV and 16 kV
substation. Vernon also confirmed the Leonis breaker ratings which were not provided on the
drawings. The short circuit study was completed using the provided Vernon 66 kV ETAP system
model. Faults were placed on the low -side of the respective transformer to determine existing circuit
breaker duty.
The short circuit study involved determining existing system short circuit values at each transformer
low -side bus at the Vernon 7 kV Substation, the Leonis 7 kV and 16 kV Substation, and the Ybarra
16 kV Substation. To determine the existing circuit breaker duty, faults were placed on the low -side
of the respective transformers. DG was then added to feeders served from the transformer, increasing
the total available fault current. The analysis was based on faulting feeders with no DG while
measuring the contribution and effects from feeders with DG. To provide margin for model
inaccuracies and other system variations, 95% of the circuit breaker interrupting rating was used as
the short circuit limit. If 95% of the circuit breaker interrupting rating was exceeded, no additional
DG could be applied to the bus. If the existing short circuit current fell short of the 95% value,
additional DG was added to calculate the appropriate DG limit resulting in reaching the 95% circuit
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breaker interrupting rating. The circuit breaker interrupting ratings used for the analysis were 40 kA
at Vernon Substation and Ybarra Substation and 25 kA at Leonis Substation.
For this analysis, both rotating machine DG as well as inverter based DG were analyzed to determine
limits based on actual installation. Inverter based generation short circuit contribution is generally
limited to approximately 150% of the nominal rated current value for less than a cycle, then reducing
to approximately nominal ratings and thus the DG limits for inverter based generation is much higher
than rotating machines. Rotating machines have different electrical characteristics and inertia and will
therefore provide fault current on the order of six times the machine rating during fault conditions.
The results of the circuit breaker study are shown in Table 2-4. For some cases, particularly inverter
based generation; the amount of DG required before the circuit breaker interrupting ratings are
exceeded would exceed the MVA ratings of the distribution transformer plus minimum load fed from
the transformer. In these instances, the limit presented is simply the top 55 degrees Celsius (°C) MVA
rating of the transformer plus the minimum loading of the transformer bank based data provided by
Vernon. These instances are designated with an asterisk in Table 2-4.
TABLE 2.4: DG LIMITS BY SUBSTATIONNOLTAGE
Rotating Machines
Vemon 7 kV — Bank #1 21 MW 37 MW*
Vemon 7 kV — Bank #2 28 MW 36 MW*
Vemon 7 kV — Bank #3
12 MW
47 MW*
Leonis 7 kV — Bank #1
0 MW**
0 MW
Leonis 7 kV — Bank #2
0 MW**
0 MW**
Leonis 7 kV — Bank #3
0 MW**
0 MW**
Leonis 16 kV — Bank #4
10 MW
29 MW*
Leonis 16 kV — Bank #5
10 MW
35 MW*
Ybarra 16 kV— Bank #1
57 MW*
57 MW*
Ybarra 16 kV — Bank #2
51 MW*
51 MW*
Notes: kV = kilovolts; MW = megawatts
*DG limits limited by transformer MVA rating
"Fault current is too close to breaker interrupting ratings
The circuit breakers in the Vernon 7 kV Substation, Ybarra 16 kV Substation, and Leonis 16 kV
Substation have room to support additional current from DG without exceeding the breaker
interrupting ratings.
However, the Leonis 7 kV Substation circuit breakers are at or very near their short circuit
interrupting ratings, depending on which Vernon ETAP model is used. Without upgrades, the 7 kV
circuits fed from Leonis cannot support any DG without risking damage to the breakers. Since the
existing short circuit currents may be within 5% of the circuit breaker interrupting ratings (25 kA), it
is recommended that Vernon consider replacing the breakers with higher ratings. Upgrading to 40 kA
interrupting rating breakers would allow approximately 30 MW of DG on each 7 kV transformer
bank at Leonis.
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2.3.6 Analysis of 66 kV System
Vernon requested that POWER examine the capability of the 66 kV system to handle the addition of a
15 to 20 MW generation facility (such as a proposed carpet burning plant) to the existing Leonis-
Owill 66 kV line as one of the 10 circuits to be analyzed. Generation of this size cannot be added to
existing 7 kV or 16 kV feeders as demonstrated in the results of this analysis, and thus must be
interconnected at 66 kV. Plants of this size should not be added without additional system analysis as
there may be a number of impacts that affect the system.
The existing Leonis-Owill 66 kV line has a 653.9 circular mils (kcmil) aluminum conductor, steel
reinforced (ACSR) conductor which can easily support the 20 MW (approximately 175 A) generation
levels. Specific to this line, since the power generally flows from Owill to Leonis, it will reduce the
loading from Owill, but increase the loading to just over 500 A to Leonis. Additionally, due to the
strength of sources at 66 kV, the additional generation will have little effect on voltage, calculated
less than 0.1% at the interconnection point as well as the Owill and Leonis Substations. Note that
Vernon presently has an operational limit of 50 MW on this line, which corresponds to 437 A. This
limit is too conservative and recommended to be reviewed.
Vernon's 66 kV system has numerous three terminal lines, however setting up proper transmission
line protection on a line with a fourth terminal to interconnect generation can be difficult. Similarly,
operating the system with four terminal lines can pose challenges under certain maintenance or
restoration scenarios. As such, it is generally recommended to avoid creating four terminal lines,
particularly where generation is involved. In these instances, an additional switching station may be
desirable at the generation facility.
2.4 Results Summary
The tabulated results of the reverse power, overload, voltage limit, voltage flicker, and short circuit
studies are shown in Tables 2-5, 2-6, and 2-7. The results are organized based on feeder voltage level
and denote the most restrictive feeder for each applicable study performed.
TABLE 2-5: DG LIMITS BY 7 KV FEEDER
Feeder 2 0.24 MW 4.1 MW 9.5 MW NA*
Feeder 11 0.40 MW
3.8 MW
7.5 MW
NA*
Feeder 19 0.95 MW
5.0 MW
2.6 MW
NA*
Feeder 21 0.64 MW
4.6 MW
5.6 MW
NA*
Feeder 63 1.00 MW
5.0 MW
9.5 MW
NA*
Feeder 66 0.60 MW
4.5 MW
13 MW
NA*
Most Limiting 0.24 MW
7 kV Feeder
3.8 MW
2.6 MW
NA*
Notes: kV = kilovolts; MW = megawatts; NA = Not Applicable
*0vedoad and voltage limits are reached before irritation from flicker is experienced
ANA 092-062 (SR 02) COV 135853 (05/08/2015) YU
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POWER ENGINEERS, INC.
Distributed Generation Impact Study
TABLE 2-6: DG LIMITS BY 16 KV FEEDER
Norris
1.3 MW
14.1 MW
22 MW
NA*
Davis
0.1 MW
12.8 MW
23 MW
NA*
Kaeser
3.1 MW
16.0 MW
14 MW
NA*
Most Limiting 16 kV
0.1 MW
12.8 MW
14 MW
NA*
Feeder
*0verload and voltage limits are reached before irritation from flicker is experienced
TABLE 2-7: DG LIMITS BY SUBSTATIONIVOLTAGE
Vernon 7 kV - Bank #1 21 MW 37 MW*
Vernon 7 kV - Bank #2 28 MW 36 MW*
Vemon 7 kV - Bank #3
12 MW
47 MW*
Leonis 7 kV - Bank #1
0 MW**
0 MW**
Leonis 7 kV - Bank #2
0 MW**
0 MW**
Leonis 7 kV - Bank #3
0 MW**
0 MW**
Leonis 16 kV - Bank #4
10 MW
29 MW*
Leonis 16 kV - Bank #5
10 MW
35 MW*
Ybarra 16 kV- Bank #1
57 MW*
57 MW*
Ybarra 16 kV- Bank #2
51 MW*
51 MW*
Notes: kV = kilovolts; MW = megawatts
*DG limits limited by transformer MVA rating
"Breaker interrupting ratings are already exceeded
09
2.5 Conclusions
This section uses the results of the five analyses performed on the sampling of Vernon's distribution
system to draw generalized conclusions applicable to the entire system. Because only a sampling of
the system was analyzed, there may be conditions where the values presented may not represent
limits for specific DG installations at specific locations. Where practical values have been calculated
conservatively to present recommendations that will apply to a majority of the system.
The reverse power scenario does not limit Vernon's ability to utilize DG. The reverse power study of
DG limits resulted in pushing a small current upstream through existing protective devices. To fully
examine the effects of the reverse power study, Vernon's existing protective relay settings were
analyzed. Adding additional DG has no effect on existing directional overcurrent elements, such as
the negative sequence elements. Placing enough DG along a feeder to result in reverse power flow
can cause non -directional overcurrent relays to pick up, but Vernon's existing protective relay
settings are not sensitive enough to detect such currents even with the addition of enough DG to
overload conductors under minimum load conditions and thus, Vernon's existing relay settings will
not limit DG penetration.
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Distributed Generation Impact Study
Tables 2-5 and 2-6 include overload limits reflecting the maximum DG levels that could be supported
�... without exceeding conductor ampacity under minimum loading conditions. Vernon's existing
distribution line structures are typically difficult to work due to location and the number of circuits
they support; are heavily loaded mechanically; and the conductors close to their electrical ampacity
ratings. Consequently, replacing existing conductors with larger conductors to increase ampacity
would be difficult and costly and in general is an impractical option.
The calculated DG voltage limits are shown in Tables 2-5 and 2-6 based on DG causing no more than
a 5% voltage rise at minimum loading levels with nominal (7 kV or 16 kV) voltages at the substation
bus. This is in conformance with IEEE 1547 which requires equipment to operate within a 5% voltage
range and ANSI C84.1-2011 for Electric Power Systems and Equipment -Voltage Rating (60 Hertz).
If DG is placed along a feeder that presently experiences significant voltage fluctuation, additional
equipment may be needed. Capacitor banks, load tap changing transformers and substation voltage
regulators can be used to regulate and stabilize voltage.
The results of the short circuit study shown in Table 2-7 indicates that the breakers at the Leonis 7 kV
Substation already need to be upgraded to a higher interrupting rating and that no generation can be
applied to the feeders out of this station until upgrades are made. Replacing circuit breakers at Leonis
7 kV Substation would allow the feeder to support additional DG.
2.5.1 Recommended Limits for DG
Based on the various analyses performed, approximately 3 MW of DG can be added to each 7 kV
feeder, except those from the Leonis Substation, without significant system physical impacts.
Similarly, approximately 12 MW of DG can be added to each 16 kV feeder without significant
physical impacts.
However, total DG per transformer bank must be limited to the values listed in Table 2-7. Generally,
the following transformer bank limits apply to each of these locations:
• Vernon 7 kV Substation Banks 1 and 2 — 20 MW of rotating DG or 35 MW of inverter DG
• Vernon 7 kV Substation Bank 3 — 10 MW of rotating DG or 45 MW of inverter DG
• Leonis 16 kV Substation Banks 4 and 5 —10 MW of rotating DG or 25 MW of inverter DG
• Ybarra 16 kV Substation Banks 1 and 2 — 50 MW of any DG
Based on the overall limits presented above, if the DG is placed properly, Vernon's distribution
system can physically support in excess of 140 MW of DG regardless of type and around 200 MW if
solely inverter based generation is added. A mixture of generation would require a limit between the
two values.
With a system peak load of around 180 MW, adding these levels of generation would likely exceed
Vernon's minimum load scenarios, creating a possibility for a net power flow out of Vernon's system
to Southern California Edison (SCE) which may present further challenges. As such, Vernon should
adopt a feasible limit considering minimum system loads and other factors. Additionally, based on the
other analysis (environmental, safety, and particularly cost) as part of the overall DG impact study,
Vernon's overall system DG limit will be lower, but in general is not constrained by the physical
system as a whole. However, system grounding, protective relaying, and anti-islanding schemes may
need to be addressed. Further discussion on these aspects is included in the safety discussion portion
of this impact study.
Please see Appendix A for more details including ETAP Reports.
ANA 092-062 (SR 02) COV 135853 (05/08/2015) YU PAGE 15
POWER ENGINEERS, INC.
Distributed Generation Impact Study
3.0 ENVIRONMENTAL IMPACTS AND INITIAL STUDY
3.1 Introduction for Environmental and Initial Study
The Comprehensive Zoning Ordinance of the City of Vernon §26.4.1-3(b) and General Plan (Section
2.2) specifically requires a (CUP) for generating facilities, power plants and cogeneration facilities.
Since a CUP is a discretionary permit, an environmental review is required under CEQA for each
project that requires a CUP process. Additionally, the CUP process allows Vernon to include
conditions for construction and operations facilities. Provided that DG facilities are identified by
Vernon as compatible with existing zoning, exempting DG facilities from the CUP requirements
would allow these facilities to be constructed and operated without environmental review under
CEQA and without project -specific conditions. Vernon is considering streamlining the process of
allowing DG facilities in the City of Vernon, provided that this streamlining does not result in adverse
environmental impacts.
The objective of this environmental analysis is to identify the types of facilities with the least
potential impacts that could reasonably be allowed without a CUP. The environmental analysis for
this study began with a preliminary screening of the potential DG options being contemplated and a
high-level assessment of the potential environmental impacts that might be associated with each type
of generation facility. Based on information provided by Vernon and proposed DG in other locations,
the types of power generation facilities that are or could be contemplated for DG are:
• Wind
• Biomass
• Carpet -waste burning power facility (15 — 20 MW)
• Fuel cells
• Fossil -fueled (diesel and natural gas, including microturbines)
• Solar PV
3.2 Initial Environmental Screening
Each of the technologies listed above were subject to preliminary screening related to potential
environmental impacts and the reasonableness of allowing the use of the technology with site -specific
permit conditions. The environmental factors from the CEQA Initial Study (IS) Checklist (CEQA
Guidelines Appendix G) were used for this preliminary screening. The details related to this screening
are presented in the following subsections and a summary is presented in Table 3-1. As indicated in
the note on Table3-1, there are a number of environmental factors that are not relevant to evaluating
potential DG facility types in the City of Vernon. This is due to Vernon's General Plan specifying
Industrial as the only land use category in Vernon, and the generally complete extent of development
on lands within Vernon. The environmental factors not considered as differentiators related to the
types of DG proposed include agriculture/forestry resources, biological resources, geology/soils, land
use/planning mineral resource, population/housing, public services, and recreation. Additionally,
technical reports with preliminary screening analysis related to noise and hazards were prepared for
the various types of DG facilities. These reports are presented in Appendices C and D, respectfully.
ANA 092-062 (SR 02) COV 135853 (05/08/2015) YU PAGE 16
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POWER ENGINEERS, INC.
Distributed Generation Impact Study
3.2.1 Wind
Wind power generating projects are not viable or known to be proposed in Vernon. The City of
Vernon is located in an area that has a Wind Power Density (W/mz) of less than 100, and this
correlates to a National Renewable Energy Laboratory (NREL) Class 1 ranking. NREL ranks wind
potential in classes ranging from Class 1 to Class 7. Class 1 is the lowest level, representing
extremely low power density and this severely limits wind power generation. According to the
NREL, Class 1 areas are generally not suitable for wind generation projects (NREL 2015). The CUP
requirements or exemption is not relevant to wind projects since they are not feasible in the Vernon
due to meteorological conditions.
3.2.2 Biomass
Biomass is derived from organic materials, including wood, crops, sewage sludge, animal waste,
municipal waste and agricultural processes. Biomass can be used to generate heat and electricity
either by direct combustion or transformation methods including gasification, anaerobic digestion and
pyrolysis. Biomass facility operations have the potential to cause impacts related to odor, air quality,
water quality, fire hazard, rodent/vermin and noise, depending on the type of biomass processed and
the facility design. Additionally, the transportation of biomass to the site and the residue/products
from the site have the potential to result in traffic impacts. Due to the variability in biomass facility
fuel stock and design, maintaining the CUP requirement will necessitate a project -specific
environmental analysis under CEQA and will allow Vernon to include additional conditions that are
considered appropriate for the type of facility, fuel stock and location proposed.
3.2.3 Carpet -waste Burning Facility
A waste carpet burning facility, or a combustion facility that processes any other kind of solid waste,
�. typically has stock -pile areas for the materials to be burned, as well as shredders, screens, conveyors
and/or other extensive mechanical equipment to process the material prior to combustion and move it
to the combustion chamber. These types of facilities have the potential to cause odor, air quality,
water quality, fire hazard and noise impacts. Additionally, the transportation of carpet waste (or other
waste) to the site and the ash/residue/products from the site have the potential to result in traffic
impacts.
A facility that converts waste to power will require a Transformation or Engineered Municipal Solid
Waste Conversion facility permit from California's Department of Resources Recycling and Recovery
(CalRecycle). Additionally, the project location will need to be added to the Siting Element of the
Integrated Solid Waste Management Plan for the local host jurisdiction. These are discretionary
actions and would require review under CEQA and an Environmental Impact Report level of analysis
is typically required for these types of projects by CalRecyle. If the facility is able to meet the three-
part test (incoming material is source -separated, less than 10% residual waste, and less than 1%
putrescible material), then the facility would be exempt from CalRecycle provisions, and solely under
the local solid waste program requirements, including CEQA and CUP.
Even though CalRecyle will require a CEQA analysis to issue their permit, Vernon should maintain
the CUP requirement for this type of facility. This would allow Vernon to be the Lead Agency for the
environmental analysis under CEQA. It would also allow Vernon to specify conditions for the
operation of the facility that would not necessarily be included in the permit conditions from
CalRecycle, and it would give Vernon the power to revoke the permit if the facility does not comply
with Vernon's conditions. With this in mind, Vernon may also want to consider revising the Zoning
Ordinance §26.4.1-3(d) to read "Solid Waste/Recycled Material to energy facilities" instead of the
current text — "Trash to energy facilities."
ANA 092-062 (SR 02) COV 135853 (05/08/2015) YU PAGE 19
POWER ENGINEERS, INC.
Distributed Generation Impact Study
3.2.4 Fuel Cells
Fuel cells generate power through an electrochemical process similar to a battery. They convert
chemical energy to electrical energy by combining hydrogen from fuel with oxygen from the air.
Hydrogen fuel can be supplied directly as pure hydrogen gas or through a process that converts
hydrocarbons such as methanol, natural gas, or gasoline into hydrogen -rich gas. There are numerous
fuel cell technologies including':
• Proton Exchange Membrane - Leading fuel cell type for passenger car application; operates at
relatively low temperatures and has a high power density.
• Phosphoric Acid - The most commercially developed fuel cell; generates electricity at more
than 40% efficiency.
• Molten Carbonate - Promises high fuel -to -electricity efficiencies and the ability to utilize
coal -based fuels.
• Solid Oxide - Can reach 60% generating efficiencies and be employed for large, high
powered applications such as industrial generating stations.
• Alkaline - Used extensively by the space program; can achieve 70% generating efficiencies.
• Direct Methanol - Expected efficiencies of 40% with low operating temperatures
• Regenerative - Currently being researched by NASA; closed loop form of power generation
that uses solar energy to separate water into hydrogen and oxygen.
As shown on Table 3-1, fuel cells are not expected to have significant environmental impacts. They
would provide reduced air emissions as an environmental benefit to the extent that power generated
by fuel cells replaces power from fossil -fuel power plants. However, this technology is evolving and
Vernon may wish to keep the CUP requirements for this type of facility so that permit conditions can
be established on a project -specific basis until the design and operations of fuel cells become
standardized.
3.2.5 Fossil -fueled
Diesel Engine
Diesel -fired power generators can be configured and used to provide electrical power on a standby or
continuous basis. Standby generators operate only during emergency outages and for maintenance
testing, and these units would not be considered as DG. If a diesel -fired power generator would be
proposed to operate on a regular or continuous basis, diesel emissions would occur on an on -going
basis. Particles in diesel exhaust have been identified as a toxic air contaminant that may pose a threat
to human health (OEHHA 2015), and an analysis would be necessary to assess potential health
impacts from diesel particulates emissions in the neighboring area. This evaluation would typically be
done as part of the CEQA review for the project. Additionally, the preparation of the IS would also
include an evaluation of potential noise and fuel storage impacts to determine if the proposed facility
would need additional design features to mitigate potential noise and fire impacts. Consequently,
maintaining the CUP requirement would necessitate a project -specific environmental analysis under
CEQA and would allow Vernon to understand the potential health risk that may result from the
proj ect.
' Additional details about these technologies: http://energy.gov/eere/fueleells/fuel-cell-technologies-office.
ANA 092-062 (SR 02) COV 135853 (05/08/2015) YU PAGE 20
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Distributed Generation Impact Study
Natural Gas -Fired Engine
Natural gas -fired engines that generate electricity include reciprocating engines and turbines. Multiple
small gas turbine units (microturbines) can be installed in commercial -sized systems to produce tens
to hundreds of kilowatts of distributed power. Since microturbines produce higher temperature
exhaust gases than reciprocating engines, they are also ideal for commercial/industrial operations that
have both heat and power cogeneration needs. Though gas -fired engine emissions do not have the
toxic air contaminant properties of diesel emissions, emissions from gas -fired engines contain a
number of criteria pollutants. The currently applicable Air Quality Attainment Plan for the South
Coast Air Basin is the 2012 Air Quality Management Plan (AQMP) that was developed by the South
Coast Air Quality Management District (SCAQMD). The AQMP addresses nonattainment pollutants
ozone and ozone precursors and PM2.5. Ozone precursors are nitrogen oxides (NOx) and reactive
organic gases (ROGs) and PM2.5 is particulate matter found in the air, including dust, dirt, soot,
smoke, and liquid droplets less than 2.5 micrometers in diameter. PM2.5 are referred to as "fine"
particles and are believed to pose the greatest health risks because these fine particles can lodge
deeply into the lungs due to their small size.
The SCAQMD adopts rules and regulations that apply to sources under its jurisdiction, which include
stationary sources such as power generating facilities that could be constructed within the City of
Vernon as DG facilities. Stationary sources that emit air pollutants would be required to comply with
the SCAQMD's New Source Review requirements under Regulation XIII. These requirements were
adopted as part of the South Coast Air Basin's (SCAB) AQMP and are part of the State
Implementation Plan. Accordingly, sources that are subject to the requirements of Regulation XIII
would not conflict with or obstruct implementation of the AQMP.
Under the requirements of Regulation XIII, Rule 1303, sources with emissions that exceed four tons
per year of NOx, ROG, sulfur oxides (SOx), or PM to (inhalable coarse particles) or 29 tons per year
of carbon monoxide (CO) would be required to offset their emissions by providing Emission
Reduction Credits, also known as offsets.
If offsets are provided, emissions would be fully mitigated as no emission increase would result.
However, if facilities fall below the offset threshold, their emissions would not be required to be
offset. To estimate the size of combustion facility that could be exempt from providing offsets under
Rule 1303, CARB's 2006 Distributed Generation Certification Regulation (17 California Code of
Regulations [CCR] 94200-94214) 2007 Fossil Fuel Emission standards were used. These emission
standards are listed in Table 3.2.
TABLE 3.2: 2007 FOSSIL FUEL EMISSION STANDARDS
Pollutant Emission standard, (pounds per MW-hour)
NOx 0.07
CO 0.10
Volatile Organic Compounds (VOCs) 0.02
Based on these emission standards, a facility meeting these emission standards would have a potential to emit four tons per year of nitrogen oxides (NOx) at 13.05
MW. Facilities below this level would not be required to provide offsets for NOx emissions by the SCAQMD, and for the purpose of this study, the 13.05 MW level is
considered as the threshold below which impacts to air quality could be considered as less than significant
If multiple gas -fired DG facilities less than 13.05 MW are be proposed in Vernon, no offsets would be required by SCAQMD for these individual facilities, and potential
significant cumulative impacts to air quality would occur when the total new gas -fired DG facilities exceeds the 13.05 MW level. Consequently, the CUP process for
gas -fired DG facilities should be maintained in order to evaluate the potential for cumulative air quality impacts when these projects are proposed.
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Distributed Generation Impact Study
3.2.6 Solar PV
Solar PV systems convert sunlight directly into electricity. Homes and businesses with individual
solar PV systems are common, especially with the recent tax credits and incentives to install
renewable energy generation. Solar panels used to power homes and businesses are typically made
from solar cells combined into modules. A reasonable rule of thumb is that 10 watts of electricity can
be generated per square foot or PV panel. The panels are mounted at a fixed angle facing south, or
they can be mounted on a tracking device that follows the sun, allowing them to capture the most
sunlight.
Traditional solar cells are made from silicon, are usually flat -plate, and generally are the most
efficient. Second -generation solar cells are called thin-film solar cells because they use layers of
semiconductor materials only a few micrometers thick. Because of their flexibility, thin film solar
cells can double as rooftop shingles and tiles, building facades, or the glazing for skylights.
As shown in Table 3-1, the screening analysis indicated that the potential for solar PV systems to
result in environmental impacts appears low, and that this technology could be considered as a
candidate for exemption from the power generating facility CUP requirement. A formal CEQA IS
was prepared to confirm this screening analysis and describe the potential environmental impacts that
could result from changing the Zoning ordinance to allow this exemption (Appendix B). A maximum
size of 1 MW, corresponding to a 100,000 square -foot system was selected for the exemption. This is
considered as a large PV system and the 1 MW limit would allow many different systems to be
installed before distribution system impacts and/or financial impacts to rate payers becomes a
concern.
The results of the IS indicate that exempting 1 MW solar PV project from the CUP requirements
would not result in significant impacts and no mitigation would be necessary. Consequently, a
`.. Negative Declaration would be the appropriate document to comply with CEQA for this exemption.
3.2.7 Environmental Summary and Conclusion
An environmental review was conducted to evaluate potential impacts associated with exempting
distributed power generating facilities from the Vernon's CUP requirement. A preliminary screening
was conducted for the following types of power generation facilities that are or could be contemplated
for distributed generation:
• Wind
• Biomass
• Carpet -waste burning power facility (15 — 20 MW)
• Fuel cells
• Fossil -fueled (diesel and natural gas, including microturbines)
• Solar PV
OR
The preliminary screening evaluated environmental factors with a particular focus on air
quality/greenhouse gas, noise, vibration, public services, hazardous materials, water quality and
utility services. The analysis included a review of the consequences of permitting numerous
generating facilities within the Vernon. Table 3-1 presents a summary of the preliminary analysis, and
solar PV was identified as a potential candidate for exemption from the CUP requirements.
A formal CEQA IS (Appendix B) was prepared to exempt solar PV projects up to 1 MW from the
CUP requirements. The results of the IS indicate that significant environmental impacts would not be
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Distributed Generation Impact Study
expected and no mitigation would be necessary. A Negative Declaration would be the appropriate
document to comply with CEQA for this exemption.
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POWER ENGINEERS, INC.
Distributed Generation Impact Study
4.0 SAFETY ASSESSMENT
4.1 Introduction of Safety Assessment
This portion of the study examines the safety impacts of adding DG to the 7 kV and 16 kV
distribution systems.
POWER has divided the Safety Assessment in to two subareas: electrical safety hazards and
hazardous materials. The scope of work in the initial Request for Proposal was to determine the
impact of DG on the safety and welfare of neighboring properties and Vernon in general, as well as
the impacts on the safety staff (fire and police). In the course of developing the proposal it was
concluded that the impact on staffing will depend upon factors which include the number of incidents
and the nature and complexity of incidents. It will be extremely difficult to predict and substantiate
the number and character of incidents that may arise from DG installations. After discussion with
Vernon, the scope was changed to evaluating the potential risks to crews and the public safety and
impact on the neighboring properties, which are addressed by this report.
The electrical hazard analysis, which includes a review of Vernon's generation interconnection
policy, is addressed in this chapter. The hazardous material analysis is addressed in a report prepared
by POWER's sub -consultant RBF, which is included as Appendix D.
The Physical Distribution Impact Study work scope was modified at Vernon's request by adding the
analysis of connecting a generation facility to Vernon's 66 kV system. The scope of the hazard
analysis was not expanded to include the 66 kV system. Generation interconnections at 66 kV require
engineering evaluation on a case by case basis for a number of reasons. Interconnections at 66 kV
almost always involve larger generators than would interconnect to the medium voltage distribution
network with power flow and voltage; reactive compensation requirements on the 66 kV system
would all potentially be affected. Voltages may be out of compliance; and line and/or transformer
ratings may be exceeded. Additionally, protective relaying requirements for both larger generators
and 66 kV lines are less standardized and require individual engineering review.
4.2 Electrical Hazard Summary
This work builds upon data collected and developed in the Physical Distribution Impact Study and
concludes that DG poses potential electrical safety hazards due to back feed into the distribution for
line workers and the general public, but that these potential safety hazards are manageable with
reasonable effort. The report begins with a description of the salient features of Vernon's electrical
distribution system and a summary of the most directly applicable industry standards to provide
background. Three areas of concern identified for the medium voltage distribution system are
addressed: islanding, grounding, and protective relaying. Approaches to monitoring DG are discussed
as well as suggestions for interconnection agreement provisions.
The Vernon distribution system serves a compact urban industrial and commercial area. Because of
this, the circuits are short and overcurrent protection is relatively simple, consisting of protective
relays for the feeder circuit breakers and fuses at transformers serving loads. The distribution lines are
three -wire (three phase conductors without a neutral conductor) and unigrounded (the ground
reference for the distribution primary voltage is established at one point in the substation).
The IEEE 1547 series of standards and the UL LLC (UL) 1741 standard are most relevant. These
standards support one another, with IEEE 1547 standards providing functional requirements for
distributed resources (DR), which includes DG, and UL 1741 providing the standards for testing and
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certification that DR products meet the requirements of IEEE 1547. Equipment to meet these
requirements is readily available for solar PV installations.
Islanding would occur when the feeder circuit breaker was open and the loads on the feeder were
served by DG only. Islanding would present a hazard to the public and Vernon's personnel. By
requiring that all DG be certified to meet IEEE 1547 and UL 1741 or otherwise provide equivalent
performance through a Vernon approved means, Vernon can be assured that DG will automatically
de -energize within two seconds after the feeder circuit breaker opens thus eliminating islanding.
Work practices for Vernon crews should be reviewed to accommodate the presence of DG on the
system and consideration should be given to requiring a lockable disconnect to assure DG is, and
remains, disconnected from the distribution system while line work is being performed. Vernon
operations and engineering staff should have ready access to DG locations and basic information
about each DG installation. Vernon's existing maps and documents should be amended to include this
information. Vernon's present interconnection policies require DG to meet IEEE 1547 and UL 1741.
Grounding must be considered because for a short period of time, two seconds or less after the feeder
circuit breaker opens, voltage can be supplied to the distribution circuit from DG. For this short
period there is no ground reference as the connection to the substation is lost when the feeder circuit
breaker opens. In this condition, higher than normal voltages on one or two of the phases can occur
with potential for equipment damage. Because of Vernon's three wire distribution system
configuration and phase to phase transformer connections, 220 mil (133%) cable insulation, and lack
of surge arrestors, this condition does not appear to require mitigation.
Protection to de -energize and isolate short circuits (faults) on distribution circuits is traditionally
based upon a single source of power at the substation with loads along the distribution feeder. The
addition of DG results in additional sources of power and short circuit current along the distribution
feeder and may cause degradation in the ability to detect faults and for the proper device to operate to
de -energize and isolate the fault. Vernon's compact distribution system which does not require
protective devices or fuses in the main lines and their modern feeder protective relays applied using
negative sequence currents to detect ground faults, mitigates both of these potential issues. Protective
relay settings should be reviewed in detail to provide assurance that protective relays will operate as
expected.
The generation levels at which monitoring, and potentially control, will be required should be
evaluated by Vernon to create a policy that permits operating the medium voltage electrical
distribution system safely and efficiently while not being unnecessarily burdensome to potential DG
operators and Vernon. Some guidance is provided in IEEE 1547.3 and is discussed later in this report.
How Vernon's policy compares with other utilities in the region will influence how it is viewed by
Vernon's ratepayers.
4.3 Existing Electrical Distribution System
Vernon serves primarily commercial and industrial load, with very limited residential load. Peak
system demand is approximately 195 MW. Primary distribution voltages are 7 kV and 16 kV.
Distribution feeders for both 7 kV and 16 kV are three wire (no neutral) with mostly three phase loads
and some single phase loads served by transformers connected line to line. Distribution feeders are
overhead except for underground cable substation get-aways on some circuits and underground
primary cable serving some individual loads. The 16 kV circuits are unigrounded with the neutral of
the substation transformer 16 kV wye winding connected to the substation ground grid. The 7 kV
circuits are energized from delta connected substation transformers and are grounded either through a
separate grounding bank (Vernon Substation) or a scheme which uses a wye connected voltage
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regulator neutral to provide a ground reference (Leonis Substation). Using the substation voltage
l .. regulator at Leonis to provide a distribution system ground source is non -typical and not
recommended. POWER understands the regulator grounding scheme will be taken out of service
when the Leonis transformers are replaced. At that time, ground reference will be established by
solidly grounding the wye point of the 7 kV winding on the new transformer in accordance with
typical practice.
Distribution feeders are relatively short due to the confined urban area served by Vernon
(approximately five square miles). It is normal for there to be several distribution circuits on one pole.
Distribution feeders are protected by present generation multi -function microprocessor based relays
using phase, negative sequence, and ground current protective relay functions. One reclose with a 10
second open interval is used on both 7 kV and 16 kV feeders. No line fuses or reclosers are used.
Transformer banks or single phase transformers are fused either at the transformer or at the source
side of short laterals connecting the transformer to the distribution primary. There are some large (up
to 3,750 kVA) three phase transformer banks at both voltages. Distribution transformer banks are
connected delta on the distribution primary (7 kV or 16 kV) side or phase to phase for single phase
transformers.
4.4 Industry Standards
There are numerous standards which apply to DG and DG installation and no attempt is made to
review them all. This section focuses on two which are of particular importance for interconnection of
DG on distribution systems, and also addresses proposed changes to the California Public Utility
Commission (CPUC) Rule 21.
`1 4.4.1 IEEE 1547
The IEEE has published the IEEE 1547 series of standards specifically addressing the interconnecting
of distributed resources, which includes distributed generation and storage, with electric power
systems. IEEE 1547 is the first of these standards. A series of additional standards and one
amendment have been published to amend, support and provide updated application guidance to the
IEEE 1547 standard. The most relevant of these documents are:
IEEE 1547
IEEE Std 1547-2003 (R2008) IEEE Standard for Interconnecting Distributed Resources with Electric
Power Systems — Approved 12 June 2003, Reaffirmed 25 September 2008.
IEEE 1547 is the parent document containing the functional requirements for the interconnecting DR
with the Area Electric Power System (Area EPS).
IEEE 1547a
IEEE Std 1547a-2104 (Amendment to IEEE Std 1547-2003) IEEE Standard for Interconnecting
Distributed Resources with Electric Power Systems Amendment 1 — Approved 16 May 2014.
IEEE 1547a makes changes to: 1) allow the use of DR to actively participate in the regulation of Area
EPS voltage with approval of the Area EPS and DR operators; 2) requires field adjustable voltage set
points and clearing times for DR greater than 300 W; 3) changes DR default response to abnormal
voltages and frequencies; 4) requires field adjustable frequency and time set points; and 5) permits
changes in the default values with mutual agreement of Area EPS and DR operators.
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IEEE 1547.1
IEEE Std 1547.1-2005(R2011) IEEE Standard Conformance Test Procedures for Equipment
Interconnecting Distributed Resources with Electric Power Systems — Approved 9 June 2005,
Reaffirmed 16 June 2011.
IEEE 1547.1 defines testing procedures for DR to assure conformance to IEEE 1547.
IEEE 1547.2
IEEE Std 1547.2-2008 IEEE Application Guide for IEEE Std 1547, IEEE Standard for
Interconnecting Distributed Resources with Electric Power Systems — Approved 10 December 2008.
IEEE 1547.2 provides more specific examples to assist in the application of IEEE 1547 technical
requirements.
IEEE 1547.3
IEEE Std 1547.3-2007 IEEE Guide for Monitoring, Information Exchange, and Control of
Distributed Resources Interconnected with Electric Power Systems - Approved 17 May 2007 by IEEE
and 30 October 2007 by American National Standards Institute (ANSI).
IEEE 1547.3 is intended to facilitate the implementation of monitoring, information exchange, and
control of DR. It is recognized as an American National Standard.
IEEE 1547.7
IEEE Std 1547.7-2013 IEEE Guide for Conducting Distribution Impact Studies for Distributed
Resource Interconnection — Approved 11 December 2013.
IEEE 1547.7 provides guidance for conducting impact studies for DR connected to distribution
systems.
IEEE 1547.8 (DRAFT)
IEEE PI547.8/D8 Recommended Practice for Establishing Methods and Procedures that Provide
Supplemental Support for Implementation Strategies for Expanded Use of IEEE Standard 1547 — In
draft, NOT YET APPROVED.
When approved IEEE 1547.8 will provided expanded guidance on the application of IEEE 1547
technical requirements.
4.4.2 UL 1741
UL 1741 Standard for Inverters, Converters, Controllers and Interconnection System Equipment for
Use With Distributed Energy Resources - published by UL LLC — Edition Date 28 January 2010.
UL 1741 is a comprehensive standard. The following two paragraphs are quoted from the UL 1741
description contained on the UL website and summarizes the portions of the standard most relevant to
utility distribution system interconnection.
"1.1 These requirements cover inverters, converters, charge controllers, and interconnection
system equipment (ISE) intended for use in stand-alone (not grid -connected) or utility-
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interactive (grid -connected) power systems. Utility -interactive inverters, converters, and ISE
are intended to be operated in parallel with an EPS to supply power to common loads.
1.2 For utility -interactive equipment, these requirements are intended to supplement and be
used in conjunction with the Standard for Interconnecting Distributed Resources With
Electric Power Systems, IEEE 1547, and the Standard for Conformance Test Procedures for
Equipment Interconnecting Distributed Resources with Electric Power Systems, IEEE
1547.1. "
UL 1741 is specifically referenced in IEEE 1547.2, IEEE 1547.3, IEEE 1547.7 and in the IEEE
1547.8/D8 DRAFT. It is also included in the bibliography of 1547.1. Likewise IEEE 1547 and IEEE
1547.1 are specifically referenced in the UL 1741 description.
Equipment which is UL 1741 certified has been tested to demonstrate that the equipment will
successfully disconnect from islanded systems in accordance with IEEE 1547 requirements even if
DR capacity would otherwise be sufficient to energize the load in the island.
4.4.3 CPUC Rule 21 Revision
California's Electric Tariff Rule 21 (Rule 21) is a CPUC-approved tariff that describes the
interconnection, operating and metering requirements for generation facilities to be connected to an
investor -owned utility's distribution system. Even though Rule 21 does not apply to Vernon, the
application of the rule will have a large impact on the usual practices for DG interconnection in
California and on the capability of readily available DG equipment and therefore should be
understood and taken into account in establishing DG interconnection policies.
In summary, the proposed revisions to Rule 21 will require enhanced autonomous inverter
functionalities and compliance with defined communications standards and capabilities. The
deployment would be phased in. In December 2013, the Smart Inverter Working Group (SIWG)
recommended a staged deployment strategy ending with a requirement that all inverter based
Distributed Energy Resource (DER) systems applying for interconnection 1 April 2016 or later
include these enhanced functionalities.
IEEE 1547a updated IEEE 1547 to accommodate the enhanced autonomous inverter functions
required by Rule 21. The autonomous inverter functions would permit DG inverters to actively
control real and reactive power to manage voltage with the approval of utility and DG operators.
Requiring DG to operate at unity power appears to be most practical and will result in negligible
impact to system power factor for the relatively low level of DG penetration anticipated by Vernon.
The more sophisticated autonomous inverter functions required by Rule 21 revisions can be
implemented in the future if circumstances change making them necessary or beneficial
4.5 Islanding
4.5.1 Background
IEEE 1547 defines an island as "a condition in which a portion of the Area EPS is energized solely by
one or more Local EPSs through the associated points of common coupling (PCCs) while that portion
of the Area EPS is electrically separated from the rest of the Area EPS." Islanding can be intentional,
as in the case of a microgrid that separates as designed from the Area EPS; or unintentional, as would
occur when a feeder circuit breaker opened leaving load and DG separated from the utility power
supply.
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For Vernon, islanding would be unintentional and would occur when a feeder circuit breaker is open
`. but the distribution feeder remains energized from power supplied by DG. Unintentional islanding
can only occur when DG capacity closely matches load on the isolated feeder. Should unintentional
islanding occur, it would result in a potential safety hazard to both the general public and Vernon
utility crews.
4.5.2 Management
Paragraph 4.4.1 of IEEE 1547 states that "For an unintentional island in which the DR energizes a
portion of the Area EPS through the PCC, the DR interconnection system shall detect the island and
cease to energize the Area EPS within two seconds of the formation of an island."
IEEE 1547 then identifies four examples by which this requirement may be met:
1. The DR aggregate capacity is less than one-third of the minimum load of the Local EPS.
2. The DR is certified to pass an applicable non-islanding test.
3. The DR installations contains a reverse or minimum power flow protection, sense between the
point of DR connection and the PCC, which will disconnect or isolate the DR if power flow
from the AREA EPS to the Local EPS reverses or falls below a set threshold.
4. The DR contains other non-islanding means, such as: a) forced frequency or voltage shifting, b)
transfer trip, or c) governor and excitation controls that maintain constant power and constant
power factor.
Using a DR certified to pass applicable non-islanding tests is the most practical and expedient method
of avoiding unintentional islanding when it is possible to do so. IEEE 1547.7 states "If the DR is
certified for the application (e.g., an inverter has been UL 1741 certified), then the Area EPS operator
has assurance that the DR will separate in a reasonable period of time ...."
Inverters for PV systems certified to meet IEEE 1547 and UL 1741 are readily available, even in very
small sizes.
Requiring DG to be certified to meet IEEE 1547 and UL 1741 rules should not prove unreasonably
burdensome to Vernon's customers and should prove possible in almost all cases. Leaving open the
possibility of using other means (e.g., transfer tripping) acceptable to Vernon if IEEE 1547 and UL
1741 certification is unavailable in extraordinary circumstances will retain flexibility for larger or
non -typical DG installations without compromising the ability to avoid unintentional islanding.
Vernon's existing interconnection rules require DG to meet IEEE 1547 and UL 1741.
4.5.3 Work Practices
This section discusses issues impacting work practices but does not define work practices. Vernon
must establish their own work practices taking into account the particulars of Vernon's electrical
system, work force, and operating practices.
In general, work practices must be held to a high standard to minimize risk to the public and the
people performing the work and at the same time should be practical and permit efficient performance
of the work at hand. Work practices that are too restrictive can invite "cutting corners" by crews who
are under pressure to restore service.
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DG certified to meet IEEE 1547 and UL 1741 will, if the DG is operating as designed and tested, shut
down within two seconds removing any source of generation once the feeder breaker is open.
However, work practices should provide for safety even if the DG is malfunctioning.
Small inverter based DG such as a rooftop PV installation of 1 or 2 kilowatts (kW) will not provide
sufficient short circuit current to create a hazard when applying personal safety grounds on the
distribution primary, nor will they provide enough short circuit current to create an arcing hazard
when removing personal safety grounds.
Conversely, larger inverter based DG or rotating DG would potentially present hazards if they were
misoperating and remained online.
A practical approach could be to require lockable disconnect switches accessible to Vernon's crews
for larger DG installations of all types. Then before working on a line that was isolated from the
substation (feeder breaker open), all DG disconnect switches would be opened and locked open with
a Vernon padlock. Conductors would then be tested to assure they were not energized and personal
safety grounds applied in the usual manner. When work was completed, grounds could be removed,
the circuit re -energized from the feeder breaker, and locks removed and disconnects closed on DG.
Any small DG without lockable disconnects would resume operation following a time delay after the
circuit was reenergized. This approach could apply to work required for service restoration, as well as
scheduled line maintenance and construction.
If hot line work were being performed, consideration should be given to removing DG from service
by opening and locking disconnects prior to performing the work. DG certified to meet IEEE 1547
and UL 1741 have up to two seconds to remove themselves from service after the feeder breaker
opened, potentially creating a hazard by delaying de-energization of the circuit if an incident
occurred. This circumstance would reinforce the practice of having a lockable disconnect on all DG.
If there are few small DG installations it may be practical to require all DG installations to have a
lockable disconnect accessible to Vernon's crews. An alternative to individual lockable disconnects
would be to open the primary fused cutouts or primary switches on installations where DG exists.
This approach could result in de -energizing an entire customer facility which may be unacceptable.
These issues should be addressed in the interconnection agreement. Vernon's existing interconnection
rules require a DG disconnect within eight feet of the meter.
4.5.4 Documentation
Up-to-date and accurate information on the location, size, type, location of disconnect switch, DG
operator contact information and other data should be available to Vernon's dispatchers, operations
management, and engineering staff to support Vernon's work practices. The location and method of
access for this data will need to be determined by Vernon; however, showing the location, size and
type of DG on circuit maps appears to be useful.
4.6 Grounding
4.6.1 Background
When the feeder circuit breaker opens the ground reference provided by the substation transformer
grounded neutral, grounding transformer, or other means is lost. There is a period of time, up to two
seconds, between when the utility system ground reference is lost and when DG is required to de -
energize in accordance with IEEE 1547. In that period the circuit could potentially remain energized,
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but without a utility voltage ground reference line to ground voltages in the unintentional island may
`.. vary from normal.
With a feeder energized normally, all three phase conductors have a line to ground voltage of
approximately the phase to phase voltage divided by the square root of three (e.g., 9.2 kV for a 16 kV
system). A single line to ground fault provides an example of what could occur. If the feeder breaker
were open removing the system ground reference, but with the DG not having shut down yet, the
faulted conductor would be at ground potential with no fault current flowing, and the two remaining
phases would be at full phase to phase voltage to ground (e.g., 16 kV for a 16 kV system).
Distribution systems are often four -wire (three phase wires and a system neutral) with transformers
connected between phase and neutral. Transformers connected phase to neutral on four -wire systems
are particularly vulnerable to the excessive phase to neutral voltages described in the previous
paragraph, as are surge arrestors and cables rated for phase to neutral voltage. Consequently, it could
be necessary to take steps such as installing grounding transformers on the feeder, sized to effectively
ground the feeder with the feeder breaker open and DG on line, in order to control voltage after the
feeder breaker opens but before the DG de -energizes.
4.6.2 Management
Mitigation such as grounding transformers appears unnecessary on Vernon's system.
Because Vernon is using a three wire distribution system at both 7 kV and 16 kV, all transformers are
of necessity connected phase to phase removing the danger of transformers being exposed to
excessive voltages while the DG is shutting down. Even if one phase were at ground potential, the
phase to phase voltages will be practically unaffected.
POWER understands that Vernon does not use surge arrestors on equipment or on underground risers,
and uses 220 mil (133% insulation level at 15 kV) cable insulation on their 7 kV and 16 kV
underground distribution cables. Consequently, the likelihood surge arrestor failures due to higher
than normal phase to ground voltages is not a concern, and the 220 mil cable insulation provides a
margin of safety for potential high voltage conditions of two seconds or less while DG shuts down.
4.6.3 Work Practices
No work practice modifications to address system grounding should be required so long as it is
unnecessary to add grounding transformers or other equipment.
4.7 Protective Relaying
4.7.1 Background
A number of potential protective relaying concerns arise with the addition DG on distribution feeders.
Traditional distribution feeders were designed and protective relaying was applied based on the feeder
being radial, with a single source of power supply at the substation through the feeder breaker to
loads along the distribution line. Protection was based on non -directional phase and ground time
graded overcurrent elements with pick-up values set to provide selectivity (coordination) with
downstream devices and desired sensitivity. More sensitive ground fault detection was provided by
ground overcurrent elements operated from zero sequence current. One to three recloses were
normally used with open interval times varying from no intentional delay to 45 seconds or more.
Downstream protection could be provided by reclosers which emulate all or a portion of the feeder
circuit breaker protection functions; sectionalizers which detect fault current and opened during an
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open interval when the upstream protection device has de -energized the line; line fuses; and fuses on
`.• individual transformers.
When DG is applied to the circuit, the presumption of a radial system with all power being supplied
from the substation no longer holds and the traditional protection approach is challenged:
• If DG levels are high enough and/or feeder loading is low enough, power flow can reverse
with power from the feeder into the substation. If reverse power flows are sufficiently high,
unintended tripping may occur as reverse power flow exceeds relay pick up settings, or
sympathetic tripping on feeders adjacent to faulted feeders could occur, as DG on the
adjacent feeder provides short circuit current to the fault in excess of the adjacent feeder relay
pick-up settings.
• Relay sensitivity to ground faults may be reduced. If grounding transformers are installed on
the feeder they will provide additional sources of zero sequence (ground) current that are
undetected by the feeder relaying. Since the feeder protective relaying sees only a part of the
ground fault current, the feeder relay protective relaying may not detect sufficient fault to
operate for faults that, previous to installation of grounding transformers, would have resulted
in an operation. This issue is of particular concern for high impedance ground faults.
• Lack of selectivity (miscoordination) of protective devices is also a possibility. If a DG of
sufficient size were located downstream from line fuses or a recloser, and a fault occurred on
the upstream side of the line fuses or recloser, there could be an unintentional operation of the
line fuse or recloser as the DG provided short circuit current to the fault.
• Reclosing open intervals, if too short, could result in reclosing before DG has de -energized.
IEEE 1547 requires that DG de -energize within two seconds after the feeder circuit breaker
opens.
4.7.2 Management
Vernon's distribution system is configured and protected to avoid or mitigate the potential problems
noted above.
• The level of DG installed on a feeder will be limited by other factors before reverse power
flow can cause protective relaying malfunctions. Refer to the Physical Impact Study Report
for more discussion.
• Feeder relay sensitivity to ground faults will not be reduced. Vernon's feeder protective
relaying uses modern multi -function microprocessor based relays. Ground fault protection is
based on negative sequence current rather than zero sequence current. As a result ground fault
detection will not be negatively influenced by the presence of grounding transformers (which
only provide zero sequence current) should grounding transformers be needed on the
distribution circuits.
• Vernon does not have main line fuses or reclosers eliminating any concerns for
miscoordination with those devices.
• Vernon uses one reclose with an open interval of 10 seconds, well above the two second time
permitted for DG to de -energize.
Vernon's protective relay settings should be evaluated in detail to determine if any setting changes are
needed to accommodate the highest level of DG expected. Settings changes may not be
recommended, but if any are, then Vernon's protective relays are expected to accommodate the
recommended settings changes without difficulty.
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Vernon does have very large transformers (up to 3,750 kVA) on both the 7 kV and 16 kV systems.
16.1 These transformers are large enough that providing coordination between the transformer fuses and
feeder relays is not possible without compromising other protective relaying objectives. The apparent
choices are to accept that feeder breakers are likely to operate for faults on the transformer side of the
transformer fuses or using more complex and expensive protection devices that provide more setting
flexibility (e.g., reclosers) to protect the large transformers.
4.8 Monitoring, Information Exchange and Control
Requirements for Monitoring, Information Exchange and Control (MIC) should be based upon the
potential impact of DR to Vernon's distribution system with consideration to consistency with
utilities that interconnect with Vernon and regional practice.
IEEE 1547 section 4.1.6 states "Each DR unit of 250 kVA or more or DR aggregate of 250 kVA or
more at a single PCC shall have provisions for monitoring its connection status, real power output,
reactive power output, and voltage at the point of DR connection." Monitoring is to be made at the
"point of DR connection", not the PCC. The point of DR connection will often be, and probably
typically is, within the customers low voltage system behind the meter. Real and reactive power
measurements are not revenue metering quantities.
The IEEE 1547 requirement for provisions for monitoring the status of DR rated 250 kVA or more
provides a supportable criterion for the minimum size of DR to consider, however "Provisions for
monitoring.. ." is a requirement IEEE 1547 imposes on the DR, Vernon is not required to remotely
monitor DR sites of 250 kVA or more by IEEE 1547.
IEEE 1547.3 section 5.3 provides generic MIC recommendations based on DR size. What follows is a
summary of the recommendations for DR in the capacity addressed by IEEE 1547 (10 MVA or less):
Class I — 0 to 250 kVA — Monitoring provisions are not required by IEEE 1547 and it is
unlikely the Area Electric Power System Operator (AEPSO) (Vernon) will require
monitoring.
• Class 2 — 250 kVA to 1,500 kVA (upper limit may vary) — AEPSO may require energy
output to be monitored by the Energy Management System (EMS) (or SCADA). Above
1,000 kW the AEPSO may require connection status and output to be monitored. Voltage
monitoring may not be required unless the DR has the ability to impact voltage at the PCC.
• Class 3 —1,500 kVA to 10 MVA — DR installations in this category could have significant
impact on the Area EPS. As a minimum the AEPSO is likely to require connection status,
real power, and reactive power to be telemetered (or provided via SCADA) to the AEPSO.
Section J.5 on sheet 133 of SCE's Rule 21 document states that SCE may require telemetry for
generators more than one MW for distribution primary voltages of 10 kV or greater and 250 kW for
distribution voltages less than 10 kV. This same section also states that "Distribution Provider shall
only require telemetering to the extent that less intrusive and/or more cost effective options for
providing the necessary data in real time are not available."
Based upon the IEEE 1547.3 recommendations and considering Vernon's distribution system and
policies of Vernon's power provider, SCE, the following approach is suggested as a starting point for
discussion:
• 0 to 250 kVA — no monitoring in conformance with IEEE 1547.
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4.3h — This requirement for the paralleling device to be capable of 220% of the COV System
rated voltage appears to be intended for rotating generators. Consider clarifying. Also see 4.31
below.
4.3 i — Telemetry requirements seem too broad. Consider modifying. Refer to the Monitoring,
Information Exchange and Control section of this report.
4.3j — Add requirement to operate generating facility at unity power factor — "The generating
facility shall be operated at unity power factor."
4.3k — Add anti-islanding testing requirement by adding a language such as "Generating
equipment shall be certified to comply with the latest versions of IEEE 1547, including
amendments and all applicable standards in the 1547 series; and UL1741. If certification is not
available COV may, at its sole discretion accept other means of validating that the generation
facility will meet the performance requirements of IEEE 1547".
4.31— Consider adding language to the effect of "Generation which is not based on inverter
technology will require additional equipment to assure that the generation is safely synchronized
to the COV system, does not disturb the COV system through voltage sags caused by inrush or
have other negative impacts. Such installations are expected to be rare and COV will review such
installations on a case by case basis to assure that generation facility is designed, tested, and
maintained to avoid negative impacts to the COV system, including power quality."
9. Monitoring and Control
9a. Telemetry requirements seem too broad. Consider modifying. Refer to the Monitoring,
Information Exchange and Control section of this report. 25 kW or higher appears too stringent, is not
in conformance with IEEE 1547 which requires "provisions for monitoring" above 250 kVA.
Riverside Public Utilities (RPU) and Burbank Water and Power (BWP) did not specify a level
requiring telemetry, but SCE requires Telemetry for 250 kW and above for system below 10 kV and 1
MW above 10 kV system.
9b. Refer to comments for 9a.
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BBase voltages are the nominal system voltages stated in ANSI C84.1-2011 Table 1
Alternatively consider using values from SCE's Rule 21.
[1] — Unless otherwise required by Distribution Provider, a trip frequency of 59.3 Hz and a maximum trip time of 10 cycles shall be used.
[2] — When a 10 cycle Maximum trip time is used, a second under frequency trip setting is not required.
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5.0 FISCAL IMPACTS OF DISTRIBUTED GENERATION
5.1 Introduction of Financial Impacts
The electric utility industry is facing a change of pace from technology integration, customer
demands and regulations like at no other time in its history. DG is one of the first wide -spread market
impacts and result of this convergence of technology, customer demands, and regulations on the
utility system. Many municipally owned utilities across the country are beginning to address and face
increasing penetration of DG and develop strategies to manage and in some cases further incentivize
their adoption.
NewGen Strategies and Solutions, LLC (NewGen) supported the study by POWER by conducting a
DG and cost of service (COS) analysis to inform and guide Vernon's decisions regarding DG levels
allowed on the system, rate structures to address potential customer inequities and ensure rates are
properly recovering all Vernon costs. In support of the analysis and evaluation, NewGen developed
the following key elements to guide decision making:
• Financial forecast to project fiscal impacts and Vernon's financial performance with
increased DG adoption levels;
• Rate strategy to guide and provide a common, long-term framework to make rate related
decisions; and
• COS and rate design to accurately calculate Vernon's total costs to recover in rates and the
breakdown of fixed and variable costs to ensure increased DG does not fiscally harm Vernon
or its other customers.
Each of the three key elements of the financial DG evaluation are briefly summarized below with
more detailed discussion of results later in this section.
5.1.1 Distributed Generation Impacts
To fully evaluate the financial impacts to Vernon of varying levels of DG on the system, NewGen
prepared a 10-year financial forecast of the system. The forecast included a projection of utility
financial performance including customer loads, system rate revenues, operations and maintenance
(O&M) expenses, capital costs, debt service, Vernon transfers, and other financial requirements of
operating the electric utility. The key output of the model was calculating projected revenue
reductions and actual operating losses from varying levels of DG on the system.
The model calculated revenue reductions associated with DG power and energy production which
reduced customer energy and demand sales. To calculate the potential operating losses for Vernon,
the financial forecast model considered utility avoided costs associated with the growth of DG on the
system. If revenue reductions were greater than avoided costs, it leads to an actual operating loss for
the utility. Multiple scenarios were evaluated to further define inflection points or aggregate dollar
amounts that were considered detrimental or would threaten the financial integrity of the utility.
Rate Strategy
Developing and following a utility Rate Strategy provides a framework and guide for the current and
future COS and rate making decisions, while integrating goals and policies such as adherence to key
financial metrics, COS results, or the Council's policies. Such a document can address key financial
metrics such as the appropriate amount of system debt, debt service coverage requirements, and cash
reserve levels for the utility to maintain. Further, the document articulates Vernon's views on
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adherence to COS -based rates, gradualism, complying with renewable energy/conservation
`. requirements, and support for economic development. This document can be particularly helpful for
decision makers that are new to the process over time (e.g., new Council members, department
managers and other stakeholders). While the Rate Strategy provides a framework to guide decision
making and the periodic COS review, it does not eliminate, nor, reduce the decision -making capacity
and final authority of the Council.
COS and Rate Design
As the evaluation of distributed generation impacts began, it became clear a comprehensive COS was
required to fully evaluate the customer class impacts related to revenue reductions, operating losses,
alignment of current fixed/variable revenue versus fixed/variable costs, and subsidization. A COS and
Rate Design study attempts to identify all costs associated with operating a utility system, evaluate
how those costs imposed on the system by customers, and appropriately allocate the costs to each
customer class. The completed COS supports the development of rates to adequately and fairly
recover the full costs of operation from each customer class.
In particular importance to evaluating the financial impacts of DG, the COS will identify the true
COS fixed (e.g., demand and customer related) and variable (e.g., energy related) costs for each
customer class. Properly and accurately identifying the fixed and variable costs for each customer
class is vital in evaluating potential losses associated with DG penetration on the system. The COS
helped highlight misalignments between current fixed rates (e.g., customer demand and customer
charges) and fixed costs that must be recovered by Vernon. Upon completion of the COS, the results
were used to design the recommended rates for each customer class for the Council to consider for
adoption.
5.2 Ten Years Financial Forecast
The 10-year financial forecast of the system was used to analyze the financial impacts of varying
levels of DG on the Vernon system. The forecast projects key utility drivers or constraints such as
customer load and the portion / limits of DG on the system in addition to financial projections such as
system rate revenues, O&M expenses, capital costs, debt service, and Vernon transfers. To ensure
Vernon remains within sound financial practices and required financial requirements, the model also
calculates required cash reserve levels and debt service coverage. The basis for the 10-year projection
was the development of the Revenue Requirement which incorporates all the above costs and reflects
all the costs associated with providing electricity to each customer class. This Revenue Requirement
is also later used in the development of the COS.
The key output of the model was the calculation of projected revenue reductions and actual operating
losses from varying levels of DG on the system. It is important to distinguish between revenue
reductions and actual operating losses for Vernon. While revenue reductions are not typically
embraced by electric utilities, if rates are structured properly, the utility will still properly recover all
of its costs and revenue reductions will not lead to actual operating losses. It is important to note,
overall revenue reductions at Vernon would also lead to eventual reductions in the Vernon transfer as
well.
DG related revenue reductions for Vernon are driven by power and energy production by customer -
owned DG technologies such as conventional natural gas generators or solar rooftop PV. Self -
generation by customers leads to reduced energy and power consumed, thus reduced utility revenues.
Customer self -generation also leads to avoided costs by Vernon as the utility no longer must supply
the energy avoided or offset by the DG. These avoided costs are primarily energy related costs such
as avoided fuel consumption or power purchases. In some cases, DG may lead to additional avoided
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transmission and distribution system benefits; however, through the previous analysis included in this
Report, this added benefit appears to be minimum.
Operating losses are created when revenue reductions are greater than the avoided costs of Vernon.
Losses occurring on the system from DG must be recovered through other customers' rates to ensure
the utility fully recovers all costs and operates in a financially sustainable manner. If the avoided costs
are equal to the revenue reductions, Vernon's rates would properly recover costs and not require
additional recovery through non-DG customers.
The model also included scenario analysis to further inform Vernon of the impacts of DG at varying
levels, adjusting the limitations of DG on the system and restricting certain technologies (where
applicable) over the course of the 10-year projection. The scenario results were evaluated to define
inflection points or aggregate dollar amounts that were considered detrimental or would threaten the
financial integrity of the utility. For example, if the maximum DG allowed on the system likely
resulted in an operating loss of less than 0.1 % of total revenues, the penetration of DG on the system
could be considered manageable and not require major rate related changes. However, if potential DG
impacts on the system began to result in losses of more than 0.5 %, it could be considered
burdensome and result in cost -shifting / subsidization between customers.
5.2.1 DG Limits on the System, Net Metering and DG State Regulations and
Legislation
State statutes and CPUC policies are one of the largest impacts on the requirements and / or
limitations of customer -owned DG on municipal utility systems. California Assembly Bill (AB) 327
in 2013 is the latest and most recent in a series of net metering statute amendments and expansions.
AB 327 sets net metering requirements for all utilities in California, including municipally owned
utilities (with the exception of LADWP). To the best of our knowledge, the discussion regarding the
�- application and requirements of AB 327 to Vernon within this Report is up to date as of May 5, 2015.
As the California net metering and renewable energy related policies are routinely modified, NewGen
recommends Vernon remain current on the legislation and applications of AB 327 and its successors
to public power utilities.
AB 327 requires utilities allow net metering of eligible and defined renewable distributed
technologies on the electric system of up to 5% of their aggregate customer peak demand. The
legislation initially defined eligible technologies as solar, wind, and hybrid systems. The legislation
was later amended and expanded to include other renewable technologies such as fuel cells and
biomass. Conventional DG, such as natural gas or diesel fired engine generators are not included in
the statute, thus do not face the same limitations or requirements as renewable DG.
Aggregate customer peak demand was also further defined to equate to the sum of the utility's
customer class non -coincident peak (NCP) demands. This equates to adding each of Vernon's
customer class NCPs and multiplying the result by 5%. This amount is slightly greater than 5% of
Vernon's system peak demand. Table 5-1 shows the net metering requirement calculation for Vernon.
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The results of AB 327 show Vernon must allow up to 9,924 kW of DG on their system under fiscal
year (FY) 2015 system results. As the table illustrates, the sum of the customer NCPs is higher than
the overall system peak for Vernon in FY 2014. This is common and expected as the peak for
individual customer classes does not typically perfectly align with the system peak. As more of DG is
installed on the Vernon system and it nears the 5% limit, the above calculation must be repeated
annual to identify potential DG additions in subsequent years (if any).
AB 327 and its proceeding legislation also includes additional requirements and guidance for net
excess generation from net metered DG, valuing excess generation from customers, and "carve -outs"
for specific technologies. In Vernon's case, the state statutes for net metering are the basis for
developing guidelines and limitations on the amount of DG on its system. As stated in previous
sections of the report, technical or permitting requirements are not necessarily limiting factors in
defining or guiding the amount of DG Vernon could safely allow on its systems.
In addition to providing requirements regarding access of renewable technologies to municipal and
investor -owned utility grids, AB 327 also includes regulation and requirements regarding
implementation of net metering rates for DG applications up to one MW. The statute requires utilities
to provide net metering rates; however, the net metering rates must not increase the costs above or
differ from those rates already offered to the customer (e.g., the customer class rate) without DG. In
effect, this requires utilities to apply net metering principles (explicitly defined in the statute) to their
existing rates, without any specific adjustments to address potential DG subsidization or cost under
recovery issues.
For customer DG installations above 1 MW, the utility has significantly more flexibility in
developing interconnection agreements and modifying rates. Above 1 MW, utilities can apply or
require interconnection agreements, charge standby or reservation rates, or develop a separate rate or
contract to serve the customer. Overall, the California net metering regulations strongly incentivize
renewable DG for customers; however, it also begins forcing utilities to better align their rates with
their COS and increase the fixed charges (demand and customer) across all rate classes. If utilities
delay aligning rates with their COS and increasing fixed charges, as more DG is installed on their
system, the larger the financial risks and subsidization issues become.
Financial Forecast Model Results
To accurately calculate the revenue reductions and potential operating losses from DG on Vernon's
system, each year of the financial forecast was functionalized (e.g., power supply, transmission,
distribution, and customer related) and classified (e.g., demand, energy, or customer related) to
properly identify the fixed and variable costs, thus the true avoided costs associated with DG on the
system. These avoided costs were then compared to the reduction in revenues due to lower energy
and potential demand sales to customers.
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The Revenue Requirement, or total Vernon costs to serve customers, was calculated to be
�. $158,341,651 in FY 2015. This amount escalates in subsequent years as specific accounts are
escalated to reflect increasing costs, inflation, changes in reserve requirements, debt issuances, and
the forecasted market conditions. The FY 2015 calculated Revenue Requirement and subsequent
forecasted years is included in Table 5-2.
TABLE 5.2:
REVENUE REQUIREMENTS FOR VERNON
2015
$158,341,651
$0.140
2016
$152,736,573
$0.133
2017
$172,056,500
$0.149
2018
$173,968,151
$0.149
2019
$176,198,184
$0.149
2020
$180,021,106
$0.151
2021
$189,493,428
$0.157
2022
$209,982,280
$0.172
2023
$213,677,705
$0.173
2024
$217,354,074
$0.174
Note: $/kWh = dollars per kilowatt hour
The Revenue Requirement decreases from 2015 to 2016 due to a slight decline in projected natural
gas market costs, while the significant increase from 2016 to 2017 is driven by a contractual change
in the power supply agreement and significant increase in capacity charges. The remaining years
escalate primarily due to steadily increasing fuel costs and inflation on expenses.
The annual Revenue Requirements were then further evaluated to identify the fixed and variable
portions of the totals to accurately estimate avoided costs associated with DG. Table 5-3 summarizes
the 10-year average Revenue Requirement and breakdown of the fixed and variable classified costs.
Please note customer and demand classified costs are considered fixed, while energy related costs are
considered variable.
TABLE 5-3:
10-YEAR AVERAGE REVENUE REQUIREMENT FORECAST FIXED
AND VARIABLE COST STRUCTURE
Customer
$7,546,450
4%
Demand
$110,875,565
60%
Energy
$65,960,949
36%
Total
$184,382,965
100%
Summarized Fixed and Variable Costs
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TABLE 5.3:
10-YEAR AVERAGE REVENUE REQUIREMENT FORECAST FIXED
AND VARIABLE COST STRUCTURE
Fixed $118,422,016 64%
Variable $65,960,949 36%
Total $184,382,965 100%
Notes: Please note the above breakdown of fixed and variable costs will vary from those presented in
the COS as the COS is a Test Year period focused on 2015 - 2017; not the 10-year average. In
addition the COS TY Revenue Requirement is more detailed with additional adjustments, as compared
to the above simplified Revenue Requirement for the financial forecast analysis
The large commercial customer class Time of Use — V (TOU-V) was used to project DG adoption in
the Vernon system and related revenue reductions. In general, the TOU-V customer class revenues
for FY 2014 were 26% fixed and 74% variable, which is essentially the opposite of Vernon's cost
structure shown in the above table. This highlights the misalignment between Vernon's rate revenue
recovery and cost structure which leads to operating losses associated with customer DG
implementation.
Figure 5-1: Vernon DG Adoption Projections and Aggregate Customer Demands (NCP)
To evaluate the potential annual and cumulative impacts of DG adoption, the financial forecast model
projected amounts of DG, by type (e.g., conventional or renewable), adopted by the TOU-V
customers. The DG adoption rates and amounts (e.g., kW) on the system for the first two years
reflected Vernon guidance related to recent customer inquiries for solar PV DG systems. The
subsequent years were an estimate and projection by NewGen of the amount of DG adopted for
evaluation purposes. Figure 5-1 illustrates a potential cumulative adoption rate over the next 10 years
for TOU-V customers (red line and right Y axis), the aggregate customer peak demand growth over
time (NCP Demands in blue) and minimum net metering requirements of AB 327 (5% of aggregate
customer peak demands shown as the yellow line and right Y axis).
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Figure 5-2: Revenue Reductions, Avoided Costs and Operating Losses for the Base Case DG
As Table 5-1 notes, Vernon's FY 2014 aggregate customer peak demand is 198.5 MW, thus the DG
requirements of AB 327 are 9.9 MW. Using average growth rates of approximately 1% per year for
the system peak and NCP, the aggregate customer peak demand increases to 221 MW by 2024. Per
AB 327, this equates to a limit of 11 MW of DG on the Vernon system by 2024 under the assumed
growth rates.
Based on the projected DG adoption and penetration levels within Vernon's system, the annual
revenue reductions and operating losses were then calculated. To fully evaluate the impacts, four
cases were developed to test the range of financial impacts to Vernon.
• Base Case: Solar PV Only. The Base Case is used as a proxy for all renewable DG added to
the system to achieve the 5% DG limit.
• Case 1: Natural Gas and PV. Case 1 evaluates the impacts if Vernon chose to allow
conventional DG to receive similar net metering treatment as renewables. This case includes
60% of the total DG capacity from PV and the remaining 40% from natural gas -fired
generators.
• Case 2: Natural Gas Only. Case 2 includes 100% conventional DG to understand the unlikely
event of large amounts of conventional DG allowed on the Vernon system. Case 2 also acts to
benchmark against the Base Case and Case 1 to understand how conventional DG may
further impact Vernon's financial performance and stability.
Using the financial forecast model, each of the cases were projected to evaluate their relative impacts
to the financial performance of the utility. The results for the Base Case solar PV are included in
The Base Case annual revenue reductions are shown in the bar graph and include a breakdown of
Vernon Transfer reductions and other Vernon revenue reductions. It is important to understand the
broader revenue reduction impacts, as revenue reductions for the Utility also results in reductions in
the Vernon Transfer. Over time, these reductions become significant as DG penetration nears the 5%
limit. In the first year, 2015, the Base Case revenue reduction is $913,666 per year ($105,072 in
Vernon Transfer reduction and $808,594 in other reductions) at 2 MW of solar PV DG. At full
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penetration in 2024, the Base Case revenue reduction is $6.07 million per year ($698,000 in Vernon
`— Transfer reduction and $5.37 million in other reductions).
While the revenue reductions are significant at full penetration, Vernon does avoid some costs in the
adoption of DG. The light blue line in Figure 5-2 represents the annual avoided costs of the Utility.
By subtracting the avoided costs from the revenue reductions, shows the annual operating losses
driven by DG. For the Base Case, in 2015 the projected annual operating losses are $484,384 and by
full penetration in 2024, reach $3.126 million. The operating losses are equal to an average of 53% of
the total revenue reductions. Thus, under current conditions, every $1.00 in revenue reduction leads to
an actual loss of $0.53. This significant portion of revenue reductions that result in operating losses
highlight the misalignment of the fixed rates with the fixed costs, thus driving losses for Vernon.
Table 5-4 summarizes the revenue reductions and operating losses for the Base Case, Case 1, and
Case 2.
TABLE 5-4: ANNUAL FINANCIAL IMPACTS FOR MAXIMUM DG PENETRATION (e.g., 5% OF NCP)
Revenue Reduction
Vernon Transfer
$698,032
$888,316
$1,177,686
Other Reductions
$5,371,809
$6,836,170
$9,063,064
Subtotal
$6,069,841
$7,724,486
$10,240,750
Operating Losses
$3,125,582
$4,414,614
$6,474,580
Notes: The above amounts reflect annual revenue reductions and operating losses at the maximum penetration of DG (e.g., 5%
demand). This equates to approximately 11 MW of DG.
of the aggregate customer peak
OR
While the net metering legislation is applicable only to renewable DG, it is important to understand
the impacts of allowing additional conventional DG resources on the Vernon system. As Vernon is
required to allow the renewable DG, it is not required to allow the conventional DG. Understanding
the impacts of conventional DG to financial performance will help inform decisions regarding
limitations of tailored rates for conventional DG customers.
The total operating losses reflect 1.4% (Base Case) up to 3.0% of total annual revenues. These
operating losses must be recovered in other rates to maintain the utility's financial integrity, thus rates
for all customers must increase by 1.4 to 3.0% to support 11 MW of DG on the system. As seen in
Table 5-4, increasing the amount of conventional DG making up the total DG on the system increases
the revenue reductions and losses.
In Case 2, the full amount of DG on the system is natural gas conventional generation which results in
$9.06 million in revenue reductions and $6.5 million in operating losses. Compared to the Base Case
of all solar PV, this is a doubling of the total operating losses from $3.125 million to $6.5 million.
Conventional DG leads to larger losses due to the ability to dispatch or dictate when the DG may run.
Thus a customer can operate the DG to reduce peak demand and the on/mid peak energy periods to
maximize the bill reductions. Many renewables are not "dispatchable" or cannot be directed to run
during specific periods. Thus the reductions associated with renewable technologies do not benefit
from the demand reductions and broader energy savings opportunities as with conventional
technologies.
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Updating the rates to align with COS results will reduce the operating losses. Rates discussed later in
'`- this section that increase the fixed charges (e.g., demand and customer) and reduce the energy charges
will partially reduce the operating losses associated with DG. By adjusting the rates to align with the
Phase 3 rates included in this report, Vernon can reduce the operating losses by 30%. For example,
the operating losses in the Base Case reach $3.1 million at maximum DG penetration as shown in
Table 5-4. The new recommended rates reduce the operating losses at maximum DG penetration to
$2.2 million, a reduction of $1 million or 30% from the current rates.
5.3 Rate Strategy
California's DG statutes and requirements increase uncertainty, risk, and operational complexity for
Vernon and other utilities. As the business environment is becoming increasingly complex and
uncertain, utilities must identify and successfully manage their business risk through a variety of
strategies that encompass power supply, conservation, renewables, efficiency, distributed generation,
and demand response options. To be successful, the City of Vernon and Vernon must send a
consistent message to customers aligning the values of the community and utility to the
corresponding customer incentives. Rate design is the most important customer incentive or pricing
signal given to Vernon customers while also ensuring proper cost recovery. To successfully support
utility strategies over the long term, pricing structures and signals must align with desired changes in
customer behavior and utility financial objectives.
Together, Vernon's rate design strategies and financial objectives are known as the Rate Strategy.
Due to the increasingly complicated and changing business environment, having a clear Rate
Strategy, which is integrated with stakeholder engagement, is becoming a best practice for high
performing utilities. The initial development of the Rate Strategy was the result of an internal City of
Vernon team meeting facilitated by NewGen. The meeting discussed utility rate, finance, customer
and operational issues affecting the utility and the Vernon. The team included representatives across
the organization including City of Vernon finance, Vernon, economic development, Vernon
Administrator, resource planning, operations, and engineering.
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Comply with City Council
Poky and Remotions
Financial Stability
Conservation and
Rowwabks
Engage Stakeholders
Equity and Fairness
Maintain High Value
Services and Accomplish
ChOW through
Grart
Accommodating Growth
E cono III, (S
Cc,t of Sery ce. Financial
Planning and Rate Design
In order to guide the long-term development of financial strategy and rates, Vernon is adopting a core
set of rate making principles that are intended to stand the test of time, help Vernon navigate the ever -
changing electric market and align rate making with the City of Vernon's broader strategy. Finally,
while the Rate Strategy acts to guide current and future rate and COS related decisions, the final
approval and direction for rate changes remains with the City of Vernon administrative leadership and
City Council. Each of the central principles of the Rate Strategy are briefly summarized below and
the full Draft Rate Strategy is attached as Appendix E.
5.3.1 Comply with City Council Policy and Regulations
Vernon must comply with state and federal laws and regulations, policies adopted by its Council, and
financial covenants made to bondholders. These policies and laws include:
• Policies adopted by the City Council and City of Vernon administrative leadership.
• California State Laws (e.g., Conservation and Renewable Portfolio Standards, Net Metering,
AB 32 Global Warming Solutions Act).
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• In addition, Vernon must meet the requirements set forth in any outstanding bond covenants
L. related to reserve funding level and debt service coverage amounts.
5.3.2 Financial Stability
The development of rates that ensure long term fiscal integrity via an adequate and sustainable
revenue stream is important to the future of Vernon. Dynamic market changes and customer usage
patterns directly impact the ability to satisfy this principle and necessitate state of the art approaches.
Without financial stability, Vernon could face severe financial consequences, including the inability
to execute its fundamental business objectives.
The financial stability principle includes financial items, policies and metrics such as:
• Following the utility's financial policies and targets will support a competitive and strong
bond rating for the Vernon and align with best practices.
• Maintaining minimum debt service coverage ratios.
• Cash reserve levels and targets.
• Debt to capitalization ratios for capital funding.
• Commitment to developing an annual financial plan.
• Adopt and use the unbundled, embedded COS framework.
5.3.3 Equity and Fairness
While the concept of fairness is subject to interpretation, rates should follow general equity and
fairness principles. Deviating from these principles may be needed as a matter of policy, but fairness
and equity should provide a guide for those policy situations and cost allocations. In alignment with
equity and fairness in rates, cross -subsidization between customer classes should be minimized.
L
Specific equity and fairness principles include, but are not limited to: performing COS studies on a
periodic basis, gradually aligning rates with the COS results, eliminate subsidization where possible /
maintain transparency where it occurs, and allocating regulatory and renewable costs following COS
and industry practices.
5.3.4 Renewable Energy and Conservation
Vernon will follow a strategy of compliance with regard to energy efficiency and renewable energy
purchases while supporting customer choice in rates, distributed renewables, and conservation.
Customer rates, distributed renewable energy, and energy conservation options will use the COS
results as a guide in addition to the City Council's direction. This will include supporting renewable
DG where desired within the limits of the system and financial stability for the Utility and properly
recovering the fixed/variable costs. Vernon will also comply with all conservation and renewable
requirements for the system.
5.3.5 Maintain Competiveness and High Value Services while
Accomplishing Changes through Gradualism
In some stakeholders' minds, the terms "high value" and "affordable" are synonymous. However, the
term affordable is subjective and may at times conflict with the need to raise rates to meet rising
costs. Given these economic realities and Vernon's strategic objectives, a focus on high value, which
includes elements such as customer service levels, reliability, choice, and cost, is more appropriate.
This can be viewed as providing the right level of quality and service at the right price.
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The phasing -in of rate change is known as gradualism and avoids "rate shock" by customers. With
`•- rate structure changes, bills can change gradually over time even as rates increase, thus supporting the
objective of delivering high value. Gradualism allows for a "no regrets" approach to each decision
and action; this is a sound method for reducing unintended consequences. Such unintended
consequences potentially include having to undo actions taken previously due to customer
misunderstanding and push back. To ensure high value competitiveness, Vernon shall periodically
benchmark rates to demonstrate its competitiveness, use gradualism for significant rate changes and
monitor / track the use of reserves used to reduce rate increases for future recollection aligned with
financial policy levels.
5.3.6 Engage Stakeholders and Communication
Stakeholder engagement fosters communication, supports transparency, educates, develops ideas, and
encourages input and feedback. Leveraging stakeholder engagement mechanisms, groups, or key
accounts are necessary to ensure proper representation and input to the Rate Strategy and ratemaking
process.
5.3.7 Accommodating Growth
As a matter of policy, Vernon implements practices that support and facilitate customer and Vernon
of Vernon growth. This includes incentivizing economic development through rates and infrastructure
extension by reducing and minimizing up -front or initial customer investment to extend or expand the
electric infrastructure to serve the customer's load. Other elements of accommodating growth include
maintaining flexibility to tailor cost recovery for infrastructure extensions and considering broader
economic development benefits when evaluating new large loads.
Cost of Service
Building on and utilizing elements of the Rate Strategy, NewGen began developing the COS. A COS
attempts to identify all costs associated with operating a utility system, evaluate how those costs
imposed on the system by customers, and appropriately allocate the costs to each customer class. The
completed COS supports the development of rates to adequately and fairly recover the full costs of
operation from each customer class. In the case of Vernon and evaluating DG impacts, a COS
provides key data required to identify and quantify fixed and variable cost and revenue misalignments
within each customer class. This data will be crucial in adjusting rates in each customer class to
minimize operating loss risk associated with DG and net metering adoptions. The Vernon COS and
rate making process included four steps:
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Figure 5-3: Rate Making Process
To remain financially sound, the electric rates must produce sufficient revenues to recover the total
costs of providing electric service to its customers. These costs imposed on the system by customers
are commonly referred to as the utility's Revenue Requirement and consist of normal operating
expenses, debt service, capital improvements, taxes, non -operating expenses, and reserve
requirements. These total Revenue Requirements are then compared to utility revenues to evaluate the
need for rate changes. The Revenue Requirement acts as the foundation of a COS study.
When completed, the COS results indicate the degree to which existing rates recover revenues from
each customer class on a COS basis and are considered in designing new electric rates.
There are three steps in developing the COS as illustrated in Figure 5-4.
. _ . _ . _ . _ . _ _ . _ . _ . _ . _ . _ . _ . _ . _ . _ . _ .
Component A • I Component B I I Component C
' Cost Cbssification • pass alocation Factors
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_._._._._._I._._._.11._._._._._._.
Figure 5-4: Cost of Service
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A. Functional Unbundling
Unbundle Revenue Requirement into utility functions (e.g., production, transmission,
distribution, and customer service).
B. Classify Costs
Classify costs within each function as demand, energy, customer related, or directly
assignable.
C. Allocate Classified Costs to Customer Classes
Allocate classified costs (e.g., demand, energy, customer) within each function to the
customer classes based on specific service and consumption characteristics of the customer
classes.
Test Year Revenue Requirement
There are two primary Revenue Requirement methodologies used in the electric utility industry, the
cash basis and the utility basis. The primary differences between the cash basis and the utility basis
involve the treatment of depreciation, return on invested capital, and debt service. The cash basis,
which is the most common method used by municipalities, includes debt service but excludes
depreciation and return on invested capital in the Revenue Requirement determination. The cash basis
focuses on meeting the cash demands of the utility. The utility basis, most commonly used by
investor -owned utilities, includes depreciation and return on invested capital, but excludes debt
service from the Revenue Requirement determination.
Figure 5-5: Test Year Revenue Requirement Process
In the COS developed for Vernon, the cash basis was utilized since the traditional cash oriented
budgeting practices are frequently used by public entities. In addition, the cash basis is generally
easier to explain to customers since the cash basis attempts to match revenues with expenditures. A
projected Test Year (TY) Revenue Requirement was developed for Vernon based on the financial
model and a three year projection of FY 2015 — 2017. The financial model projections were based on
Vernon's FY 2014 actual costs. Any known or measurable adjustments to expenses are then applied
to the three year projection of costs to develop the final TY Revenue Requirement. Figure 5-5 reflects
the process used in developing the TY Revenue Requirement.
Table 5-5 summarizes the TY Revenue Requirement.
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TABLE 5-5: TEST YEAR REVENUE REQUIREMENT
Operating and Maintenance Expenses
Power Supply and Transmission
$102,538,106
63%
Light and Power
$5,816,417
3%
Overhead
$6,813,420
4%
Subtotal Operating and Maintenance
$120,167,943
70%
Other Expenses (Income)
$(31,931,711)
-19%
Debt Service/Other Interest Expense
$51,959,893
30%
ILOT and Transfers
$16,941,775
10%
Capital Improvements Paid with Cash
$3,907,007
2%
Increase to Fund Reserves
$10,432,846
6%
Total Revenue Requirement
$171,477,754
100%
The majority of Vernon's TY Revenue Requirement is associated with power supply costs and debt
service. The above TY Revenue Requirement is inclusive of accounts and costs such as AB 1890
public benefits charges, greenhouse gas related costs, and renewable energy purchasing costs
associated with meeting state mandates and regulations regarding emissions, efficiency, and
renewables. These costs, in addition to costs above and beyond a base budgeted amount of natural gas
costs ($7.50 per mmbtu) are included in the Public Benefits Charge (PBC), fuel cost adjustment, and
renewable energy cost adjustment, collectively called "pass-throughs."
These pass-throughs are not included in the base rates and are used to manage costs that have greater
volatility (e.g., natural gas market prices) or are not core to Vernon's business. These costs are
collected on a one-to-one cost basis with the pass -through rates. The pass-throughs are also adjusted
periodically to align with the changing collection needs and market prices. Base rates are the rates
included in the Vernon tariff, and are designed to collect the core, more stable Vernon costs or "non
pass -through" related costs. Table 5-6 shows the Base Rate TY Revenue Requirement, including an
adjustment to account for the discounts provided to customers served at higher voltages. This Base
Rate TY Revenue Requirement is then compared to the projected TY Base Rate Revenues to identify
the rate changes needed for the study period of three years.
TABLE 5-6: BASE RATE TEST YEAR REVENUE REQUIREMENT
Operating and Maintenance Expenses
Power Supply and Transmission
$96,844,028
60%
Light and Power
$5,816,417
4%
Overhead
$6,813,420
4%
Subtotal Operating and Maintenance
$120,167,943
68%
Other Expenses (income)
$(31,931,711)
-20%
Debt Service/Other Interest Expense
$51,959,893
32%
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TABLE 5-6: BASE RATE TEST YEAR REVENUE REQUIREMENT
ILOT and Transfers
$16,941,775 11%
Capital Improvements Paid with Cash
$3,907,007 2%
Increase to Fund Reserves
$10,432,846 6%
Subtotal Revenue Requirement
$160,783,675 100%
Adjustment for Discounts
$7,200,711
Base Rate TY Revenue Requirement
$167,984,385
Base Rate TY Revenue Projection
$158,672,763
Base Rate Adjustment
5.9%
The Base Rate TY Revenue Requirement shows current rates must increase by 5.9% to fully recover
Vernon's costs for the three year TY period.
Unbundling of Revenue Requirement
The TY Revenue Requirement was "unbundled" into the four functional areas (or primary business
units) of the system, including power supply, transmission, distribution, and customer. Administrative
and general costs were either directly assigned to the customer function or functionalized based on
labor, Revenue Requirement, or total net plant ratios.
Production (Power Sunaly) Function
`.. The production (power supply) function commonly consists of costs for generating or purchasing
power and electricity. Typically, the power supply function includes costs associated with operating
and maintaining electric generation facilities and making capital investments, as necessary. However,
for many municipal utilities, this function primarily includes costs associated with purchase power
contracts, purchased power from markets, or both. Vernon currently purchases all of its power and
electricity needs. The majority of Vernon's purchased power costs are associated with the contract for
the power and energy delivered from the Malburg Generating Station.
L
Transmission Function
The transmission function consists of costs associated with operating and maintaining the
transmission portion of the electric grid and making capital investments, as necessary. The
transmission facilities transmit electricity at a high voltage from the generation stations to the
distribution system. This function also includes transmission related costs associated with the
purchased power and market related transmission costs.
Distribution Function
The distribution function consists of costs associated with operating and maintaining the distribution
portion of the electric grid and making capital investments as necessary. The distribution facilities
deliver power to the retail customers after it has been transmitted and transformed to lower
distribution voltages. This function includes substations, low voltage distribution lines, distribution
poles, underground lines, customer service conductor connections, meters, and street lighting -related
assets.
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Customer Service Function
The customer service function consists of costs associated with operating and maintaining the
customer -related facilities to meet customer support needs. This includes, but is not limited to,
customer accounting, customer information systems, billing, meter reading, key account services, and
the customer call centers or representatives.
Table 5-7 summarizes the functionalized Base Rate TY Revenue Requirement into the four functional
categories. The most significant portion of the Base Rate TY Revenue Requirement is related to the
power supply costs, which represents 80% of the total. The distribution function is the second largest
cost center representing 12% of the Base Rate TY Revenue Requirement and is reflective of Vernon's
primary operations.
TABLE 5-7: UNBUNDLED BASE RATE TY REVENUE REQUIREMENT
Power Supply
$127,079,389
80%
Transmission
$12,782,385
7%
Distribution
$19,862,366
12%
Customer
$1,059,536
1 %
Total Revenue Requirement
$160,783,675
100%
Classification of Revenue Requirement
After the costs have been functionalized, these system costs can be classified into four generally
accepted rate -making cost classifications: (i) demand or fixed costs; (ii) energy or variable costs; (iii)
customer -related costs; and (iv) directly assignable costs. In order to provide a reasonable basis for
the assignment of total Base Rate TY Revenue Requirements (costs) to each customer class, costs for
each function in the electric system have been analyzed and classified into four categories.
The functional costs were classified on the following basis:
• Demand Costs — Capacity (fixed- or demand -related) costs are those costs incurred to
maintain a utility system in a state of readiness to serve, enabling it to meet the total
combined demands of its customers. Demand costs include portions of operating and
maintenance expenses, all debt service, all capital expenditures, and other costs that are
generally fixed, and do not vary materially with the quantity of usage or that cannot be
designated specifically as a customer or variable cost.
• Energy Costs — Energy, or variable costs, are costs that vary directly with energy usage,
including such items as fuel, energy -related purchased power, and portions of operating and
maintenance expenses.
• Customer Costs — Customer costs are those costs directly related to the number and type of
customers, such as customer accounting, billing, and meter related expenses.
• Direct Assignment Costs — Direct assignment costs are those costs that are readily identifiable
and applicable to a particular customer or customer class (e.g., street lighting).
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Once the costs within each function are assigned to each service category, the demand, energy,
�- customer, and direct assignment component of each service is calculated. Table 5-8 summarizes the
three cost classifications (demand, energy, and customer). This breakdown of demand, energy,
customer, and direct assignment costs is later applied to each customer class to facilitate the electric
system rate design.
TABLE 5-8: CLASSIFICATIONS OF BASE RATE TY REVENUE REQUIREMENT
Customer
$5,657,146
3%
Demand
$99,135,291
59%
Energy
$55,991,237
38%
Total $160,783,675 100%
Thirty-eight percent of the total Base Rate TY Revenue Requirement is energy related or variable
costs. The remaining 62% of the Base Rate TY Revenue Requirement is classified as demand or
customer related costs, which are fixed costs. It is important to understand the mix of fixed and
variable costs as compared to the fixed and variable revenues. When the revenue recovery is
misaligned with the costs, it places the utility at risk for operating losses due to dramatic changes in
energy consumption, increasing energy efficiency and DG.
Until DG and net metering began widespread adoption, utilities typically collected much of their
revenues in energy related or variable rates. However, as DG has spread and more utilities become
L. familiar with the potential risks to financial stability, fixed charges have started to increase to address
the misalignment. Figure 5-6 shows the relationship between Vernon's fixed and variable costs and
its revenue recovery.
L
Test Year COS
Variable
35%
Fixed
65%
Revenues
Variable
74%
Fixed 26%
Figure 5-6: Fixed and Variable Costs and Revenues Comparison
Cost of Service Allocation to Customer Classes
Subsequent to the classification process, various factors were developed to allocate the adjusted Base
Rate TY Revenue Requirements to individual customer classes based upon customer service
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characteristics. These allocation factors reflect accepted ratemaking principles and were based upon
fully distributed embedded cost allocation procedures. For the system and customer classes, we
developed demand -related, energy -related and customer -related allocation factors.
To evaluate the ability of current rates to adequately recover the COS, revenues were estimated based
on TY billing data and existing rates, then resulting revenues were compared to the COS for each
customer class. Table 5-9 shows the results of the comparison. Please note, as discussed previously,
the COS shown in the table for each customer class represents the Base Rate TY Revenue
Requirements and Base Rate TY Revenues, which do not include the pass throughs. Base rates are
used for each customer class in preparation for Rate Design in the following section.
The first column shows the allocated Base Rate COS for each customer class, and the second column
provides the related Base Rate TY revenues under existing rates. The third column summarizes the
amount that revenues from existing rates are either over or under the allocated COS levels. The last
column shows the percentage change that revenues from existing rates would need to be reduced or
increased for rates to align with COS levels for each customer class.
TABLE 5-9: COMPARISON OF REVENUES AND REVENUE REQUIREMENTS
Residential $51,700 $15,151 $(36,500) 241.2%
GS-1 $15,769,012 $14,196,026 $(1,572,986) 11.1%
GS-2
$22,014,833
$21,477,375
$(537,459)
2.5%
TOU-G
$17,686,458
$16,620,383
$(1,066,075)
6.4%
TOU-V
$111,350,979
$104,799,000
$(6,551,980)
6.3%
TOU-PA
$467,448
$535,608
$68,160
-12.7%
PA-1
$207,625
$272,718
$65,093
-23.9%
Others (LS,OL,TC)
$436,329
$756,501
$320,173
-42.3%
Total
$167,984,385
$158,672,763
$(9,311,623)
-5.9%
Please note the above COS includes adjustments to account for the voltage discounts to larger customers.
The COS results show rate increases are necessary for all of the major customer classes; however, the
smaller TOU-PA, PA-1 and others (lighting) show the need for a decrease in current rates. The
percentage increase or decrease shown in the table above provides guidance for rate design.
5.4 Rate Design
Rate design is the culmination of a COS study as the rates and charges for each customer class are
designed to equitably and fully recover the customer class and system wide cost of service. The COS
for each customer class represents the total costs for the customer class that should be recovered
through rates
The proposed rates are applied to the appropriate monthly billing determinants (e.g., number of
customer months, kilowatt-hour [kWh] consumption) to project the new rate revenues by customer
class. These projected revenues from the proposed rates are compared to the Base Rate TY Revenue
Requirements to ensure the rates generate sufficient revenue to recover the COS. This process is
known as the "revenue adequacy" test.
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As shown previously, it was determined that the fixed and variable cost recovery of the different
�... components (e.g., monthly base, energy and/or demand charges) of the current rates were not in
alignment with the COS results. In addition, the recommended rates were developed by applying
aspects of the Rate Strategy including: gradualism, economic development, and equity and fairness in
the rate structures. Finally, the proposed rates include a phase -in of the rate changes over three years.
Furthermore, Vernon leadership recommended slightly higher rate increases than the COS originally
identified. While the Vernon recommendations result in slightly higher rates than the COS, this will
effectively allow Vernon to reduce its almost complete reliance on debt financings to fund capital
projects. This also supports a more balanced approach of using both cash from revenues and debt
issuances to finance capital projects. This more balanced approach will enhance the Utility's financial
integrity, and support financial stability and higher credit ratings which reduce operating costs. 5
summarizes the phase -in of the rate changes on a class average basis and compares the result to the
COS.
TABLE 5.10: VERNON BASE RATE PHASE IN AND COS
Residential 3.6% 2.9% 2.5% 9.3% 241%
GS-1 6.4% 5.5% 4.5% 17.5% 10.8%
GS-2 1.5% 1.3% 1.1 % 4.0% 2.5%
TOU-G 3.7% 3.3% 2.7% 10.1% 6.4%
TOM 3.6% 2.8% 2.5% 9.1% 6.1%
TOU-PA 0.0% 0.1 % 0.1 % 0.2% -14.3%
PA-1 0.0% 0.0% 0.0% 0.0% -23.9%
TC-1 0.0% 0.0% 0.0% 0.0% -23.5%
Lighting (LS,OL) 0.0% 0.0% 0.0% 0.0% -43.4%
Total 3.5% 3.0% 2.5% 9.2% 5.9%
Please note the above COS includes adjustments to account for the voltage discounts to larger customers.
The proposed rates were designed to bring each customer class closer to its true cost of service while
evaluating the impact of rate changes on customers' monthly bills. As a result, proposed rates,
although moving closer to the cost of service, do not precisely match the cost of service results. At the
time of this report, the rates had not yet been approved or adopted, but the proposed rates are
estimated to fully recover Vernon's costs and generate the results shown in Table 5-11.
TABLE 5.11: VERNON BASE RATE PHASE IN AND COS
Residential $15,150 $15,692 $16,152 $16,558 $1,408
GS-1 $14,360,088 $15,285,613 $16,131,170 $16,874,200 $2,514,111
GS-2 $21,477,369 $21,802,159 $22,091,375 $22,332,957 $855,588
TOU-G $16,619,679 $17,239,993 $17,816,931 $18,306,199 $1,686,520
TOU-V $104,560,329 $108,280,711 $111,291,313 $114,037,189 $9,476,860
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TABLE 5.11: VERNON BASE RATE PHASE IN AND COS
TOU-PA $535,742 $535,986 $536,347 $536,666 $924
PA-1 $272,718 $272,718 $272,718 $272,718 $0
TC-1 $42,038 $42,038 $42,038 $42,038 $0
Lighting (LS,OL) $714,464 $714,464 $714,464 $714,464 $0
Total $158,597,5780) $164,189,357 $168,912,474 $173,132,956 $14,606,784
Change 3.5% 2.9% 2.5% 9.2%
Please note the above COS includes adjustments to account for the voltage discounts to larger customers
M Current revenues do not match TY Revenues exactly as the billing database and billing determinants were used to project current revenues. The TY Revenues
reflected audited revenues while there is always some minor (e.g. <0.5%) difference between the TY Revenue projections from audits and revenue reports and
recreating the billing database as shown in this table.
Residential D
The Domestic Service D (Residential) class is available to all single-family residential customers.
According to the COS analysis, the Residential class significantly under recovers its COS.
Individually, both the fixed customer charge and the energy charge are currently under -recovering
their COS. With the Residential class being such a small portion of total COS, only small changes to
the rate components were proposed. Table 5-12 summarizes and compares the current and proposed
rates for the Residential class.
TABLE 5-12: CURRENT AND PROPOSED BASE RATES: RESIDENTIAL
Customer Charge $/Month $2.95 $28.59 $3.05 $3.14 $3.22
Energy Charges $/kWh $0.0856 $0.2512 $0.0887 $0.0913 $0.0936
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Figure 5-7 compares the unit costs ($/kWh) for the current rates, three phases of rate adjustments and
�..- the COS for a series of monthly energy usage amounts within the Residential customer class.
Residential Rate Curve - Actual vs. Cost of Service Results
50.33
50.28
Y
50.23
Effective Rate (COS)
50.18 Effective Rate (Actual)
Effective Rate (Phase 1)
d — — Effective Rate (Phase 2)
w 50.13 — —Effective Rate (Phase 3)
50.08
10"/0 2006 30% 40'/ 501/ 60% 70'D 80% 90'/0 100 0
Load Factor
Figure 5-7: Unit Costs for D Current, Proposed and COS Rates
General Service —1
The General Service-1 (GS-1) includes all customers receiving single and three phase service that do
not otherwise require service under an alternate rate tariff. According to the COS analysis, the GS-1
class currently under recovers its COS. The fixed customer charge is currently under recovering its
COS, while the energy charge is over -recovering its COS. The GS-1 customer class will experience
an average class increase of 17.5% over the three phases. Phase 1 will lead to an average increase
6.4%, Phase 2: 5.5% average increase and Phase 3: 4.6% increase. Table 5-13 summarizes and
compares the current and proposed rates for the GS-1 class.
TABLE 5-13: CURRENT AND PROPOSED BASE RATES: GS-1
Customer Charge $/Month $25.33 $282.65 $50.00 $100.00 $150.00
Energy Charges
Summer' $/kWh $0.2088 $0.1775 $0.2155 $0.2186 $0.2208
Winter' $/kWh $0.1942 $0.1775 $0.2054 $0.2085 $0.2095
Notes:
1..Summer months include May through October. Winter months include all other months.
Significant changes were proposed to the current customer charges to more properly recover fixed
costs. As the table above shows, the customer charges increase significantly while the energy charges
increase only slightly over each phase as compared to current rates. This further aligns the GS-1 rates
to the COS and begins to gradually address the higher fixed COS elements.
Figure 5-8 compares the unit costs ($/kWh) for the current rates, three phases of rate adjustments and
the COS for a series of monthly energy usage amounts within the GS-1 customer class.
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GS-1 Rate Curve - Actual vs. Cost of Service Results
$0.48
—Effective Rate (Actual)
$0.43 — Effective Rate (COS)
$0.3$ — Effective Rate (Phase 1)
— Effective Rate (Phase 2)
_ $0.33
Effective Rate (Phan 3)
3 $0.28
A $0.23 �-- —_= v—
----
—-
- — — —
$0.18
m
uJ $0.13
$0.08
10% 20% 30% 40% 50% 60% 70% 80% 90% 100%
Load Factor
Figure 5-8: Unit Costs for GS-1 Current, Proposed and COS Rates
General Service — 2
0
The General Service-2 (GS-2) is available to all customers receiving single and three phase service
with demands that do not exceed 500 kW for any three months during the preceding 12 months and
for whom time of use recording meters have not been installed. According to the COS analysis, the
GS-2 class currently under recovers its COS. The demand charge is currently under recovering its
COS, the energy charge is over -recovering its COS, and there are additional fixed charges which are
currently not being recovered. The GS-2 customer class will experience an average class increase of
4.0% over the three phases. Phase 1 will lead to an average increase 1.5%, Phase 2: 1.3% average
increase and Phase 3: 1.1% increases. Table 5-14 summarizes and compares the current and proposed
rates for the GS-2 class.
TABLE 5.13: CURRENT AND PROPOSED BASE RATES: GS•2
Customer Charge
$/Month
NA
$285.91
$100.00
$150.00
$200.00
Demand Charges
Facilities
$/kW
NA
$8.62
$8.65
$8.65
$8.65
Power Supply
$/kW
$19.054
$29.01
$14.00
$16.00
$18.00
Energy Charges
$/kWh
$0.1205
$0.0555
$0.1080
$0.1022
$0.0960
Significant changes were proposed to the current rate structure to more properly recovery costs,
convey costs to customers, and improve fixed / variable cost recovery misalignment. As the table
above shows, the proposed rates include a new facilities demand charge to recover Vernon related
transmission and distribution fixed costs. The Power Supply demand charge recovers the power
supply related fixed costs. In total, the demand charges are increasing while the energy charges are
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decreasing over each phase as compared to current rates. This further aligns the TOU-G rates to the
COS and begins to gradually address the fixed / variable revenue and cost misalignment. Figure 5-9
compares the unit costs ($/kWh) for the current rates, three phases of rate adjustments and the COS
for a series of monthly energy usage amounts within the GS-2 customer class.
$0.53
$0.48
$0.43 �I
3 $0.38
$0.33
d
$0.28
d
$0.23
v
W $0.18
$0.13
$0.08 ■
10% 20% 30% 40% 50% 60% 70% 80% 90% 100%
GS-2 Rate Curve - Actual vs. Cost of Service Results
1,200
Eff-10 . Rat. (At-1)
ER.Riv. fait. (cos) 1,000 r+
�CC
- - ER.ctiv. We (Phaa. 1) O
ErfWtly. Rat. (Phisa 2) Soo �
Eff-ti- Rats (Ph.- 31 W
600 V
a
's
400 d
a
E
CM 200 Z
14 0
Load Factor
Figure 5-9: Unit Costs for GS-2 Current, Proposed and COS Rates
General Service - Large (TOU-G)
The General Service - Large (TOU-G) class includes customers with demand exceeding 100 kW for
three months of the past 12 months but less than 500 kW for the remaining nine months. Service is
elective for customers with TOU metering. According to the COS analysis, the demand charge is
currently under -recovering its COS, while the energy charge is over -recovering its COS. The TOU-G
customer class will experience an average class increase of 10.1% over the three phases. Phase 1 will
lead to an average increase of 3.7%; Phase 2 will lead to a 3.3% average increase and Phase 3 a 2.7%
increase. Table 5-15 summarizes and compares the current and proposed rates for the TOU-G class.
TABLE 5.15: CURRENT AND PROPOSED BASE RATES: TOU-G
Customer Charge'
$/Month
$315.48
$285.91
$290.00
$290.00
$290.00
Demand Charges
Facilities
$/kW
NA
$9.64
$9.60
$9.60
$9.60
Power Supply - Summer 112
On / Mid Pk3
$/kW
$20.18 /
$3.13
$29.55 (all)
$12.50 /
$5.50
$15.00 /
$7.50
$17.50 /
$10.00
Power Supply - Other2
On / Mid Pk3
$/kW
$17.08 I
$29.55 (all)
$8.50 /
$10.00 /
$12.501
$3.13
$5.50
$7.50
$10.00
Energy Charges
Summer 112
On I
$/kWh
$0.1261 /
$0.0555 (all)
$0.1187 /
$0.1136 I
$0.1037 /
Mid /
$0.11975 /
$0.1079 /
$0.1033 /
$0.0943 /
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TABLE 5.15: CURRENT AND PROPOSED BASE RATES: TOU-G
Off Pk3
$0.09822
$0.0971
$0.0929
$0.0848
Other2
On I
$0.1011 /
$0.0971 /
$0.0929 /
$0.0848/
Mid /
$/kWh $0.09480 / $0.0555 (all)
$0.0882 /
$0.0844 /
$0.0771 /
Off Pk3
$0.08528
$0.0794
$0.0760
$0.0694
Notes:
1. Customer Charge includes customer charge and AMR meter charge of $12.76/month.
2. Summer II period is July, August and September. Other or Non Summer II is all other months.
3.On peak periods are 1 pm to 7pm M- F, Mid Peak is 9am to 1 pm and 7pm to 11 pm weekdays, and Off peak is all other hours, including holidays
Significant changes were proposed to the current rate structure to more properly recover costs, convey
costs to customers and improve fixed / variable cost recovery misalignment. As the table above
shows, the proposed rates include a new facilities demand charge to recover Vernon related
transmission and distribution fixed costs. The Power Supply demand charge recovers the power
supply related fixed costs. In total, the demand charges are increasing while the energy charges are
decreasing over each phase as compared to current rates. This further aligns the TOU-G rates to the
COS and begins to gradually address the fixed / variable revenue and cost misalignment.
The difference or ratio between the On and Mid -Peak demand charges were also decreased gradually
over the phases to further align with costs. There are no current cost drivers for Vernon that require a
demand charge differential between On and Mid -Peak periods. Similar ratios for On / Mid / Off -Peak
energy rates were maintained as a policy to support off-peak energy consumption.
Figure 5-10 compares the unit costs ($/kWh) for the current rates, three phases of rate adjustments
and the COS for a series of monthly energy usage amounts within the TOU-G customer class.
TOU-G Rate Curve - Actual vs. Cost of Service Results
$0.68
350
Effective Rate (COS)
Effective Rate ;Actual!
300
$0.58
Effective Rate (Phase 1)
s
Effective Rate iPhase 2)
0
250 c
_
`i
$0.48
,
Effective Rate (Phase 3)
�
v
\ `
v
200 E
a
$0.38
��
O
N
150 v
0
50.28
v
w
100
®
E
50.18
Z
50
•
'
$0.08
—
0
109/8 20%
30% 40% 50% 60% 7C% 801/0 90% 100%
Load Factor
Figure 5-10: Unit Costs for TOU-G Current, Proposed and COS Rates
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Figure 5-11 breaks down these same unit costs for the current rates, three phases of rate adjustments,
`.- and the COS by season. The figure shows a larger rate change for winter/other seasons than the
Summer II season.
IN
TOU-G Rate Curve - Winter
$0.68
350
Summer I - Actual
$0.58
\
Effective Rate (COS)
300 N
s
Winter- Phase 1
c
\
250 0
$0.48
\
Winter - Phase 2
Winter - Phase 3
200 E
$0.38
\\
v
\\
150 U
o
Y
$0.28
y
100
e
'"'
E
w
$0.18
z
50
•
$0.08
—
0
10%
20%
30% 40% 50% 60% 70%
80% 90% 100%
Load Factor
TOU-G Rate Curve - Summer II
$0.68
350
Summer 11 - Actual
Effective Rate (COS)
300
$0.58
N
`
Summer 11 - Phase 1L
c
Summer 11 -Phase 2
250 O
s
$0.48
\�
Summer 11 -Phase 3
11
\�
\
200 E
$0.38
\�
0
Ln
v
a
\
150 U
O
$0.28
\
100
v
w
�
$0.18
z
50
$0.08
—
0
10% 20%
30%
40% 500/o 60% 7M.
80% 90% 100%
Load Factor
Figure 5-11: Unit Costs for TOU-G Current, Proposed and COS Rates by Season
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General Service - Large (TOU-V)
The General Service Large (TOU-V) class includes customers with demand exceeding 500 kW for
any three months of the past 12 months. Service is elective for customers with TOU metering.
According to the COS analysis, the TOU-V class currently under -recovers its COS. The demand
charge is currently under recovering its COS, the energy charge is over -recovering its COS, fixed
customer charges are being slightly over recovered, and there are fixed demand charges which are
currently not recovered. The TOU-V customer class will experience an average class increase of
9.1 % over the three phases. Phase 1 will lead to an average increase 3.6%, Phase 2 will lead to a 2.8%
average increase and Phase 3 a 2.5% increase. Table 5-16 summarizes and compares the current and
proposed rates for the TOU-V class.
TABLE 5.16: CURRENT AND PROPOSED BASE RATES: TOU-V
Customer Charge'
Demand Charges
$/Month
$315.48
$285.91
$290.00
$290.00
$290.00
Facilities
$/kW
NA
$9.96
$10.00
$10.00
$10.00
Power Supply - Summer 12
On / Mid Pk3
$/kW
$15.99 /
$3.03
$26.08 (all)
$8.00 / $5.50
$9.50 /
$7.50
$12.00 /
$10.00
Power Supply - Summer 112
On I Mid Pk3
$/kW
$19.54 /
$3.03
$26.08 (all)
$12.50 / $5.50
$15.50 /
$7.50
$18.00 /
$10.00
Power Supply - Winter2
On / Mid Pk3
$/kW
$12.67 /
$3.03
$26.08 (all)
$8.00 / $5.50
$9.50 /
$7.50
$12.00 /
$10.00
Energy Charges
Summer 112
On /
$0.1207 /
$0.1057 /
$0.1001 /
$0.0912 /
Mid /
$/kWh $0.1146 / $0.0555 (all)
$0.0961 /
$0.0910 /
$0.0829 /
Off Pk3
$0.0933
$0.0865
$0.0819
$0.0746
Other2
On /
$0.0961 /
$0.0858 /
$0.0813 /
$0.0740/
Mid I
$/kWh $0.0899 / $0.0555 (all)
$0.0780 /
$0.0739 /
$0.0673 /
Off Pk3
$0.0807
$0.0702
$0.0665
$0.0606
Notes:
1. Customer Charge includes customer charge and AMR meter charge of $12.76/month.
2. Summer II period is July, August and September. Other or Non Summer II is all other months.
3.On peak periods are 1 pm to 7pm M- F, Mid Peak is gam to 1 pm and 7pm to 11 pm weekdays, and Off peak is all other hours, including holidays
Significant changes were proposed to the current rate structure to more properly recover costs, convey
costs to customers and improve fixed / variable cost recovery misalignment. As the table above
shows, the proposed rates include a new facilities demand charge to recover Vernon related
transmission and distribution fixed costs. The Power Supply demand charge recovers the power
supply related fixed costs. In total, the demand charges are increasing while the energy charges are
decreasing over each phase as compared to current rates. This further aligns the TOU-V rates to the
COS and begins to gradually address the fixed / variable revenue and cost misalignment.
The difference or ratio between the On and Mid -Peak demand charges were also decreased gradually
over the phases to further align with costs. There are no current cost drivers for Vernon that require a
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demand charge differential between On and Mid -Peak periods. Similar ratios for On / Mid / Off -Peak
`.. energy rates were maintained as a policy to support off-peak energy consumption.
Figure 5-12 compares the unit costs ($/kWh) for the current rates, three phases of rate adjustments
and the COS for a series of monthly energy usage amounts within the TOUN customer class.
$0.68
$0.58
3 $0.48
$0.38
$0.18
TOUN Rate Curve - Actual vs. Cost of Service Results
u Customers
Effective Rate (COS)
$0.08
10% 20% 30% 40% 50% 60% 700/ 80% 90% 100%
Load Factor
Figure 5-12: Unit Costs for TOU-V Current, Proposed and COS Rates
350
300
r
250 0
200 E
0
150 u
0
100 2
E
z
50
0
Figure 5-13 breaks down these same unit costs for the current rates, three phases of rate adjustments,
and the COS by season. The figure shows a larger rate change for Summer II than the other two
seasons.
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TOUN Rate Curve - Other
$0.18
350
$0.17
` i
� � ♦
300
$0.16
,
$0.15
i \ ♦
# Customers \ 1
250 0
Y
$0.14
� ♦
—0—Effective Rate (COS) \� \
200 v
v $0.13
+Effective Rate (Current)
°
M
Cc
(1) $0.12
—9— Summer I (Phase 1)
150 u
o
`
—�— Summer I (Phase 2)
y
v$0.11
`
100
�9— Summer I (Phase 3)
$0.10
z
$0.09
I
' 50
$0.08
—
0
10% 20% 30% 40% 50% 609/o 70% 80% 90%
100%
Load Factor
TOUN Rate Curve - Summer II
$0.20
�- `
350
♦
$0.18
♦ ♦�
300
$0.16
# Customers
♦
250 c
a y
— >—Effective Rate (COS
w
200
$0.14
—Effective Rate (Current)
°
�
>
—M Summer II (Phase 1)
150 w
—
o
v $0.12
—N Summer II (Phase 2)
`y
w
100 E
—N Summer II (Phase 3)
z
$0.10
I
'
50
$0.08
— —
0
10% 20% 30%
40% 50% 60% 70%
809/o 90% 100%
Load Factor
Figure 5-13: Unit Costs for TOU-V Current, Proposed and COS Rates by Season
General Service — Large (TOU-PA)
The Power -Agricultural and Pumping (TOU-PA) class includes customers that require power for
general agricultural purposes for general water or sewerage pumping and with demand exceeding
100 M for three months of the past 12 months but less than 500 M for the remaining nine months.
Service is elective for customers with TOU metering. According to the COS analysis, the TOU-PA
class currently over -recovers its COS. The demand charge is currently over -recovering its COS, the
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energy charge is over -recovering its COS, the fixed customer charges are being slightly over -
recovered, and there are fixed demand charges which are not currently recovered. The TOU-PA
customer class will experience an average class increase of 0.2% over the three phases. Phase 1 will
lead to an average increase 0.0%, Phase 2 will lead to a 0.1 % average increase and Phase 3 a 0.1 %
increase. Table 5-17 summarizes and compares the current and proposed rates for the TOU-PA class.
TABLE 5.17: CURRENT AND PROPOSED BASE RATES: TOU•PA
Customer Charge'
$/Month
$315.48
$285.91
$290.00
$290.00
$290.00
Demand Charges
Facilities
$/kW
NA
$6.80
$7.00
$7.00
$7.00
Power Supply
On / Mid Pk2
$/kW
$20.18 /
$3.13
$19.90 (all)
$13.00 /
$5.50
$13.50 /
$6.50
$14.00 /
$7.00
Energy Charges
On /
Mid /
Off Pk2
$/kWh
$0.1016 /
$0.0952 /
$0.0857
$0.0555 (all)
$0.0957 I
$0.0870 /
$0.0783
$0.0913 /
$0.0830 I
$0.0747
$0.0884 I
$0.0804 /
$0.0724
Notes:
1. Customer Charge includes customer charge and AMR meter charge of $12.76/month.
2.On peak periods are ipm to 7pm M- F, Mid Peak is 9am to 1 pm and 7pm to 11 pm weekdays, and Off peak is all other hours, including holidays
Significant changes were proposed to the current rate structure to more properly recover costs, convey
costs to customers and improve fixed / variable cost recovery misalignment. As the table above
shows, the proposed rates include a new facilities demand charge to recover Vernon related
transmission and distribution fixed costs. The Power Supply demand charge recovers the power
supply related fixed costs. In total, the Power Supply demand charges are increasing while the energy
charges are decreasing over each phase as compared to current rates. This further aligns the TOU-PA
rates to the COS and begins to gradually address the fixed / variable revenue and cost misalignment.
The difference or ratio between the On and Mid -Peak demand charges were also decreased gradually
over the phases to further align with costs. There are no current cost drivers for Vernon that require a
demand charge differential between On and Mid -Peak periods. Similar ratios for On / Mid / Off -Peak
energy rates were maintained as a policy to support off-peak energy consumption.
Figure 5-14 compares the unit costs ($/kWh) for the current rates, three phases of rate adjustments
and the COS for a series of monthly energy usage amounts within the TOU-PA customer class.
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TOU-PA Rate Curve - Actual vs. Cost of Service Results
$0.47 18
$0.42
$0.37
L
$0.32
$0.27
$0.22
a
w $0.17
$0.12
$0.07
10% 20% 30% 40% 50% 60% 70% 80% 90% 100%
Load Factor
Figure 5-14: Unit Costs for TOU-PA Current, Proposed and COS Rates
16
L
14 c
12
v
10 E
8 '
U
6 °
v
n
4 E
z
6
9
In addition to the above rate classes, the lighting (e.g., OL, LS and TC) classes and the Power
Agriculture class (PA) were evaluated for rate changes. In line with the broader rate strategy, these
customer class rates will not change, thus remain at the current Vernon base rates. In total, these four
rate classes represent approximately 0.5 percent of the total Vernon rate revenues. In addition, the
lighting rates are structured as a fixed monthly rate due to their standard "dusk until dawn' operating
periods. This fixed nature of the rates also supports the fixed cost recovery of costs for these rate
classes.
5.4.1 Rate Design Revenue Adequacy Conclusions
Overall, the proposed rates summarized above begin aligning the Base Rates with the COS results.
This addresses the fixed and variable costs misalignment with fixed and variable revenues. Figure 5-
15 illustrates the change in fixed revenue recovery over the three phases. While it does not fully
achieve the COS results, it has significantly addressed the misalignment in most of the customer
classes and will reduced the operating losses and risks associated with significant DG adoption by
customers.
Current
61r,
Phase 1
Phase 2
Phase 3
to
COS
. Fixed . Variable . Fixed . Variable • Fixed • Variable . Fixed . Variable • Fixed • Variable
Figure 5-15: Progression of Fixed Cost Recovery from Current Rates to Phase 3
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As an example of the improvement in fixed cost recovery, in the TOU-V customer class, the fixed
�.. revenue recovery is significantly higher than the current rates and aligns with the COS. The current
TOU-V current rate revenue is 28% fixed charge related. The Phase 3 revenue recovery is 50% fixed
charge related, while the COS results are 58% fixed charge related.
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6.0 INTEGRATED IMPACTS
DG impacts on each of four distinct but interconnected areas were analyzed independently and
concurrently as much as practical. Initial evaluations revealed DG impacts all four areas, but potential
financial impacts likely outweigh the other areas. Further analysis demonstrated the financial impacts
to customers and the related net metering state legislation and policies will act as a limiting factor for
the amount and optimal level of DGs permitted.
Compliance with the current Net Metering Law and AB 327 requires Vernon to permit up to 5% of
customer peak loads (i.e., the sum of non -coincident peak load of each class of customers) for
renewable distributed generation. Using the 2014 Vernon electric system data, the 5% limitation is
9,924 kW and will vary each subsequent year based on the customer class demands. At full
subscription, the 5% requirement is estimated to result in annual operating losses ranging from
$3,125,852 to $6,474,580 dependent upon the mix of Solar PV and conventional fossil DG, if
allowed. These operating losses equate to a rate increase from 1.4% to 3% for non-DG customers to
ensure Vernon remains financial stable recovering all costs.
Currently 2,000 kW of Solar PV is the pipe line which results in an estimated operating loss of
$484,000 per year. This level of operating losses equates to a rate increase of 0.3% for other non-DG
customers to fully recover the costs to operate the Vernon system. Please refer to Financial Impacts at
the end of this chapter for more details.
As stated in the Environmental Impacts and Initial Study, solar PV's environmental and safety
impacts are less than significant and can be exempted from the CUP process. For any DG involving
the rotating machines such as microturbines or other fossil fueled generators it is more appropriate to
stay with the current CUP process. Rotating machines have significantly more contribution to the
short-circuit capacity of the distribution system and have a potential to impact fault detection by the
substation relays. Fuel cells have no moving parts, but it is an evolving technology that is not fully
matured it yet and is non -typical type of installation. It is prudent to continue with the CUP process
for all DG that is non -solar PV generation and solar PV generation larger than I MW.
Other areas of the analysis also have impacts, but can be managed with careful planning, monitoring
and controls. Please see the below the summary of impacts of each area.
6.1 Physical Distribution System Impacts
The results of the five analyses of various scenarios for rotating and non-rotation/inverter DGs
performed on the sampling of the Vernon distribution system provide generalized conclusions
applicable to the entire system. The reverse power scenario does not limit Vernon's ability to utilize
DG. Reverse power study DG limits resulted in pushing a small current upstream through existing
protective devices. To further examine the effects of reverse power study, Vernon's existing
protective relay settings were analyzed. Adding DG has no significant effect on existing directional
overcurrent elements, such as the negative sequence elements. Placing enough DG along a feeder to
result in reverse power flow can cause non -directional overcurrent relays to pick up, but Vernon's
existing protective relay settings are not sensitive enough to detect such currents even with the
additional of enough DG to overload conductors under minimum load conditions and thus, Vernon's
existing relay settings will not limit DG penetration.
Tables 2-5 and 2-6 include overload limits reflecting the maximum DG levels that could be supported
without exceeding conductor ampacity under minimum loading conditions. Vernon's existing
distribution line structures are typically difficult to modify due to location and the number of circuits
they support; they are heavily loaded mechanically; and the conductors close to their electrical
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ampacity ratings. Consequently replacing existing conductors with larger conductors to increase
�. ampacity would be difficult and costly and in general is an impractical option.
L
The calculated DG voltage limits are shown in Tables 2-5 and 2-6 based on DG causing no more than
a 5% voltage rise at minimum loading levels with nominal (7 kV or 16 kV) voltages at the substation
bus. This is in conformance with IEEE 1547 which requires equipment to operate within a 5% voltage
range and ANSI C84.1-2011 for Electric Power Systems and Equipment- Voltage Rating (60 Hertz).
If DG is placed along a feeder that presently experiences significant voltage fluctuation, additional
equipment may be needed. Capacitor banks, load tap changing transformers and substation voltage
regulators can be used to regulate and stabilize voltage.
The results of the short circuit study shown in Table 2-7 indicates that the breakers at the Leonis 7 kV
Substation already need to be upgraded to a higher interrupting rating and that no generation can be
applied to the feeders out of this station until upgrades are made. Replacing circuit breakers at Leonis
7 kV Substation would allow the feeder to support additional DG.
The addition of a 20 MW carpet waste burning plant connected to Leonis-Owill 66 kV line is a
feasible addition on the sub -transmission system. Power generally flows from Owill to Leonis
Substation and this addition of DG will increase the power flowing towards Leonis Substation which
is well below the capacity of the overhead conductor and but slightly above the conservative
operating limit of 50 MW set by Vernon. More analysis is required after the exact capacity, location
and other technical details of this DG are known.
6.2 Environmental Impacts and Initial Study
It started with reviewing the current City of Vernon Comprehensive Zoning Ordinance §26.4.1-3(b)
and General Plan (Section 2.2) specifically requires a CUP for generating facilities, power plants and
cogeneration facilities. The Vernon is considering streamlining the process of allowing DG facilities
in the Vernon provided that this streamlining does not result in adverse environmental impacts.
The objective of this environmental analysis was to identify the types of facilities with the least
potential impacts that could reasonably be allowed without a CUP. The environmental analysis for
this study began with a preliminary screening of the potential DG options being contemplated and a
high-level assessment of the potential environmental impacts that might be associated with each type
of generation facility. Based on information provided by the Vernon and proposed DG in other
locations, the types of power generation facilities that are or could be contemplated for DG are:
• Wind
• Biomass
• Carpet -waste burning power facility (15 — 20 MW)
• Fuel cells
• Fossil -fueled (diesel and natural gas, including microturbines)
• Solar PV
Initial Environmental Screening of each of the technologies listed above were subject to preliminary
screening related to potential environmental impacts and the reasonableness of allowing the use of the
technology with site -specific permit conditions. The environmental factors from the CEQA IS
Checklist (CEQA Guidelines Appendix G) were used for this preliminary screening.
An environmental review was conducted to evaluate potential impacts associated with exempting
distributed power generating facilities from the Vernon's CUP requirement. The preliminary
screening evaluated environmental factors with a particular focus on air quality/greenhouse gas,
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noise, vibration, public services, hazardous materials, water quality and utility services. The analysis
N-. included a review of the consequences of permitting numerous generating facilities within the
Vernon. As shown in Table 3-1, the screening analysis indicated that the potential for solar PV
systems to result in environmental impacts appears low, and that this technology could be considered
as a candidate for exemption from the power generating facility CUP requirement. A formal CEQA
IS was prepared to confirm this screening analysis and describe the potential environmental impacts
that could result from changing the Zoning ordinance to allow this exemption (Appendix B). The
results of the IS indicate that exempting I MW solar PV project from the CUP requirements would
not result in significant impacts and no mitigation would be necessary. Consequently, a Negative
Declaration would be the appropriate document to comply with CEQA for this exemption.
M
Table 3-1 summarized the description of each type of generation and its impacts on noise, vibration,
air/odor/ greenhouse gas, hazardous materials, utilities and public services of each type of generations
with comments. Based on the information available wind generation has very limited potential in
Vernon. Based on the discussion with Vernon staff it appears most of the customers' interest is
focused on solar PV installations. Three solar PV plants rated at 400 kW, 500 kW and 950 kW are
already in the pipe line. There are also inquiries on fossil fueled DG (diesel and natural gas fired,
including microturbines). A potential 15 to 20 MW carpet waste burning plant has also been
proposed. The interest of the customers in biomass and fuel cells is unknown at this time.
6.3 Safety Assessment — Hazard Analysis
POWER has divided the Safety Assessment in to two subareas of electrical safety hazards and
hazardous materials.
6.4 Electrical Hazard Summary
This work builds upon data collected and developed in the Physical Distribution System Impact Study
and concludes that DG poses potential electrical safety hazards due to back feed into the distribution
for line workers and the general public, but that these potential safety hazards are manageable with
reasonable effort. Three areas of concern identified for the medium voltage distribution system is
addressed: islanding, grounding, and protective relaying. Approaches to monitoring DG are discussed
as well as suggestions for interconnection agreement provisions.
Islanding would occur when the feeder circuit breaker was open and the loads on the feeder were
served by DG only. Islanding would present a hazard to the public and Vernon's personnel. By
requiring that all DG be certified to meet IEEE 1547 and UL 1741 or otherwise provide equivalent
performance through a Vernon approved means Vernon can be assured that DG will automatically
de -energize within two seconds after the feeder circuit breaker opens thus eliminating islanding.
Grounding must be considered because for a short period of time, two seconds or less after the feeder
circuit breaker opens, voltage can be supplied to the distribution circuit from DG. For this short
period there is no ground reference as the connection to the substation is lost when the feeder circuit
breaker opened. In this condition higher than normal voltages on one or two of the phases can occur
with potential for equipment damage. Because of Vernon's three wire distribution system
configuration and phase to phase transformer connections, 220 mil (133%) cable insulation, and lack
of surge arrestors this condition does not appear to require mitigation.
Protection to de -energize and isolate short circuits (faults) on distribution circuits is traditionally
based upon a single source of power at the substation with loads along the distribution feeder. The
addition of DG results in additional sources of power and short circuit current along the distribution
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feeder and may cause degradation in the ability to detect faults and for the proper device to operate to
�.- de -energize and isolate the fault. Vernon's compact distribution system which does not require
protective devices or fuses in the main lines and their modern feeder protective relays applied using
negative sequence currents to detect ground faults mitigates both of these potential issues.
6.5 Hazardous Materials Analysis
Appendix G, Environmental Checklist Form of the CEQA Statues and Guidelines criteria was used to
determine the Short -Term and Long -Term hazardous materials impacts.
6.5.1 Short -Term Construction Impacts
Structural Modifications/Demolitions — Solar PV has no impact, other DG has potential of exposure
to asbestos containing materials (ACMs) and lead -based paints (LBPs).
Grading/ Excavation Activities — Solar PV will not require any grading or excavation of the soil and
no exposure to contaminated soil. Other DG may involve grading or excavation and exposure to
contamination soil. But that activity is no different than routine site improvement and construction
projects executed with the building permits without CUP. A formal Phase 1 Environmental Site
Assessment (ESA) will be prudent for any development and additional mitigation measures (MM-1 to
MM-3) as deemed necessary descried under Section 5.2.1.2
Construction Equipment — Risk associated with this is minimum.
Long -Term Operational Impacts Involving the Release of Hazardous Materials — The long-term
operation of Solar PV Systems is not anticipated to require any use/ handling or storage of hazardous
materials or result in hazardous waste. Other DG facilities such as microturbines, fuel cells and
�..� combustion gas turbines could require use of gasoline/diesel fuel, which may be stored on -site via
underground or aboveground storage tanks. With implementation of federal, state, and local laws and
regulations the impacts of routine transport, use or disposal of hazardous materials would be less than
significant.
M
Biomass and carpet waste burning facilities could result in handling or transport of hazardous
materials or production of the hazardous waste as a result of the operation. These facilities currently
require a CUP and this requirement should be maintained.
Long -Term Operational Hazard Associated with Potential Explosions and/or Fires — Solar PV
Systems may have some impacts such as potential of fire hazard if not properly installed or collapsing
of roof due to overweight if not properly designed. In properly designed and installed PV facilities,
impact would be less than significant. Microturbines and Combustion Gas Turbines — will use
petroleum -related products and could be susceptible to explosion and fire hazard similar to other
industrial uses in the city. Compliance with California Fire Code, similar to other existing industrial
uses already present in the city, impacts would be reduced to less than significant. Fuel cells have a
potential fire hazard should the gas leak and ignite. Fuel Cells would be required to comply with
California Fire Code Chapter 53. There are several Cal/OSHA standards that pertain to fire and
explosion hazards and compliance with those reduce the impacts to less than significant. Biomass and
carpet waste burning facilities will result in unknown hazards associated with explosion/fire hazards
as a result of operation. These facilities currently require a CUP and should be maintained.
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6.5.2 Discussion on Current Cup Process
Based on the short-term and long-term impacts solar PV facilities has less than significant impacts
and any facility less than 1 MW should be safe to exempt from CUP. Biomass and carpet waste
burning has unknown release of hazardous materials and fire/explosion hazard and current CUP
process should be maintained. Microturbines and combustion gas turbines may have less than
significant impacts from hazardous materials and fire hazard perspective, but have rotating machines
which has short-circuit current contribution to the distribution grid and has a potential to impact the
detection of the fault by the substation relays depending upon the size and location of the DG. For
those reasons, CUP process should be maintained which will provide another opportunity to Vernon
to investigate specific impacts of the project and impose additional conditions if deemed necessary.
Fuel cells have no moving parts and are very clean technology. The technology has around for around
at least around two decades but is still evolving and not fully matured yet. There are different types of
fuel cells and using different fuels. Although environmental impacts are less than significant to
require a CUP, but it is safe to do due diligence, error on the side of caution, and maintain the current
CUP process. It will provide another opportunity to analyze the impacts of the specific project and
impose certain conditions such as obtaining a certification from CARB and maintaining an active
license with CARB to keep operation of the facility.
Keeping the CUP process for every other type of DG except solar PV will allow Vernon to do its due
diligence and add additional conditions if deemed necessary during the CUP to maintain public
safety.
6.6 Rate Payers Impacts
In addition to technical and operational DG impacts to Vernon's system, the POWER team evaluated
the results of increasing adoption of DG to the overall financial performance of the electric system.
The focus of the DG impacts on financial performance included potential reductions in utility
revenues, actual operating losses, and rate related impacts for customers. The conclusions and
recommendations from the financial impacts evaluation are summarized below.
Compliance with Assembly Bill (AB) 327 sets a limit of eligible DG on the system of 10 to
11 MW. AB 327 sets net metering requirements for public power utilities in California. AB
327 requires utilities allow eligible and defined renewable and distributed resources on the
electric system up to 5% of the aggregate customer peak demand. Compliance with the AG
327 requires Vernon to allow 10 to 11 MW (depending on the aggregate customer demand)
of eligible DG on the system. Specific compliance levels and more detailed calculations are
included with the Rate Payers Impacts section of this report.
• AB 327 identifies specific technologies covered by the legislation including solar PV, wind,
biomass and fuel cells. Non-renewable and conventional DG such as natural gas -fired
combustion engines or micro -turbines are not included with the legislation, thus utilities are
not required to apply AB 327 and the net metering rate constraints and requirements to such
applications.
• Adopting a clear Rate Strategy provides a framework and guide for current and future COS,
DG, and rate related decision making at Vernon. A Rate Strategy integrates and supports
adherence to key financial metrics and policies such as adequate reserve balances, debt
service coverage and rates alignment with COS results. Vernon's adoption of a Rate Strategy
will improve the financial integrity of the electric utility while minimizing disruption and
impacts to customers.
ANA 092-062 (SR 02) COV 135853 (05/08/2015) YU PAGE 74
POWER ENGINEERS, INC.
Distributed Generation Impact Study
• DG adoption will result in reduced revenues for Vernon. Under current rate structures, 2 MW
`... of eligible DG on the system results in an annual revenue reduction of $913,000, which
includes a $105,000 reduction in Vernon Transfers. If or when customer DG adoption reaches
the maximum allowable by AB 327 currently 5% (approximately 11 MW), revenue
reductions reach $6 million per year which includes $700,000 in Vernon Transfer reductions.
• While revenue reductions are significant at initial and full penetration levels of DG, the actual
operating losses incurred by Vernon are less due to avoidance of some costs for the utility.
Actual operating losses for 2 MW of DG on the system are $484,000 per year. At full
penetration of DG, the operating losses are $3.1 million per year. The $3.1 million of
operating losses equate to approximately 1.4% of the total annual Vernon revenues, or a 1.4%
increase in customers rates to allow up to 11 MW of DG on the system.
• AB 327 requires utilities to offer a net meter rate that is the same as the rates offered to
similar customers in the applicable customer class or customers without DG. The legislation
does not allow a utility to charge a different or adjusted net metering rate which could
improve the fixed cost recovery and operating losses associated with DG customers.
• The COS study identified misalignment in Vernon's fixed costs with fixed charge related
revenues. Currently Vernon's Revenue Requirement (all costs required to serve customers) is
62% fixed and 38% variable. However, Vernon's revenues are currently 26% fixed and 74%
variable. This misalignment is the driver of the operating losses associated with DG on the
system. Better aligning fixed charges (e.g., demand and customer) with the COS fixed costs
results will reduce losses and improve the financial integrity of the system.
• The COS study identified the need for a 5.9% increase in Vernon base rates to adequately
recover all costs for the next three years. These COS results assume the 100% debt financing
of capital projects for the next 10 years.
• Vernon selected a phased -in rate increase of 3.5%, 3.0% and 2.5% in 2016, 2017 and 2018
respectively. This results in an effective rate increase of 9.0% over the three year period. The
recommended rate increase will provide greater financial integrity to Vernon, significantly
improve reserve levels, while also improving capital flexibility with slightly reduced debt
requirements. This may also support improved credit ratings for future debt issuances which
will reduce Vernon costs.
• The recommended rates for each customer class begin increasing the fixed charges and
decreasing variable charges (e.g., energy) to align with the COS results over a phase -in period
of three years. This shift in charges from variable charges to fixed charges will reduce
Vernon's revenue reductions and operating losses associated with DG on the system.
ANA 092-062 (SR 02) COV 135853 (05/08/2015) YU PAGE 75
POWER ENGINEERS, INC.
Distributed Generation Impact Study
7.0 RECOMMENDATIONS
7.1 Overall Project Recommendations:
Adopt and comply with the current Net Metering Law and AB 327 requirements to define the
maximum amount and types of DG to allow on Vernon electric system. This regulatory
compliance approach sets a limitation of 5% of aggregate customer demand (i.e., sum of
customer class NCPs), or 9,924 MW based on the 2014 system and customer peak data.
Complying with AB 327 is limited to renewable DG technologies such as Solar, Wind, Fuel
Cells, and Biomass etc., up to 1 MW each. Non-renewable and conventional Fossil — Fuels
including natural gas -fired microturbines DGs are not included in 5% limit and should be
evaluated on a case -by -case basis. DG applications above 1 MW are currently exempt from AB
327 requirements, thus Vernon has increased flexibility and options in limiting or allowing
larger 1 MW+ applications. Evaluate the carpet waste burning plant based on complete
Environmental Impact Report (EIR) including the financial impacts on Vernon.
2. Permit Solar PV DG up to 1 MW without CUP process and continue CUP process for all other
DGs both renewable and non-renewable. Modify and update the language on the Diesel Engines
strictly used as a back-up and stand by generators to clarify that those are exempt from the CUP.
3. If any DG customer is going to be connected to Leonis 7 kV circuits, then the circuit breaker of
that circuit should be replaced with higher interrupting current before energizing it. To be on the
safe side all 7 kV circuit breakers at Leonis substation shall be replaced as soon as it is practical.
4. Adopt the recommended Rate Strategy with the framework for long-term financial integrity of
the Vernon including:
a. Improving the amount of cash reserves (e.g., day's cash on hand).
b. Gradually realign the rates over time with the COS as much as possible.
c. Adopt the restructured rates to recover additional fixed costs via the increased Demand
Charges and introduce a Facilities Charge (i.e., distribution demand) in addition to
current Power Supply Demand Charge.
The maximum DG penetration on the system under AB 327 (e.g., 5% of aggregate customer
demands) results in an estimated operating loss of $3,125,182. This equates to a rate increase of
1.4% for all customers to ensure the adequate recovery of all costs associated with delivering
services to customers. Initial operating losses will likely be near $484,384 associated with 2 MW
of DG on the system which equates to a 0.3% rate increase. No rate increase is recommended
due to DG impacts at this time.
7.2 Physical Distribution System Impacts
7.2.1 Recommended Limits for DG
Based on the various analyses performed, approximately 3 MW of DG can be added to each 7 kV
feeder, except those from the Leonis Substation, without significant system physical impacts.
Similarly, approximately 12 MW of DG can be added to each 16 kV feeder without significant
physical impacts.
ANA 092-062 (SR 02) COV 135853 (05/08/2015) YU PAGE 76
POWER ENGINEERS, INC.
Distributed Generation Impact Study
However, total DG per transformer bank must be limited to the values listed in Table 2-7. Generally
�... speaking the following transformer bank limits apply to each of these locations:
• Vernon 7 kV Substation Banks 1 and 2 — 20 MW of rotating DG or 35 MW of inverter DG
• Vernon 7 kV Substation Bank 3 — 10 MW of rotating DG or 45 MW of inverter DG
• Leonis 16 kV Substation Banks 4 and 5 —10 MW of rotating DG or 25 MW of inverter DG
• Ybarra 16 kV Substation Banks 1 and 2 — 50 MW of any DG
Based on the overall limits presented above, if the DG is placed properly, the Vernon distribution
system can physically support in excess of 140 MW of DG regardless of type and around 200 MW if
solely inverter based generation is added. A mixture of generation would require a limit between the
two values.
With a system peak load of around 180 MW, adding these levels of generation would likely exceed
Vernon's minimum load scenarios, creating a possibility for a net power flow out of Vernon's system
to SCE which may present further challenges. Based on the other analysis (environmental, safety, and
particularly cost) as part of the overall DG impact study, Vernon's overall system DG limit will be
lower, but in general is not constrained by the physical system as a whole. However, system
grounding, protective relaying, and anti-islanding schemes may need to be addressed. Further
discussion on these aspects is included in the safety discussion portion of this impact study.
In addition to Leonis 7kV circuit breakers replacement, recommendation due to limited interrupting
current rating we have also observed that each Leonis 66 kV to 7 kV transformer bank is grounded
via regulator which is not a common practice. Our understanding is those transformers banks planned
to be replaced as part of CIP and we recommend alleviate that as part of that replacement. No
141. substation relays and other substation equipment was specifically identified to be replaced but as
mentioned above since each circuit was not analyzed values presented may not represent limits for
specific DG installation at specific locations
7.3 Environmental Impacts and Initial Study
Recommendations are already covered under Overall recommendation and CUP requirements and
there is no additional recommendation.
7.4 Safety Assessment
Work practices for Vernon crews should be reviewed to accommodate the presence of DG on the
system and consideration should be given to requiring a lockable disconnect to assure DG is, and
remains, disconnected from the distribution system while line work is being performed. Vernon
operations and engineering staff should have ready access to DG locations and basic information
about each DG installation. Vernon's existing maps and documents should be amended to include this
information. Vernon's present interconnection policies require DG to meet IEEE 1547 and UL1741.
Protective relay settings should be reviewed in detail to provide assurance that protective relays will
operate as expected.
The generation levels at which monitoring, and potentially control, will be required should be
evaluated by Vernon to create a policy that permits operating the medium voltage electrical
distribution system safely and efficiently. Some guidance is provided in IEEE 1547.3 and should be
referred to.
ANA 092-062 (SR 02) COV 135853 (05/08/2015) YU PAGE 77
POWER ENGINEERS, INC.
Distributed Generation Impact Study
Implement our suggestions on DG Interconnection Agreement and Requirement and Guidelines as
�..- much as practical.
In Appendix C on the hazardous materials analysis under section 6, three mitigations measures MM-1
to MM-3 are mentioned if the need arises depending upon the specific DG project and there is no
additional recommendation.
7.5 Ratepayers Impacts Recommendations
Included in the overall project recommendation in the beginning of this chapter and no additional
recommendations are required.
ANA 092-062 (SR 02) COV 135853 (05/08/2015) YU PAGE 78
MR
POWER ENGINEERS, INC.
Distributed Generation Impact Study
8.0 REFERENCES
California Energy Commission (CEC). 2015. California Energy Maps: California Win Resource
Maps. Institute of Electrical and Electronic Engineers, Inc. Standard 1547-2003 (R2008),
IEEE Standard for Interconnecting Distributed Resources with Electric Power Systems,
Institute of Electrical and Electronic Engineers, Inc., New York, New York, p. 4. Accessed
May 13, 2015.
Institute of Electrical and Electronic Engineers, Inc. (IEEE). 2015. Standard 1547-2003 (R2008),
IEEE Standard for Interconnecting Distributed Resources with Electric Power Systems,
Institute of Electrical and Electronic Engineers, Inc., New York, New York, p. 10. Accessed
May 2015.
2015. Standard 1547.7-2013 IEEE Guide for Conducting Distribution Impact Studies for
Distributed Resource Interconnection, Institute of Electrical and Electronic Engineers, Inc.,
New York, New York, p. 38. Accessed May 2015.
National Renewable Energy Laboratory (NREL). 2015. Wind Data Details. http://www.nrel.gov/gis/
wind detail.html. Accessed May 13, 2015.
Office of Energy Efficiency & Renewable Energy. Fuel Cell Technologies Office.
Office of Environmental Health Hazard Assessment (OEHHA). 2015. Health Effects of Diesel
Exhaust: A fact sheet by Cal/EPA's Office of Environmental Health Hazard Assessment and
the American Lung Study: Physical Impacts. http://oehha.ca.gov/public—info/
facts/dieselfacts.html. Accessed May 13, 2015.
POWER Engineers Inc. (POWER). 2015. Distributed Generation Financial Impacts and Cost of
Service.
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Distributed Generation Impact Study
APPENDIX A DG STUDY - ETAP MODELS
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OR
M
POWER ENGINEERS, INC.
Distributed Generation Impact Study
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Project:
Location:
Contract:
Engineer:
Filename: Feeder 2
Bus
Voltage
ETAP
12.5.00
Study Case: Min Loading
LOAD FLOW REPORT
Generation Load
Page:
Date:
SN:
Revision:
Config.:
Load Flow
I
02-27-2015
POWERENG-2
Base
Normal
_ .
XFMR
ID
kV
%Mag.
Ang.
MW
War
MW
War
ID
MW
Mvar
Amp
%PF %Tap
* 50TH ST
7.000
100.000
0.0
0.244
0.146
0
0
SEVILLE AVE
0.244
0.146
23.4
85.8
Busl
7.000
99.892
0.0
0
0
0
0
Bm22
0.012
0.008
L2
82.3
PACIFIC BLVD
-0.243
-0.145
23A
85.8
Bm31
0.232
0.137
22.2
86.0
Bus13-1
7.000
99.724
-0.1
0
0
0
0
Bm14-1
0.219
0.128
20.9
86.4
13 s38
-0.219
-0.128
20.9
86.4
Line12-1-
0.000
0.000
0.0
0.0
Bus14-1
7.000
99.711
-0.1
0
0
0
0
Bm13-1
-0.219
-0.128
20.9
86.4
PABCO PAPER
0.219
0.128
20.9
$6.4
Bus19
7.000
W829
-0.1
0
0
0
0
LEONIS
-0.231
-0.137
22.2
86.0
Bus27
0.006
0.005
0.7
80.0
�„-
Bus26
0.225
0.133
21.6
86.2
Bus22
7.000
99.892
0.0
0
0
0
0
BmI
4012
-0.008
1.2
82.3
DIGIFAB SYSTEMS
0.012
0.008
1.2
82.3
Bus26
7.000
99121
-0.1
0
0
0
0
Bm38
0.219
0.128
20.9
86.4
13 s19
-0.225
-0.133
21.6
86.2
Bus36
0.006
0.005
0.7
80.0
Bm27
T000
99.829
-21
0
0
0
0
Bus19
-0.006
-0.005
0.7
79.9
Bus28
0.006
0.005
0.7
79.9
Bus28
0.480
W733
-0.1
0
0
0.006
0.005
Bm27
-0.006
-0.005
9.5
80.0
11us29
T000
W947
0.0
0
0
0
0
FRUITLANDAVE
-0.244
-0.145
23.4
85.9
PACIFIC BLVD
0.244
0.145
23.4
85.9
Bus31
7.000
99.859
0.0
0
0
0
0
BmI
-0.231
-0.137
22.2
86.0
LEOMS
0.231
0.137
22.2
86.0
Bus32
7.000
99.943
-0.1
0
0
0
0
LEOMS
0.000
0.000
0.0
0.0
Bm33
0.000
0.000
0.0
0.0
Line35-
0.000
0.000
0.0
0.0
Bus33
7.000
99.843
-0.1
0
0
0
0
Bw32
0.000
0.000
0.0
0.0
Bus36
T000
99.820
-0.1
0
0
0
0
13us26
-0.006
-0.005
0.7
79.9
Bm37
0.006
0.005
0.7
79.9
Bus37
0.480
99.716
-0.1
0
0
0.006
0.005
Bus36
-0.006
-0.005
9.5
80.0
Bus38
T000
W776
-0.1
0
0
0
0
Bus26
-0.219
4 128
20.9
86A
13 s13-1
0.219
0.128
20.9
86.4
DIGIFAB SYSTEMS
0.480
W791
-0.1
0
0
0.012
0.008
Bm22
-0.012
-0.008
IT4
82.3
FRUITLANDAVE
7.000
99.974
0.0
0
0
0
0
SEVILLE AVE
-0.244
-0.145
23.4
85.9
Bm29
0.244
0.145
23.4
85.9
SAN 094-216 (SR-06) VERNON (03/06/2015) MM 135853 REV. 0
ETAP
Project:
Page:
2
12.5.00
Location:
Date:
02-27-2015
Contract:
SN:
POWERENG-2
Engineer:
Revision:
Base
Study Case: Min
Loading
Filename: Feeder 2
Config.:
Normal
Bus Voltage
Generation
Load
Load Flow
XFMR
ID kV %Mag Ang.
MIN
War
MIN
War
ID
MW
War
Amp
%PF %Tap
LEONIS 7.000 99.843 -0.1
0
0
0
0
Bus32
0.000
0.000
0.0
0.0
BM19
0.231
0.137
22.2
86.0
Bus31
-0.231
-0.137
22.2
86.0
PABCO PAPER 0.480 99.428 -0.3
0
0
0.219
0.126
Bus 14-1
-0.219
-0.126
305.4
86.6
PACIFIC BLVD 7.000 99.920 0.0
0
0
0
0
Bust
0.243
0.145
23.4
85.8
Bus29
-0.243
-0. 145
23.4
85.9
Line20-
0.000
0.000
0.0
0.0
SEVILLE AVE T000 99.987 0.0
0
0
0
0
50TH ST
-0.244
-0.146
23.4
85.8
FRUITLAND AVE
0.244
0.146
23.4
85.8
Line20- 7.000 99.920 0.0
0
0
0
0
PACIFIC BLVD
0.000
0.000
0.0
0.0
Linel2-1- T000 99.724 -0.1
0
0
0
0
Bus13-1
0.000
0.000
0.0
0.0
Line35- 7.000 99.843 41
0
0
0
0
Bus32
0.000
0.000
0.0
0.0
• Indicates a voltage regulated bus (voltage controlled or swing type machine
connected to it)
# Indicates a bus with a load mismatch of more than 0.1 MVA
SAN 094-216 (SR-06) VERNON (03/06/2015) MM 135853
REV. 0
Project: ETAP Page: I
Location: 12.5.00 Date: 02-27-2015
Contract: SN: POWERENG-2
Engineer: Revision: Base
Study Case: Min Loading
Filename: FEEDERII Config.: Normal
LOAD FLOW REPORT
Bus
Voltage
Generation
Load
Load Flow
XFMR
ID
kV
%Mag
Ang.
MW Mvar
MW
Mvar
H)
MW
Mvar
Amp
%PF %Tap
• 50TH ST
7.000
100.000
0.0
0.406 0.215
0
0
SOTO ST
0.406
0.215
37.9
88.3
54TH ST & SOTO
7.000
99.876
0.0
0
0 0
0
FRUITLAND AVE
-0A05
-0.215
37.9
88.3
Bus3
0.208
0.128
20.2
85.3
BwI0
0.197
0.087
IT8
91A
BCBG MAX
0.480
98.199
-1.1
0
0 0.191
0.113
Bus8
-0.191
-0.113
271.3
86.1
BEST MEXICAN FOODS
0A80
99.759
-0.1
0
0 0.010
0.004
Bm24
-0.010
-0.004
12.7
9LO
BICKETT ST
7.000
99.842
-0.1
0
0 0
0
BmIO
-0.142
-0.057
12.7
92.7
Bus13
0.098
0.036
8.6
93.8
Bm23
0.045
0.021
4.1
90.2
BOYLEAVE
7.000
99.833
-0.1
0
0 0
0
Bm23
-0.035
-0.017
3.2
89.9
BwI
0.035
0.017
3.2
89.9
Bust
7.000
99.825
-0.1
0
0 0
0
BOYLE AVE
-0.035
4017
3.2
89.9
Bust
0.035
0.017
3.2
89.9
Bust
7.000
99.821
-0.1
0
0 0
0
Bus
-0o35
-0.017
3.2
89.8
Bus6
0.035
0.017
3.2
89.8
Bus3
7.000
99.856
-0.1
0
0 0
0
54TH ST & SOTO
-0.208
-0.128
20.2
85.3
Bus4
0.208
0.128
20.2
85.3
Line3-
0.000
0.000
0.0
0.0
Bus4
7.000
99.847
-0.1
0
0 0
0
BmS
0.017
0.010
1.6
86.8
Bus3
-0.208
-0.128
20.2
85.3
Bus7
0.192
0.118
18.6
85.2
Buss
7.000
99.846
-0.1
0
0 0
0
Bus4
-0.017
-0.010
L6
86.8
RICHARD KORAL
0.017
0.010
1.6
W8
Bus6
7.000
99.817
-0.1
0
0 0
0
Bus2
-0.035
-0.017
3.2
W8
Bus9
0.035
0.017
3.2
89.8
Bus7
7.000
99.845
41
0
0 0
0
Bus4
-0.192
-0.118
18.6
85.2
Bm8
0.192
0.118
18.6
85.1
Line7-
0.000
0.000
0.0
0.0
Buss
7.000
99.844
-0.1
0
0 0
0
Bus7
-0.192
-0.118
18.6
85.1
BCBG MAX
0.192
0.118
18.6
85.1
Bus9
7,000
99.816
-0.1
0
0 0
0
Bus6
-0.035
-0.017
3.2
89.8
Bus12
0.035
0.017
3.2
89.8
Bus10
7.000
99.861
-0.1
0
0 0
0
Bw11
0.054
0.030
5.1
87.6
54TH ST & SOTO
-0.197
-0.087
17.8
91.4
BICKETT ST
0.142
0.057
12.7
92.7
Bus11
7.000
99.859
-0.1
0
0 0
0
Bus10
4054
-0.030
5.1
87.6
SAN 094-216 (SR-06) VERNON
(03/06/2015) MM 135853
REV. 0
Project: ETAP Page: 2
Location: 12.5.00 Date: 02-27-2015
Contract: SN: POWERENG-2
Engineer: Revision: Base
Study Case: Min Loading
Filename: FEEDERII Config.: Normal
Bus Voltage Generation Load Load Flow XFMR
ID
kV
%Mag.
Ang.
MW
Mvar
MW
Mvar
ID
MW
Mvar
Amp
%PF %Tap
WORLD VARIETY FOODS
0.054
0.030
5.1
87.6
Bus12
7.000
99.812
-0.1
0
0
0
0
Bus9
-0.035
-0.017
3.2
89.7
BM15
0.035
0.017
3.2
89.7
Bus13
7.000
99.835
-0.1
0
0
0
0
BICKETT ST
-0.098
-0.036
8.6
93.8
Bm14
0.042
0.002
3.4
99.9
Bm16
0.056
0.034
5.4
85.3
Linell--
0.000
0.000
0.0
0.0
Bm14
7.000
99.833
-0.1
0
0
0
0
Bw13
-0.042
-0.002
3.4
99.9
SK TEXTILE
0.042
0.002
3.4
99.9
Bus15
7.000
99.811
-0.1
0
0
0
0
Bw22
0.018
0.009
1.6
89.6
Bus12
-0.035
-0.017
3.2
89.7
Bm27
0.018
0.009
1.6
89.8
Bus16
7.000
99.833
-0.1
0
0
0
0
Bm13
-0.056
-0.034
5A
85.3
Bm17
0.056
0.034
5A
85.3
Bus17
7.000
99.829
-O.l
0
0
0
0
Bus 18
0.018
0.009
16
89.6
Bus 16
-0.056
-0.034
5.4
85.2
Bw20
0.038
0.026
3.8
83.2
Bus18
7.000
99.829
-0.1
0
0
0
0
Bm17
-0.018
-0.009
L6
89.6
KATIE INC
0.018
0.009
L6
89.6
Bus20
7.000
99.828
-0.1
0
0
0
0
Bw21
0.038
0.026
3.8
83.1
Bush
-0.038
-0.026
3.8
83.2
Line16-
0.000
0.000
0.0
0.0
Bus21
7.000
99.826
-0.1
0
0
0
0
Bm20
-0.038
-0.026
3.8
83.1
KELLY TOY
0.038
0.026
3.8
811
Bus22
7.000
99.810
-0.1
0
0
0
0
Bus15
-0.018
-0.009
16
89.6
SANDBERG FURNITURE
0.018
0.009
1.6
89.6
Bus23
7.000
99.835
-0.1
0
0
0
0
BICKETT ST
-0.045
-0.021
4.1
90.2
Bm24
0.010
0.004
0.9
91.0
BOYLE AVE
0.035
0.017
3.2
89.9
Bus24
T000
99.835
-0.1
0
0
0
0
Bw23
-0.010
-0.004
0.9
90.9
BEST MEXICAN FOODS
0.010
0.004
0.9
90.9
Bus26
7.000
99.805
-0.1
0
0
0
0
Bm27
-0.018
-0.009
1.6
89.6
WALTERS ELECTRIC
0.018
0.009
1.6
89.6
Bus27
7.000
99.805
-0.1
0
0
0
0
Bus26
0.018
0.009
1.6
89.6
Bw15
-0.018
-0.009
1.6
89.6
FRUITLAND AVE
T000
99.967
0.0
0
0
0
0
SOTO ST
-0.405
-0.215
37.9
88.3
54TH ST & SOTO
0.405
0.215
37.9
88.3
KATIE INC
0.480
99.712
-0.1
0
0
0.018
0.009
Bus18
-0.018
-0.009
23.6
89.7
KELLYTOY 0.480 99.708 -0.1 0 0 0.038 0.026 Bm21 -0.038 -0.026 55.6 83.2
SAN 094-216 (SR-06) VERNON (03/06/2015) MM 135853 REV. 0
Project:
Location:
Contract:
Engineer:
Filename: FEEDER 11
Bus
Voltage
ETAP
12.5.00
Study Case: Min Loading
Generation Load
Page:
Date:
SN:
Revision:
Config.:
Load Flow
3
02-27-2015
POWERENG-2
Base
Normal
XFMR
ID
kV
%Mag Ang.
MW
Mvar
MW
Mvar
ID
MW
Mvar
Amp
%PF %Tap
RICHARD KORAL
0.480
99.574 -0.2
0
0
0.017
0.009
Bus5
-0.017
-0.009
23.2
87.0
SANDBERG FURNITURE
0.480
99.693 -0.2
0
0
0.018
0.009
Bus22
-0.018
-0.009
23.6
89.7
SK TEXTILE
0.480
99.697 -0.3
0
0
0.042
0.002
Bus14
-0.042
-0.002
50.2
99.9
SOTO ST
7.000
99.990 0.0
0
0
0
0
50TH ST
-0.406
-0.215
37.9
88.3
FRUITLAND AVE
0.406
0.215
37.9
88.3
WALTERS ELECTRIC
0.480
99.727 -0.1
0
0
0.018
0.009
Bus26
-0.018
-0.009
23.6
89.7
WORLD VARIETY FOODS
0.480
99.212 -0.5
0
0
0.054
0.029
Buslt
-0.054
-0.029
74.7
88.0
Linea-
7.000
99.856 -0.1
0
0
0
0
Bus3
0.000
0.000
0.0
0.0
Line7-
7.000
99.845 -0.1
0
0
0
0
Bus7
0.000
0.000
0.0
0.0
Linell-
7.000
99.835 -0.1
0
0
0
0
Bus13
0.000
0.000
0.0
0.0
Linel6-
7.000
99.828 -0.1
0
0
0
0
Bus20
0.000
0.000
0.0
0.0
Indicates a voltage regulated bus (voltage controlled or swing type machine
connected to it)
# Indicates a bus with a load mismatch of more
than 0.1 MVA
SAN 094-216 (SR-06)
VERNON (03/06/2015) MM 135853
REV. 0
Project:
ETAP
Location: 12.5.00
Contract:
Engineer:
Study Case: Min Loading
Filename: feeder 19
Page:
1
Date:
02-27-2015
SN:
POWERENG-2
Revision:
Base
Config.:
Normal
Bus
Voltage
LOAD FLOW REPORT
Generation Load
ID
kV
%Mag.
Ang.
MW
War
MW
War
ID
27TH ST
7.000
99.334
-1.3
0
0
0
0
Bus25
Bus29
37TH ST
7.000
99.498
-1.3
0
0
0
0
Bus17
Bw18
Bus24
50TH ST
7.000
100.009
-0.2
0
0
0
0
SEVILLE AVE
Bus?
51ST ST
7.000
99.700
-0.6
0
0
0
0
SANTA FE AVE
Bus8
ALAMEDAAVE
7.000
99.520
-0.9
0
0
0
0
Busll
Bus14
Line12-
AROMA
0.480
98.515
-1.6
0
0
0.059
0.055
Bus52
COSMESTICS/UNIREX
Busl
T000
99.963
-0.3
0
0
0
0
SEVILLE AVE
Bust
Bus2
7.000
99.810
-0.4
0
0
0
0
Busl
Bus4
Bus5
Bus3
0A80
99.810
-0.4
0
0
0
0
Bus4
Bus4
T000
W810
-0.4
0
0
0
0
Bus2
Bm3
Bu55
7.000
99.795
-0.5
0
0
0
0
Bus2
Bush
SANTA FE AVE
Bus6
7.000
99.794
-0.5
0
0
0
0
Bus5
CONSOLIDATED
METALS
* Bus7
69.000
100.000
0.0
0.954
-0.061
0
0
50TH ST
Bus8
7.000
99.564
-0.8
0
0
0
0
51STST
Bus9
Bw11
Bus9
7,000
99.564
-0.8
0
0
0
0
Bus8
Bus10
Bus10
0.480
W200
-1.0
0
0
0.039
0.026
Bus9
Busl1
7.000
W522
-0.9
0
0
0
0
Bus8
11 s12
Load Flow XFMR
MW
War
Amp
%PF %Tap
-0.316
-0.300
36.2
72.5
0.316
0.300
36.2
72.5
-0.359
-0.335
40.7
73.2
0.043
0.034
4.5
77.9
0.317
0.300
36.2
72.5
0.954
-0.064
78.8
-99.8
4954
0.064
78.8
-99.8
-0.867
0.124
72.5
-99.0
0.867
-0.124
72.5
-99.0
-0.647
0.328
60.2
-89.2
0.647
-0.328
60.2
-89.2
0.000
0.000
0.0
0.0
-0.059
-0.055
98.8
73.5
-0.953
0.065
78.8
-99.8
0.953
-0.065
78.8
-99.8
-0.951
0.068
78.8
-99.7
0.000
0.000
0.0
0.0
0.951
-0.068
78.8
-99.7
0.000
0.000
0.0
0.0
0.000
0.000
0.0
0.0
0.000
0.000
0.0
0.0
-0.951
0.068
78.8
-99.7
0.083
0.054
8.2
83.7
0.868
-0.122
72.5
-99.0
-0.083
-0.054
8.2
83.7
0.083
0.054
8.2
83.7
0.954
-0.061
8.0
-99.8
-0.866
0.127
72.5
-98.9
0.039
0.026
3.9
83.1
0.826
-0.153
69.6
-98.3
-0.039
-0.026
3.9
83.1
0.039
0.026
3.9
83.1
-0.039
-0.026
57.3
83.3
-0.826
0.154
69.6
-98.3
0.178
0.174
20.6
71.5
SAN 094-216 (SR-06) VERNON (03/06/2015) MM 135853 REV. 0
Project:
Location:
Contract:
Engineer:
Filename: feeder 19
ETAP
12.5.00
Study Case: Min Loading
Bus
Voltage
Generation
Load
ID
W
%Mag
Ang.
MW War
MW
War
ID
ALAMEDA AVE
Bus12
7.000
99.518
-0.9
0
0 0
0
Busll
PUNCH PRESS
PRODUCTS
Bus14
7.000
99.498
-1.1
0
0 0
0
BmI5
ALAMEDA AVE
Bw 17
BmI5
T000
99.484
-LI
0
0 0
0
Bm14
NEPTUNE FOODS
Bus17
T000
99.602
-1.2
0
0 0.0o0
-0.893
Bus14
37TH ST
Bus18
7.000
99.494
-1.3
0
0 0
0
37TH ST
Bus19
Bm21
Bus19
T000
99.494
-1.3
0
0 0
0
BmI8
Bus20
Bus20
0.480
98.594
-1.6
0
0 0.032
0.025
Bw19
Bus2l
7.000
99.493
-1.3
0
0 0
0
Bus18
Bus22
ROSS ST
Bus22
7.000
99.493
-1.3
0
0 0
0
Bm21
Bw23
Bus23
0.480
99.306
-1.4
0
0 0.011
0.009
Bus22
Bm24
T000
99.433
-1.3
0
0 0
0
37TH ST
Bus25
Line24-
Bus25
7.000
99AII
-1.3
0
0 0
0
Bus24
Bus26
27TH ST
Bus26
7.000
99.411
-1.3
0
0 0
0
Bus25
Bus27
Line28-
Bus27
7.000
99.411
-1.3
0
0 0
0
Bus26
Bm28
Bus28
0.480
99.411
-1.3
0
0 0
0
Bus27
Bw29
7.000
99.299
-1.3
0
0 0
0
27TH ST
Bus30
Bw32
Bus30
7.000
99.299
-1.3
0
0 0
0
Bus29
Page:
2
Date:
02-27-2015
SN:
POWERENG-2
Revision:
Base
Config.:
Normal
Load Flow XFMR
MW
War
Amp
%PF %Tap
0.648
-0.328
60.2
-89.2
-0.178
-0.174
20.6
71.5
0.178
0.174
20.6
71.5
0.286
0.226
30.2
78.5
-0.646
0.331
601
-89.0
0.360
-0.557
55.0
-54.3
-0.296
4226
30.2
78.5
0.286
0.226
30.2
78.5
-0.360
0.558
55.0
-54.2
0.360
0.335
40.7
73.2
-0.043
-0.034
4.5
7T9
0.032
0.026
3.4
7Z9
0.011
0.009
1.1
78.0
-0.032
-0.026
3A
77.9
0.032
0.026
3 A
77.9
-0.032
-0.025
49.6
78.3
-0.011
-0.009
1.1
77.9
0.011
0.009
IA
77.9
0.000
0.000
0.0
0.0
-0.011
-0.009
1.1
77.8
0.011
0.009
1.1
77.8
-0.011
-0.009
16.6
77.8
-0.316
-0.300
36.2
72.6
0.316
0.300
36.2
72.5
0.000
0.000
0.0
0.0
-0.316
-0.300
36.2
72.5
0.000
0.000
0.0
0.2
0.316
0.300
36.2
72.5
o.000
0.000
0.0
1.0
0.000
0.000
0.0
-20.5
0.000
0.000
0.0
0.0
0.000
0.000
0.0
-58.9
0.000
0.000
0.0
0.o
0.000
0.000
0.0
0.0
-0.316
-0.300
36.2
72.6
0.000
0.000
0.0
-25.8
0.316
0.300
36.2
72.6
0.000
0.000
0.0
-75.6
SAN 094-216 (SR-06) VERNON (03/06/2015) MM 135853 REV. 0
Project:
Location:
Contract:
Engineer:
Filename: feeder 19
ETAP
12.5.00
Study Case: Min Loading
Bus Voltage Generation Load
ID
W
%Mag.
Ang.
MW
Mvar
MW
Mvar
ID
Bm31
Bm31
0.480
99.299
-1.3
0
0
0
0
Bw30
Bus32
7.000
99.207
-1.3
0
0
0
0
13 s29
Bm41
Bus37
Bus38
Bus37
7.000
99.192
-1.3
0
0
0
0
Bm32
Bw59
Bw44
Bus38
7.000
99.205
-1.3
0
0
0
0
Bw32
CATALINA PACIFIC
CONCRETE
Bus41
7.000
99.207
-1.3
0
0
0
0
Bm42
Bus32
Bw42
7.000
99.205
-1.3
0
0
0
0
13 s41
CUTE GIRL
Bus44
7.000
99.178
-1.3
0
0
0
0
Bus37
Bus45
Bm47
Bus45
7.000
99.178
-1.3
0
0
0
0
Bm44
Bm46
Bus46
0.480
98.215
-L7
0
0
0.043
0.041
Bus45
Bus47
7.000
99.171
-1.3
0
0
0
0
Bus44
Bus48
Bm50
Bus48
7.000
99.171
-1.3
0
0
0
0
Bw47
Bm49
Bus49
0.480
97.014
-2.0
0
0
0.061
0.064
13us48
Bus50
7.000
99.164
-1.3
0
0
0
0
13us47
BW51
Bus54
Bus51
7.000
99.163
-1.3
0
0
0
0
Bus52
BM50
Bus52
7.000
99.160
-1.3
0
0
0
0
Bm51
AROMA
COSMESTICS/UNIREX
Bus54
7.000
99.164
-1.3
0
0
0
0
Bm50
Bm57
Line49-
11 s57 7.000 99.164 -1.3 0 0 0 0 Bus54
Page:
3
Date:
02-27-2015
SN:
POWERENG-2
Revision:
Base
Config.:
Normal
Load Flow XFMR
MW
Mvar
Amp
%PF %Tap
0.000
0.000
0.0
0.0
0.000
0.000
oo
0.0
-0.316
-0.300
36.2
72.6
0.025
0.025
10
70.6
0.185
0.182
21.6
71.3
0.105
0.092
I L6
75.4
-0A85
4182
21.6
71.3
0.021
0.019
2.4
73.0
0.165
0.163
19.3
71 A -
-0.105
-0.092
I L6
75.4
0.105
0.092
I L6
75A
0.025
0.025
3.0
70.6
4025
-0.025
3.0
70.6
4025
4025
3.0
70.6
0.025
0.025
3.0
70.6
-0.165
-0.163
19.3
71.1
0.043
0.042
5.0
7L8
0.122
0.121
14.3
70.8
-0.043
-0.042
5.0
71.8
0.043
0.042
5.0
71.8
-0.043
-0.041
72.8
72.2
-0.122
-0.121
14.3
70.8
0.062
0.066
7.5
68.6
0.060
0.055
6.8
73.2
-0.062
-o066
T5
68.6
0.062
0.066
7.5
68.6
-0.061
-0.064
109.6
69.4
-0.060
-0.055
6.8
73.2
0.060
0.056
6.8
73.2
0.000
0.000
0.0
0.0
0.060
0.056
6.8
73.2
-0.060
-0.056
6.8
73.2
-0.060
-0.056
6.8
73.2
0.060
0.056
6.8
73.2
0.000
0.000
0.0
0.0
0.000
0.000
oo
0.0
0.000
0.000
oo
0.0
0.000
0.000
0.0
0.0
SAN 094-216 (SR-06) VERNON (03/06/2015) MM 135853 REV. 0
ETAP
Project:
Page:
4
Location:
12.5.00
Date:
02-27-2015
Contract:
SN:
POWERENG-2
Engineer:
Revision:
Base
Study Case: Min
Loading
Filename: feeder 19
Config.:
Normal
Bus
Voltage
Generation
Load
Load Flow
XFMR
H)
kV
%Mag Ang.
MW
Mvar
MW
War
ID
MW
War
Amp
%PF %Tap
Bus58
0.000
0.000
0.0
0.0
Bus58
0.480
99.164 -1.3
0
0
0
0
Bus57
0.000
0.000
o.0
0.0
Bus59
7.000
99.191 -1.3
0
0
0
0
Bus37
-0.021
-0.019
2.4
73.0
PHYSICAL
0.021
0.019
2.4
73.0
DISTRIBUTION SER
CATALINA PACIFIC
0.480
97.411 -2.1
0
0
0.105
0.089
Bus38
-0.105
-0.089
169.5
76.3
CONCRETE
CONSOLIDATED
0.480
99.235 -0.8
0
0
0.083
0.053
Bus6
-0.083
4053
119.5
84.0
METALS
CUTE GIRL
0.480
98.915 -1.4
0
0
0.025
0.025
Bus42
-0.025
-0.025
43.3
70.7
NEPTUNE FOODS
0.480
97.274 -2.1
0
0
0.283
0.216
Bus15
-0.283
-0.216
440.0
79.5
PHYSICAL
0.480
98.916 -1.4
0
0
0.021
0.019
Bus59
-0.021
-0.019
34.3
73.1
DISTRIBUTION SER
PUNCH PRESS
0.480
97.308 -1.7
0
0
0.177
0.167
Busl2
-0.177
-0.167
30o8
72.6
PRODUCTS
ROSS ST
7.000
99.493 -1.3
0
0
0
0
Bus21
0.000
0.000
0.0
0.0
w
Line2l-
0.000
0.000
0.0
0.0
Line22-
0.000
0.000
0.0
0.0
SANTAFEAVE
7.000
99.770 -0.5
0
0
0
0
Bus5
-0.868
0.123
72.5
-99.0
51 ST ST
0.868
-0.123
72.5
-99.0
SEVILLE AVE
7.000
99.986 -0.2
0
0
0
0
50T14 ST
-0.953
0.065
78.8
-99.8
Busl
0.953
-0.065
78.8
-99A
Linel2-
7.000
99.520 -0.9
0
0
0
0
ALAMEDAAVE
0.000
0.000
no
0.0
Line2l-
T000
99.493 -1.3
0
0
0
0
ROSS ST
0.000
0.000
0.0
0.0
Line22-
7.000
99.493 -1.3
0
0
0
0
ROSS ST
0.000
0.000
0.0
0.0
Line24-
7.000
99.433 -1.3
0
0
0
0
Bus24
0.000
0.000
0.0
0.0
Line28-
7.000
99AII -1.3
0
0
0
0
Bus26
0.000
0.000
0.0
o.0
Line49-
7.000
99.164 -1.3
0
0
0
0
Bus54
0.000
0.000
0.0
0.0
+ Indicates a voltage regulated bus (voltage
controlled or swing type machine
connected to it)
# Indicates a bus with a load mismatch
of more than 0.1 MVA
SAN 094-216
(SR-06) VERNON
(03/06/2015) MM 135853
REV. 0
Project:
Location:
Contract:
Engineer:
Filename: Feeder 21
Bus
ID
45TH ST
45TH ST-2
46TH ST
• 50TH ST
Bust
t\t Bus3
Bus4
Bus6
BuS9
Bu510
Busl1
Bus15
Bus16
Bus17
Bus 19
11 .
ETAP
12.5.00
Study Case: Min Loading
Page:
1
Date:
02-27-2015
SN:
POWERENG-2
Revision:
Base
Config.:
Normal
Voltage
LOAD FLOW REPORT
Generation Load
kV
%Mag_
Ang.
MW
Mvar
MW
Mvar
ID
7.000
100.075
-0.2
0
0
-0.001
-0.001
SEVILLE AVE
PACIFIC BLVD
Bw38
7000
100.259
-0.7
0
0
0
0
Bw6
Bus9
Bw15
7.000
100.025
-0.1
0
0
0
0
TP 3
SEVILLE AVE
VERNON AVE
7.000
100.000
0.0
0.639
-0.515
0
0
SOTO ST
2.400
99.805
-0.9
0
0
0.273
0202
Bus34
7 000
100.156
-0.5
0
0
-0.002
-0.001
Bus4
PACIFIC BLVD
Bus6
7.000
100.155
-0.5
0
0
0
0
Bus3
SECOND GENERATION
7.000
100.235
-0.7
0
0
-0.001
-0.001
Bus34
Bw3
45TH ST-2
7.000
100.388
-0.7
0
0
0.003
-0.005
45TH ST-2
Bus10
Bus33
7.000
100.389
-0.7
0
0
-0.001
0.002
Bus9
Busl l
0.480
100.338
-0.8
0
0
0.003
0.001
Bm10
7.000
100.241
47
0
0
0
0
45TH ST-2
Bus16
Bus37
7.000
100,210
-0.7
0
0
0
0
BmI5
Bm17
Bw 19
7.000
100.209
-o7
0
0
0
0
Bus16
GREEN ISLAND &
LIFOAM
7.000
100A89
-0.7
0
0
0
0
Bw16
Bw20
Bus22
Load Flow XFMR
MW
Mvar
Amp
%PF %Tap
-0.611
0.528
66.6
-75.7
0.600
-0.532
66.1
-74.9
0.012
0.005
1.1
93.0
-0.308
0.744
66.2
-38.2
0.005
-0.907
74.7
-0.5
0.302
0.164
28.3
87.8
-0.639
0.515
67.7
-778
0.612
-0.527
66.6
-75.8
0.028
0.012
2.5
91.6
0.639
-0.515
67.6
-77.9
-0.273
-0.202
82.0
80A
0.020
0.005
1.7
96.9
-0.600
0.534
66.1
-74.7
0.582
-0.538
65.2
-73 4
-0.020
-0.005
1.7
96.9
0.020
0.005
1.7
97.0
0.274
0.205
28.1
80.1
-0.580
0.540
65.2
-73.2
0.308
-0.743
66.2
-38.3
-0.004
0.909
74.7
-0.5
0.001
0.003
0.3
35.8
0.000
-0.908
74.6
0.0
-0.001
-0.003
0.3
35.8
0.003
0.001
0.2
90.0
-0.003
-0.001
3.4
90.0
-0.302
-0.164
28.3
87.9
0.302
0.164
28.3
878
0.000
0.000
0.0
71.0
-0.302
-0.164
28.3
87.8
0.035
0.020
3.3
86.5
0.267
0.144
24.9
87.9
-0.035
-0.020
3.3
86.5
0.035
0.020
3.3
86.7
-0.267
-0.144
25.0
87.9
0.266
0.144
24.9
87.9
0.000
0.000
0.0
-99.8
SAN 094-216 (SR-06) VERNON (03/06/2015) MM 135853 REV. 0
ETAP
Project:
Page:
2
12.5.00
Location:
Date:
02-27-2015
Contract:
SN:
POWERENG-2
Engineer:
Revision:
Base
Study
Case: Min
Loading
Filename: Feeder 21
Config.:
Normal
Bus
.. ..____._.. _._._._....
Voltage
Generation
Load
Load Flow
XFMR
ID
kV
%Ma&
Ang.
MW War
MW
War
iD
MW
War
Amp
%PF %Tap
Bus20
7.000
100.177
-0.7
0
0
0
0
13 s19
-0.266
-0.144
24.9
87.9
RED CHAMBERS
0.266
0.144
24.9
87.9
Bus22
7.000
100,189
-0.7
0
0
0
0
Bus19
0.000
0.000
0.0
-99.1
Bus23
0.000
0.000
0.0
99.9
Bus23
0.480
100.189
-0.7
0
0
0
0
Bm22
0.000
0.000
0.0
99.9
Bw24
7.000
100.013
-0.1
0
0
0
0
VERNON AVE
-0.028
-0.012
2.5
91.4
13us25
0.016
0.007
1.4
91.3
13us27
0.012
0.005
1.1
9L6
Bus25
7.000
100,013
-0.1
0
0
0
0
Bus24
-0.016
-0.007
1.4
91.3
Bm26
0.016
0.007
1.4
91.3
Bm26
0.480
99.796
-0.3
0
0
0.016
0.007
Bus25
-0.016
-0.007
20.8
91A
Bus27
7.000
100.012
-0.1
0
0
0
0
Bus24
-0.012
-0.005
1.1
91.5
Bus28
0.012
0006
1.1
90.9
SANTAFEAVE
0.000
0.000
0.0
0.0
Bus28
7.000
100.012
-0.1
0
0
0
0
Bus27
-0.012
-0.006
1.1
90.9
Bw29
0.012
0.006
1.1
90.9
13 s29
0.480
99.843
-0.2
0
0
0.012
0.006
Bus28
-0.012
-0.006
16.0
91.0
Bus31
0.480
100A45
-0.7
0
0
0
0
Bus32
0.000
0.000
0.0
-71.4
Bus32
7.000
100.445
-0.7
0
0
0
0
Bm33
0.000
0.000
0.0
-70.2
Bus31
0.000
0.000
0.0
-71.4
Bus33
7.000
100.445
-0.7
0
0
0.000
-0.908
Bus32
0.000
0.000
0.0
-64.7
13 s9
0.000
0.908
74.6
0.0
Bus34
7.000
100.223
47
0
0
0
0
Bw6
-0.274
-0.204
28.1
80.1
Bus2
0.274
0.204
28.1
80.1
Bus36
T000
100.074
-0.2
0
0
0
0
Bw38
-0.012
-0.005
LI
92.9
OKK TRADIND ( SOLAR)
0,012
0.005
1.1
92.8
Bus37
7.000
100141
-0.7
0
0
0
0
Bus15
0.000
0.000
0.0
-94.6
Bus38
7.000
100.074
42
0
0
0
0
Bus36
0.012
0.005
1.1
92.9
45TH ST
-0.012
4005
1.1
92.9
GREEN ISLAND &
0.480
99.906
-0.9
0
0
0.035
0.020
Bm17
-0.035
-0.020
48.5
86.9
LIFOAM
OKK TRADrND ( SOLAR
0.480
100.051
-0.3
0
0
0.012
0.005
Bus36
-0.012
-0.005
15.9
92.8
PACIFIC BLVD
7.000
100.122
-0.4
0
0
-0.001
-0.001
45TH ST
-0.599
0.533
66.1
-74.7
Bus3
0.601
-0.533
66.1
-74.8
RED CHAMBERS
0.480
99.241
-1.4
0
0
0.265
0.140
Bm20
-0.265
-0.140
3635
88.4
SANTAFEAVE
7.000
100.012
41
0
0
0
0
Bus27
0.000
0.000
0.0
0.0
SECOND GENERATION
0.480
99.964
-0.7
0
0
0.020
0.005
Bm4
-0.020
-0.005
24.7
97.1
SEVILLE AVE
7.000
100.048
-0.2
0
0
0
0
46TH ST
-0.611
0.528
66.5
-75.7
45TH ST 0.612 -0.527 66.6 -75.8
SAN 094-216 (SR-06) VERNON (03/06/2015) MM 135853 REV. 0
ETAP
Page:
3
Project:
12.5.00
Location:
Date:
02-27-2015
Contract:
SN:
POWERENG-2
Engineer:
Revision:
Base
Study Case: Min Loading
Filename: Feeder 21
Config.:
Normal
Bus
Voltage
Generation Load
Load Flow
XFMR
ID
kV
%Mag. Ang.
MW Mvar MIN Mvar
ID
MW
Mvar
Amp %PF %Tap
SOTO ST
7.000
IM002 0.0
0 0 0 0
50TH ST
-0.639
0.515
67.6 -7T9
TP 3
0.639
-0.514
67.6 -77.9
TP 3
7.000
100.009 0.0
0 0 0 0
SOTO ST
-0.639
0.515
67.6 -77.9
46TH ST
0.639
-0.514
67.7 -7Z9
VERNON AVE
7.000
100.015 -0.1
0 0 0 0
46TH ST
-0.028
-0.012
2.5 91.4
Bus24
0.028
0.012
2.5 91.4
• Indicates a voltage regulated bus (voltage controlled or swing type machine connected to it)
# Indicates a bus with a load mismatch of more than 0.1 MVA
SAN 094-216 (SR-06) VERNON (03/06/2015) MM 135853 REV. 0
Project: FEEDER 63 ETAP Page: 1
Location: 12.5.00 Date: 02-27-2015
Contract: SN: POWERENG-2
Engineer: Study Case: Min Loading Revision: Base
Filename: Feeder 63 Config.: Normal
.... _.. _......... .
.... _. _. --_ _ _......... .
LOAD FLOW REPORT
Bus Voltage Generation Load Load Flow XFMR
ID
kV
%Mag-
Ang.
MW
Mvar
MW
Mvar
ID
MW
Mvar
Amp
%PF %Tap
50TH ST
7200
99.949
0.0
0
0
0
0
Bust
-1.015
-0.831
105.3
77.4
Bus8
1.015
0.831
105.3
77.4
AMERICOLD LOGISTICS
0.480
10L863
-0.7
0
0
0.410
0.216
Bust
-0.410
-0.216
547.7
88.5
* Busl
7.200
100.000
0.0
1.016
0.832
0
0
SOT 4 ST
L016
0.832
105.3
77.4
Bus2
7.200
99.816
0.0
0
0
0
0
DOWNEY RD
-0.411
-0.222
37.6
88.0
AMERICOLD LOGISTICS
0.411
0.222
37.6
88.0
Bus4
7.200
99.625
-0A
0
0
0
0
BmS
0.345
0.187
31.6
87.9
DISTRICT BLVD
-0.602
-0.388
57.6
84.1
Bw17
0.257
0.201
26.3
78.8
BUS5
7.200
99.613
-0.1
0
0
0
0
Bus4
-0.345
-0.187
31.6
87.9
PACKAGING
0.345
0.187
31.6
8T9
ADVANTAGE CORP.
Bus6
7.200
99.561
-0.1
0
0
0
0
Bus7
0.148
0.107
14.7
81.1
CHARTER AVE
0.109
0.094
11.6
75.6
Bus17
-0.257
4201
26.3
78.8
Bus7
7.200
99.555
-0.1
0
0
0
0
Bus6
4148
-0.107
14.7
81.1
COV W # 12,17 & BSTR2
0.148
0.107
14.7
81.1
Buss
7200.
99.937
U0
0
0
0
0
50TH ST
-1.015
-0.831
105.3
77A
DOWNEY RD
1.015
0.831
105.3
77.4
Bus9
7.200
99.493
-0.1
0
0
0
0
Exchange Ave.
-0.109
-0.094
11.6
75.6
U.S.GROWERS
0.109
0.094
11.6
75.6
Bus11
7.200
99.546
-0.1
0
0
0
0
Maywood
0.000
0.000
0.0
0.0
INTERNATIONAL
0.000
0.000
0.0
0.0
SUBLIM
Bus12
7,200
99.700
0.0
0
0
0
0
DISTRICT BLVD
0.000
-0.218
17.5
0.1
Bus14
0.000
0.218
17.5
0.1
Bw15
0.000
0.000
0.0
0.0
Bus14
7.200
99.692
0.0
0
0
0
0
Bus12
0.000
-0.218
17.5
0.1
CWS INDUSTRIES
0.000
0.218
17.5
0.1
Bus15
T200
99.700
0.0
0
0
0
0
Bus12
0.000
0.000
0.0
0.0
Bus16
0.000
0.000
0.0
0.0
Bus16
7200.
99.700
0.0
0
0
0
0
Bus15
0.000
0.000
0.0
0.0
Bus17
7.200
99.584
-0.1
0
0
0
0
Bus4
-0.257
-0.201
26.3
78.8
Bus6
0.257
0.201
26.3
78.8
CHARTER AVE
T200
99.554
-0.1
0
0
0
0
Bus6
-0.109
-0.094
1L6
75.6
Maywood
0.109
0.094
11.6
75.6
Line9-
0.000
0.000
0.0
0.0
7
SAN 094-216 (SR-06) VERNON (03/06/2015) MM 135853 REV. 0
Project: FEEDER 63
ETAP
Page:
2
12.5.00
Date:
02-27-2015
Location:
Contract:
SN:
POWERENG-2
Engineer:
Study Case: Min
Loading
Revision:
Base
Filename: Feeder 63
Config.:
Normal
Bus
Voltage
Generation
Load
Load Flow
XFMR
ID
kV
%Mag
Ang.
MW
Mvar
MW
Mvar
ID
MW
Mvar
Amp
%PF %Tap
COV W. # 12,17 & BSTR2
0.480
101.356
-0.6
0
0
0.148
0.105
Bus7
-0.148
-0.105
214.5
81.6
CWS INDUSTRIES
0.480
101699
0.0
0
0
0.000
0.216
Bus14
0.000
-0.216
255.6
0.0
DISTRICT BLVD
T200
99.726
-0.1
0
0
0
0
DOWNEY RD
-0.603
-0.607
68.8
70.5
Bus4
0.602
0.389
57.6
84.0
Busl2
0.000
0.218
17.5
0.1
DOWNEY RD
7.200
99.851
0.0
0
0
0
0
Bus2
0.411
0.222
37.6
88.0
DISTRICT BLVD
0.603
0.607
68.8
70.5
Bus8
-1.015
-0.830
105.3
77.4
Line28-
0.000
0.000
0.0
0.0
Exchange Ave.
7.200
99.494
-0.1
0
0
0
0
Maywood
-0.109
-0.094
11.6
75.6
Bus9
0.109
0.094
11.6
75.6
Linel2-
0.000
0.000
0.0
0.0
INTERNATIONAL
0A80
102.390
-0.1
0
0
0
0
Busll
0.000
0.000
0.0
0.0
SUBLIM
Maywood
7.200
99.546
-0.1
0
0
0
0
Exchange Ave.
0.109
0.094
11.6
75.6
CHARTER AVE
-0.109
-0.094
IL6
75.6
Busll
0.000
0.000
0.0
0.0
PACKAGING
0.480
101.594
-0.7
0
0
0.344
0.181
Bus5
-0.344
-0.181
460.6
88.5
ADVANTAGE CORP.
U.S.GROWERS
0.480
98.902
-0.3
0
0
OA08
0.093
Bus9
-0.108
-0.093
173.9
75.8
Line9-
7.200
99.554
-0.1
0
0
0
0
CHARTERAVE
0.000
0.000
0.0
0.0
Linel2--
7.200
99.494
-0.1
0
0
0
0
Exchange Ave.
0.000
0.000
0.0
0.0
Line28-
7.200
99.851
0.0
0
0
0
0
DOWNEY RD
0.000
0.000
0.0
0.0
* Indicates a voltage regulated
bus (voltage
controlled
or swing type machine
connected to it)
# Indicates a bus with a load mismatch
of more
than 0.1
MVA
SAN 094-216 (SR-06) VERNON (03/06/2015) MM 135853
REV. 0
Project: ETAP Page: 1
Location: 12.5.00 Date: 02-27-2015
Contract: SN: POWERENG-2
Engineer: Revision: Base
Study Case: Min Loading
Filename: FEEDER 66 Config.: Normal
LOAD FLOW REPORT
Bus Voltage Generation Load Load Flow XFMR
ID
kV
%Mag.
Ang.
MW
Mvar
MW
Mvar
ID
MW
Mvar
Amp
%PF %Tap
44TH AVE
7.000
100.210
-0.3
0
0
0
0
ALCOA AVE
-0.533
0.788
78.3
-56.1
BUS 2
0.491
-0.814
78.3
-51.7
VERNON AVE
0.042
0.026
4.1
84.8
SOTH ST
7.000
100.015
0.0
0
0
0
0
Bust
-0.644
0.721
79.7
-66.6
Bust
0.644
-0.721
79.7
-66.6
ALCOA AVE
7.000
100.178
-0.3
0
0
0
0
Bus9
0.054
0.031
5.1
86.6
Bm2
-0.588
0.756
78.8
-61.4
44TH AVE
0.534
-0.787
78.3
-56.1
* Busl
T000
100.000
0.0
0.644
-0.720
0
0
50TH ST
0644
-0.720
79.7
-66.7
BUS 2
7.000
100.231
-0.3
0
0
0
0
Bus11
0.025
0.015
2.4
84.8
44TH AVE
-0.491
0.815
78.3
-51.6
Bus12
0.466
-0.830
78.3
-49.0
Bust
7.000
100.027
-ol
0
0
0
0
50TH ST
-0.644
0.721
79.7
-66.6
Bw3
0.054
0.032
5.2
86.4
ALCOAAVE
0.590
-0.753
78.9
-61.7
BUS 3
T000
100.277
-0.4
0
0
0
0
Bus15
0.400
0.036
33.0
99.6
Bus13
-0.466
-0.074
38.8
98.8
BUS 5
0.066
0.038
6.3
86.4
Bus3
7.000
100.012
-ol
0
0
0
0
Bus2
-0.054
-0.032
5.2
86.4
WELL # 19
0.054
0.032
5.2
86.4
BUS 5
7.000
100.276
-0.4
0
0
0
0
Bw17
0.054
0.031
5.1
86.7
BUS 3
-0.066
-0.038
6.3
86.4
BUS 7
0.012
0.007
1.1
85.1
BUS 7
7.000
100.276
-0.4
0
0
0
0
Bm21
0.012
0.007
1.1
85.0
BUS 5
-0.012
4007
1.1
85.1
Bm22
0.000
0.000
0.0
0.0
Bus9
7.000
100.177
-0.3
0
0
0
0
ALCOAAVE
-0.054
-0.031
5.1
86.6
CEG CONSTRUCTION
0.054
0.031
5.1
86.6
Busl l
7.000
100,230
-0.3
0
0
0
0
BUS 2
-0.025
-0.015
2.4
84.8
U.S. GROWERS - 3269
0.025
0.015
2.4
84.8
Bus12
T000
100.254
-0.3
0
0
0
0
BUS 2
-0A66
0.830
78.3
-49.0
Bw13
0.466
4830
78.3
49.0
Bus13
7.000
100.289
-0.4
0
0
0.000
-0.905
BUS 3
0.466
0.074
38.8
98.8
Bm12
-0.466
0.831
78.3
-48.9
Bus15
7.000
100.254
-0.4
0
0
0
0
BUS 3
-0.400
-0.036
33.0
99.6
U.S. GROWERS -3211
0.400
0.036
33.0
99.6
m
SAN 094-216 (SR-06) VERNON (03/06/2015) MM 135853 REV. 0
ETAP
Project:
Page:
2
12.5.00
Location:
Date:
02-27-2015
Contract:
SN:
POWERENG-2
Engineer:
Revision:
Base
Study Case: Min
Loading
.__._.......
Filename: FEEDER 66
Config.:
Normal
Bus
Voltage
Generation
Load
Load Flow
XFMR
ID
kV
%Mag. Ang.
MW Mvar
MW
Mvar
ID
MW
Mvar
Amp
%PF %Tap
Bus17
7.000
100.271 -0.4
0
0
0
0
BUS 5
-0.054
-0.031
5.1
86.7
U.S. GROWERS-3269
0.054
0.031
5.1
86.7
Bus21
7.000
100.275 -0.4
0
0
0
0
BUS 7
-0.012
-0.007
1.1
85.0
SAS TEXTILES
0.012
0.007
1.1
85.0
Bus22
7.000
100.276 -0.4
0
0
0
0
BUS 7
0.000
0.000
0.0
0.0
Bus25
7.000
1M199 -0.3
0
0
0
0
Bus26
-0.042
-0.026
4.1
84.7
PUMP HOUSE 92
0.042
0.026
4.1
84.7
Bus26
7.000
100.199 -0.3
0
0
0
0
VERNON AVE
-0.042
-0.026
4.1
84.8
Bus27
0.000
0.000
0.0
0.0
Bus25
0.042
0.026
4.1
84.7
Bus27
7.000
100.199 -0.3
0
0
0
0
Bus26
0.000
0.000
0.0
0.0
CEG CONSTRUCTION
0A80
99.778 -0.5
0
0
0.054
0.031
Bus9
-0.054
-0.031
74.9
86.8
PUMP HOUSE#2
0.480
99.648 -0.6
0
0
0.042
0.026
Bus25
-0.042
-0.026
59.7
85.0
SAS TEXTILES
0.480
100.244 -0.4
0
0
0.012
0.007
Bus21
-0.012
-0.007
16.6
85.0
U.S. GROWERS -3211
0.480
99.884 -1.1
0
0
0.399
0.031
Busl5
-0.399
-0.031
481.7
99.7
U.S. GROWERS - 3269
0.480
99.850 -0.5
0
0
0.025
0.015
Busll
-0.025
-0.015
35.0
85.0
U.S. GROWERS- 3269
0.480
100.139 -0.5
0
0
0.054
0.031
Busl7
-0.054
-0.031
74.8
86.8
VERNON AVE
7.000
100.203 -0.3
0
0
0
0
44TH AVE
-0.042
-0.026
4.1
84.8
Bus26
0.042
0.026
4.1
84.8
WELL #19
0.480
98.636 -R6
0
0
0.054
0.031
Bus3
-0.054
-0.031
75.5
86.8
* Indicates a voltage regulated bus (voltage
controlled or swing type machine connected to it)
# Indicates a bus with a load mismatch of more
than 0.1 MVA
Y
SAN 094-216 (SR-06)
VERNON (03/06/2015) MM 135853
REV. 0
Project: ETAP Page: 1
Location: 12.5.00 Date: 02-27-2015
Contract: SN: POWERENG-2
Engineer: Study Case: Min Loading Revision: Base
Filename: DAVIS Config.: Normal
LOAD FLOW REPORT
Bus Voltage Generation Load Load Flow XFMR
ID
kV
%Mag
Ang.
MW
Mvar
MW
Mvar
ID
MW
Mvar
Amp
%PF %Tap
BAKER COMMODITIES
0.480
100.342
-0.1
0
0
0.009
0.004
Bus15
-0.009
-0.004
11.9
93.6
BANDINI BLVD
16.500
100.140
0.0
0
0
0
0
BUS 3
0.104
-2.353
82.3
4A
Bus43
-0.104
2.353
82.3
-0 4
Line14-
0.000
0.000
0.0
0.0
' BmI
16.500
100.000
0.0
0.105
-2.350
0
0
BM51
0.105
-2.350
82.3
-4.5
Bust
16.500
100.055
0.0
0
0
0
0
Bus51
-0.105
2.351
82.3
4.5
DOWNEY RD
0.105
-2.351
82.3
-4.5
BUS 3
16.500
100.188
-0.1
0
0
0
0
BANDIM BLVD
-0.103
2.354
82.3
-4.4
BmIO
0.096
-2.362
82.6
-4.0
Bus7
0.008
0.009
0.4
66.6
Bus3
16.500
100.555
-0.2
0
0
0
0
Bus45
-0.009
-0.005
0.4
86.9
NATURAL DYEING CO.
0.009
0.005
0.4
86.9
Bm7
16.500
100.187
-0.1
0
0
0
0
BUS 3
-0.008
-0.009
0.4
66.3
UPS (333 Downey)
0.008
0.009
0.4
66.3
Bus8
16.500
100.553
-0.2
0
0
0
0
Bm37
-0.011
-0.008
0.5
82.2
HANNIBAL
0.011
0.008
0.5
82.2
tNDUSTtES(3851)
Bus9
16.500
100.354
-0.1
0
0
0
0
Bus10
-0.093
2.366
82.5
-3.9
Bus14
0.009
0.003
0.3
94.0
Bm16
0.084
-2.369
82.7
-3.6
Bus10
16.500
100.199
-0.1
0
0
0
0
BUS 3
-0.096
2.362
82.6
4.0
Bus9
0.096
-2.362
82.6
-4.0
Bus12
16.500
100,552
-0.2
0
0
0
0
Bm39
0.004
0.005
0.2
63.8
Bus38
-0.004
-0.005
0.2
63.8
Bus14
16.500
100.354
-0.1
0
0
0
0
BmI5
0.009
0.004
0.3
93.6
Bus9
-0.009
-0.004
0.3
93.6
13 s15
16.500
100.354
-0.1
0
0
0
0
13 s14
-0.009
-0.004
0.3
93.6
BAKER COMMODITIES
0.009
0.004
0.3
93.6
Bus16
16.500
100.417
-ol
0
0
0
0
Bus9
-0.083
2.370
82.6
-3.5
BM19
0.083
-2.370
82.6
-3.5
Bus18
0.480
100.451
-0.1
0
0
0
0
Bw20
0.000
0.000
0.0
0.0
Bus19
16.500
100.432
-0.1
0
0
0.000
-1.210
Bus16
-0.083
2.371
82.6
-3.5
13 s44
0.083
-1.160
40.5
-7.1
Bm20
16.500
100.451
-0.1
0
0
0
0
Bus44
-0.083
1.160
40.5
-7.1
Bus25
0.053
-1.179
41.1
4.5
Bm22
0.030
0.019
1.2
84.5
Bus18
0.000
0.000
0.0
0.0
SAN 094-216 (SR-06) VERNON (03/06/2015) MM 135853 REV. 0
ETAP
Page:
2
Project:
12.5.00
Location:
Date:
02-27-2015
Contract:
SN:
POWERENG-2
Engineer:
Revision:
Base
Study Case: Min
Loading
Filename: DAVIS
Config.:
Normal
Bus
Voltage
Generation
Load
Load Flow
XFMR
ID,
kV
%Mag.
Ang.
MW War
MW
War
iD
MW
War
Amp
%PF %Tap
Bus22
16.500
100A51
-0.1
0
0
0
0
Bw23
0.030
0.019
1.2
84.4
Bus20
-0.030
-0.019
1.2
84.4
Bus23
16.500
100.451
-0.1
0
0
0
0
Bus22
-0.030
-0.019
1.2
84.4
FARNER JOHN (NORTH
0.030
0.019
1.2
84.4
SUB)
Bus24 -37th ST.
16.500
100.496
-0.2
0
0
0
0
Bus47
0.004
0.003
0.2
85.0
SOTO ST
-0.038
1.189
41.4
-3.2
Bus29
0.034
-1.191
41.5
-2.8
Bus25
16.500
100.456
-0.1
0
0
0
0
Bw20
-0.053
1.179
41.1
4.5
SOTO ST
0.053
-1.179
41.1
4.5
Bus26
16.500
100.466
-0.2
0
0
0
0
SOTO ST
-0.015
-0.009
0.6
85.0
Bus33
0.004
0.003
0.2
85.0
Bus41
0.011
0.007
0.4
85.0
Bus27
16.500
100.466
-0.2
0
0
0
0
Bus28
0.000
0.000
0.0
0.0
SOTO ST
0.000
0.000
0.0
0.0
Bm28
16.500
100.466
-0.2
0
0
0
0
Bus27
0.000
0.000
0.0
0.0
Line20-
0.000
0.000
0.0
0.0
Bus29
16.500
100A96
-0.2
0
0
0
0
Bw30
0.034
-1.191
41.5
-2.8
Bus24 -37th ST.
-0.034
1.191
41.5
-2.8
Bus30
16.500
100.555
-0.2
0
0
0.000
-1.213
Bm29
-0.033
1.191
41.5
-2.8
Bm31
0.033
0.022
1.4
83.0
Bm31
16.500
100.555
-0.2
0
0
0
0
Bw30
-0.033
4023
1.4
82.9
Bm45
0.012
OA06
0.5
88.4
Bus34
0.021
0.016
0.9
79.6
Bm33
16.500
100.466
-0.2
0
0
0
0
13 s26
-0.004
-0.003
0.2
85.0
Bm35
0.004
0.003
0.2
85.0
Bm34
16.500
100.554
-0.2
0
0
0
0
Bus31
-0.021
-0.016
0.9
79.1
Santa Fe Ave
0.021
0.016
0.9
79.1
Bus35
0.480
I00A47
-0.2
0
0
0.004
0.003
Bus33
-0.004
-0.003
6.0
85.0
Bus37
16.500
100.553
-0.2
0
0
0
0
Santa Fe Ave
-0.021
-0.017
1.0
77.4
Bus38
0.010
0.010
0.5
72.0
Bus8
0.011
0.008
0.5
82.4
Bus38
16.500
100.552
-0.2
0
0
0
0
Bm40
0.005
o005
0.3
75.7
Bus37
-0.010
-0.010
0.5
70.5
Bm12
0.004
0.005
0.2
64.5
Bus39
16.500
100.552
-0.2
0
0
0
0
Bm12
-0.004
-0.005
0.2
63.8
HANNIBAL INDUSTRIES
0.004
0.005
0.2
63.8
(2250
Bus40
16.500
100.552
-0.2
0
0
0
0
Bus38
-0.005
4005
0.3
75.7
SAN 094-216 (SR-06) VERNON (03/06/2015) MM 135853 REV. 0
ETAP
Project:
Page:
3
12.5.00
Location:
Date:
02-27-2015
Contract:
SN:
POWERENG-2
Engineer:
Revision:
Base
Study Case: Min
Loading
Filename: DAVIS
Config.:
Normal
Bus
Voltage
Generation
Load
Load Flow
XFMR
ID
kV
%Mag.
Ang.
MW Mvar
MW
Mvw
ID
MW
Mvar
Amp
%PF %Tap
HANNIBAL INDUSTRIES
0.005
0.005
0.3
75.7
(2240
Bus41
16.500
100.466
42
0
0
0
0
Bus26
-0.011
-0.007
0.4
85.0
Bm42
0.011
0.007
0.4
85.0
Bus42
0A80
100.452
-0.2
0
0
0.011
0.007
Bm41
-0.011
-0.007
15.0
85.0
Bus43
16.500
1 00. 125
0.0
0
0
0
0
DOWNEY RD
-0.104
2.353
82.3
4A
BANDINI BLVD
0.104
-2.353
82.3
4A
Bus44
16.500
I00A39
-0.1
0
0
0
0
Bm20
0.083
-1.160
40.5
-T1
Bus19
-0.083
1.160
40.5
-7.1
Bus45
16.500
100.555
-0.2
0
0
0
0
Bm31
-0.012
-0.006
0.5
98.3
Bus46
0.003
0.001
0.1
91.4
Bm3
0.009
0.005
0.4
8T 1
Bus46
W500
100554
-0.2
0
0
0
0
Bus45
-0.003
-0.002
0.1
86.7
Bw50
0.000
0.000
0.0
93.7
CR LAURENCE
0.003
0.002
0.1
85.8
Bus47
16.500
100.496
42
0
0
0
0
Bw24 -37th ST.
-0.004
-0.003
0.2
85.0
Bw48
0.004
0.003
0.2
85.0
Bus48
0.480
100.478
-0.2
0
0
0.004
0.003
Bus47
-0.004
-0.003
6.0
85.0
Bus49
0.480
100.550
-0.2
0
0
0
0
13 s50
0.000
0.000
0.5
88.5
Bus50
1&500
100.554
-0.2
0
0
0
0
Bm46
0.000
no00
0.0
88.5
Bus49
0.000
0.000
0.0
88.5
Bus51
16.500
100.006
0.0
0
0
0
0
BmI
-0.105
2.350
82.3
4.5
Bust
0.105
-2.350
82.3
4.5
Bm52
16.500
100.554
-0.2
0
0
0
0
Santa Fe Ave
0.000
0.000
0.0
0.0
C.R. LAURENCE
0.480
100.522
-0.2
0
0
0.003
0.002
Bus46
-0.003
4002
3.9
85.8
DOWNEYRD
16.500
100.096
0.0
0
0
0
0
Bm43
0.104
-2.352
82.3
4A
Bm2
-0.104
2.352
82.3
4.4
FARMER JOHN (NORTH
0.480
100A23
42
0
0
0.030
0.019
Bm23
-0.030
-0.019
42.2
84.5
SUB)
HANNIBAL
0.480
100.529
-0.2
0
0
0.011
0.008
Bm8
-0.011
-0.008
16.4
82.3
INDUSTIES(3851)
HANNIBAL INDUSTRIES
0.480
100.538
-0.2
0
0
0.005
0.005
Bus40
-0.005
-0.005
8.7
75.7
(2240
HANNIBAL INDUSTRIES
0.480
100.525
-0.2
0
0
0.004
0.005
Bm39
-0.004
4005
8.2
63.9
(2250
NATURAL DYEING CO.
0.480
100.538
-0.2
0
0
0.009
0.005
Bm3
-0.009
-0.005
12.5
86.9
Santa Fe Ave
16.500
100.554
-0.2
0
0
0
0
Bus34
-0.021
4016
0.9
79.0
Bm37
0.021
0.017
0.9
78.0
Bm52
0.000
0.000
0.0
0.0
Line28-
0.000
0.000
0.0
0.0
Line36-
0.000
0.000
0.0
0.0
SAN 094-216 (SR-06) VERNON (03/06/2015) MM 135853 REV. 0
ETAP
Project:
Page:
4
12.5.00
Location:
Date:
02-27-2015
Contract:
SN:
POWERENG-2
Engineer:
Revision:
Base
Study
Case: Min
Loading
Filename:
DAVIS
Config.:
Normal
Bus
Voltage
Generation
Load
Load Flow
XFMR
ID W
%Mag Ang.
MW
Mvar
MW
War
ID
MW
War
Amp
%PF %Tap
SOTO ST
16.500
100.466 -0.2
0
0
0
0
Bus26
0.015
0.009
0.6
85.0
Bus25
-0.053
1.179
41.1
4.5
Bus27
0.000
0.000
0.0
0.0
Bus24 -37th ST.
0.038
-L 188
41.4
-3.2
Linel 7-
0.000
0.000
0.0
0.0
UPS (333 Downey) 0.480
100.145 -0.1
0
0
0.008
0.009
Bus?
-0.008
-0.009
13.8
66.3
Linel4-
16.500
100.140 0.0
0
0
0
0
BANDINI BLVD
0.000
0.000
0.0
0.0
Linel7-
16.500
100.466 -0.2
0
0
0
0
SOTO ST
0.000
0.000
0.0
0.0
Line20-
16.500
100.466 -0.2
0
0
0
0
Bus28
0.000
0.000
0.0
0.0
Line28-
16.500
100.554 -0.2
0
0
0
0
Santa Fe Ave
0.000
0.000
0.0
0.0
Line36-
16.500
100.554 -0.2
0
0
0
0
Santa Fe Ave
0.000
0.000
0.0
0.0
Indicates
a voltage regulated bus (voltage
controlled or swing type machine
connected to it)
# Indicates a bus with a load mismatch of more
than 0.1 MVA
SAN 094-216 (SR-06) VERNON (03/06/2015) MM 135853
REV. 0
Project: ETAP
Location: 12.5.00
Contract:
Engineer:
Study Case: Min Loading
Filename: KAESER
LOAD FLOW REPORT
Bus
Voltage
Generation
Load
ID
kV
kV
Ang.
MW War
MW
War
1- AIR PRODUCTS (3305)
0.480
0A74
-0.7
0
0 0.112
0.090
Bus24
2-AIR PRODUCTS
0.480
0.461
-2.4
0
0 0.010
0.004
Bm30
3- VERNON
0.480
0.479
-0.3
0
0 0
0
Bw23
DISTRIBUTION C.
4- CONTAINER RECYCLE
0.480
0.470
-1.0
0
0 0.208
0.219
Bw99
5-(1) VERNON DIS.
0480
0.475
-1.0
0
0 0.294
0.154
Bm35
CENTER
5- (2) VERNON DIS.
0.480
0A73
-0.9
0
0 0.176
0.170
Bm37
CENTER
5- (3) VERNON DIS.
0.480
0.479
43
0
0 0.001
0.001
Bus39
CENTER
6- SEVEN UP
0.480
0A75
-0.9
0
0 0.616
0.421
Bus42
8- CARGIL
0.480
0A79
-0.4
0
0 0.042
0.019
Bm49
CONTINENTAL
9- COMMERCIAL
0.480
0.475
-L I
0
0 0.097
0.047
Bm48
SANBLAST
10- V & L PRODUCE
0.480
0.471
-1.1
0
0 0.069
0.057
Bw54
I I- ENJOY PLASTIC
0.480
0.477
-0.7
0
0 0.057
0.083
Bus61
12- AMERICAN
0A80
0.480
-0.5
0
0 0
0
13 s64
ACTIVEWEAR
13- THE TIMING INC.
0.480
0.480
45
0
0 0
0
Bm66
14- NICOLO CONCEPT
0.480
0.477
-0.8
0
0 0.025
0.016
Bm72
16- C. R. LAURANCE
0.480
0.451
-3.3
0
0 0.220
0.149
Bus76
17- HANNIBAL
0A80
0A64
-2.3
0
0 0.092
0.058
Bw78
INDUSTRIES
18- SANTA FE BUSINESS
0.480
0.479
-0.5
0
0 0.002
0.002
Bus58
PAR
19- PROFESSIONAL
0.480
0.477
-0.7
0
0 0.114
0.091
Bw51
PRODUCE
20- SANTA FE PLAZA
0.480
0.478
-0.7
0
0 0.017
0.013
Bus69
21- PREFERRED
0.480
0A76
-0.8
0
0 0.267
0.127
Bus20
FREEZER
22-ARCADIA, INC.
0.480
0.469
-1.3
0
0 0.482
0.386
Busll
23- PREFEERED
0.480
0.477
-0.6
0
0 0.173
0.086
B-19
FREEZER
26TH ST
16.500
16.483
-u l
0
0 0
0
Bm4
Buss
Line5-
28TH ST
16.500
16.491
-0.5
0
0 0
0
Bw56
Bw60
Line51-
38TH ST
16.500
16.524
-0.6
0
0 0
0
13 s94
"Im
Page:
I
Date:
02-27-2015
SN:
POWERENG-2
Revision:
Base
Config.:
Normal
Load Flow
XFMR
ID MW
War
Amp
%PF %Tap
-0.112
-0.090
174.5
77.8
-0.010
4004
13.8
914
0.000
0.000
0.0
0.0
-0.208
.0.219
37L5
68.9
-0.294
-0.154
403.9
88.6
-0.176
-0.170
298.5
71.9
4001
-0.001
1.6
83.2
-0.616
-0.421
906.6
82.6
-0.042
-0.019
55.3
9L0
-0.097
-0.047
130.7
90.1
-0.069
-0.057
109.0
77.2
4057
-0.083
122.2
56.3
0.000
0.000
0.0
0.0
0.000
0.000
0.0
0.0
-0.025
-0.016
35.9
84.4
-0.220
-0.149
340A
82.9
-0.092
4058
135.4
84.5
-0.002
4002
3.3
83.2
-0.114
-0.091
176.6
78.2
-0.017
-0.013
26.1
78.9
-0.267
-0.127
358.5
90.2
-0.482
-0.386
760.6
78.1
-0.173
-0.086
233.9
89A
-3.099
0.121
108.6
-99.9
3.099
-0.121
108.6
-99.9
0.000
0.000
0.0
0.0
-0.057
-0.084
3.5
56.2
0.057
0,084
3.5
56.2
0.000
0.000
0.0
0.0
0.321
-0.972
35.8
-31.3
SAN 094-216 (SR-06) VERNON (03/06/2015) MM 135853 REV. 0
Project:
Location:
Contract:
Engineer:
Filename: KAESER
Bus
Voltage
ETAP
12.5.00
Study Case: Min Loading
Generation Load
Load Flow
Page:
Date:
SN:
Revision:
Config.:
2
02-27-2015
POWERENG-2
Base
Normal
XFMR
ID
kV
kV
Ang.
MW
Mvar
MW Mvar
ID
MW
Mvar
Amp
%PF %Tap
ALAMEDA&37TH
-0.321
0.972
35.8
-31.3
Line62-
0.000
0.000
0.0
0.0
ALAMEDA & 37TH
16.500
16.522
-0.6
0
0
0
0 Bus81
-0.321
0.972
35.8
-31.3
38TH ST
0.321
-0.972
35.8
-31.3
ALAMEDAAVE
16.500
16.509
-0.6
0
0
0
0 Bus71
-0.321
0.972
35.8
-31A
Bus8t
0.321
-0.972
35.8
-31.4
•Bust
16.500
16.500
0.0
3.102
-0.114
0
0 VERNONAVE
3.102
-0.114
108.6
-99.9
Bw3
16.500
16.488
-0.1
0
0
0
0 DOWNEY RD
-3.100
0.118
108.6
-99.9
Bus4
3100
-0. 118
108.6
-99.9
Bus4
16.500
16.488
-0.1
0
0
0
0 26TH ST
3.100
-0.118
108.6
-99.9
Bus3
-3.100
0.118
108.6
-99.9
Bus5
16.500
16.482
-0.1
0
0
0
0 26TH ST
-3.099
0.121
108.6
-99.9
Bus6
3.099
-0.121
108.6
-99.9
Bus6
16.500
16A82
-0.1
0
0
0
0 Bus7
0.925
0.623
39.1
82.9
Bus5
-3 098
0.121
108.6
-99.9
Siena Pine Ave.
2.173
4745
80.5
-94.6
Bus7
16.500
16.480
-0.1
0
0
0
0 Bus6
4925
-0.623
39.1
82.9
Bw8
0.925
0.623
39.1
82.9
Bus8
16.500
16.480
-0.1
0
0
0
0 Bus7
-0.925
-0.623
39.1
829
WASHINGTON BLVD
0.925
0.623
39.1
82.9
Linel l-
0.000
0.000
0.0
0.0
Bus9
1&500
16.475
-0.3
0
0
0
0 Siena Pine Ave.
-2.170
0.748
80.5
-94.5
Bus24
0.112
0.092
5.1
77.4
Bus23
0.000
0.000
0.0
0.0
Bw29
2.058
-0.940
77.9
-92.6
Busll
16.500
16.475
-0.2
0
0
0
0 WASHINGTON BLVD
-0.485
-0.404
211
76.8
22- ARCADIA, INC.
0.485
0.404
22.1
76.8
Bw12
16.500
16.476
-0.2
0
0
0
0 Bus14
0A40
0.219
17.2
89.5
WASMNGTON BLVD
-0.440
-0.219
17.2
89.5
Line14-
0.000
0.000
0.0
0.0
Bus14
16.500
16.476
-0.2
0
0
0
0 Bus12
-0A40
-0.219
17.2
89.5
Bw19
0.173
0.088
6.8
89.1
Bus20
0.267
0.131
10.4
89.8
Bus19
16.500
16.475
-0.2
0
0
0
0 Bus14
-0.173
-0.088
6.8
89.1
23- PREFEERED FREEZER
0.173
0.088
6.8
89.1
Bus20
16.500
16.475
-0.2
0
0
0
0 Bus14
-0.267
-0.131
10.4
89.8
21- PREFERRED FREEZER
0.267
0.131
10A
99.8
Bus23
16.500
16.475
-0.3
0
0
0
0 Bus9
0.000
0.000
0.0
0.0
SAN 094-216 (SR-06) VERNON (03/06/2015) MM 135853 REV. 0
ETAP
Project:
Page:
3
12.5.00
Location:
Date:
02-27-2015
Contract:
SN:
POWERENG-2
Engineer:
Revision:
Base
Study Case: Min
Loading
Filename:
KAESER
Config.:
Normal
Bus
Voltage
Generation
Load
Load Flow
XFMR
ID kV
kV
Ang.
MW Mvar
MW
Mvar
ID
MW
War
Amp
%PF %Tap
3- VERNON
0.000
0.000
0.0
0.0
DISTRIBUTION C.
Bus24
16.500
16.474
-0.3
0
0
0
0
Bus9
-0.112
-0.092
5.1
773
1- AIR PRODUCTS(3305)
0.112
0.092
5.1
773
Bus29
16.500
16.475
-0.3
0
0
0
0
BUS9
-2.058
0.940
77.9
-92.6
Bus31
2.048
-0.945
77.6
-92A
Bus80
0.010
0.005
0.4
90.7
Bus30
16.500
16.475
-0.3
0
0
0
0
BM80
-0.010
-0.005
0A
89.9
2- AIR PRODUCTS
0.010
0.005
0A
89.9
Bus31
16.500
16.474
-0.3
0
0
0
0
Bus29
-2.047
0846
7T6
-92A
Bus34
0.473
0.334
20.3
8L7
Bus40
1.365
-L405
68.6
-69.7
Bus33
0.210
0.226
10.8
68.1
Bus33
16.500
16.473
-0.3
0
0
0
0
Bus31
-0.210
-0.226
10.8
68.1
Bus99
0.210
0.226
10.8
68.1
Bm34
16.500
16.473
-0.3
0
0
0
0
Bus31
-0.473
-0.334
20.3
81.7
Bus35
0.295
0.159
11.7
88.0
Bus36
0.177
0.175
8.7
71.3
Bus35
16.500
16.472
-0.3
0
0
0
0
Bus34
-0.295
-0.159
11.7
88.0
5- (1) VERNON DIS.
0.295
0.159
11.7
88.0
CENTER
Bus36
16.500
16.473
-0.3
0
0
0
0
Bus34
-0.177
-0.175
8.7
71.3
Bus37
0.176
0.174
8.7
7L2
Bus38
0.001
0.001
0.0
85.6
Bus37
16.500
16.472
-0.3
0
0
0
0
Bus36
-0.176
-0.174
8.7
71.2
5- (2) VERNON DIS.
0.176
0.174
8.7
71.2
CENTER
Bus38
16.500
16.473
-0.3
0
0
0
0
Bus36
-0.001
-0.001
0.0
83.7
Bus39
0.001
0.001
0.0
83.7
Bus39
16.500
16.473
-0.3
0
0
0
0
Bus38
-0.001
-0.001
0.0
83.2
5- (3) VERNON DIS.
0.001
0.001
0.0
83.2
CENTER
Bus40
16.500
16.475
-0.3
0
0
0
0
Bus31
-1.365
1.405
68.6
-69.7
Bus41
0.617
-0.766
34.5
-62.8
Bus43
0.747
-0.640
34.5
-76.0
Bm41
16.500
16.475
43
0
0
0.000
-1.196
Bus40
-0.617
0.766
34.5
-62.8
Bus42
0.617
0.431
26.4
82.0
Bus42
W500
16.473
-0.3
0
0
0
0
Bus41
-0.617
-0.431
26.4
82.0
6- SEVEN UP
0.617
0.431
26.4
82.0
Bus43
16.500
16.476
44
0
0
0
0
Bus40
-0.747
0.640
34.5
-76.0
SOTO ST
0.747
-0.640
34.5
-76.0
SAN 094-216 (SR-06) VERNON
(03/06/2015) MM 135853
REV. 0
ETAP
Project:
Page:
4
~�
Location:
12.5.00
Date:
02-27-2015
Contract:
SN:
POWERENG-2
Engineer:
Revision:
Base
Study Case: Min Loading
Filename: KAESER
Config.:
Normal
Bus
Voltage
Generation
Load
Load Flow
XFMR
ID
W
W
Ang.
MW War
MW War
ID
MW
War
Amp
%PF %Tap
13 s45
16.500
16.478
-0.4
0
0
0
0
SOTO ST
-0.747
0.640
34.5
-76.0
Bus47
0.747
.0.640
34.5
-76.0
Bm47
16.500
16.480
-0.4
0
0
0
0
13 545
-0.747
0.640
34.5
-75.9
Bus48
0.097
0.048
3.8
89.7
Bus49
0.042
0.019
1.6
91.0
Bus50
0.608
-0.707
32.7
-65.2
Bus48
16.500
16.480
-0.4
0
0
0
0
Bm47
-0.097
-0.048
3.8
89.6
9- COMMERCIAL
0.097
0.048
3.8
89.6
SANBLAST
Bus49
16.500
16.480
-0.4
0
0
0
0
Bm47
-0.042
-0.019
1.6
91.0
8- CARGIL
0.042
0.019
1.6
91.0
CONTINENTAL
Bus50
16.500
16.484
-0.4
0
0
0
0
Bw47
-0.607
0.707
32.6
-65.2
Bus51
0.114
0.092
5.1
77.9
Bus53
0.493
-0.799
32.9
-52.5
Bus5l
16.500
16.483
-0.4
0
0
0
0
Bw50
-0.114
-0.092
5.1
77.9
19- PROFESSIONAL
0.114
0.092
5.1
77.9
PRODUCE
Bm52
16.500
16.487
-0.5
0
0
0
0
Bus54
0.069
0.058
3.2
76.5
Bus53
-0.493
0.799
32.9
-52.5
SANTA FE AVE
0.424
-0.857
33.5
-44.3
Bus53
16.500
16.485
-0.5
0
0
0
0
Bus50
-0A93
0.799
32.9
-52.5
Bw52
0.493
-0.799
32.9
-52.5
Bw54
16.500
16.487
-0.5
0
0
0
0
Bus52
-0.069
4058
3.2
76.5
to- V & L PRODUCE
0.069
0.058
3.2
76.5
Bus56
16.500
16A91
45
0
0
0
0
Bus58
0.002
0.002
0.1
83.2
SANTA FE AVE
-0.059
-0.085
3.6
57.1
28TH ST
0.057
0.084
3.5
56.3
Bus58
16.500
16.491
-0.5
0
0
0
0
Bus56
-0.002
-0.002
0.1
83.2
18- SANTA FE BUSINESS
0.002
0.002
0.1
83.2
PAR
Bus60
16.500
16.491
-0.5
0
0
0
0
28114 ST
-0.057
-0.084
3.6
56.2
13 s61
0.057
0.084
3.6
56.1
Bm63
0.000
0.000
0.0
0.0
13 s61
16.500
16A91
-0.5
0
0
0
0
Bus60
-0.057
4084
3.6
56.1
II - ENJOY PLASTIC
0.057
0.084
3.6
56.1
Bm63
16.500
16.491
-0.5
0
0
0
0
Bm60
0.000
0.000
0.0
0.0
13 s64
0.000
0.000
0.0
0.0
13 s65
0.000
0.000
0.0
0.0
Bus64
16.500
16A91
45
0
0
0
0
Bm63
0.000
0.000
0.0
0.0
SAN 094-216 (SR-06) VERNON (03/06/2015) MM 135853 REV. 0
ETAP
Project:
Page:
5
12.5.00
Location:
Date:
02-27-2015
Contract:
SN:
POWERENG-2
Engineer:
Revision:
Base
Study Case: Min
Loading
Filename: KAESER
Config.:
Normal
Bus
Voltage
Generation
Load
Load Flow
XFMR
tD
kV
kV
Ang.
MW Mvar
MW
Mvar
ID
MW
Mvar
Amp
%PF %Tap
12- AMERICAN
0.000
0.000
0.0
0.0
ACTIVEWEAR
Bus65
16.500
16.491
-0.5
0
0
0
0
Bus63
0.000
0.000
0.0
0.0
Bus66
0000
0.000
0.0
&0
Bus66
16.500
16A91
-0.5
0
0
0
0
Bus65
0.000
0.000
0.0
0.0
13- THE TIMING INC.
0.000
0.000
0.0
0.0
Bus67
16.500
16.493
-0.5
0
0
0
0
Bas69
0.017
0.013
0.8
78.8
SANTA FE AVE
-0.364
0.942
35.4
-36.1
Bus70
0.347
-0.956
35.6
-34.1
Bus69
16.500
16.493
-0.5
0
0
0
0
Bus67
-0.017
-0.013
0.8
78.8
20- SANTA FE PLAZA
0.017
0.013
0.8
78.8
Bus70
16.500
16.495
-0.5
0
0
0
0
Bus67
-0.347
0.956
35.6
-34.1
Bus71
0.347
-0.956
35.6
-34.1
Bus71
16.500
16.497
-0.5
0
0
0
0
Bus70
-0.347
0.956
35.6
-34.1
Bw72
0.025
0.016
1.0
84.2
ALAMEDA AVE
0.322
-0.972
35.8
-31.4
Bus72
16.500
16.497
-0.5
0
0
0
0
Bm71
4025
-0.016
10
84.1
14- NICOLO CONCEPT
0.025
0.016
LO
84.1
Bus73
16.500
16.522
-0.6
0
0
0
0
ROSS ST
0.321
0.232
13.8
81.0
Bus84
-0.321
-0.232
13.8
81.0
Bus76
16.500
16.521
-0.6
0
0
0
0
ROSS ST
-0.227
-0.169
9.9
80.2
16- C. K LAURANCE
0.227
0.169
9.9
80.2
Bus77
16.500
16.520
-0.6
0
0
0
0
ROSS ST
-0.093
-0063
3.9
82.9
Bw78
0.093
0.063
3.9
82.9
Line69-
0.000
0.000
0.0
0.0
Bus78
W500
16.520
-0.6
0
0
0
0
Bus77
-0.093
-0.063
3.9
82.9
17- HANNIBAL
0.093
0.063
3.9
82.9
INDUSTRIES
Bus80
16.500
-16.475
-0.3
0
0
0
0
Bw30
0.010
0.005
0.4
90.4
Bus29
-0.010
-0.005
0A
90.4
Bus81
16.500
16.512
-0.6
0
0
0
0
ALANIEDA& 37TH
0.321
-0.972
35.8
-31 A
ALAMEDA AVE
-0.321
0.972
35.8
-31.4
Bus84
16.500
16.525
-0.6
0
0
0.000
-1.204
38TH ST
-0.321
0.972
35.8
-31.3
Bus73
0.321
0.232
13.8
81.1
Bus99
0.480
0.471
-1.0
0
0
0
0
4- CONTAINER RECYCLE
0.209
0.219
37L5
68.9
Bus33
-0.209
-0.219
371.5
68.9
DOWNEY RD
W500
16.495
0.0
0
0
0
0
VERNON AVE
-3.101
0.116
108.6
-99.9
Bw3
3.101
-0.116
108.6
-99.9
ROSS ST
16.500
16.521
-0.6
0
0
0
0
Bus73
-0.321
-0.232
13.8
81.0
{
Bus76
0.227
0.169
9.9
80.2
SAN 094-216 (SR-06) VERNON (03/06/2015) MM 135853 REV. 0
Project:
Location:
Contract:
Engineer:
Filename: KAESER
Bus
Voltage
ETAP
12.5.00
Study Case: Min Loading
Generation Load
Page:
Date:
SN:
Revision:
Config.:
Load Flow
6
02-27-2015
POWERENG-2
Base
Normal
XFMR
ID
kV
kV
Ang.
MW
Mvar
MW Mvar
ID
MW
Mvar
Amp
%PF %Tap
Bus77
0.093
0.063
3.9
83A
SANTAFEAVE
16.500
16.492
45
0
0
0
0
Bus52
-0.423
0.857
33.5
-44.3
Bus56
0.059
0.085
3.6
57.2
Bus67
0.364
-0.942
35.4
-36.1
Sierra Pine Ave.
16.500
16.477
-0.2
0
0
0
0
Bus6
-2.171
0.747
80.5
-94.6
Bus9
2.171
.0.747
80.5
-94.6
Line82-
0.000
0.000
0.0
0.0
SOTO ST
16.500
16.477
-0.4
0
0
0
0
Bus43
-0.747
0.640
34.5
-76.0
Bus45
0.747
-0.640
34.5
.76.0
Line34-
0.000
0.000
0.0
0.0
VERNON AVE
16.500
16.497
0.0
0
0
0
0
Bust
-3.102
0.115
108.6
-99.9
DOWNEY RD
3.102
4115
108.6
-99.9
WASHINGTON BLVD
16.500
16.477
42
0
0
0
0
Bus8
-0.925
-0.623
39.1
82.9
Bus11
0.485
0.404
22.1
76.8
Busl2
0.440
0.219
17.2
89.5
Line5-
16.500
16.483
-0.1
0
0
0
0
26TH ST
0.000
0.000
0.0
0.0
Linell-
16.500
16.480
-0.1
0
0
0
0
Bus8
0.000
0.000
0.0
0.0
Linel4-
16.500
16.476
-0.2
0
0
0
0
Busl2
0.000
0.000
0.0
0.0
Line34-
16.500
16.477
-0.4
0
0
0
0
SOTO ST
0.000
0.000
0.0
0.0
Line51-
16.500
16A91
-0.5
0
0
0
0
28TH ST
0.000
0.000
0.0
0.0
Line62-
16.500
16.524
-0.6
0
0
0
0
38TH ST
0.000
0.000
0.0
0.0
Line69-
16.500
16.520
46
0
0
0
0
Bus77
0.000
0.000
0.0
0.0
Line82-
16.500
16.477
-0.2
0
0
0
0
Sierra Pine Ave.
0.000
0.000
0.0
0.0
Indicates a voltage regulated bus (voltage
controlled
or swing type
machine connected to it)
# Indicates a bus with a load
mismatch of more
than o.I
MVA
SAN 094-216 (SR-06) VERNON (03/06/2015) MM 135853
REV. 0
ETAP
Project:
12.S.00
Location:
Contract
Engineer:
Study Case: Min
Loading
Filename: NORRIS
LOAD FLOW REPORT
Bus
Voltage
Generation
Load
ID
W
%Mag
Ang.
MW
War
MW
War
ID
26TH & BONNIE BLVD
16.500
100.465
-0.4
0
0
0
0
Bus72
Bus50
Line48-
48TH St.
16.500
100.155
-0.2
0
0
0
0
49TH ST
Bus53
49TH ST
1&500
100.156
-0.2
0
0
0
0
Bus9
Bus10
48TH St
Line42-
ACADEMIA FURNITURE
0.480
100.073
42
0
0
0.005
0.004
Bus17
ATLANTIC BLVD
16.500
100.298
-0.3
0
0
0
0
Bas19
Bus22
Bus33
Atlantic Blvd
16.500
100.353
-0A
0
0
0
0
Bus63
Bus92
BANDINI BLVD
16.500
100.352
-0.4
0
0
0
0
Bus38
Bus39
Bus44
Line62-
Y Bus1
1&500
100.000
0.0
1.323
-1,415
0
0
DOWNEY(RISER)
Bust
16.500
100.014
0.0
0
0
0
0
FRUITLAND I
Southland box
Buss
16.500
100.043
-0.1
0
0
0
0
FRUITLAND 2
UNICOLD
Bus?
16.500
100.092
-0.1
0
0
0
0
FRUITLAND 3
PRINCESS PAPER
Bus8
16.500
100.110
41
0
0
0
0
FRUITLAND 3
CORONAAVE
Bus9
16.500
100.161
-0.2
0
0
0
0
CORONAAVE
49TH ST
Bus10
1&500
100,147
-0.2
0
0
0
0
49TH ST
Busl1
Bus16
Busl1
16.500
100.146
-0.2
0
0
0
0
Buslo
Bus12
Busl4
Page:
1
Date:
02-27-2015
SN:
POWERENG-2
Revision:
Base
Config.:
Normal
Load Flow XFMR
MW
War
Amp
%PF %Tap
-0.011
-0.007
0.5
85.0
0.011
0.007
0.5
84.6
0.000
0.000
0.0
0.0
-0.012
-0.022
0.9
48.8
0.012
0.022
0.9
48.8
-0.157
-0.126
7.0
77.8
0.144
0.105
6.2
80.9
0.012
0.022
0.9
49.0
0.000
0.000
0.0
0.0
-0.005
-0.004
7.9
77.4
-0.795
L849
70.2
-39.5
0.119
-1.097
38.5
-10.8
0.677
-0.752
35.3
-66.9
0.275
0.149
10.9
88.0
-0.275
-0.149
10.9
88.0
-0.648
0.771
35.1
-64.4
0.091
0.057
3.7
84.8
0.557
4827
34.8
-55.9
0.000
0.000
0.0
0.0
1.323
-L415
6T8
-68.3
-0.296
-0.222
12.9
80.1
0.296
0.222
12.9
80.1
-0.044
-0.037
2.0
76.3
0.044
0.037
2.0
76.3
-0.026
4042
L7
53.2
0.026
0.042
1.7
53.2
-0.955
1.719
68.7
-48.6
0.955
-1.719
68.7
-48.6
-0.157
-0.126
7.0
7T9
0.157
0.126
7.0
77.9
-0.144
-0.105
6.2
80.8
0.139
0.101
6.0
80.9
0.005
0.004
0.2
78.9
-0.139
-0.101
6.0
90.9
0.107
0.079
4.6
80.6
0.032
0.023
1.4
81.8
SAN 094-216 (SR-06) VERNON (03/06/2015) MM 135853 REV. 0
Project:
Location:
Contract:
Engineer:
Filename: NORRIS
Bus
Voltage
Generation
ETAP
12.5.00
Study Case: Min Loading
Load
Load Flow
Page:
Date:
SN:
Revision:
Config.:
2
02-27-2015
POWERENG-2
Base
Normal
XFMR
ID
kV
%Mag
Ang.
MW Mvar
MW
Mvar
ID
MW
Mvar
Amp
%PF %Tap
Bus12
16.500
100.146
-0.2
0
0
0
0
Busll
-0.107
-0.079
4.6
80.6
WINPLAST
0.107
0.079
4.6
80.6
Bus14
16.500
100.146
-0.2
0
0
0
0
Bush
-0.032
-0.023
1.4
8L7
Bm15
0.032
0.023
1.4
8L7
Bust
16.500
100.146
-0.2
0
0
0
0
Bus14
-0.032
-0.023
1.4
81.7
U.S COSMOS PLASTIC
0.032
0.023
1.4
81.7
Bw16
16.500
100.147
-0.2
0
0
0
0
BmIo
-0.005
-0.004
0.2
77.4
Bw17
0.005
0.004
0.2
77A
Bus17
16.500
100.147
-0.2
0
0
0
0
Bm16
-0.005
4004
0.2
77.4
ACADEMIA FURNITURE
0.005
0.004
0.2
77.4
13 s18
16.500
100.203
-0.2
0
0
0
0
CORONAAVE
-0.797
1.947
70.2
-39.6
Bm19
0.797
-1.847
70.2
-39.6
Bus19
16.500
100.280
-0.3
0
0
0
0
BM18
-0.796
1.849
70.2
-39.5
ATLANTIC BLVD
0.796
-1.949
70.2
-39.5
Bus22
16.500
100.315
-0.3
0
0
0
0
ATLANTIC BLVD
-0.119
1.097
38.5
-10.8
Bus23
0.119
-1.097
38.5
-10.8
Bus23
16.500
100.351
-0.3
0
0
0.000
-L208
Bus22
-0.118
L097
38.5
-10.7
Bw24
0.118
0.111
5.7
72.9
Bw24
16.500
100.345
43
0
0
0
0
Bus23
-0.118
4111
5.7
72.8
Bus25
0.118
0. 111
5.7
72.8
Bus25
16.500
100.335
-0.3
0
0
0
0
Bm24
-0.118
-0.112
5.7
72.7
Bm26
0.016
0.023
1.0
55.7
Bus27
0.103
0.089
4.7
75.8
Bw26
16.500
100.335
-0.3
0
0
0
0
13us25
4016
4023
1.0
55.7
DUNN-EDWARDS (4885)
0.016
0.023
1 0
55.7
Bus27
16.500
100333
-0.3
0
0
0
0
Bus25
-0.103
-0.089
4.7
75.7
Bm28
0.040
0.053
2.3
59.8
Bus29
0.063
0.035
2.5
87.3
Bus28
16.500
100.332
-0.3
0
0
0
0
11us27
-0.040
-0.053
2.3
59.8
DUNN EDWARDS (4927)
0.040
0.053
2.3
59.8
Bus29
16.500
100332
-0.3
0
0
0
0
Bus27
-0.063
-0.035
2.5
87.2
Bm30
0.063
0.036
2.5
86.7
Bm31
0.000
-0.001
0.0
0.0
Bus30
16.500
100.332
-0.3
0
0
0
0
Bus29
-0.063
-0.036
2.5
86.7
DUNN EDWARDS (4979)
0.063
0.036
2.5
86.7
Bus31
16.500
100,332
-0.3
0
0
0
0
13us29
0.000
0.000
0.0
0.0
Line64-
0.000
0.000
0.0
0.0
Bus33
16.500
100.304
-0.3
0
0
0
0
ATLANTIC BLVD
-0.676
0.752
35.3
-66.9
Bw34
0.676
-0.752
35.3
-66.9
SAN 094-216 (SR-06) VERNON (03/06/2015) MM 135853 REV. 0
Project:
Location:
Contract:
Engineer:
Filename: NORRIS
ETAP
12.5.00
Study Case: Mn Loading
Bus
Voltage
Generation
Load
ID
kV
%Mag.
Ang.
MW War
MW War
ID
Bus34
16.500
100.315
-0.3
0
0 0
0 Bus33
Bus35
Bus38
Line32-
Bus35
16.500
100.313
-0.3
0
0 0
0 13us34
VIACOM OUTDOOR
Bus38
16.500
100.347
-0.3
0
0 0
0 Bus34
BANDINI BLVD
Bus39
16.500
100.350
-0.4
0
0 0
0 BANDINI BLVD
Bus40
Bus40
1&500
100.349
-0.4
0
0 0
0 Bus42
Bus39
Bm42
1&500
100.348
-0.4
0
0 0
0 Bm40
RANDALLFOODS
Bus44
16.500
100.354
-0.4
0
0 0
0 BANDINI BLVD
Bw45
Bus46
Bus56
Bus45
16.500
100.354
-0.4
0
0 0
0 Bus44
WATINKS TRUCKING
Bus46
16.500
100.353
-0.4
0
0 0
0 Bus47
Bw44
Bus48
Bus47
16.500
100.353
-0.4
0
0 0
0 Bm46
CLASSIC CONCEPTS
Bus48
16.500
100.353
-0.4
0
0 0
0 Bus49
Bus46
Bus49
16.500
100.353
-0A
0
0 0
0 Bus48
PRIME WIRE & CABLE
Bus50
16.500
100.464
-0.4
0
0 0
0 26TH & BONNIE BLVD
13 s67
Bw53
1&500
1 00. 153
-0.2
0
0 0
0 48TH St.
13 s55
Bus55
0.480
99.407
-0.3
0
0 0
0 STERICYCLE
Bw53
Bus56
16.500
100.377
-0.4
0
0 0
0 Bus44
Bm80
Bus57
16.500
100.413
-0A
0
0 0
0 Bus58
Bm75
Page:
3
Date:
02-27-2015
SN:
POWERENG-2
Revision:
Base
Config.:
Nonnal
Load Flow XFMR
MW
Mvar
Amp
%PF %Tap
-0.676
0.752
35.3
-66.9
0.028
0.019
1.2
82.5
0.649
-0.771
35A
-64A
0.000
0.000
on
0.0
-0.028
-0.019
1.2
82.2
0.028
0.019
1.2
82.2
-0.648
0.771
35.1
-64.4
0.648
-0.771
35.1
64.4
-0.091
-0.057
3.7
84.8
0.091
0.057
3.7
84.8
0.091
0.057
3.7
84.7
-0.09I
-0.057
3.7
84.7
-0.091
-0.057
3.7
84.7
0.091
0.057
3.7
84.7
-0.557
0.827
34.8
-55.9
0.012
0.021
0.8
48.9
0.041
0.052
2.3
62.0
0.505
-0.900
36.0
-49.0
-0.012
-0.021
0.8
48.9
0.012
0.021
0.8
48.9
0.027
0.037
1.6
58.4
-0.041
-0.052
2.3
61.9
0.014
0.015
0.7
69.0
-0.027
-0.037
1.6
58A
0.027
0.037
1.6
58.4
0.014
0.015
0.7
68.9
-0.014
-0.015
0.7
68.9
-0.014
-0.015
0.7
68.9
0.014
0.015
0.7
68.9
-0.011
-0.007
0.5
82.8
0.011
0.007
0.5
82.8
-0.012
-0.022
0.9
48.3
0.012
0.022
0.9
48.3
0.012
0.022
30.4
48.4
-0.012
-0.022
30.4
48A
-0.505
0.900
36.0
4&9
0.505
-0.900
36.0
-48.9
0.180
0.143
8.0
78.1
0.050
-1.191
41.6
-4.2
SAN 094-216 (SR-06) VERNON (03/06/2015) MM 135853 REV. 0
ETAP
Project:
Page:
4
12.5.00
Location:
Date:
02-27-2015
Contract:
SN:
POWERENG-2
Engineer:
Revision:
Base
Study Case: Min Loading
Filename: NORRIS
Config.:
Normal
Bus Voltage Generation Load Load Flow XFMR
ID
kV
%Mag.
Ang.
MW
Mvar
MW
Mvar
ID
MW
Mvar
Amp
%PF %Tap
Bus80
-0.229
1.048
37A
-21A
Bus58
16.500
100.413
-0.4
0
0
0
0
Bus89
0.090
0.072
4.0
78.1
Busl15
0.090
0.072
4.0
78.1
Bus57
-0.180
-0.143
8.0
78.1
Bus63
1&500
100.346
-0.4
0
0
0
0
Atlantic Blvd
-0.275
-0.149
10.9
88.0
Preferred Freezer
0.275
0.149
10.9
8&0
Bus67
16.500
100.464
-0.4
0
0
0
0
Bas93
0.011
0.008
0.5
811
Bus50
-0.011
-0.008
0.5
82.3
Line67-
0.000
0.000
0.0
0.0
Bus72
16.500
100.465
-0A
0
0
0.000
-1.211
26TH & BONNIE BLVD
0.011
0.007
0.5
85.5
Bus75
-0.011
L204
42.0
-0.9
Bus75
16.500
100.452
-0.4
0
0
0
0
Bus57
-0.049
L192
4L5
-4.1
Bus72
0.011
-1.204
42.0
-0.9
Bus97
0.038
0.013
1.4
94.8
36.0
-08.9
Bus80
16.500
100.383
-0A
0
0
0
0
Bus56
-0.505
0.900
Bus57
0.229
-1.048
37.4
-21.4
Busl05
0.276
0.148
10.9
88.1
Bus89
16.500
100.411
-0.4
0
0
0
0
Bus58
-0.090
-0.072
4.0
78.1
SFAM & US GARMENT
0.090
0.072
4.0
78.1
BM91
16.500
100.365
-0.4
0
0
0
0
Bus92
0.276
0.149
10.9
88.0
Bus105
-0.276
4 149
10.9
88.0
Bus92
16.500
100.356
44
0
0
0
0
BM91
-0.275
-0.149
10.9
88.0
Atlantic Blvd
0.275
0.149
10.9
88.0
Bus93
16.500
100,464
44
0
0
0
0
Bus67
-0.011
-0.008
0.5
81.3
VAC ACQUSITION
0.011
0.008
0.5
81.3
Bus97
16.500
100.451
-0.4
0
0
0
0
Bus75
-0.038
-0.013
14
94.7
SEVEN FOR ALL
0.038
0.013
1 4
94.7
MANKIND
Busl05
16.500
100.368
-0.4
0
0
0
0
Bus80
-0.276
4 149
10.9
88.0
Bus91
0.276
0.149
10.9
88.0
Bus]15
16.500
100.412
-0.4
0
0
0
0
Bus58
-0.090
-0.072
4.0
78.1
Bus116
0.090
0.072
4.0
78.1
Bust 16
0A80
100.198
-0.5
0
0
0.090
0.071
Bus]15
-0.090
-0.071
137.7
78.3
CLASSIC CONCEPTS
0A80
101,535
-0.6
0
0
0.026
0.036
Bus47
-0.026
-0.036
53.2
58.8 2.500
CORONAAVE
16.500
100.163
-0.2
0
0
0
0
Bus8
-0.954
1.720
68.7
48.5
Bus9
0.157
0.126
TO
77.9
BM18
0.797
-1.846
70.3
-39.7
DOWNEY(RISER)
16.500
100.006
0.0
0
0
0
0
Bust
-1.323
1.416
67.8
-68.3
FRUITLAND 1
1.323
-L416
67.8
-68.3
ml
SAN 094-216 (SR-06) VERNON (03/06/2015) MM 135853 REV. 0
ETAP
Project:
Page:
5
l -
12.5.00
T
Location:
Date:
02-27-2015
Contract:
SN:
POWERENG-2
Engineer:
Revision:
Base
Study Case: Min
Loading
Filename: NORRIS
Config.:
Nonnal
Bus
Voltage
Generation
Load
Load Flow
XFMR
ID
kV
%Mag-
Ang.
MW
Mvar
MW
Mvar
ID
MW
Mvar
Amp
%PF %Tap
DUNN EDWARDS (4927)
0,480
99.780
-0.4
0
0
0.040
0.053
Bus28
-0.040
-0.053
79.9
59.9
DUNN EDWARDS (4979)
0.480
99.881
-0.6
0
0
0.063
0.036
Bus30
-0.063
-0.036
86.9
87.0
DUNN-EDWARDS (4885)
0.480
99.525
-0A
0
0
0.016
0.023
Bus26
-0.016
-0.023
33.8
55.8
FRUITLAND 1
16.500
100.016
0.0
0
0
0
0
Bus2
0.296
0.222
12.9
80.1
DOWNEY(RISER)
-1.323
1.416
67.8
-68.3
FRUITLAND 2
1.027
-1.638
67.6
-53. t
FRUITLAND 2
16.500
100.044
41
0
0
0
0
Bus5
0.044
0.037
2.0
76.3
FRUITLAND 1
-I 026
1.638
67.6
-53.1
FRUITLAND 3
0.982
-1.675
67.9
-50.6
FRUITLAND 3
16.500
100.092
-0.1
0
0
0
0
Bus7
0.026
0.042
1.7
53.2
FRUITLAND 2
-0.982
1.677
67.9
-50.5
Bus8
0.955
-L718
68.7
-48.6
Preferred Freezer
0.480
99.949
-0.7
0
0
0.275
0.147
Bus63
-0.275
4 147
375.4
88.2
PRIME WIRE & CABLE
0.480
100.101
-0.4
0
0
0.014
0.015
Bus49
4014
-0.015
24.8
69.0
PRINCESS PAPER
0.480
99.670
-0.2
0
0
0.026
0.042
Bus?
-0.026
-0.042
59.3
53.3
RANDALL FOODS
0A80
100.039
-0.6
0
0
0.091
0.056
Bus42
-0.091
-0.056
128.3
84.9
SEVEN FOR ALL
0.480
100.322
-0.5
0
0
0.038
0.013
Bus97
-0.038
4013
48A
94.8
MANKIND
SFAM & US GARMENT
0.490
100.197
-0.5
0
0
0.090
0.071
Bus89
4090
-0.071
137.7
78.3
Southland box
0.480
99.346
-0.5
0
0
0.296
0.218
Bust
-0.296
-0.218
445.0
80.5
STERICYCLE
0480
99.338
-0.2
0
0
0.012
0.022
Bus55
-0.012
-0.022
30.4
48.3
U.S COSMOS PLASTIC
0.480
99.744
44
0
0
0.032
0.023
Bus15
-0.032
-0.023
47.3
81.9
UNICOLD
0.480
99.747
-0.2
0
0
0.044
0.037
Bus5
-0.044
-0.037
68.8
76.5
VAC ACQUSITION
0.480
100.137
-0.5
0
0
0.011
0.008
Bus93
4011
-0.008
16.3
81.4
VIACOM OUTDOOR
0A80
99.516
-0.6
0
0
0.028
0.019
Bus35
-0.028
4019
40.3
82.6
WATINKS TRUCKING
0.480
100.049
-0A
0
0
0.012
0.020
Bus45
-0.012
-0.020
28.2
49.0
WINPLAST
0.490
99.229
-0.6
0
0
0.107
0.077
Bus12
-0.107
-0.077
159.5
81.1
Line32-
16.500
100.315
-0.3
0
0
0
0
Bas34
0.000
0.000
0.0
0.0
Line42-
16.500
100,156
-0.2
0
0
0
0
49TH ST
0.000
0.000
0.0
0.0
Line67-
W500
100.464
44
0
0
0
0
Bus67
0.000
0.000
0.0
0.0
Line48-
1&500
100,465
-0.4
0
0
0
0
26TH &BONNIE BLVD
0.000
0.000
0.0
0.0
Line62-
16.500
100,352
-0.4
0
0
0
0
BANDIM BLVD
0.000
0.000
0.0
0.0
Line64-
16.500
100.332
-0.3
0
0
0
0
Bus31
0.000
0.000
0.0
0.0
Indicates a voltage regulated
bus (voltage
controlled
or swing type
machine connected to it)
0 Indicates a bus with a load mismatch
of more
than 0.1
WA
SAN 094-216
(SR-06) VERNON (03/06/2015) MM 135853
REV. 0
�11
01
Maximum Loading - ETAP Results
SAN 094-216 (SR-06) VERNON (03/06/2015) MM 135853
REV.0
Project: ETAP
Location: 12.5.00
Contract:
Engineer:
Study Case: Max Loading
Filename: Feeder 2
Bus
voltage
LOAD FLOW REPORT
Generation Load
ID
kV
%Mag.
Ang.
MW
War
MW
War
ID
" 50TH ST
7.000
100.000
0.0
3.360
2.346
0
0
SEVILLE AVE
Bust
7.000
98.391
-0A
0
0
0
0
Bus22
PACIFIC BLVD
Bus31
Bus13-1
7000
95.870
-L2
0
0
0
0
Bus14-1
Bus38
Linel2-1-
Bus14-1
7.000
95.679
-1.2
0
0
0
0
Bus13-1
PABCO PAPER
Bus19
7.000
97.444
-0.7
0
0
0
0
LEONIS
Bus27
\
Bus26
Bus22
7000
98.385
-0.4
0
0
0
0
Bus]
DIGIFAB SYSTEMS
Bus26
7.000
97.318
-0.7
0
0
0
0
Bus38
Bus19
Bus36
Bus27
T000
97.443
-0.7
0
0
0
0
Bus19
Bus28
Bus28
0.480
96.095
-1.4
0
0
0.085
0.064
Bus27
Bus29
T000
99.212
-0.2
0
0
0
0
FRUITLAND AVE
PACIFIC BLVD
Bus31
7.000
97.890
-0.6
0
0
0
0
Bust
LEONIS
Bus32
7.000
97.652
-0.6
0
0
0
0
LEONIS
Bus33
Line35-
Bus33
7.000
97.652
-0.6
0
0
0
0
Bw32
Bus36
T000
97.316
-0.7
0
0
0
0
Bus26
Bus37
Bus37
0.480
95.844
-1.5
0
0
0.085
0.064
Bus36
Bus38
7.000
96.655
-0.9
0
0
0
0
Bus26
Bus 13-1
DIGtFAB SYSTEMS
0.480
96.968
-1.2
0
0
0.161
0.111
Bus22
FRUITLAND AVE
7.000
99.613
-0.1
0
0
0
0
SEVILLE AVE
Bus29
Page:
1
Date:
02-27-2015
SN:
POWERENG-2
Revision:
Base
Config.:
Normal
Load Flow XFMR
MW
Mvar
Amp
%PF %Tap
3.360
2.346
338.0
820
0.162
0.115
W6
8L5
-3.324
-2.283
338.0
82.4
3.162
2.168
321.4
82.5
1937
1.945
303. t
83 4
-2.937
-1.945
303A
83.4
0.000
0.000
0.0
0.0
-2.932
-1.940
303A
83.4
2.932
1.940
303.1
83.4
-3.141
-2.133
321A
82.7
0.086
0.066
9.2
79.3
3.055
2.067
312.2
828
-0A62
-0A15
16.6
8L5
0.162
0.115
16.6
81.5
2.967
1.996
303A
83.0
-3.053
-2.062
312.2
82.9
0.086
0.066
9.2
79.2
-0.086
4066
9.2
79.3
0.086
0.066
9.2
79.3
-0.085
-0.064
133.7
80.0
-3.342
-2.315
338.0
82.2
3.342
2.315
338.0
82.2
-3.151
-2.150
321.4
82.6
3.151
2.150
321.4
82.6
0.000
0.000
oo
0.0
0.000
0.000
0.0
0.0
0.000
0.000
0o
0.0
0.000
0.000
0.0
0.0
-0.086
-0.066
9.2
79.2
0.086
0.066
9.2
79.2
-0.085
-0.064
134.0
80.0
-2.953
-L973
3011
83.2
1953
1.973
303.1
83.2
-0.161
-0.111
242.8
82.3
-3.351
-2.331
338.0
82.1
3.351
2.331
338.0
82.1
SAN 094-216 (SR-06) VERNON (03/06/2015) MM 135853 REV. 0
ETAP
Project:
Page:
2
12.5.00
Location:
Date:
02-27-2015
Contract:
SN:
POWERENG-2
Engineer:
Revision:
Base
Study Case: Max
Loading
Filename: Feeder 2
Config.:
Normal
Bus
Voltage
Generation
Load
Load Flow
XFMR
ID W
%Mag Ang.
MW
Mvar
MW
War
ID
MW
War
Amp
%PF %Tap
LEONIS 7.000
97.652 -0.6
0
0
0
0
Bus32
0.000
0.000
0.0
0.0
Busl9
3.146
2.141
321.4
82.7
Bus31
-3.146
-2.141
321A
82.7
PABCO PAPER 0.480
91426 -4.6
0
0
2.908
L682
Bus14-1
-2.908
-1.682
4419.6
86.6
PACIFIC BLVD 7.000
98.802 -0.3
0
0
0
0
Busl
3.333
2.299
338.0
82.3
Bus29
-3.333
-2.299
33&0
82.3
Line20-
0.000
0.000
0.0
0.0
SEVILLEAVE 7.000
99.808 -0.1
0
0
0
0
50TH ST
-3.356
-2.339
338.0
82.0
FRUITLAND AVE
3356
2.339
338.0
82.0
Line20- 7.000
98.802 -0.3
0
0
0
0
PACIFIC BLVD
0.000
0.000
o.0
0.0
Linel2-1- T000
95.870 -1.2
0
0
0
0
Busl3-1
0.000
0.000
0.0
0.0
Line35- 7.000
97.652 -0.6
0
0
0
0
Bus32
0.000
0.000
0.0
0.0
* Indicates a voltage regulated bus (voltage
controlled or swing type machine
connected to it)
�.
# Indicates a bus with a load mismatch of more than 0.1 MVA
SAN 094-216 (SR-06) VERNON (03/06/2015) MM 135853
REV. 0
ETAP
Project:
Page:
1
12.5.00
Location:
Date:
02-27-2015
Contract:
SN:
POWERENG-2
Engineer:
Revision:
Base
Study
Case: Max
Loading
Filename: FEEDER I1
Config.:
Nonnal
LOAD FLOW REPORT
Bus
Voltage
Generation
Load
Load Flow
XFMR
ID
W
%Mag.
Ang.
MW
War
MW
War
ID
MW
Mvar
Amp
%PF %Tap
• 50TH ST
7.000
IW000
0.0
2.031
L219
0
0
SOTO ST
2.031
1.219
195.4
85.7
54TH ST & SOTO
T000
99.341
-0.2
0
0
0
0
FRUITLAND AVE
-2.022
-1.204
195.4
85.9
Bus3
1.040
0.746
106.2
81.3
Bus10
0.982
0.458
90.0
90.6
BCBG MAX
0A80
90.119
-5.7
0
0
0.924
0.547
Bus8
-0.924
-0.547
1432.8
86.1
BEST MEXICAN FOODS
0.480
98.749
-0.6
0
0
0.048
0.022
Bus24
-0.048
-0.022
619
91.0
BICKETT ST
7.000
99.165
-0.3
0
0
0
0
Bus10
-0.710
-0.296
64.0
92.3
Bus13
0.487
0.186
43A
93.4
Bus23
0.223
0.110
20.7
89.7
BOYLE AVE
7.000
99. 120
-0.3
0
0
0
0
Bus23
-0.175
-0.088
16.3
89A
Bust
0.175
0.088
16.3
89.4
Bust
7.000
99.083
-0.3
0
0
0
0
BOYLE AVE
-0.175
-0.088
16.3
89A
Bus2
n175
0.088
16.3
89A
Bust
7.000
W062
-0.3
0
0
0
0
Bust
-0.175
-0.088
16.3
89.4
Bush
0.175
0.088
16.3
89.4
Bus3
7.000
99.233
-0.2
0
0
0
0
54TH ST & SOTO
-1.039
-0.744
106.2
81.3
Bus4
1.039
0.744
106.2
81.3
Line3-
0.000
0.000
0.0
0.0
Bus4
7.000
99.184
-0.3
0
0
0
0
Bus5
0.083
0.049
8.0
86.2
Bus3
-1.039
-0.744
106.2
81.3
Bus7
0.956
0.695
98.3
80.9
Buss
7.000
W 180
-0.3
0
0
0
0
Bus4
-0.083
-0.049
&0
86.2
RICHARD KORAL
0.083
0.049
8.0
86.2
Bush
7,000
99.041
-0.3
0
0
0
0
Bus2
-0.175
-0.088
16.3
89.4
Bus9
0.175
0.088
16.3
89.4
Bus7
7.000
99.171
-0.3
0
0
0
0
Bus4
-0.955
4695
98.3
80.9
Buss
0.955
0.695
98.3
80.9
Line7-
0.000
0.000
0.0
0.0
Buss
7,000
99.165
-0.3
0
0
0
0
Bus7
-0.955
-0.695
98.3
80.9
BCBG MAX
0.955
0.695
98.3
80.9
Bus9
7.000
99.033
43
0
0
0
0
Bus6
-0.175
-0.088
16.3
89.4
Bus12
0.175
0.088
16.3
89A
Bus10
7,000
99.262
-0.2
0
0
0
0
Bus]]
0.271
0.160
26.2
86.1
54TH ST & SOTO
-0.982
-0.457
90.0
90.6
BICKETT ST
0.711
0.297
64.0
92.3
Busll
7.000
99.252
-0.2
0
0
0
0
Bus10
-0.271
-0.160
26.2
86.1
SAN 094-216 (SR-06) VERNON
(03/06/2015) MM 135853
REV. 0
Project: ETAP Page: 2
Location: 12.5.00 Date: 02-27-2015
Contract: SN: POWERENG-2
Engineer: Study Case: Max Loading Revision: Base
Filename: FEEDERII Config.: Normal
Bus Voltage Generation Load Load Flow XFMR
ID
kV
%Mag.
Ang.
MW
Mvar
MW
Mvar ID
MW
Mvar
Amp
%PF %Tap
WORLD VARIETY FOODS
0.271
0.160
26.2
86.1
13 s12
7.000
99.013
-0.3
0
0
0
0 Bus9
-0.175
-0.088
16.3
89A
Bw15
0.175
0.088
16.3
89.4
Bus13
7.000
99.132
-0.3
0
0
0
0 BICKETT ST
-0.487
-0.186
43.4
93.4
Bus 14
0208
0.013
17.3
99.8
Bus 16
0.279
0.173
27.3
84.9
Linell-
0.000
0.000
0.0
0.0
Bus14
7.000
99.122
-0.3
0
0
0
0 Bw13
-0.208
-0.013
17.3
99.8
SK TEXTILE
0.208
0.013
17.3
99.8
13 s15
7.000
99.007
-0.3
0
0
0
0 Bus22
0.088
0.044
8.2
89.4
Bus12
-0.175
-0.088
16.3
89.4
Bus27
0.088
0.044
8.2
89.5
Bus16
7.000
99.120
-0.3
0
0
0
0 Bm13
-0.279
-0.173
27.3
84.9
Bus17
0.279
O. 173
27.3
84.9
Bus17
7.000
99.103
-0.3
0
0
0
0 13 s18
0.088
0.044
8.2
89.4
Bus 16
-n279
-0.173
27.3
84.9
Bus20
0.191
0.129
19.2
82.8
Bus18
7.000
99.099
-0.3
0
0
0
0 Bus17
-0.088
-0.044
8.2
89.4
KATIE INC
0.088
0.044
8.2
89.4
Bus20
T000
99.095
-0.3
0
0
0
0 Bus21
0.191
0.129
19.2
82.8
Bm17
-0.191
-0.129
19.2
828
Line16-
0.000
0.000
0.0
0.0
13 s21
7-000
99.086
-0.3
0
0
0
0 Bus20
-0.191
4 129
19.2
82.8
KELLY TOY
0.191
0.129
19.2
828
Bus22
7.000
99.003
-0.3
0
0
0
0 Bw15
-0.088
-0.044
8.2
89A
SANDBERG FURNITURE
0.088
0.044
8.2
89A
Bus23
7.000
99.134
-0.3
0
0
0
0 BICKETT ST
-0.223
-0.110
20.7
89.7
Bw24
0.048
0.022
4.4
90.8
BOYLE AVE
0.175
0.088
16.3
89.4
Bus24
7.000
99.131
-0.3
0
0
0
0 Bus23
-0.048
-0.022
4.4
90.8
BEST MEXICAN FOODS
0.048
0.022
4.4
90.8
Bus26
7.000
98.978
-0.4
0
0
0
0 13 s27
4088
-0.044
8.2
89.5
WALTERS ELECTRIC
0.088
0.044
8.2
89.5
Bm27
7.000
98.982
-0.4
0
0
0
0 Bus26
0.088
0.044
8.2
89.5
BwIS
-0.088
-0.044
8.2
89.5
FRUITLAND AVE
7.000
99.823
-o l
0
0
0
0 SOTO ST
-2.029
-1.215
195.4
85.8
54TH ST & SOTO
2.029
1.215
195.4
85.8
KATIE INC
0.480
98.508
-0.7
0
0
0.087
0.043 Bw18
-0o87
-0.043
119.1
89.7
KELLY TOY 0.480 98.490 47 0 0 0.191 0.127 Bus21 -0.191 -0.127 280.1 83.2
SAN 094-216 (SR-06) VERNON (03/06/2015) MM 135853 REV. 0
ETAP
Project:
Page:
3
12.5.00
Location:
Date:
02-27-2015
Contract:
SN:
POWERENG-2
Engineer:
Revision:
Base
Study Case: Max
Loading
Filename: FEEDER 11
Config.:
Normal
Bus
Voltage
Generation
Load
Load Flow
XFMR
ID
kV
%Mag. Ang.
MW
Mvar
MW
Mvar
ID
MW
Mvar
Amp
%PF %Tap
RICHARD KORAL
0.480
97.791 -1.1
0
0
0.083
0.047
Bus5
-0.083
-0.047
117.0
87.0
SANDBERG FURNITURE
0.480
98.412 -0.8
0
0
0.087
0.043
Bus22
-0.087
-0.043
119.2
89.7
SK TEXTILE
0.480
98.415 -1.6
0
0
0.207
0.008
Busl4
-0.207
-0.008
252.8
99.9
SOTO ST
T000
99.949 0.0
0
0
0
0
50TH ST
-2.030
-1.218
195A
85.8
FRUITLAND AVE
2.030
L218
195.4
85.8
WALTERS ELECTRIC
0.480
98.584 -0.6
0
0
0.088
0.043
Bus26
-0.088
-0.043
119.0
89.7
WORLD VARIETY FOODS
0.480
95.889 -2.5
0
0
0.268
0.144
Busll
-0.268
-0.144
381.5
88.0
Linea-
7.000
99.233 -0.2
0
0
0
0
Bus3
0.000
0.000
0.0
0.0
Line7-
7.000
99.171 -0.3
0
0
0
0
Bus7
0.000
0.000
0.0
0.0
Linell-
7.000
99.132 -0.3
0
0
0
0
Bus13
0.000
0.000
0.0
0.0
Linel6-
7.000
99.095 -0.3
0
0
0
0
Bus20
0.000
0.000
0.0
0.0
Indicates a voltage regulated bus (voltage
controlled or swing type machine
connected to it)
k Indicates a bus with a load mismatch of more than 0.1 MVA
SAN 094-216 (SR-06) VERNON (03/06/2015) MM 135853
REV. 0
Project:
Location:
Contract:
Engineer:
Filename: feeder 19
Bus
Voltage
ETAP
12.5.00
Study Case: Max Loading
LOAD FLOW REPORT
Generation Load
Load Flow
Page:
Date:
SN:
Revision:
Config.:
1
02-27-2015
POWERENG-2
Base
Normal
CFMR
ID
kV
%Mag.
Ang.
MW
Mvar
MW
Mvar
ID
MW
Mvar
Amp
%PF %Tap
27rH ST
7.000
91.871
-2.8
0
0
0
0
Bus25
-L007
-L008
127.9
70.7
Bus29
1.007
L008
127.9
70.7
37TH ST
T000
92.454
-2.7
0
0
0
0
Bw17
-1.147
-1.128
143.5
71.3
Bus18
0.136
0.112
15.7
77.0
Bus24
1.011
1.016
12T9
70.6
50TH ST
T000
99.073
-0.7
0
0
0
0
SEVILLE AVE
3.144
2.227
3208.
81.6
Bus7
-3.144
-2.227
320.8
81.6
51ST ST
7.000
96.340
-1.4
0
0
0
0
SANTA FE AVE
-2.819
-1.949
293A
82.3
Bus8
2.819
1.949
293.4
82.3
ALAMEDA AVE
7.000
94.409
-2.0
0
0
0
0
Busll
-2.086
-1.194
209.9
86.8
Bm14
2.096
1.194
209.9
86.8
Line12-
0.000
0.000
0.0
0.0
AROMA
0.480
88.997
-3.9
0
0
0.187
0.173
Bw52
-0.187
-0.173
343.7
73.5
COSMESTICS/UNIREX
Busl
T000
98.687
-0.8
0
0
0
0
SEVILLEAVE
-3.136
-2.213
320.8
81.7
Bw2
3.136
2.213
320.8
81.7
Bust
7.000
9T404
-1.1
0
0
0
0
BmI
-3.109
-2.165
320.8
811
Bw4
0.000
0.000
0.0
0.0
Bus5
3.109
2.165
320.8
82.1
Bus3
0A80
9T404
-1.1
0
0
0
0
Bm4
0.000
0.000
0.0
0.0
Bus4
7.000
97.404
-1.l
0
0
0
0
Bm2
0.000
0.000
0.0
0.0
Bus3
0.000
0.000
0.0
0.0
Bus5
T000
97.275
-1.2
0
0
0
0
Bus2
-3.106
-1161
320.8
82.1
Bus6
0.268
0.180
27.4
83.0
SANTA FE AVE
2.838
1.981
293.4
82.0
Bus6
7.000
97.272
-1.2
0
0
0
0
Bus5
-0.268
-0.180
27A
83.0
CONSOLIDATED
0.268
0.180
27A
83.0
METALS
' Bus7
69.000
100.000
0.0
1147
2.286
0
0
50TH ST
3.147
2286
32.5
80.9
Bus8
7.000
95.007
-1.8
0
0
0
0
51 ST ST
-2.793
-1.903
293A
82.6
Bus9
0.126
0.086
13.3
82.6
Bus11
2.667
1.817
280.2
82.6
Bus9
7.000
95.004
-1.8
0
0
0
0
Bus8
-0.126
-0.086
13.3
82.6
Bus10
0.126
0.086
13.3
82.6
BuslO
0A80
93.771
-2.5
0
0
0.126
0.083
Bus9
-0.126
-0.083
193.5
83.3
Busll
7000
94.546
-1.9
0
0
0
0
Bus8
-2.658
-1.802
280.2
82.8
Bus12
0.570
0.605
72.5
68.6
M
SAN 094-216 (SR-06) VERNON (03/06/2015) MM 135853 REV. 0
Project:
Location:
Contract:
Engineer:
Filename: feeder 19
ETAP
12.5.00
Study Case: Max Loading
Bus
Voltage
Generation
Load
rD
W
%Mag.
Ang.
MW War
MW
War
1D
ALAMEDAAVE
Bus12
7.000
94.532
-1.9
0
0 0
0
Bus11
PUNCH PRESS
PRODUCTS
Bus14
7.000
91152
-2.4
0
0 0
0
Busl5
ALAMEDAAVE
Bw17
Busl5
7.000
93.104
-2.4
0
0 0
0
Bus14
NEPTUNE FOODS
Bus17
7.000
92.825
-2.6
0
0 0.000
-0.775
Bus14
37TH ST
Bus18
7.000
92.440
-2.7
0
0 0
0
37TH ST
Bm19
Bus21
Bus19
7.000
92.440
-2.7
0
0 0
0
Bus18
Bm20
Bw20
0.480
99.295
-4.1
0
0 0.100
0.080
BM19
Bus21
7.000
92.437
-2.7
0
0 0
0
Bm18
Bm22
ROSS ST
Bm22
7.000
92A37
-2.7
0
0 0
0
Bm21
Bus23
Bus23
0A80
91.797
-3.0
0
0 0.034
0.027
Bm22
Bus24
7.000
92.225
-2.7
0
0 0
0
37TH ST
Bus25
Line24-
Bus25
7.000
92.146
-2.7
0
0 0
0
Bus24
Bus26
27TH ST
Bus26
7.000
92.146
-2.7
0
0 0
0
Bw25
Bm27
Line28-
Bus27
T000
92.146
-2.7
0
0 0
0
Bus26
Bm28
Bus28
0A80
92.146
-2.7
0
0 0
0
Bus27
Bus29
7.000
91.746
-2.8
0
0 0
0
27TH ST
Bm30
Bus32
Bus30
7.000
91.746
-2.8
0
0 0
0
Bw29
OR
Page:
2
Date:
02-27-2015
SN:
POWERENG-2
Revision:
Base
Config.:
Normal
Load Flow XFMR
MW
Mvar
Amp
%PF %Tap
2.088
1.197
209.9
86.8
-0.570
-0.605
72.5
68.6
0.570
0.605
72.5
68.6
0.914
0.798
107.4
75.3
-2.067
-1.162
2W9
87.2
1.153
0.363
107.1
95A
-0.913
-0.798
107.4
75.3
0.913
0.798
107A
75.3
-1.150
-0.359
107.1
95.5
1.150
1.134
143.5
7L2
-0.136
-0.112
15.7
7TO
0.102
0.085
11.8
76.8
0.034
0.028
3.9
77.6
-0.102
-0.085
11.8
76.8
0.102
0.085
IL8
76.8
-0.100
-0.080
172.5
78.3
-0.034
-0.028
3.9
77.5
0.034
0.028
3.9
77.5
0.000
0.000
0.0
0.0
-0.034
-0.028
3.9
77.5
0.034
0.028
3.9
77.5
4034
4027
56.8
77.9
-1.010
-1.013
127.9
70.6
1.010
1.013
127.9
70.6
0.000
0.000
0.0
0.0
-1.009
-1.012
127.9
70.6
0.000
0.000
0.0
0.0
1.009
L012
12T9
70.6
0.000
0.000
0.0
0.0
0.000
0.000
0.0
0.0
0.000
0.000
0.0
0.0
0.000
0.000
0.0
0.0
0.000
0.000
0.0
0.0
0.000
0.000
0.0
0.0
-1.006
-1.006
127.9
70.7
0.000
0.000
0.0
0.0
1.006
1.006
127.9
70.7
0.000
0.000
0.0
0.0
SAN 094-216 (SR-06) VERNON (03/06/2015) MM 135853 REV. 0
ETAP
Project:
Page:
3
12.5.00
Location:
Date:
02-27-2015
Contract:
SN:
POWERENG-2
Engineer:
Revision:
Base
Study
Case: Max
Loading
Filename:
feeder 19
Config.:
Normal
Bus
Voltage
Generation
Load
Load Flow
XFMR
ID W
%Mag
Ang.
MW War
MW
Mvar
ID
MW
War
Amp
%PF %Tap
13 s31
0.000
0.000
0.0
0.0
Bus31
0.480
91.746
-2.8
0
0
0
0
Bw30
0.000
0.000
0.0
0.0
Bus32
7.000
91.419
-2.9
0
0
0
0
Bm29
-L003
-1.002
127.9
70.8
Bus41
0.080
0.081
10.3
70.2
Bus37
0.589
0.605
76.2
69.8
Bus38
0.334
0.316
41.5
72.7
Bus37
7 000
91.366
-2.9
0
0
0
0
Bus32
-0.589
-0.605
76.2
69.8
Bus59
0.065
Q062
8.1
72.6
Bus44
0.523
0.543
68.1
69.4
Bus38
7.000
91.411
-2.9
0
0
0
0
Bus32
-0.334
-0.316
41.5
72.7
CATALINA PACIFIC
0.334
0.316
41.5
72.7
CONCRETE
Bus41
7.000
91.418
-2.9
0
0
0
0
Bm42
0.080
0.081
10.3
70.2
Bus32
-0.080
-0.081
10.3
70.2
Bus42
7.000
91.413
-2.9
0
0
0
0
Bus41
-0.080
-0.081
10.3
70.2
CUTE GIRL
0.080
0.081
10.3
70.2
Bus44
7.000
91.315
-2.9
0
0
0
0
Bm37
-0.523
-0.543
68.1
69A
13 s45
0.136
0.137
17.5
70.5
Bw47
0.387
0.405
50.6
69.1
Bus45
T000
9L314
-2.9
0
0
0
0
Bm44
-0.136
4137
IT5
70.5
Bw46
0.136
0.137
17.5
70.5
Bus46
0.480
87,921
-4.3
0
0
0.135
0.129
Bus45
-0.135
-0.129
254.9
72.2
Bus47
7,000
91.291
-2.9
0
0
0
0
Bw44
-0.387
-0.405
50.6
69.1
Bus48
0.198
0.225
27.1
66.1
Bm50
0.189
0.180
23.6
72.3
Bus48
T000
91.290
-2.9
0
0
0
0
Bus47
-0.198
-0.225
2T1
66.1
Bus49
0.198
0.225
27.1
66.1
Bus49
0.480
83.453
-5.4
0
0
0.190
0.197
Bus48
-0.190
-0.197
394.9
69.4
Ba550
7.000
91.265
-2.9
0
0
0
0
Bus47
-0.189
-0.180
23.6
713
Bw51
0.189
0.180
216
72.3
Bus54
0.000
0.000
0.0
0.0
Bus51
T000
91,261
-2.9
0
0
0
0
Bw52
0.189
0.180
23.6
72.3
Bus50
-0.189
-0.180
23.6
72.3
Bus52
7.000
91.251
-2.9
0
0
0
0
Bm51
-0.189
-0.180
23.6
72.3
AROMA
0.189
0.180
23.6
72.3
COSMESTICSIUNIREX
Bus54
7.000
91.265
-2.9
0
0
0
0
Bus50
0.000
0.000
0.0
0.0
Bw57
0.000
0.000
0.0
0.0
Lme49-
0.000
0.000
0.0
0.0
13 s57
7.000
91.265
-2.9
0
0
0
0
Bus54
0.000
0.000
0.0
0.0
SAN 094-216 (SR-06) VERNON (03/06/2015) MM 135853
REV. 0
ETAP
Project:
12.S.00
Location:
Contract:
Engineer:
Study
Case: Max
Loading
Filename: feeder 19
Bus
Voltage
Generation
Load
ID
W
%Mag.
Ang.
MW
Mvar
MW
Mvar
ID
Bus58
Bus58
0.480
91.265
-2.9
0
0
0
0
Bus57
Bus59
7.000
91.363
-2.9
0
0
0
0
Bus37
PHYSICAL
DISTRIBUTION SER
CATALINA PACIFIC
0.480
84.911
-6.0
0
0
0.326
0.276
Bus38
CONCRETE
CONSOLIDATED
0.480
95.394
-2.2
0
0
0.266
0.172
Bush
METALS
CUTE. GIRL
0.480
90.410
-3.3
0
0
0.079
0.079
Bus42
NEPTUNE FOODS
0.480
85.083
-6.3
0
0
0.881
0.672
Bus15
PHYSICAL
0.480
90.412
-3.3
0
0
0.065
0.061
Bus59
DISTRIBUTION SER
PUNCH PRESS
0.480
86.651
-5.2
0
0
0.553
0.524
Busl2
PRODUCTS
ROSS ST
7.000
92.437
-2.7
0
0
0
0
Bus21
Line21-
Line22-
SANTAFEAVE
7.000
97.034
-1.2
0
0
0
0
Bus5
51 ST ST
SEVILLEAVE
7.000
98.883
-0.7
0
0
0
0
50TH ST
Bust
Linel2-
7.000
94.409
-2.0
0
0
0
0
ALAMEDAAVE
Line21-
7.000
92.437
-2.7
0
0
0
0
ROSS ST
Line22-
7.000
92.437
-2.7
0
0
0
0
ROSS ST
Line24-
T000
92.225
-2.7
0
0
0
0
Bus24
Line28-
7.000
92.146
-2.7
0
0
0
0
Bus26
Line49-
7.000
91.265
-2.9
0
0
0
0
Bus54
* Indicates a voltage regulated bus (voltage
controlled
or swing type machine connected to it)
ff Indicates a bus with a load mismatch of more
than 0.1
MVA
'IN-,
Page:
4
Date:
02-27-2015
SN:
POWERENG-2
Revision:
Base
Config.:
Normal
Load Flow XFMR
MW
Mvar
Amp
%PF %Tap
0.000
0.000
0.0
0.0
0.000
0.000
0.0
0.0
-0.065
-0.062
8.1
72.6
0.065
0.062
8.1
72.6
-0.326
-0.276
605.0
76.3
-0.266
-0.172
399.4
84.0
-0.079
-0.079
149.6
70.7
-0.881
4672
1566.7
79.5
-0.065
-0.061
118A
73.1
-0.553
-0.524
1058.0
72.6
0.000
0.000
0.0
0.0
0.000
0.000
0.0
0.0
0.000
ROW
0.0
0.0
-2.833
-1.972
293A
82.1
2.833
1.972
293A
82.1
-3.140
-2.220
320.8
81.7
3.140
2.220
320.8
81.7
0.000
0.000
0.0
0.0
0.000
0.000
0.0
0.0
0.000
0.000
0.0
0.0
0.000
0.000
0.0
0.0
0.000
0.000
0.0
0.0
0.000
0.000
0.0
0.0
SAN 094-216 (SR-06) VERNON (03/06/2015) MM 135853 REV. 0