HomeMy WebLinkAbout2017-0717 Study Session PACKET
C-ITY OF
-ASHLAND
CITY COUNCIL STUDY SESSION
AGENDA
Monday, July 17, 2017
Siskiyou Room, 51 Winburn Way
5:30 p.m.
1. Public Input (15 minutes, maximum)
II. Look Ahead review
III. 10 by 20 Status Update
IV. Discussion of options for increasing effectiveness of study sessions (request of
Councilor Slattery)
V. Discussion of Indigenous Peoples Day (request of Councilor Slattery)
In compliance with the Americans with Disabilities Act, if you need special assistance to participate in this
meeting, please contact the City Administrator's office at (549) 488-6002 (TTY phone number 1-800-735-
2900). Notification. 72 hours prior to the meeting will enable the City to make reasonable arrangements to
ensure accessibility to the meeting (28 CFR 35.102-35.104 ADA Title 1).
COUNCIL MEETINGS ARE BROADCAST LIVE ON CHANNEL 9. STARTING APRIL 15, 2014,
CHARTER CABLE WILL BROADCAST MEETINGS ON CHANNEL 180 OR 181.
VISIT THE CITY OF ASHLAND'S WEB SITE AT WWW.ASHLAND.OR.US
City of Ashland Council Meeting Look Ahead
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City of Ashland Council Meeting Look Ahead
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Council Stud Session
July 17, 2017
Title: 10 by 20 Status Update
Item Type: Update
Requested by Council? Yes i
From: Adam Hanks Interim Assistant to the City Administrator
Tom McBartlett Electric Distribution Systems Manager
Adam. Hanks(cD-ash land. or. us
Thomas McBartlett(-ashland.or.us
Discussion Q & A:
1) What is the status of the potential 10-12 MW solar generation facility at the Imperatrice
Property?
Environmental Assessment
With direction from Council at its February 21, 2017 meeting, City staff from the Electric, Parks, and
Public Works Departments commissioned a consultant to conduct a rare plants and bird assessment of
the entire property as a likely required precursor to any formal development application on the site.
Much of the inventory survey work has been completed, with the final report anticipated to be
completed in mid to late August at which time a presentation from the consultant will be scheduled.
BPA Contract
Additionally, Electric Department staff continued communications and dialogue with both Bonneville
Power Administration (BPA) and Bonneville Environmental Foundation (BEF) regarding the
implications of the project on the City's current bilateral contract agreement for the purchase and
delivery of wholesale power to the City's distribution system. Of particular importance and impact is
the "take or pay" provision which requires that the City purchase a minimum volume of power annual
from BPA based on a pre-determined formula that incorporates expected growth, expected and
required energy efficiency achievements and other system elements.
Through these discussions, City staff has re-affirmed its position that the modification or removal of
the take or pay provision within the City's current contract is highly unlikely to occur prior to the
agreement expiration in 2028. BPA is aware of the growing interest from the City and other public
utility customers to incorporate local distributed generation into individual utility resource portfolio's
and will likely modify the structure of the agreements post 2028 to address changing customer needs
and desires. Doing so prior to the contract expirations would create a significant and detrimental
financial impact to the entire BPA system.
2) What is the status of the potential use of the Imperatrice Property for required waste water
treatment processes? .
The Engineering Division is currently evaluating all available options for anticipated temperature
Page 1of5 CITY OF
ASHLAND
compliance associated with the City's future National Pollution Discharge Elimination System
(NPDES) permit to discharge treated wastewater effluent. A "final engineered solution" cannot
occur until the City actually receives the new DEQ NPDES permit limits. Until then, the
Engineering Division requires flexibility in its approach to generate probable solutions to meet
permit requirements. This flexibility includes use of the Imperatrice property for potential future
effluent storage and wetlands. DEQ has not provided the City formal notice on when they will
begin the process of updating our permit, but anticipates starting the process after October 2018
(the beginning of federal fiscal year 2019).
Temperature compliance contains both "near field" and "far field" components. The near field
component deals with the temperature of the treated wastewater at the point of discharge. The far
field component deals with an overall temperature for the watershed's receiving streams.
DEQ has not started the process of updating the City's NPDES permit as they have been working
through challenging litigation and new rulemaking language.
The City's Engineering staff continues to move forward with solving the estimated temperature
exceedance. The 2012 Wastewater Master Plan defined the need to relocate the existing outfall
from Ashland Creek to Bear Creek as a first step toward meet anticipated future NPDES
temperature limits. In addition, the master plan recommended construction of cooling wetlands
and water quality trading (shading) to more fully meet the anticipated temperature requirements
for discharge to Bear Creek.
Currently the City is:
• developing a water quality trading plan with DEQ to meet estimated far field temperature
requirements
® finalizing the mixing zone study and RPA and is expected DEQ to provide formal
comment with estimated permit limits for near field temperature compliance.
• Soliciting proposals for the engineering plans and specifications to relocate the outfall
from Ashland Creek to Bear Creek (Summer 2017)
• Soliciting proposals for plans and specifications for the proposed new oxidation ditch and
adjacent wetland cooling systems (Fall 2017)
3) How does the proposed conservation easement/trail system proposal preliminarily brought
forward by the Parks and Recreation Commission and the Southern Oregon Land
Conservancy (SOLO) align with the two Council directed priorities described above (solar
generation and waste water temperature treatment)?
The Parks and Recreation Commission and Director presented a concept level interest in some level of
conservation easement, transfer of management and/or trail easements at the May 1, 2017 special Joint
Meeting between the City Council and Parks Commission and subsequently to the Citizen's Budget
Committee on May 11, 2017. Given the extensive biodiversity of the property, both the Parks
Commission and SOLC have interest in securing and preserving all or at least the "above the ditch"
portion of the property and additionally provide access and enjoyment of the property with the creation
of a trail system on the property and ultimately up the southern face of Grizzly Peak.
The property was purchased in 1996 for $946,000 with revenues from the City's waste water treatment
Page 2 of 5 CITY OF
-ASHLAND
fund. While no formal land sale or transfer of ownership would occur, discussions with the Parks
Commission and the City would involve transfer of long term management and oversight of the
property along with a mechanism to repay or otherwise ensure that the wastewater fund is "made
whole" financially.
City staff is reticent to engage in formal, transactional discussions regarding the property until more is
known in regards to solutions to the wastewater effluent temperature requirements in addition to
having a better understanding of Council's desired direction regarding any potential local renewable
power generation on the property. However, it is possible that all of the desired uses for the property
could co-exist and not require exclusivity of the property. Because of this, Parks, Public Works,
Administration and Electric Department staff continue to keep abreast and communicate on the status
of each of the potential uses. If Council is interested in formalizing these discussions, the development
of a master plan for the property could be a viable and productive process to engage in.
4) What are the next steps in meeting the commitment made with the acceptance of the 10 by 20
ordinance?
City staff consulted with both BEF and OS Engineering in the initial exploration of the Imperatrice
Property for a solar generation facility. As presented at. the February 21, 2017 Council business
meeting, key timelines for continued movement towards the development of the project include the
following:
Spring 2017 - Conduct initial environmental review of site (flora/fauna survey) In Process
Spring 2017 - Submit new generator request to Pacific Power (6-18 month No Started
process)
Summer/Fall 2017 - Begin application process for land use approval with Not Started
Jackson County .
Sumner/fall 2017 - Further address issues related to substation capacity and Not Started
interconnection
Ongoing - Continue to explore additional opportunities to develop renewable
energy installations with City facilities, community/co-op solar projects,
smaller (1 MW) utility owned/managed systems located within the local In Process
distribution grid system and other potential solutions that could meet the intent
of the 10 by 20 ordinance
Pursuing the tasks listed above have been determined by both of our project research partners as
needed steps prior to the issuance of a complete technical RFP/RFQ and also maintain the general
timeline needed to realistically be able to advance the project through to completion by the end of
2020 as specified in the 10 by 20 ordinance.
5) Are there viable alternatives to the solar generation facility at the Imperatrice Property that
would meet the requirements of the 10 by 20 ordinance?
Staff has identified a variety of potentially cost effective projects and programs that could advance the
City towards meeting the intent of the 10 by 20 ordinance. Each of the potential opportunities would
Page 3 of 5 CITY OF
-ASHLAND
need further exploration to determine total reasonable expected generation/displacement and
associated cost per unit generated/displaced. Projects examples include:
Project Description Benefit
Purchase Power Agreement - Wheeled to City Lower cost
Community Solar Minimal Utility cost (not utility o
Solar installations on City Facilities Good long term ROI
1 MW Solar Facility No BPA Contract impact
Expand hydro capacity at Reeder Reservoir Existing infrastructure
Expand Commercial Solar Incentive Programs Shared investment, scalable costs
Expand Residential Solar Incentive Programs Shared Investment, scalable costs
Expand Energy Efficiency Program Shared investment, scalable. costs
In addition to cost and generation/displacement calculations, each project should be evaluated to
determine potential co-benefits, financing opportunities and implications and needed combinations and
timelines to meet both the 10% generation/displacement requirement and the 2020 required
achievement due date.
Of equal or greater import ance, it will be critical for City staff to fully understand the policy objectives
associated with the 10 by 20 ordinance. Given the unique circumstances that led to the ordinance
creation and approval, an agreed upon clear set of objectives has yet to be developed. Stated, but
unofficial objectives have included energy independence, energy resiliency and carbon reduction. The
priority of the policy objectives determine the types and scale of the projects and programs developed
to achieve the desired objectives.
Resource Requirements:
To date, a total of approximately $22,000 has been expended for the initial feasibility study for the
interconnection component of the project and the plant and bird inventory. Roughly $16,000 of that
total has come from the Electric Dept and the remaining funds from Public Works and Parks
Departments.
Additional costs-will be incurred should Council decide to direct staff to move forward with the next
two items on the project timeline. Both the initial land use application and the Pacific Power system
impact study will require staff time from both the Electric and Administration Departments and likely
would include some level of consultant services to complete. The exact figures for each of those are
unknown at this point, but .likely do not exceed $10,000 in total.
Suggested Next Steps:
Staff would like to obtain Council direction on the following:
1) Should staff move forward in the development application process to both Jackson County
Planning Dept and Pacific Power for the solar generation facility project?
2) Is Council interested in developing a set of prioritized objectives for the 10 by 20 ordinance to
assist in developing alternative projects/programs to advance towards the current ordinance
requirements?
3) Should staff develop a process, timeline and cost estimate for the development of an Imperatrice
Page 4 of 5 CITY OF
ASHLAND
Property Master Plan?
Policies, Plans and Goals Supported:
22. Prepare for the impact of climate change on the community.
22.1 Develop and implement a community climate change and energy plan
Background and Additional Information:
See packet materials from February 21, 2017 (Attachments)
Attachments:
February 21, 2017 - Packet Materials
Page 5of5 CITY OF
-ASHLAND
CITY OF
-ASHLAND
Council Communication
February 21, 2017, Business Meeting
"10 by 20" Ordinance - Project Update
FROM:
Adam Hanks, Management Analyst, adam@ashland.or.us
Mark Holden, Director of IT & Electric Utility, mark.holden@ashland.or.us
SUMMARY
With direction provided by Council at the November 15, 2016 study session, staff has worked with two
consulting firms to provide research, analysis and proposed schedule of tasks necessary to fully
evaluate the feasibility of the use of the City owned Imperatrice property to construct a utility scale
solar generation facility as one option to meet the requirements of the "10 by 20" ordinance (10% new,
clean, local electricity generation by 2020).
BACKGROUND AND POLICY IMPLICATIONS:
10 by 20 Ordinance
A citizen initiative petition for a local ballot measure was submitted to the City Council on August 16,
2016 titled "Shall Ashland produce 10% of electricity used in the City by year 2020 from new, local
and clean sources?"
On September 6, 2016, Council accepted and approved the ordinance language contained within the
ballot measure verbatim, consistent with Oregon State Elections procedures (ORS 250.325 and
254.095)
With initial discussions at the November 1, 2016 Council meeting and subsequent discussions at the
November 15, 2016 Council meeting, Council directed staff to develop a Request for Proposals (RFP).
or a Request for Qualifications (RFQ) as a method of gathering the data necessary to properly evaluate
the potential use of the Imperatrice property as a means of complying with the 10 by 20 ordinance
requirements.
Council direction purposefully excluded several known variables in order to focus efforts on the
technical and financial feasibility of the potential project with the intent and expectation that these
variables would be integrated back into the evaluation process after the technical and financial
elements of the project are better understood. These variables include:
• Potential need for a portion of the property for waste water treatment solutions (note: the
property was originally purchased with waste water funds for waste water treatment solutions)
• Historical stated interest in a portion of the property to be reserved via conservation and/or trail
easement for habitat and viewshed protection
Page 1 of 3
~r,
CITY OF
ASHLAND
• BPA wholesale electricity contract inclusion of a "take or pay" provision that requires the City
to purchase all of its electricity needs through BPA. The current contract runs through 2028.
Imperatrice Property- Solar project analysis
Staff received assistance in the research, analysis and proposed schedule of tasks through its
partnership with the Bonneville Environmental Foundation (REF), a leading environmental non-profit
with programs focused on solar and other renewable solutions.
Staff also relied heavily on OS Engineering, the City's electrical engineering consulting firm to
provide key technical review, analysis on the ability and requirements of connecting a utility scale
solar system directly to the City's distribution grid (called an interconnect).
Key Findings of this initial round of research and analysis include:
• Estimated total capital costs of a 12 MW system is likely between $15,000,000 and
$20,000,000, resulting in a levelized cost of energy of $90 per Megawatt hour 10%)
compared with current wholesale pricing of approximately $30/MWh
• Estimated interconnection cost of approximately $1,200,000 depending on final specifications
• A 12 MW system cannot be served by either of the two nearby sub-stations, requiring the
interconnect to split the system to distribute the load to each of the existing sub-stations.
• Development of a smaller sized system that is scalable over time may provide benefits and
avoid regulatory and financial obstacles.
• Additional opportunities to meet the 10 by 20 requirement should be evaluated concurrent with
proposed next steps for the Imperatrice property
Staff has found this round of research and analysis invaluable in better understanding the issues
specific to a large utility scale solar project and concur with the recommendations made by BEF on
pages 2-3 of the attached report with key timeline items outlined briefly below:
• Spring 2017 - Conduct initial environmental review of site (flora/fauna survey)
• Spring 2017 - Submit new generator request to Pacific Power (6-18 month process)
• Summer/Fall 2017 - Begin application process for land use approval with Jackson County
• Summer/fall 2017 - Further address issues related to substation capacity and interconnection
• Ongoing - Continue to explore additional opportunities to develop renewable energy
installations with City facilities, community/co-op solar projects, smaller (1 MW) utility
owned/managed systems located within the local distribution grid system and other potential
solutions that could meet the intent of the 10 by 20 ordinance
Pursuing the tasks listed above have been determined by both of our project research partners as
needed steps prior to the issuance of a complete technical RFP/RFQ and also maintain the general
timeline needed to realistically be able to advance the project through to completion by the end of 2020
as specified in the 10 by 20 ordinance.
COUNCIL GOALS SUPPORTED:
22. Prepare for the impact of climate change on the community.
22.1 Develop and implement a community climate change and energy plan
Page 2 of 3
CITY OF
ASHLAND
FISCAL IMPLICATIONS:
The above described initial round of research and analysis was conducted with minimal City
expenditure; a memorandum of understanding facilitated the work with BEF and the City's existing
contract with OS Engineering was utilized for the technical research on the inter-connection aspect of
the project at a cost of just over $3,000
The costs associated with pursuing the recommended initial environmental review of the site are not
yet known, but is expected to be in the $10,000 to $20,000 range and would be funded from the
contract services budget in the Electric Fund. Other listed tasks will involve staffing resources from
both the Electric and Administration Departments.
STAFF RECOMMENDATION AND REQUESTED ACTION:
To pursue the project further, staff recommends that the initial environmental review of the site be
conducted this spring to take advantage of the spring bloom that assists in the inventory component of
the review. As staff assesses the needed scope of the review and the approximate costs, a
determination can be made as to whether or not the contract for the desired services will necessitate
Council approval.
Staff also recommends that Council consider directing staff to develop a proposed strategy document
to assist Council, staff and the community as the "set aside" variables noted above integrate back into
the project feasibility evaluation.
SUGGESTED MOTION:.
I move to direct staff to move forward with an environmental review of the Imperatrice Property and to
develop a project strategy document to help guide future project evaluation.
ATTACHMENTS:
BEF - Letter of February 10, 2017
OS Engineering Analysis - January 31, 2017
Council Meeting November 15, 2017 - Staff Report and Minutes
Page 3 of 3
~r,
Mark Holden
Ashland Municipal Electric Utility
90 N. Mountain Ave
Ashland, OR 97520
February 10, 2017
Dear Mark,
The following includes our recommendations to the City of Ashland with respect to the goals of
Ordinance No. 3134, and enabling the production of 10% of Ashland's electricity consumption to
be produced from new, local and clean resources by the year 2020. The Bonneville
Environmental Foundation is committed to partnering and supporting this effort per our dually
executed Memorandum of Understanding, 800036-12, dated 12/28/16.
At the Bonneville Environmental Foundation (BEF), we-believe that. addressing the most
pressing energy and environmental challenges requires, innovation, creative problem solving
and discovering new ways of doing business. As an entrepreneurial non-profit we thrive in
working,tgward innovative solutions and value partnerships as essential to success. BEF hasa
long" history of supporting publicly owned utilities in the development of cost-effective renewable.
resources including the first pubic power wind project in the region, the first community solar
proje.ct-with Ashland, and subsequently 22 community solar partnerships with utilities across the
Pacific NW.. BEF's partnership "with the Bonneville Power Administration (BPA) allows us to aid.
BPA's Wholesale Public utility customers like Ashland as they endeavor to integrate more
renewable energy projects into the PNW's utility generation mix.
BEF is uniquely positioned to assist Ashland in rn.eeting its "10x20" goals. Our team dedicated
to the project includes Dick Wanderscheid, Vice President'of the Renewable Energy Group, and
Evan Ramsey, Senior Project Manager for the Renewable Energy Group. Collectively we bring
over 40 years of experience with publically..owned electric utilities, energy efficiency, =
sustainability, and renewable energy. Dick brings the intimate knowledge of Ashland's situation;`
having served in the city's energy conservation and renewable energy programs for 20 years
and also as the City's Electric Utility's Director.for nearly d-.decade. Evan brings a wealth of
experience in solar energy systems having :deep.commercial management experience with--
SolarCity, and has served as the primary BE,F. co's.ultant to.. all our--utility partners developing..
solar projects.
BEF fully supports Ashland's commitment to renewable energy, and has committed all of the
resources at our disposal to help the City develop the most cost effective, resilient, and
beneficial solution for the electric Utility and it's citizens. While the actual cost and scope of solar
PV construction is relatively simple, the development, siting, and financing provides the bulk of
bonneville environmental foundation
240 southwest 1st ave. 503.248.1905 ;
portland, oregon 97204 www.b-e-f.org*
Pre-Proposal for Education Services 12
the risk and complexity. It is with this in mind that BEF recommends a measured approach with
as much due diligence as possible on the front end to maximize the project economics and
benefits to the City of Ashland. Solidifying as many of the pre-development unknowns as
possible lessens the unknowns and risk to developers and will provide the best ultimate price to
the City. This approach has been validated through our research and outreach with other
industry experts such as Rocky Mountain Institute (RMI) and the Smart Electric Power Alliance
(SEPA), who both specialize in utility solar procurement. We have also discussed solar
integration and contract issues with the BPA's Solar Task force staff.
The entire process of developing a solar project includes system siting, environmental reviews,
interconnection studies, financing, procurement, contractual negotiations, engineering,
permitting, land use approvals, distribution system upgrades, construction, commissioning, and
finally standard operations and maintenance. This overall process can take years and it is
advisable to have a destination before undertaking a journey.
To release an RFP simply for pricing of the solar does not return all the necessary data points
needed to evaluate the full impact of a utility scale project to the City of Ashland. Furthermore,
there is industry data available that will provide PV system cost estimates, without having to run
a premature RFP. SEPA has published a "Utility Scale Pricing Report" which provides a matrix
of capital costs with associated levelized costs of energy (LCOE). The total capital cost of a 12
MW system alone is likely to be between $15,000,000 and $20,000,000. We can expect with
confidence the LCOE of a horizontal single access tracker for this sized system, with a 20%
capacity factor, to provide an LCOE of $90 per Megawatt hour, plus or minus 10%. This is
nearly a three-fold increase compared to existing wholesale power pricing of around $30/MWh.
This pricing is not inclusive of any development activities, distribution system upgrades,
resource support services, contractual and take or pay implications.
Given all the outlined complexities, BEF remains committed to supporting the City of Ashland,
as it pursues the goal of 10% of Ashland's energy consumption from new, clean, and local
energy sources. After substantial research and evaluation we would like to present the following
recommendations:
1. Rare Species Survey: Complete the biological survey, Spring of 2017.
• This study will be necessary for the entire parcel regardless of where the solar
array is located. If rare species are found during the Spring bloom, this will allow
for project siting changes and may ultimately dictate a necessary location for the
array.
2. Utility Interconnection: Submit a request to PacifiCorp, Spring of 2017.
• Regardless of whether a new solar generation project connects to a substation in
Ashland or a Pacificorp line, a feasibility and system impact study will be required
by Pacificorp. This is their responsibility as the Balancing Authority for the area,
and this process can take 6-18 months. It will provide valuable information
regarding interconnection capacity, location, and cost. In parallel, the City may
evaluate costs and benefits for the various utility interconnection options.
3. Conditional Use Permit (CUP): Submit for a CUP with Jackson County for siting on the
Imperatrice Property. Once siting and size are known. Fall of 2017.
4. Substation Capacity: Determine capacity of an interconnect to the BPA owned
Mountain Substation and minimum load at this wholesale point of delivery. If direct
connection to this Substation is feasible, secure cost estimates for the necessary
distribution work.
BONNEVILLE 2405W1stAvenue
ENVIRONMENTAL = Portland OR 97204
FOUNDATION 503-248-1905
www.b-a-forg
Pre-Proposal for Education Services 13
5. BPA Contract: Evaluate implications to the existing Bonneville Power Administration
power sales contract, including "take or pay" provisions, resources support services cost,
transmission implications, purchase of the substation, and effect on the General Transfer
Agreement between Pacificorp and BPA.
6. Rooftop Solar Potential: Determine the rooftop solar capacity for City owned facilities,
privately and publically owned buildings, SOU facilities and determine the total
distributed generation potential if possible. Any project less than 200kW nameplate that
serves customer load does not have a negative effect on the BPA power sales contract
with Ashland. Evaluate energy and economic impacts of implementing additional solar
rebates or feed-in-tariffs for customer owned capacity.
7. 1 MW Solar Siting: Determine if there is a suitable site for a ground mounted 1 MW array
with a direct connection to Ashland's distribution system. A system sized less that 1 MW
is easily integrated into the distribution system and also does not have a negative effect
on the BPA power sales contract.
8. Energy Efficiency: Determine the potential conservation measures that could be
accelerated by 2020, as energy efficiency is the least cost, local, and cleanest resource.
9. Low Income Support: Determine what support may be available for low-to-moderate
income utility customers, to insulate them from projected rate increases. This could
include dedicated low-income community solar, voluntary energy assistance programs,
or a broader partnership with ACCESS to increase low-income weatherization and
renewable energy benefits.
10. Request for Proposals: Release an RFP for up to 13MW of solar on the Imperatrice
property after these critical questions have clarity, 2018.
Upon receiving all this information the City can then evaluate all of the options for complying
with Ordinance No. 3134 and begin the hard job of implementing a cohesive and well
researched package of measures.
Best Regards,
W
Dick Wanderscheid Evan Ramsey
Vice President Senior Project Manager
Renewable Energy Group Renewable Energy Group
503-553-3934 503-553-3933
dwanderscheid(aD-b-e-f.org eramsey(o)_b-e-f.org
13ONNEVILLE 240 SW ist Avenue
ENVIRONMENTAL = Portland OR 97204
FOUNDATION 503-248-1905
= WWW.b-a-forg
TECHNICAL MEMORANDUM ' ENGINEERING
PO Box 70413 ■ SPRINGFIELD, OR 97475 ■ PHONE (541)393-3345 ■ FAX (541)505-8917
City of Ashland PV Generation Interconnect Analysis
PREPARED FOR: Tom McBartlett, Electrical System Manager/City of Ashland, Elec. Dept.
PREPARED BY: Martin Stoddard, P.E./OS Engineering
COPIES: Mark Holden/City of Ashland, Elec. Dept.
Adam Hanks/City of Ashland, Elec. Dept
Jerry Witkowski, RE./OS Engineering
Jiajia Song, Ph.D./OS Engineering
DATE: January 31, 2017
1.0 EXECUTIVE SUMMARY
1.1 General
This engineering document describes a preliminary review of options and interconnect feasibility for
adding a large scale Photovoltaic (PV) generation facility and cormecting it into the City's existing
electrical distribution system. It is our understanding that the project objective is to install a solar
generation system with the capacity to meet approximately 10% of the City's annual energy consumption,
which is equivalent to a system with a nameplate capacity of approximately 10 MW. It is also our
understanding that the City prefers to interconnect the PV system directly to the City's existing
distribution system rather than a transmission interconnection.
This engineering investigation evaluated integrating photovoltaic systems with generation output ranging
between 2.5 MW and 10 MW. This range was based on the ability of the City's existing facility
capabilities at practical interconnection locations.
The PV site is located approximately I mile from nearby City electric distribution facilities and, although
the solar array would be constructed on City owned property, the interconnection would be constructed
outside the City's existing service territory. Therefore, interconnect construction will require permitting,
easements and rights-of-way access.
Presently the City has an exclusive power purchase agreement with the Bonneville Power Administration
(BPA) and BPA has a General Transfer Agreement with PacifiCorp. Our review of the interconnect
options assumes generation export is not desired and that all energy production from the new system will
be utilized by the City. Because of the City's intent to maximize the amount of solar generation and the
desire to not export power, the engineering investigation evaluated the estimated PV generation profile
with seasonal adjustment against typical seasonal load profiles as a base criteria for establishing
maximum interconnect generation capacity.
City of Ashland PV Generation Interconnect Analysis Page 1 of 34
1.2 PV System Interconnect
Distribution system connected generation can have significant impacts on protection and power quality of
an electric distribution system. Therefore, carefully defined protection and control requirements are
necessary. This includes output protection and control at the inverter by the PV developer and protection,
control and metering at the utility point of common coupling (PCC) by the City.
Multiple interconnection points are available within the City's distribution system. Several of these
connection points were evaluated to identify maximum feasible PV capacity. This included remote
interconnections at radial taps and connection with main backbone circuits. To maximize PV generation,
interconnection with a distribution backbone feeder circuit is necessary. However, due to minimum peak
substation loading at certain times of the year, the maximum PV output that can be interconnected to any
one substation is limited to 5 MW based on a review of historic load data and estimated generations
profiles. To interconnect PV output generation to the extent desired by the City (-10 MW), it will likely
be necessary to interconnect with two backbone feeder circuits from two separate substations.
We have assumed the PCC interconnection between the PV system and utility system will be located
within the southwest region of the Imperatrice Property, not within the Short-Term Lease area. Leaving
the Short-Term Lease property available for other future uses.
We recommend that the City substantiate, through the PV development RFP, that the solar construction
project conforms to all applicable industry standards regarding equipment, construction and operation to
assure protection of the electric systems normal operation and quality of service to existing customers.
1.3 Comments and Recommendations
Our preliminary analysis and review indicates that the City can achieve the PV generation interconnect
desired without excessive deleterious effect to the existing distribution system or violation of existing
purchase agreements. However, interconnection to the existing City distribution facilities should be
coordinated as stated above and described in greater detail in this memorandum. Where are analysis has
concluded a maximum interconnect generation size, it can be assumed that a smaller system can be
accommodated thus allowing the City to install PV generation in increments staged, for example, in 1
MW or 2.5 MW output capacities.
To achieve strong interconnection(s) between the PCC and the existing electric distribution system it is
recommended that a tie location occur near the vicinity or N Mountain Avenue and E Nevada Street. This
location offers connection to a feeder from Ashland Substation, Mountain Avenue Substation, or both to
accommodate the full PV build-out capacity of 10 MW. This location should be considered even if the PV
facility is built in stages. Other interconnection locations are available and are described elsewhere in this
memorandum but to achieve the City's ultimate capacity goal this tie point is the optimal location for the
existing system.
To accomplish interconnection between the PV system and the City's existing distribution system we
recommend consideration for underground construction to meet the least public resistance. This can be
accomplished with both open trench and directional bore construction. If the City intends to have the PV
City of Ashland PV Generation Interconnect Analysis Page 2 of 34
site developed in incremental stages, it is suggested that all underground infrastructure be installed
initially, with major equipment installed as needed to meet generation capacity.
If the City is considering having the utility interconnection construction performed by the PV developer it
is suggested that construction technical specifications and material standards be assembled and provide to
ensure quality construction.
Budgetary pricing has been assembled to expand the City's electric system to interconnect at the PCC
with the PV site as described herein. The cost to construct circuit interconnections for a PV facility with
capacity ranging between 2.5 MW and 10 MW is estimated to be between $0.9 and $1.5M.
2.0 INTRODUCTION
2.1 Overview of the project
The City of Ashland intends to install a PV generation system that can support approximately 10% of its
annual energy usage, 17AM kWh, which the City has determined to be equivalent to approximately 10
MW. The City has explained its preference to interconnect the PV system directly to the City's existing
12.47 kV distribution system, and requested OS Engineering, engineering service contractor for the City,
to evaluate the feasibility and impacts of various interconnect options to meet the City's intent. In this
study, OS Engineering has developed and assessed three different interconnecting options of the
integration of a power generation PV system into existing City of Ashland distribution facilities. Our
review includes estimated generation output, system load profiles, power quality considerations,
protection, and approximate cost estimates.
2.2 Map of the project and potential interconnect points
The following two maps show the City of Ashland Imperatrice Property Map 2005, and potential PV
Interconnection Points Map, respectively.
City of Ashland PV Generation Interconnect Analysis Page 3 of 34
Base Map: zoos Aerial. Photo
Proposed Short.Term Use TVI
~ Y t
h h 4o-'
Lease Area
• l`{q x! 4
r t u
N
r~
'r. 7 - s }.may s "r•
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4
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(F~,rcef area) ~ ti '+ut y
Legend
Short -term Lease Use
- . \
propose ease area _ ~`~r-~ 5
Imperatrice Property
u
Ashland City Limits
Taxlots
i
? f Proposed Trail Easement
O. Access Points AN
s ~ i1, rp wQ ~E
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' x, -As I f I 1 I I 1 I I I •s
City of Ashland PV Interconnection Map Legend
Option
i
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00 00
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s
Q rlrJ . r- ` xf . r~
e r~ r = t r.. ~
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01
3.0 PV TECHNOLOGY OVERVIEW
Photovoltaics (PV) systems have been well recognized as a promising renewable energy technology and
have been growing exponentially worldwide for more than two decades, during which PV technologies
evolved in many different aspects, such as flat-plate vs. concentrating, improved materials, higher
efficiency, lower costs, etc. During this time, many improvements have been realized in inverter
technology, tracking systems, controls, and protection that facilitate PV generation in large scale power
production interconnected to transmission and distribution systems. As a preliminary study regarding the
City of Ashland PV project, we did not investigate the option of concentrator and different type of PV
modules and inverters, but utilized a generic flat-plate PV and inverter combination in order to provide
representative PV generation profiles for different mounting configurations based on actual seasonal
weather data in the City of Ashland area.
3.1 PV Generation Profile
The City of Ashland 2014 hourly weather data, including solar irradiance (Solar irradiance is the power
per unit area received from the Sun in the form of electromagnetic radiation), is available from the NREL
National Solar Radiation Database (NSRDB). The database contains satellite-derived data from the
Physical Solar Model (PSM) for both typical year data and historical single year data for 1998 through
2014 for locations in the United States. The weather in the Northwest area has a fairly repeatable pattern
every year, therefore the 2014 weather data is used to as a typical profile for the City of Ashland.
One of the parameters available in the 2014 weather data is the Global Horizontal Irradiance (GHI). The
GHI is the total amount of shortwave radiation received from above by a surface horizontal to the ground.
This value is of particular interest to photovoltaic installations and includes both Direct Normal Irradiance
(DNI) and Diffuse Horizontal Irradiance (DHI). DNI is solar radiation that comes in a straight line from
the direction of the sun at its current position in the sky. DHI is solar radiation that does not arrive on a
direct path from the sun, but has been scattered by molecules and particles in the atmosphere and comes
equally from all directions. Figure 1 shows the three profiles for City of Ashland, 2014.
City of Ashland PV Generation Interconnect Analysis Page 6 of 34
400 - ashland, oregon_i_„Global irradiance - GHI (W/m2)
- ashland, oregon`„'^•-_eeam irradiance - DM (N11m2)
ry 350 - - - - - - -
E -ashland, oregon___DifSue irradiance - DHI (W/m2)
300 - - - - - - - -
t
250 . - -
200
m
150 - -
t
100 -
0
50 - - - - - - -
o
500
450
400 - - - - -
350
- I
-300
E
3 250 - - - - - - - - - - -
200 - - -
150 - - - - - - - -
100
50
0
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Figure 1: Global Horizontal Irradiance (GHI), Direct Normal Irradiance (DNI), and Diffuse Horizontal Irradiance (DHI) in
wattsIM2 in City of Ashland, 2014
Figure 2 shows the daily temperature map throughout the entire year of 2014 in degrees Celsius. The data
provides the typical temperature distribution pattern in Pacific Northwest area. Figure 3 illustrates the
same data as provided in Figure 1 and 2 but in monthly averages. The left axis and blue line of Figure 3
represents the level of irradiance and the right axis and orange line represent temperature.
39
34.2
29.4
20 24.6
19.8
15
10.2
15E' 11 5.4
0.6
T
m
~ -4.2
`o
_y
0
x
10
5
0
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Figure 2: Daily temperature map for City of Ashland, 2014
City of Ashland PV Generation Interconnect Analysis Page 7 of 34
January February March April
Legend
Soo 30 Boo 30 800 30 Soo 30 Temperature
20 20 20 20 Irradiance
10 10
10 10
A,N
0 o 0 0 0 0 0 0
0 10 20 0 10 20 0 10 20 0 10 20
N May June July August
800 - 30 Boo— - 30 800 - - 30 800 - - - 30
S
t7
20 20 20 20
C
E
10 to l0 10
F
00 10 20 0 00 10 20 0 00 10 20 0 00 10 20 0 T
r
September October November December 3
30 - - 30 - - - 30
Boo Boo Soo---- Boo— - 303
20 20 20 20
10 zA\- to 10 10
0 0 0 0 0 0 0 0
0 10 20 0 10 20 0 10 20 0 10 20
Figure 3: Monthly irradiance and temperature profile for City of Ashland, 2014
With the actual weather data, PV array power outputs can be estimated or simulated using System
Advisor Model (SAM) developed by National Renewable Energy Laboratory (NREL) SAM is a tool that
is able to facilitate renewable energy integration in both system performance and financial aspects. In this
study, a compatible generic combination of flat-plate PV module and inverter is utilized to form a 1 MW
grid-connected PV array as an example. Larger size PV arrays can be achieved by increasing the number
of modules and inverters, and their power output is essentially scaled up linearly.
PV generation, for the same solar profile, can be maximized/optimized by using technologies such as
tracking systems. Tracking systems orient PV panels toward the Sun, which increases the power
generating capability significantly. Tracking technologies add complexity and may require extra cost and
maintenance and generally is not feasible for most home systems but can provide great benefit to utility
scale grid-connected PV arrays. The additional energy production may offset the added cost of the
tracking system and the increased generation typically is equivalent to a smaller array for the same overall
level of energy production. Figure 4 shows the monthly average power profile using a fix-mount array
that is oriented south (180° Azimuth degree) for a 1 MW PV array, while Figure 5 shows a similar
monthly power profile using an array with a 2-axis tracking system. As can be seen from these two
figures, there is a considerable difference in PV array power output with and without tracking capability.
Specifically, with a tracking system, power output of the same PV array can reach the high power region
much quicker and maintains at that level longer than PV arrays using fixed-mounting. (Note: Simulation
is based on hourly weather data, and no loss and shade is considered for this early phase study.)
City of Ashland PV Generation Interconnect Analysis Page 8 of 34
January February March April
600 - 600 - - 600 600
I
400 400 400 400
200 200 200 200 n
-N [L 0 0 0 0
0 5 10 15 20 0 5 10 15 20 0 5 10 15 20 0 5 10 15 20
May June July August
E 600 600 - 600 600
S
v 400 400 - 400 400 .
I
€ 200 _ 200 200 200
0 0 0 0
0 5 10 15 20 0 5 10 15 20 0 5 10 15 20 0 5 10 15 20
September October November December
600 600 - 600 _ 600
400 - - 400 - - - 400 400
200 200 200 - 200 - -
0 0 0 0
0 5 10 15 20 0 5 10 15 20 0 5 10 15 20 0 5 10 15 20
Figure 4: Monthly average power profile using fixed-mount for a I MW PV array in City of Ashland, 2014
January February March April
800 B00 800 800
600 600 - - - - 600 600
400 400 400 400
200 - - 200 - 200 200 -
0 0 0 0
0 5 10 15 20 0 5 10 15 20 0 5 10 15 20 0 5 10 15 20
May June July August
800 800 800 800
600 600 600 600
$ 400 400 400 400
m 200 200 200 200
t
0
a 0 0 0 0
0 5 10 15 20 0 5 10 15 20 0 5 10 15 20 0 5 10 15 20
800 September 800 October 600 November 800 December
600 600 - 600 - 600
400 400 400 400
200 LO _ 200. 200 200
0 0 0 0
0 5 10 15 20 0 5 10 15 20 0 5 10 15 20 0 5 10 15 20
Figure 5: Monthly average power profile using 2 -Axis tracking for a I MW PV array in City of Ashland, 2014
City of Ashland PV Generation Interconnect Analysis Page 9 of 34
3.2 System load evaluation
The City of Ashland 2016 metering data from BPA was evaluated and the results shown in below table.
The coincident peak demand in 2016 is about 40 MW and occurred during the month of August. The
minimum coincident demand is about 10 MW and occurred during the month of June. At peak demand,
each substation has about 13 MW of load and, in general, the City's load is typically divided uniformly
across the three substations.
Table 1: BPA metering data summary for City of Ashland 2016
{ C r• , i ~ riYi ~a G 1l~1.13 Cat C FACIXUI C~e~i+,fl M~ la l'ub1ae 4A\~1~~: Lad
Meter ID 575 1014 1304 1705 1820
Demand
Average Demand 6,333 2,384 2,541 1,905 6,431 19,594
Peak Demand MM 4,690 5,320 4,040 MM 40,100
Date/Hour 8/19/16 5:00 PM 7/29/16 5:00 PM 12/7/16 7:00 PM 8/19/16 4:00 PM 8/19/16 5:00 PM
Min Demand ) I 1,390 0 940 EM 8,740
Date/Hour 4/18/16 4:00 AM 4/11/16 4:00 AM 1/1/16 2:00 AM 1/3/16 12:00 AM 6/12/16 4:00 AM
Load Factor 0.48 0.51 0.48 0.47 0.50 0.49
Coincident Peak Demand
Maximum
Date 8/19/16 5:00 PM
Minimum 29:
Date 6/12/16 5:00 AM
To better evaluate how PV power generation affects the metering profile at the point of delivery, four
daily profiles in 2016 are selected to represent the Spring light load, Summer peak load, Fall light load,
and Winter peak load cases. Those four days are picked according to daily power consumption in each of
the four meteorological seasons. The typical PV power profiles in those associated months (monthly
average curve as shown in Figure 5) were compared with the selected four daily profiles in the below
plots.
PV generation along with other renewable generation are often treated as negative load. The BPA meter
data summary in Table 1 shows that the peak load at Ashland substation is approximately 13 MW.
However, it does not indicate that this substation can support the integration of as much as 13 MW PV
generation because load curves and PV generation curve do not match each other the majority of the time.
The four groups of plots in Table 2 demonstrate how daily power consumption patterns in different
seasons at Ashland Substation change with the addition of I MW or 5 MW. The PV generation is the
monthly average data and does not represent actual power output for any given date since the actual daily
profile will typically have a significant amount of variation due to weather and operational factors.
However, the plot represents a typical trend of power generation for a day in those months, and it
provides a sufficient approximation of a typical output profile.
The overlaid plots in Table 2 provide an indication of how much PV generation that can be added to
Ashland Substation. It can be seen that Ashland substation can readily integrate a 1 MW PV system
connected to any of its feeders without causing power export. It is also found that Ashland substation is
safe to have 5 MW PV system integrated to any of its feeders as long as the feeder has sufficient ampacity
City of Ashland PV Generation Interconnect Analysis Page 10 of 34
for the peak generation. Power factor exceeds the 0.97 limit during the summer peak of 2016 due to a
large amount of reactive power consumption, presumably by HVAC loads. This is likely to get worse
with more active power generation by PV integrated into the system. A further discussion of power factor
issues is discussed in Section 4.2. A similar conclusion can be made at the Mountain Avenue Substation
as having capacity to integrate as much as 5 MW of PV generation to any of its feeders provided the
feeder has sufficient ampacity.
Table 4 shows a group of similar plots indicating the integration of a 10 MW PV system at Ashland
Substation. The combined daily curves reach a net negative region at the substation resulting in power
export. Similar trends show the same result at Mountain Avenue Substation. To prevent power export, we
estimate significant periods of generation curtailment would be necessary with a 10 MW system
integrated into one substation. Therefore, we do not recommend the full integration of 10 MW of PV
generation to either individual substation.
City of Ashland PV Generation Interconnect Analysis Page 11 of 34
Table 2: Ashland Substation Daily Power Profile with and without PV Generation, I MW or 5 MW
Daily Power Profile Daily Power Profile Daily Power Profile Daily Power Profile
Spring Minimum, May 15 2016 Summar Maximum, Aug 19 2016 Fall Minimum, Sep 5 2016 Winter Maximum, Dec 18 2016
Ashland Subsation Ashland Subsation Ashland Subsation Ashland Subsation
14¢nm -r-Simmer Ma.irnum rlorallld.f, Nb 19, i01f, I+,II%!Itr
c,r..Yrct +t!mv w ]yu,tm HoorlY .~m+raroYl m wcws 4 nM m
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m Id,mim :Doom
uwum
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v.nmm arr,rh HUd, M.v ls, :n 10 4J%Iltel 6,omm
-~1.8 !l rimmil lluwhi Iwd, FU
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With 1 MW PV With 1 MW PV - - - With 1 MW PV With 1 MW PV
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With 5 MW PV With 5 MW PV With 5 MW PV With 5 MW PV
Spring Minimum Summer Maximum Fall Minimum Winter Maximum
un at
tot tot
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F with 1 MW and 5 MW PV F with 1 MW and 5 MW PV PF with 1 MW and 5 MW PV F with 1 MW and 5 MW PV
City of Ashland PV Generation Interconnect Analysis Page 12 of 34
Table 3: Mountain Avenue Substation Daily Power Profile with and without PV Generation, I MW or 5 AlflV
Daily Power Profile Daily Power Profile Daily Power Profile Daily Power Profile
Spring Minimum, May 29 2016 Summar Maximum, Jun 6 2016 Fall Minimum, Sep 4 2016 Winter Maximum, Dec 7 2016
Mtn Ave Subsation Mtn Ave Subsation Mtn Ave Subsation Mtn Ave Subsation
1J,fnM1m unoiM dunun lnnuN Lu..l.lu~l•, )011.
ltrmm
6,000m t A+w 15• Ivuuel HwdVOrrt•le!iun In loon 6.bm00
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U,uw m
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1 gLU31Yl
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IJYUW f~Jp 1,1%.]D"J - )~IJrI ~-Wn[r R+mmmi brit/IntJ wth lrAYfw
nJLn n - b nm
].LO 3SQ q¢ ]d qtQ `vo° z„tfl ]„dJ tidr } a^ ]ld] ] c° n1]~ ]d s`n ]cP qlo R `.z~ 4gfP z~P~ qt}l ] LA ,f1z m510 ,sCU q~ if•C qlo fly" ` ds , ip ~ tP +8 } 35
]5A° ]d ,.14 yd' vl~ q~ 5Rf♦' v~ ],~dv ~5Q 1 8
With 1 MW PV With 1 MW PV With 1 MW PV With 1 MW PV
MfOO ~-s Mw wGnrirpolimuMOr'ara6min Mav ivrs' ~suw Nnr.av rrAVlm°nf r,.~r.,vrn Mn:°a e~ ~-srtrwwar:/rvdr,~Ho-.,nr e°x°!,;im,msrp<noerr 3uxJf ~-sevv Narr.,r rrar~lmark
~*+>Jo-,mmlrovr
)gyp -O-suina rnirimum HwlN foal. M,vzO. mlE _ b~S"TM"'r R!+"m°m"°~°Nlma,r~a)(110 y~Lee Mimrtrim MwhLwJ, SC, e, 3016 -'f•tttnlx R•~dnvmibxN fool, 4=t I. )CLL
1HNY1 -~S.mmer MJ.6num HewNlwErith S.Y.WV iHYIr -awimv M.umun~IY„r~h h•.+1 xi1nS lA5'I rl
-a5uing rAilimum HwrN Loadnnn 5 Mw R' r-rut R+i~vrnun FbuH Lazl ri+h 5 Riw M
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10Dm 1r[xLJ -
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With 5 MW PV With 5 MW PV With 5 MW PV With 5 MW PV
Spring Minimum Summer Maximum Fall Minimum Winter Maximum
L UI - - 1.U1
fAl !m - - - - - - lAl 1nL
1 m 0.93 ]m 1 iW
a L IM ~ YA a I m a I.m
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a b.rf C nn) _ _ oar
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-►-rr v:nlw,w rv -►-rr licrovr w -.-rr vum,t w ~-rr nvLlouL w
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PF with 1 MW and 5 MW PV F with 1 MW and 5 MW PV PF with 1 MW and 5 MW PV PF with 1 MW and 5 MW PV
City of Ashland PV Generation Interconnect Analysis Page 13 of 34
Table 4: Ashland Substation Daily Power Profile with and without PV Generation, 10 MW
Daily Power Profile Daily Power Profile Daily Power Profile Daily Power Profile
Spring Minimum, May 29 2016 Summar Maximum, Jun 6 2016 Fall Minimum, Sep 4 2016 Winter Maximum, Dec 7 2016
Mtn Ave Subsation Mtn Ave Subsation Mtn Ave Subsation Mtn Ave Subsation
ICl1U tIM 1-w Rrnr Txdrm-V Lncr nANr I~WC +-lU MY'J t` A 1,P1.1 l x..virf rwr: ivrm N~uu ]rAVJ r-ICMV/rV ar,.rlr1H-ri turrrir r>i~r.ewrin5eµenan, r~xu -a-IOMW IN
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With 10 MW PV With 10 MW PV With 10 MW PV With 10 MW PV
City of Ashland PV Generation Interconnect Analysis Page 14 of 34
3.3 Overview of options for interconnect
Based on the evaluation in Section 4 and Section 5 and geographic proximities, several locations have
been identified for interconnection to the City's electric distribution system including:
• Ashland Substation
o Business Feeder to WWTP radial tap circuit, support for -2.5 MW.
o N Main Feeder at Oak St/Nevada St backbone circuit, support for -5 MW.
o Business Feeder at Oak St/Nevada St, backbone circuit support for -5 MW.
o E Nevada Feeder at N Mountain Rd, backbone circuit, support for -5 MW.
• Mountain Avenue
o N Mountain Feeder at N Mountain Rd, backbone circuit support for -5 MW.
Any of these interconnection points are estimated to be able to support up to approximately 2.5 MW to 5
MW as indicated. To accommodate greater generation, up to approximately 10 MW, would require
generation to be split between feeders from different substations. The interconnect locations and
construction requirements are summarized below and described greater detail in Section 5.0.
Option I
Strong and recommended distribution interconnection points are near the E Nevada Street and N
Mountain Avenue intersection vicinity southwest of the PV point of common coupling (PCC).
This location, approximately 1.1 miles from the southwest corner of the PV Imperatrice Property
site, allows interconnection to two feeders and different substations. The route from the solar site
could be south and west along N Mountain Avenue, then via the 1-5 N Mountain Avenue
overpass to the electric system interconnections.
At this location good circuit interconnections can tie into one or two existing City of Ashland
electric distribution backbone circuits at the PV system primary delivery voltage (12.47 W). The
existing interconnection points available are 1) the N Mountain Feeder served from the Mountain
Avenue Substation; and 2) the E Nevada Feeder served from the Ashland Substation with minor
switching changes. A generated capacity of up to 5 MW could be delivered to one circuit or up to
10 MW delivered and split between both circuits. The associated PV array interconnection
configuration one-line diagrams are shown in Figure 6 for 10 MW capacity and Figure 7 for 5
MW capacity.
In Figures 6, 7, and 8, the PV system is modeled as a cluster of 500 kW PV arrays and 500 kW
inverters, with individual step-up transformers having built-in fusing and disconnects for
isolation. This is one potential arrangement and is not intended to indicate a technical requirement
or preference for the PV system arrangement. However, the arrangement does show our
recommendation for the City operated interface at the PCC. As shown, we recommend two
switchgear sections with a combination breaker and disconnect switch plus metering as the utility
interface to the PV system.
City of Ashland PV Generation Interconnect Analysis Page 15 of 34
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Option II
A second interconnection location is a tie between the PV system PCC primary delivery voltage
(12.47) and the existing Business Feeder or N Main Feeder served from the Ashland Substation
near the intersection of Oak Street and Nevada Street. This tie location is approximately 1.5 miles
from the southwest corner of the PV Imperatrice Property site and could be connected by
overhead or underground construction. The route from the solar site could be south along N.
Mountain Avenue, west along Eagle Mill Road and via the 1-5 Eagle Mill overpass south along
Oak Street to the Nevada Street interconnect. This interconnection location could accommodate
one feeder interconnection up to -5 MW, whose potential interconnection configuration is shown
in Figure 7.
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City of Ashland PV Generation Interconnect Analysis Page 16 of 34
I
Option III
An option to the Case II interconnection description above would be to intercept the circuit
feeding the WWTP by extending the line along the Bear Creek Greenway access road from Oak
Street. This option would be limited to -2.5 MW of PV generation. Although the total distance is
similar, approximately 1.4 miles, the advantage is a more accessible easement for construction
along the Bear Creek Greenway access road which could include open trench and underground
bore construction beneath I-5 from the generation site to the circuit interconnect. Figure 8
illustrates a possible interconnecting configuration for a 2.5 MW PV farm.
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Figure 8: 2.5 MW PV configuration
4.0 ANALYSIS AND SYSTEM REQUIREMENTS
The following assumptions are consistent for all study scenarios unless otherwise noted.
• This study assumed that no major system expansion projects were implemented by the area utility
since the Electrical System 10-Year Planning Study for City of Ashland (by CVO Electrical
Systems), in 2014.
• This study mainly focused on integrating PV generation into City of Ashland electrical
distribution system as proposed by the City, and did not analyze in detail any PPL distribution or
transmission interconnections options with BPA, even though they are physically closer to the
potential PV sites.
For inverter-based energy resource including PV generation, the following standards and guidelines are
recommended as required for the construction of this project:
IEEE Standard 929-2000, "IEEE Recommended Practice for Utility Interface of Photovoltaic (PI)
Systems. "
City of Ashland PV Generation Interconnect Analysis Page 17 of 34
IEEE Standard 1547-2003, "IEEE Standard for Interconnecting Distributed Resources with Electric
Power Systems. "
UL Standard 1741, "Inverters, Converters and Charge Controllers for Use in Independent Power
Systems. "
4.1 Power flow analysis.
This study included steady state analysis and system response analysis only. Transient and stability
analysis was not conducted. A description of the procedures used to complete the analyses is presented
below:
a. Development and Description of System Model
The City of Ashland distribution system model was developed in EasyPower analysis software
according to the 2014 System Planning Study based on the information provided by the City,
State, County, BPA and PacifiCorp. Two base cases used in this analysis are shown below:
• Base Case IA - normal system configuration under peak load conditions, 2013.
• Base Case 1B - normal system configuration under light load conditions, 2013.
(Note: the 2013 model is readily available from the 2014 System Planning Study. Its peak
consumption is about 43 MW, which is higher than the 2016 peak demand - 40 MW, however,
the light loads for both years are almost the same. It should not make significant differences in
this study.)
b. PV Generation Modeling
IEEE Standard 929-2000 requires that PV system should operate at a power factor >0.85 lagging
or leading when output is >10% of rating. Modern inverter technologies typically have high
efficiency and provide a nearly unit power factor (pf> 0.99) at rated power. Some inverters are
able to provide reactive power compensation to the grid by advanced inverter control, to enable
PV arrays to participate in grid voltage control and power factor correction. This is briefly
discussed in Section 4.1. PV arrays in this study are modeled as PQG type generators and we
have assumed that inverters operate at unit power factor (pf = 1) with no reactive power (var)
generation. The generator was modeled at the voltage level of the point of the interconnection,
and no step-up transformer (GSU) was modeled.
c. Steady State Power Flow Analysis
Power flow analysis was implemented for each of the interconnecting options that have been
discussed in this study. More details about the interconnecting options can be found in Section
3.3 and Section 5.
I. Two available interconnecting points near the E Nevada Street and N Mountain Avenue
intersection for up to 10 MW:
o 5 MW, N Mountain feeder served from Mountain Avenue Substation
o 5 MW, E Nevada feeder served from Ashland Substation
II. Two available interconnecting points near the Nevada Street and Oak Street intersection
for up to5MW:
City of Ashland PV Generation Interconnect Analysis Page 18 of 34
0 5 MW, N Main feeder served from Ashland Substation, or
0 5 MW, Business feeder served from Ashland Substation, or
o Split to the above two feeders and not exceed a total of 5 MW
III. Interconnecting with the circuit serving Waste Water Treatment Plant (WWTP) for up to
2.5 MW.
Peak load and light load base cases were evaluated regarding equipment overload and bus voltage
violation under both normal and contingency conditions prior to and after the addition of the proposed PV
generation. Equipment is evaluated as overloaded if load exceeds its rated capacity, and voltage violation
is assessed in accordance with standards established by the American National Standard Institute (ANSI
C84.1, Range A), the voltage ranges in Table 5, shown as acceptable voltage or allowable voltage drop,
should be maintained throughout the City's electric system. The voltages shown are presented on a 120
volt base, however the percentages indicated apply to any voltage base, for example 12.47/7.2 kV,
480/277 V, etc., as applicable to the specific location.
Table 5: Acceptable voltage levels, City of Ashland
Facility Acceptable Voltage or Allowable Acceptable Percentage
Voltage Drop (Volts)
Bus voltage range at substation. 122 - 126 102%-105%
Maximum voltage drop along a distribution feeder. 8
Voltage range at primary terminals of distribution 118- 126 98%-105%
transformers;
Maximum voltage drop across distribution 4
transformer and service conductors.
Voltage range at customer meter. 114-126 95%-105%
oltage range at customers utilization equip. 110- 126 92%-105%
Power flow analysis results
Power flow study analysis results are summarized in Table 6 and Table 7. It is shown in Table 6 that no
transmission facilities were overloaded and bus voltage did not exceed the acceptable limits in Table 5 in
the territory of City of Ashland electrical system at normal system conditions, peak and light load cases,
and prior to and after the addition of the PV generation proposed in the three interconnection options.
In the 2014 System Planning Study, system's switching flexibility during outages and abnormal
conditions were evaluated. While in this study, two major contingency scenarios significant to this PV
integration project are assessed. Specifically, the loss of either the Ashland Substation or Mountain
Avenue Substation. Loss of Oak Knoll Substation was not considered in the assessment because the
proposed interconnection options do not involve any major feeder served from Oak Knoll Substation.
The scenario involving the loss of Ashland Substation during peak load results in the transfonner at
Mountain Avenue Substation being heavily overloaded. There are also conditions of overloaded cables
and a number of bus voltage violations. More information about this case can be found in the 2014
System Planning Study Section D. From Table 7, it can be concluded that PV generation proposed in
three options can actually eliminate or reduce the overload within the system, which is reasonable since
renewable energy generation are normally treated as negative load due to its varying characteristic.
City of Ashland PV Generation Interconnect Analysis Page 19 of 34
Similarly during loss of Mountain Avenue Substation, the transformer at Ashland Substation is
significantly overloaded prior to integrating PV generation. However, with proposed PV integration
options, the transformer overload is eliminated. From this analysis we conclude that with or without full
PV generation integrated to the City's distribution system, no overload or voltage violation was observed
for the scenarios reviewed.
Table 6: Power flow analysis results at NORMAL condition for both peak and light base cases
Condition Option Interconnection Points Peak Load Light Load
Base Case 1A Base Case 1B
Pre-Project No PV generation integrated No overload and No overload and
voltage violation voltage violation
5 MW, N Mountain feeder from No overload and No overload and
I Mountain Avenue substation voltage violation voltage violation
(Up to 10 MW) 5 MW, E Nevada feeder served No overload and No overload and
from Ashland Substation voltage violation voltage violation
Normal 5 MW, N Main feeder served No overload and No overload and
II from Ashland Substation voltage violation voltage violation
(Up to 5 MW) . OR
5 MW, Business feeder served No overload and No overload and
from Ashland Substation voltage violation voltage violation
III 2.5 MW Interconnecting with No overload and No overload and
(Up to 2.5 MW) circuit serving (WWTP) voltage violation voltage violation
Table 7: Power flow analysis results at CONTINGENCY condition (e.g., loss ofsubstation) for both peak and light base cases
Condition Option Interconnection Points Peak Load Light Load
(Base Case 1A) (Base Case 1B)
Significant overload
observed at Mountain No overload and
Pre-Project No PV generation integrated Ave Substation
transformer and several voltage violation
cables
5 MW, N Mountain feeder from No overload at
Mountain Avenue Substation Mountain Ave
I Substation transformer, No overload and
(Up to 10 MW) 5 MW, E Nevada feeder served and much less voltage violation
from Ashland Substation overloaded cables
observed.
Less overloaded at
Loss of Mountain Ave
Ashland 5 MW, N Main feeder served Substation transformer, No overload and
Substation from Ashland Substation and less overloaded voltage violation
II cables observed.
(Up to 5 MW) OR
Less overloaded at
5 MW, Business feeder served Mountain Ave No overload and
Substation transformer,
from Ashland Substation and less overloaded voltage violation
cables observed.
Less overloaded at
III 2.5 MW Interconnecting with Mountain Ave No overload and
(Up to 2.5 MW) circuit serving (WWTP) Substation transformer, voltage violation
and less overloaded cables observed.
City of Ashland PV Generation Interconnect Analysis Page 20 of 34
Condition Option Interconnection Points Peak Load Light Load
(Base Case 1A (Base Case 1B)
Significant overload
observed at Ashland
Substation
Pre-Project No PV generation integrated transformer, No overload and
and no other overload voltage violation
and voltage violation
observed..
5 MW, N Mountain feeder from No overload at Ashland
I Mountain Avenue Substation Substation transformer, No overload and
(Up to 10 MW) 5 MW E Nevada feeder served and no other overload voltage violation
and voltage violation from Ashland Substation observed.
Less overloaded at
Ashland Substation
Loss of 5 MW, N Main feeder served transformer, and no No overload and
Mountain from Ashland Substation other overload and voltage violation
Avenue voltage violation
Substation observed.
II OR
(Up to 5 MW)
Less overloaded at
Ashland Substation
5 MW, Business feeder served transformer, and no No overload and
from Ashland Substation other overload and voltage violation
voltage violation
observed.
Less overloaded at
Ashland Substation
III 2.5 MW Interconnecting with transformer, and no No overload and
(Up to 2.5 MW) circuit serving (WWTP) other overload and voltage violation
voltage violation
observed.
In summary, the analysis showed that the addition of the proposed PV generation to the system would not
have an adverse impact on the City of Ashland electrical distribution system in steady state power flow
analysis. Instead, it could relieve the transformer overload and the potential voltage violations during peak
load when there is a loss of either Ashland Substation or Mount Avenue Substation, depending on the
level PV generation. In addition, there is no overload and voltage violation observed during light load
conditions with or without PV generation integration.
4.2 Power factor
In October 1999 BPA began requiring compliance by its customers to adhere to a 97 percent power
factor, an increase from the previous power factor requirement of 95 percent. This compliance is based on
a bandwidth established at 25% reactive deadband of monthly real power demand compared to the
previous 33% reactive deadband. Consumers must not only conform to a smaller power factor bandwidth
but will encounter more rigid penalties for failure to comply. Poor power factors will also be penalized
through a ratcheted demand penalty. This penalty will be enforced for a 12-month period, the violation
month and the following 11-months after each violation. During this 12-month period BPA metering will
continue to monitor for out of range power factors, and if a power factor is incurred that results in a
greater penalty a new penalty will be assessed for the next 12 months. This process continues and will
repeat until the power factor is in compliance with the penalty criteria at all times.
Figure 9 shows the power factor profile in a day without and with 1 MW or 5 MW PV generation for
Ashland Substation, August 19, 2016. Power factor exceeds the 0.97 (97 percent) limit in summer peak
City of Ashland PV Generation Interconnect Analysis Page 21 of 34
2016 due to large amounts of reactive power consumption, presumably by HVAC load, even without PV
generation. This likely results in the City of Ashland having to pay an approximate $1,000 penalty
change. However, with more active power generation by PV arrays integrated to the system the overall
peak demand during the month is likely to be reduced. With the reactive power demand remaining the
same in the system the probability of the peak reactive power exceeding the deadband value (25% of
monthly demand peak) and the duration and extent of the reactive power exceeding the deadband are
likely to increase.
Summer Maximum
1.01
i
0.99
0 0.98
L
0.77 - - - - I
a
--41--Pr 'Mthcut PV
095 ~Pr•~Ath1MW PV
j
--a'-PF %Vith S MW PV
094 - -
093
Figure 9: Power factor profile without and with I MW or S MW PV generation (Operating PF =1) for Ashland Substation,
August 19, 2016
Additional considerations for power factor improving/correcting measurements might be required to
avoid increased penalties. As mentioned briefly in the introduction, advanced inverter control technology
could be utilized to either generate or absorb certain reactive power by adjusting the current phase angle
allowing the PV system to participate grid stability control and power quality improvement. A quick
example is shown in Figure 10, where the operating power factor of the inverter is set at 0.95 lagging
(note, a lagging power factor on a generator is equivalent to a leading power factor on a load). This would
produce approximately 30% of total kVA demand as reactive power. The supplied vars would
compensate lagging loads in the system reducing the total reactive power requirement from the
substation. As can be seen, with inverter power factor at 0.95, the power factor profile at the substation is
improved overall. However, the morning var consumption is over compensated and results in leading
overall system power factor for 5 MW PV array. Therefore, a dynamic inverter operating power factor
could be developed according to an active or simulated Ashland load profile to more closely match
compensation with changing load, although this advanced control could impact the system cost. There are
additional methods that can help improve power factor as alternatives to the above. These methods are not
described here but can be provided by OS Engineering if of interest to the City.
City of Ashland PV Generation Interconnect Analysis Page 22 of 34
Summer Maximum
1.01 - - - - - - -
I ~
1.00
0.99 - - i
j
0.98
i
097
II o -
a 0.96
9-PF v ithout PV
095
' I --4P---PF vrithlMW PV, invert er Pf=
0.95
094
I
0.93
Figure 10: Power factor profile without and with I MW or 5 MW PV generation (Operating PF = 0.95) for Ashland Substation,
August 19, 2016
4.3 Short circuit capabilities at PCC
A short circuit analysis is required to evaluate the maximum fault current level at the PCC with the
addition of the proposed PV generation. This is necessary to determine the adequacy of equipment
interrupting capability.
For a grid-tie PV farm, the maximum fault current at PCC consists of three parts:
• Potential fault current contribution from step-up transformers (GSU)
• Fault current contribution form inverter-based PV array
• Fault current from the system.
In this study, the PV array was modeled as a lump generator at the PCC and the GSU was not modeled. In
any case, the GSU would not contribute fault current at the PCC for three-phase faults. However, if a
Delta-Grounded Wye connected transformer is used as is common for generation interconnects with the
PV array connected on the Delta side, the transformer will contribute zero-sequence fault current at the
PCC for unbalanced faults (i.e., single-line to ground fault, line to line fault, and double-line to ground
fault) due to the circulating current within Delta connection. Taking a Delta-Grounded Wye transformer
with z% impedance as an example, the fault current contribution from a single-line to ground fault is If=
3 * VLN / (Za + Zb + Zo + 3Zb), where Za, Zb, Zo, and Zg are the positive sequence, negative sequence, zero
sequence, and ground impedances. Assuming a solid ground fault with typical impedance values as an
example, a single-line to ground fault is estimated to contribute approximately 1 kA from a 5 MVA
transformer.
The second contribution factor from inverter-based PV array is more difficult to quantify mathematically.
Unlike synchronous generators or induction motors, inverters do not have a rotating mass component;
therefore, they do not develop inertia to carry fault current based on an electro-magnetic characteristics.
Power electronic inverters have a much faster decaying envelope for fault currents because the devices
lack predominately inductive characteristics that are associated with rotating machines. Research has been
done to quantify the fault current from inverter based renewable energy generation, and the general
conclusion is that inverter-based distributed energy resource provides insignificant or minimal fault
City of Ashland PV Generation Interconnect Analysis Page 23 of 34
current contribution. The current industry's practice regarding fault current level assessment for setting
protective relays has been to apply a "rule of thumb" of 2 times rated continuous current for distributed
energy resource. Therefore, assuming the inverter ac voltage is 480V, the maximum fault current
contribution at the 12.47kV PCC for a 5 MW PV array is estimated as:
5000 / 480 / 1.732 * 2 * (480 / 12470) = 463 A
The third part is the fault current contributed by the existing distribution system, which can be readily
obtained from a short circuit study using computer-based tool. The fault current levels for those proposed
interconnection points, from the simulation, are in a range of 3.5 kA to 5 kA for both single-line to
ground and three-phase fault.
At PCC, the equipment installed shall have a minimum interrupting rating higher than the summation of
the above three parts for both three-phase fault and single-line to ground fault, which should be less than
10 kA due to the insignificance of the first two parts. Detailed calculation can be done when the actual PV
technology and size are selected but the result is not expected to exceed the capabilities of existing
distribution system equipment.
4.4 Harmonic requirements
Harmonics are omnipresent in electrical distribution systems and can cause a variety of problems. In both
IEEE Standard 929 and IEEE Standard 1547, they refer to IEEE Standard 519-1992, which establishes
limits for harmonic currents and voltages. The objective of these limits is to limit the maximum individual
frequency voltage harmonic to 3% and the total harmonic distortion (THD) to 5%. It also requires that
each individual harmonic to be limited to the percentages listed in Table 8. These limits apply to the Point
of Common Coupling (PCC) with the utility.
Table 8: Distortion limits as recommended in IEEE Std 519-1992 for six pulse converters
Odd harmonics Distortion limit
31e_91t' <4.0%
17'~-?ls< < 1.5%
23rd-33rd <0.6%,
Above the 331d <03%
Note: These requirements are for six-pulse converters and general distortion situations. IEEE Std 519-1992 gives a conversion
formula for converters with pulse numbers greater than six.
4.5 Voltage requirements includingflicker
Voltage flicker is defined as a voltage variation sufficient in duration to allow visual observation of a
change in electric light intensity of an incandescent light bulb. The IEEE curve in Figure 11 showing
fluctuations per time period versus borderline of visibility and borderline of irritation is shown below.
City of Ashland PV Generation Interconnect Analysis Page 24 of 34
The suggested operating criteria is that the magnitude of voltage flicker must be limited to less than 3%
and that the frequency of flicker fluctuations be less than the border line of irritation boundary.
6
5
a 4
o`
w
[7
3
BORDERLINE OF IRRITATION
O
1
W 2 t70RDERLINE OF VISIBILITY OF FLICKER
U
w
C I
0
1 2 5 10 20 30 1 2 5 10 20 30 1 2 5 10 20
DIPS PER HOUR DIPS PER MINUTE DIPS PER SECOND
FREQUENCY OF DIPS
Figure A.1--Flicker tolerance curve from IEEE Std 141-1993itEEE Std 519-1992
Figure 11: Flicker curve in IEEE Standard 141-193IIEEE Standard 519-1992
Clouds shading adversely impact the output of a PV system. As a cloud shadow passes over a PV system
the power output will decrease due to the reduction in sunlight. The change in PV system power output on
a distribution circuit may cause a fluctuation of voltage that might be seen by City of Ashland electric
customers. This fluctuation would be classified as a voltage flicker.
Additionally, a rapid change in load cannot be compensated by the voltage regulation equipment installed
on a distribution system. Most utilities use a typical time delay setting of 60 seconds for substation LTCs
and 90 seconds for line voltage regulators. This time delay means that an LTC or voltage regulator will
not respond to voltage changes until the voltage has been outside of the bandwidth for as long as 60 to 90
seconds. This helps to control "hunting" of the multiple devices trying to control the voltage.
As a cloud passes over a PV system.the output will decrease to a lower value. Given the amount of PV
system output reduction due to clouds is not known, the assumption is that it goes to zero and returns to
full output once sunlight returns. A semi-transient simulation was implemented by switching on and off
of the PV system in both peak load and light load conditions, and no significant voltage drop or flicker
was noted in the system analysis.
4.6 Metering requirements
Per FERC Standardization of Small Generator Interconnection Agreements and Procedures and BPA
Standard Small Generator Interconnection Procedures (Attachment N of BPA Open Access
Transmission Tariff), any metering necessitated by the use of the Small Generating Facility shall be
installed at the Interconnection Customer's expense in accordance with the Transmission Provider's
specifications. It also would require that the Interconnection Customer's metering equipment conform to
applicable industry rules and operating requirements.
For this project, metering is recommended to be installed at the 12.47kV interconnection/tie point, and
shall be connected with the City's existing SCADA network. Typically, each PV array will have an
independent monitoring system, which can be tied with the existing SCADA network if desired.
City of Ashland PV Generation Interconnect Analysis Page 25 of 34
4.7 Protection requirements, including disconnecting means, relaying, grounding, and prevention of
islanding
Proper and safe operation of the installed PV system shall be ensured for both normal and
abnormal/emergency conditions. IEEE Standard 929 lists a few import safety and protective function
requirements of PV inverters.
a. Response to abnormal utility condition
• Voltage disturbance
VOLTAGE AT PCC MAXIMUM TRIP TIME*
V< 60 (V<50%) 6 CYCLES
60_<V<106 (50%<_V<88%) 120 CYCLES
1065V<_132 (889/6<_V<_110%) NORMAL OPERATION
132<V<165 (110%<V<137%) 120 CYCLES
1655V (137%<_V) 2 CYCLES
Note: Trip time refers to the time between the abnormal condition being applied and the inverter ceasing to
energize the utility line.
• Frequency disturbance
FREQUENCY AT PCC MAXIMUM TRIP TIME*
<59.3 HZ 6 CYCLES
59.3 - 60.5 HZ (NORMAL)
>60.5 HZ 6 CYCLES
• Islanding protection
Most inverters are nonislanding type inverters to ensure that the inverter ceases to energize
the utility line when the inverter is subjected to islanding conditions. However, it is possible
that circumstances may exist on a line section that has been isolated from the utility and
contains a balance of load and PV generation that would allow continued operation of the PV
systems. This is not supported mostly due to its inability to supply demand distortion or non-
unity power factor associated with nonlinear loads as well as the inability to resync the
system: As such, transfer trips are typically utilized to ensure the generation facility is tripped
off-line any time the interconnecting feeder or substation is off-line
• Reconnect after a utility disturbance
A minimum 5 mins after continuous normal voltage and frequency have been maintained is
required before reconnect PV system to the grid.
b. Direct Current Injection
The PV system should not inject do current > 0.5% of rated inverter output current into the ac
interface under either normal or abnormal operating conditions.
c. Grounding
IEEE Standard 929 does not discuss grounding issue in detail, but requires that PV system and
interface equipment should be grounded in accordance with applicable codes, including NEC.
City of Ashland PV Generation Interconnect Analysis Page 26 of 34
d. Manual Disconnect
Manual disconnect switch is required to provide a visible load break from the PV system when
the utility determines that the PV site needed to be isolated from the utility during maintenance on
utility lines. This switch would only be operated when the utility were operating in the immediate
vicinity of the maintenance work. This manual disconnect is shown in all one-line sketches in
Figures 6 to 8.
4.8 Control/Communication requirements (curtailment, SCADA data, etc)
A wide array of options are available for integrating the PV system into the City's existing SCADA.
system. However, it is common that large scale PV system have integration packages that provide HTML
based monitoring via Internet connections. The City will need to consider functional requirements for
information desired to be integrated into the utilities system but, as a minimum, the following should be
required:
• Transfer trip control from the associated interconnecting substation. This could be network
based but dedicated hard wire, fiber, or radio is preferred to ensure reliability
Curtailment control from the substation to force PV output reduction. when substation net
load becomes negative
• Active power factor control from the substation. This would allow active compensation of
power factor at the substation by controlling PV phase angle similar to compensation with a
synchronous generator.
5.0 SYSTEM RECOMMENDATIONS
Due to the potential adverse impact of the solar facility on power quality, as discussed in detail in Section
4, the amount of PV power generation should be limited to approximately 2.5 MW to 5 MW if
interconnecting at one location to the City's electric distribution system at medium voltage (12.47 W). If
greater generated capacity is desired we recommend two interconnection locations and different
substations.
Should the City determine it feasible to export all solar generated power, the PCC circuit could
interconnect with PacifiCorp at the distribution or transmission voltage, but transmission interconnection
would require the PV inverter voltage be stepped-up to 115 W. This type of interconnection complicates
matters since the City presently does not own any transmission facilities, does not have bi-directional
metering in place to export power, all construction would be out of the Ashland service territory, and will
require permitting, acquisition of easements and rights-of-way. In addition the City has an exclusive
power purchase agreement with the Bonneville Power Administration (BPA), and BPA has a General
Transfer Agreement with PacifiCorp for use of their transmission facilities. These agreements would
require re-negotiation to modify.
Based on the evaluation, practical options for interconnection to the City's electric distribution system
that are within reasonable distance from the PV property include:
• Ashland Substation
o Business Feeder to WWTP radial tap circuit, support -2.5 MW.
City of Ashland PV Generation Interconnect Analysis Page 27 of 34
o N Main Feeder at Oak St/Nevada St backbone circuit, support -5 MW.
o Business Feeder at Oak St/Nevada St, backbone circuit support -5 MW.
o E Nevada Feeder at N Mountain Rd, backbone circuit, support -5 MW.
• Mountain Avenue
o N Mountain Feeder at N Mountain Rd, backbone circuit support -5 MW.
Any of these interconnection options can support up to approximately 2.5 MW or 5 MW as indicated, but
to accommodate greater generation up to approximately 10 MW will require connection to feeders from
different substations. These interconnect option routes and possible construction are described greater
detail below:
5.1 Option I
Strong and recommended distribution interconnection points are near the E Nevada Street and N
Mountain Avenue intersection vicinity southwest of the PV point of common coupling (PCC). This
location, approximately 1.1 miles from the southwest corner of the PV Imperatrice Property site, allows
interconnection to two feeders and different substations. The route from the solar site could be south and
west along N Mountain Avenue, then via the I-5 N Mountain Avenue overpass to the electric system
interconnections.
At this location good circuit interconnections can tie into one or two existing City of Ashland electric
distribution backbone circuits at the PV system primary delivery voltage (12.47 kV). The existing
interconnection points available are 1) the N Mountain Feeder served from the Mountain Avenue
Substation; and 2) with minor switching changes the E Nevada Feeder served from the Ashland
Substation. A generated capacity of up to 5 MW could be delivered to one circuit or up to 10 MW
delivered and split between both circuits.
The PV circuit extension from the PCC could either be overhead or underground construction, but is out
of the existing City of Ashland service territory. Therefore, permitting, easements and rights-of-way will
need to be established as will the I-5 crossing even if bored underground.
It is suggested to accommodate a total PV system capacity of approximately 10 MW and allow for either
substation to be out of service with continuous PV generation that two paralleled circuits extend from the
PCCs to interconnection ties with the existing electric system. Since an existing single-phase PPL circuit
presently exists along N Mountain, construction of a double circuit overhead line on the opposite side of
the roadway would likely be considered unsightly and with difficulty to obtain access permits, but
undergrounding the circuits, either open trench and/or bore construction, will allow paralleled circuits
with little landscape disturbance through the use of vaults as needed to accommodate construction.
With these two points for PV generation delivery the electric distribution system configuration can
accommodate a total of approximately 10 MW generation without concern of power export. More details
can be found in Section 4.1 - power flow analysis. Should either substation be out of service for any
reason, that substation's feeder circuits and load will be transferred to the substation feeders remaining in
service, and will actually make it easier to disperse the total amount of PV generated energy (10 MW).
City of Ashland PV Generation Interconnect Analysis Page 28 of 34
However, this option requires a major modification where the existing VFI near the E Nevada Street and
N Mountain Avenue intersection resides, and it must be replaced by two VFIs to better incorporate a total
generation of 10 MW. This increase the total construction cost as indicated in Section 6.
5.2 Option II
A second interconnection location is a tie between the PV system PCC primary delivery voltage (12.47)
and the existing Business Feeder or N Main Feeder served from the Ashland Substation near the
intersection of Oak Street and Nevada Street. This tie location is approximately 1.5 miles from the
southwest corner of the PV Imperatrice Property site and could be connected by overhead or underground
construction. The route from the solar site could be south along N Mountain Avenue, west along Eagle
Mill Road and via the 1-5 Eagle Mill overpass south along Oak Street to the Nevada Street interconnect.
However, this construction is out of the existing City of Ashland service territory. Therefore, permitting,
easements and rights-of-way will need to be established as will the 1-5 crossing even if bored
underground. In addition, both PPL transmission and distribution facilities exist along Eagle Mill Road
and Oak Street so negotiations will be necessary if joint-use facility construction is a viable option. This
interconnection location could accommodate one feeder interconnection up to -5 MW.
5.3 Option III
An option to the Case II interconnection description above, but only to accommodate one -2.5 MW
interconnection, could be to intercept the circuit serving the WWTP, which would require line extension
along the Bear Creek Greenway access road from Oak Street. Although the total distance is similar,
approximately 1.4 miles, the advantage is more accessible easement for construction along the Bear Creek
Greenway access road which could include open trench and underground bore construction beneath I-5
from the generation site to the circuit interconnect. Again some construction is out of the Ashland service
territory, permitting, easements and rights-of-way will need to be established as will the I-5 crossing even
if bored underground.
6.0 SYSTEM COST ESTIMATES
Cost estimates have been determined regarding the electrical interconnection. The cost estimates are in
US dollars and are based upon typical construction costs in the area for previously performed similar
construction. Budgetary pricing for three different capacity PV system interconnection options are
summarized in Table 9. The cost estimates for utility construction to interconnect the existing City's
electric system to the PV sites point of common coupling (PCC) range between $0.9M to $1.5M. They
are budgetary pricing estimates and not detailed take-off construction estimates. Each estimate includes
some pricing related to the City's electric staff and administration requirements considered necessary for
the PV projects interconnection. The City may want to evaluate these items for accuracy and comment or
edit as necessary.
In addition, the estimates show pricing for miscellaneous contractor services which include: permitting,
easement and rights-of-way acquisition, survey, erosion sedimentation control (ESC) requirements
applicable for the region and any necessary traffic control planning (TCP).
City of Ashland PV Generation Interconnect Analysis Page 29 of 34
Table 9: Construction Cost Estimate, City of Ashland
Option I Option H Option III
Cost $1,481,877 $963,707 $876,420
The estimated total cost for the required upgrades using Option I is $1.5M, which is the highest among
the three options. This is because Option I as described previously is to integrate a total of 10 MW. It
requires two switchgear (one for each 5 MW array) and involves replacing an existing VFI by two VFIs
near the E Nevada Street and N Mountain Avenue intersection, while Option II and Option III only need
one switchgear and one VFI.
Detailed cost breakdown (i.e., sectionalizing equipment, vaults, conductors, fiber, conduit, connectors,
modification, contingency, etc.) can be found in the following three sheets:
• CASE I: PV PCC - ELECTRICAL SYSTEM INTERCONNECT, PV SYSTEM TOTAL
GNERATION - 10 MW
• CASE II: PV PCC - ELECTRICAL SYSTEM INTERCONNECT, PV SYSTEM TOTAL
GNERATION - 5 MW
• CASE III: PV PCC - ELECTRICAL SYSTEM INTERCONNECT, PV SYSTEM TOTAL
GNERATION - 2.5 MW
City of Ashland PV Generation Interconnect Analysis Page 30 of 34
ASHLAND ELECTRIC CONSTRUCTION COST ESTIMATE
CITY OF CASE I - PV PCC - ELECTRIC SYSTEM INTERCONNECT
1E® -ASHLAND PV SYSTEM TOTAL GENERATION -10 MW
January 2017 - Work Order #534.100
WO 534.100 WO 534.100
Description Quantity Installed Cost/Unit Developer Cost CoA Cost
Sectionalizing Equipment:
PV-PCC-SWGR (30-rly-mtr-SCADA)' 2 $125,000 $250,000 $0
VFI (30, 4-way)' 2 $32,000 $64,000 $0
VR PadMounted (30, 250-kVA)' 2 $36,000 $72,000 $0
Vaults:
UV-5106-LA' (splice vaults) 2 $8,000 $16,000 $0
UV-810-LA' (swgr + VRs) 4 $8,000 $32,000 $0
UV-444-LA' (comm) 4 $3,200 $12,800 $0
Conductors:
750-kcmil AL, EPR, 15-kV' 0 $11.50 /Ft $0 $0
500-kcmil AL, EPR, 15-kV' 0 $9.25 /Ft $0 $0
350-kcmil AL, EPR, 15-kV' 33480 $7.00 /Ft $234,360 $0
#4/0 AWG, AL, EPR, 15-kV' 0 $5.00 /Ft $0 $0
Fiber System
Fiber cable/equipment' 1 Lot $15,000 $0
Conduit Installed
6" PVC Sch. 40' (qty 2) 5020 60IFt $301,200 $0
4" PVC Sch. 40' 0 0 /Ft $0 $0
3" PVC Sch. 40' 0 0 /Ft $0 $0
2" PVC Sch. 40' (qty 1) 5020 20 /Ft $100,400 $0
2.5" Flex Conduit' 0 0/Ft $0 $0
Bore 1-5 Xing (2-6"+1-2")' 380 140 /Ft $53,200 $0
Cable Connectors
3-Way Junction Module' 0 $750 $0 $0
4-Way Junction Module' 0 $1,000 $0 $0
Separable Splice (600-Amp)' 12 $1,000 $12,000 $0
Elbows (600-Amp)' 42 $350 $14,700 $0
Elbows (200-Amp)' 6 $175 $1,050 $0
Deadbreak Protective Cap' 0 $50 $0 $0
Fault-Current Indicator' 12 $150 $1,800 $0
Fused Elbow (200-Amp)' 0 $375 $0 $0
Metering and CT's' 0 Lot $0 $0
Miscellaneous Connectors' 1 Lot $2,500 $0
Miscellaneous Contingency' (5%) $59,151 $0
Contractor Mob/Demob/Insur/Survey/ESC/TCPz 1 Services $50,000 $0
Permitting-Easements-Rights-of-Way2 1 Services $50,000 $0
Energization5 1 Services $5,000 $0
Administrative5 (10%) 1 Lot $134,716 $0
TOTAL COST ESTIMATE: $1,481,877 $0
Notes:
' This item furnished and installed by the developer, unless Contract Documents state otherwise.
2 These services provided by developer.
3 This item furnished by City and installed by the developer, cost includes material and wire make-up.
a This item furnished and installed by City, full cost is included in this estimate.
5This effort includes City crew inspection, voltage check and energization coordination with developer.
5This item includes City administration, engineering, design and inspection.
[V - typ rural pri const -$120/ft multiple conduit, open trench excavation/backfiII/compaction/restoration; assume
3 conduits/cables @$135/ft x 5600',= $0.8M + maj equip_@$400k + admin/misc @15% = $1.4M]
ASHLAND ELECTRIC CONSTRUCTION COST ESTIMATE
InLAA CITY O F CASE II - PV PCC; ELECTRIC SYSTEM INTERCONNECT
~S H L1~N I) PV SYSTEM TOTAL GENERATION - 5 MW
January 2017 - Work Order #534.100
WO 534.100 WO 534.100
Description Quantity Installed Cost/Unit Developer Cost CoA Cost
Sectionalizing Equipment:
PV-PCC-SWGR (30-rly-mtr-SCADA)' 1 $125,000 $125,000 $0
VFI (30, 4-way)' 1 $32,000 $32,000 $0
VR PadMounted (30, 250-kVA)' 1 $36,000 $36,000 $0
Vaults: -
UV-5106-LA' (splice vaults) 2 $8,000 $16,000 $0
UV-810-LA' (swgr + VRs) 2 $8,000 $16,000 $0
UV-444-LA' (comm) 4 $3,200 $12,800 $0
Conductors:
750-kcmil AL, EPR, 15-kV' 0 $11.50 /Ft $0 $0
500-kcmil AL, EPR, 15-kV' 0 $9.25 /Ft $0 $0
350-kcmil AL, EPR, 15-kV' 16740 $7.00 /Ft $117,180 $0
#4/0 AWG, AL, EPR, 15-kV' 0 $5.00 /Ft $0 $0
Fiber System
Fiber cable/equipment' 1 Lot $15,000 $0
Conduit Installed
6" PVC Sch. 40' (qty 1) 5020 40 /Ft $200,800 $0
4" PVC Sch. 40' 0 0 /Ft $0 $0
3" PVC Sch. 40' 0 0 /Ft $0 $0
2" PVC Sch. 40' (qty 1) 5020 20 /Ft $100,400 $0
2.5" Flex Conduit' 0 0 /Ft $0 $0
Bore 1-5 Xing (1-6"+1-2")' 380 130 /Ft $49,400 $0
Cable Connectors
3-Way Junction Module' 0 $750 $0 $0
4-Way Junction Module' 0 $1,000 $0 $0
Separable Splice (600-Amp)' 6 $1,000 $6,000 $0
Elbows (600-Amp)' 18 $350 $6,300 $0
Elbows (200-Amp)' 0 $175 $0 $0
Deadbreak Protective Cap' 0 $50 $0 $0
Fault-Current Indicator' 6 $150 $900 $0
Fused Elbow (200-Amp)' 0 $375 $0 $0
Metering and CT's' 0 Lot $0 $0
Miscellaneous Connectors' 1 Lot $2,500 $0
Miscellaneous Contingency' (5%) $36,814 $0
.Contractor Mob/Demob/Insur/Survey/ESC/TCP2 1 Services $50,000 $0
Permitting-Easements-Rights-of-Way2 1 Services $50,000 $0
Energization5 1 Services $3,000 $0
Administrative5 (10%) 1 _ Lot $87,609 $0
TOTAL COST ESTIMATE: $963,703 $0
Notes:
' This item furnished and installed by the developer, unless Contract Documents state otherwise.
2 These services provided by developer.
3 This item furnished by City and installed by the developer, cost includes material and wire make-up.
4 This item furnished and installed by City, full cost is included in this estimate.
'5 This effort includes City crew inspection, voltage check and energization coordination with developer.
5This item includes City administration, engineering, design and inspection.
ASHLAND ELECTRIC CONSTRUCTION COST ESTIMATE
CITY OF CASE III - PV PCC - ELECTRIC SYSTEM INTERCONNECT
ASHLAND PV SYSTEM TOTAL GENERATION - 2.5 MW
January 2017 - Work Order #534.100
WO 534.100 WO 534.100
Description Quantity Installed Cost/Unit Developer Cost CoA Cost
Sectionalizing Equipment:
PV-PCC-SWGR (30-rly-mtr-SCADA)' 1 $110,000 $110,000 $0
VFI (30, 4-way)' 1 $32,000 $32,000 $0
VR PadMounted (30, 114-kVA)' 1 $30,000 $30,000 $0
Vaults:
UV-5106-LA' (splice vaults) 2 $8,000 $16,000 $0
UV-810-LA' (swgr + VRs) 2 $8,000 $16,000 $0
UV-444-LA' (comm) 4 $3,200 $12,800 $0
Conductors:
750-kcmil AL, EPR, 15-kV' 0 $11.50 /Ft $0 $0
500-kcmil AL, EPR, 15-kV' 0 $9.25 /Ft $0 $0
350-kcmil AL, EPR, 15-kV' 0 $7.00 /Ft $0 $0
#1/0 AWG, AL, EPR, 15-kV' 16740 $4.00 /Ft $66,960 $0
Fiber System
Fiber cable/equipment' 1 Lot $15,000 $0
Conduit Installed
6" PVC Sch. 40' (qty 1) 0 40 /Ft $0 $0
4" PVC Sch. 40' 5020 40 /Ft $200,800 $0
3" PVC Sch. 40' 0 0 /Ft $0 $0
2" PVC Sch. 40' (qty 1) 5020 20 /Ft $100,400 $0
2.5" Flex Conduit' 0 0 /Ft $0 $0
Bore I-5 Xing (1-4"+1-2")' 380 130 /Ft $49,400 $0
Cable Connectors
3-Way Junction Module' 0 $750 $0 $0
4-W6y Junction Module' 0 $1,000 $0 $0
Separable Splice (200-Amp)' 6 $800 $4,800 $0
Elbows (600-Amp)' 0 $350 $0 $0
Elbows (200-Amp)' 18 $175 $3,150 $0
Deadbreak Protective Cap' 0 $50 $0 $0
Fault-Current Indicator' 6 $150 $900 $0
Fused Elbow (200-Amp)' 0 $375 $0 $0
Metering and CT's' 0 Lot $0 $0
Miscellaneous Connectors' 1 Lot $2,500 $0
Miscellaneous Contingency' (5%) $33,036 $0
Contractor Mob/Demob/Insur/Survey/ESC/TCPZ 1 Services $50,000 $0
Perm itting-Easements-Rights-of-Way2 1 Services $50,000 $0
Energization5 1 Services $3,000 $0
Administratives (10%) 1 Lot $79,675 $0
TOTAL COST ESTIMATE: $876,420 $0
Notes:
' This item furnished and installed by the developer, unless Contract Documents state otherwise.
2 These services provided by developer.
3 This item furnished by City and installed by the developer, cost includes material and wire make-up.
4 This item furnished and installed by City, full cost is included in this estimate.
6This effort includes City crew inspection, voltage check and energization coordination with developer.
5This item includes City administration, engineering, design and inspection.
In closing we appreciate the opportunity to provide engineering services to the City of Ashland. If there
are any concerns or questions with the information presented herein please contact us at your
convenience. In addition, we would gladly be available to meet and discuss our findings.
City of Ashland PV Generation Interconnect Analysis Page 34 of 34
CITY OF
ASHLAND
Council Communication
November 15, 2016, Business Meeting
Discussion of policy questions to be addressed regarding the 10x20 Ordinance
FROM:
Dave Kanner, city administrator, dave.kanner@ashland.or.us
Mark Holden, director, Ashland Electric Utility, mark.holden@ashland.or.us
Adam Hanks, management analyst (manager of Conservation Division and staff to the ad hoc Climate
and Energy Action Plan Committee), adam.hanks@ashland.or.us
SUMMARY
This is a discussion of potential answers to a list of policy questions that need to be addressed in ordei
to conduct feasibility and cost analyses for implementation of the 10x20 ordinance. These questions
were initially developed by City staff and supplemented by the ad hoc Climate and Energy Action Plan
Committee.
BACKGROUND AND POLICY IMPLICATIONS:
On April 26, 2016, a group of local citizens filed an initiative petition to refer to the ballot an
ordinance titled "An Ordinance Requiring the City of Ashland to Produce 10 Percent of the Electricity
Used in the City from New, Local and Clean Resource by the Year 2020." On August 10, the City
Recorder verified that the petitioners had gathered enough signatures to refer the ordinance to the
ballot. At its August 16 business meeting, the Council agreed to accept the ordinance rather than
referring it, and. adopted the ordinance on first and second reading at its September 6 meeting.
Before the ordinance can be implemented and the fiscal implications of various implementation
scenarios can be determined, many clarifying questions must be answered. This includes not just
definitional and ordinance content questions, but basic policy questions that relate to the goals of the
ordinance, the juxtaposition of the ordinance with state-mandated renewable portfolio standards and
the relationship of the ordinance to the still-in-progress Climate and Energy Action Plan.
Given the above, staff assembled a list of questions both policy questions and clarifying questions that it feels must be answered to determine how and at what cost the ordinance
will be implemented.
This list was shared with the Climate and Energy Action Plan ad hoc committee for the purpose of
having the committee add other questions that staff may not have considered. When these questions
were reviewed with the Council at its November 1 business meeting, the Council requested that a
discussion of the policy questions be scheduled for this meeting.
The policy questions developed by staff and the ad hoc committee are as follows:
1. What are the primary objectives of the ordinance and in what order of priority?
a. Independence from the regional electricity grid?
b. Emergency access to electricity due to regional grid failure?
c. Carbon mitigation locally?
Page 1 of 2
Mr®
CITY OF
ASHLAND
d. Carbon mitigation regionally?
2. Should the ordinance be developed to utilize the State of Oregon Renewable Portfolio Standards
(RPS) structure as defined in Oregon Revised Statutes as the template and model to implement the 10
by 20 ordinance?
3. Should the ordinance be developed with its own set of definitions, standards and eligible resources
separate from the State RPS structure?
4. If separate from the State RPS, should the local supplemental RPS include or exclude the state RPS
mandates, i.e. cumulative or additive?
5. Should the clarified goals and intent of the ordinance be incorporated into the Climate and Energy
Action Plan (CEAP) or remain as a stand-along ordinance?
6. How does the ordinance fit in with the other goals of the CEAP? Should it take precedence both
financially and in priority or should it be reviewed and evaluated equally with the other strategies and
actions within the plan?
7. What would the impacts of this ordinance be on low income residents/customers in our community?
8. How does the ordinance impact the existing BPA contract?
9. What is the total renewable energy potential in the City?
10. How would implementation of this ordinance impact future GHG emissions as defined and
calculated in the City's GHG Inventory?
Attached to this Council communication is background information and staff's perspective on the
answers to some of these questions to aid in the Council discussion.
In addition to addressing these policy questions, staff will develop alternative answers to the ordinance
content questions and with those answers, assemble a variety of scenarios for achieving the goal of the
ordinance. Staff will then return to the Council to have it review, amend or add to these scenarios, after
which staff will hire an objective third-party consultant to evaluate the feasibility and cost of each of
the scenarios. With this information in hand, the Council can then either amend the ordinance or adopt
an implementing resolution and the City can begin the work of actual implementation.
COUNCIL GOALS SUPPORTED:
21. Be proactive in using best practices in infrastructure management and modernization.
FISCAL IMPLICATIONS:
None
STAFF RECOMMENDATION AND REQUESTED ACTION:
N/A. This item is for discussion only
SUGGESTED MOTION:
N/A. This item is for discussion only
ATTACHMENTS:
10x20 ordinance policy questions for Council
Renewable Portfolio Standards fact sheet
Ordinance No. 3134
Page 2 of 2
CITY OF
ASHLAND
10% by 2020 Ordinance Questions for Council
Policy Questions
1. Q -What are the primary objectives of the ordinance and in what order of priority?
The answer to this question impacts how we define "local." If the goal is to reduce the carbon
emissions of the regional grid, then new generation capacity - if that is how the 10% is to be
achieved - can be built anywhere that is served by the regional grid. However, if the objective is
energy independence or access to emergency power, then new generation capacity must be built in
a location that allows direct connection to the City's distribution system. Objectives for Council to
consider include the following:
1) Reduction of carbon emissions
Local GHG Calculation - Greenhouse gas (GHG) inventory protocol utilizes the regional
energy mix to calculate a community's carbon emissions in the energy sector. Any action
that reduces total net electric consumption locally reduces the carbon emissions
equivalent to the regional grid. Generation of 10 percent of local annual consumption is
roughly equivalent to mitigation of just over 5,000 metric tons of C02.
Regional GHG Calculation - GHG Inventory protocol utilizes the regional energy mix
rather than the City's purchased power contract to calculate net carbon emissions.
While the 10% local generation reduces the City's contractual (predominantly hydro)
resource commitment (although not what we are required to purchase from the BPA),
the benefit accrues to the regional grid, as this action would "free up" hydro resources to
be used elsewhere and incrementally avoid future potential high carbon generation.
GHG Calculation caveat - If 10 percent local generation utilizes Renewable Energy Credits
(RECs) as part of the financing mechanism (common practice), the carbon mitigation
described above would apply to the City's GHG inventory only if the City were to
retain/obtain ownership of the RECs. If the City were to contract with a third party to
build new renewable energy generation facilities and the contractor kept the RECs (again,
common practice), the City would receive no credit for carbon reduction.
2) Independence from the regional electricity grid -Local generation of 10 percent of
electricity provides no functional independence from the larger regional grid. Any
intermittent sources of electricity require battery storage. Additionally, grid
independence requires the ability to generate, store and distribute peak load levels of
electricity, which can be over twice the average daily capacity resulting in total
infrastructure costs far exceeding the community's financial abilities.
However, incremental levels of local generation do provide benefits such as:
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C I T Y OF
ASHLAND
Diversification of local energy sources -The City currently has one predominant supplier
of electricity. While BPA has been and is expected to continue to be a reliable source of
cost effective, low carbon electricity, local generation provides some level of insulation
from potential unforeseen financial, regulatory or environmental risks of that sole source
provider.
Reduction in transmission costs and associated energy losses -The delivery of electricity
requires transmission from its source to its destination, resulting in costs for the use of
the transmission lines of various other utilities owning and maintaining transmission grid
infrastructure between source and destination. Additionally, the movement of energy
along the transmission lines results in electricity being consumed in the delivery process,
called line loss. This loss is typically between 4-7% of total electricity delivered. Local
generation eliminates the transmission and line loss costs associated with delivery into
the local grid.
3) Emergency access to electricity due to regional grid failure - While regional grid failures
are exceedingly rare, significant natural disasters could impact the regional grid and
cause power outages locally. If deemed a priority, solutions to regionally caused power
outages would be considerably different than standard grid supported local electricity
generation. Generation facilities would need to be matched to local community
emergency shelter locations. Generation facilities would also need to be supported with
battery storage infrastructure and be designed to connect to the facility's electrical
distribution system to provide power to the building(s). While potentially feasible, a
completely different cost/benefit analysis and project design would be required to meet
this particular objective.
2. Q - Should the ordinance be developed with its own set of definitions, standards and eligible
resources separate from the State Renewable Portfolio Standards (RPS) structure?
A-The RPS structure is state law and the City is required to comply with that law irrespective of
the 10x20 ordinance. Certain elements of the RPS, if adopted in whole as part of the 10x20
ordinance, would effectively negate the ordinance. However, the definitions contained in the
RPS provide guidance for definitions that might become part of the ordinance. To the extent
practical, staff recommends that the ordinance be as consistent as possible with the Oregon RPS
definitions and structure, with exceptions being clearly justified and defined.
3. Q - If separate from the State RPS, should the local supplemental RPS include or exclude the
state RPS mandates, i.e. cumulative or additive?
A -This is likely to be reviewed as part of the third party consultant scenario analysis. The
ultimate ordinance language and actions taken to meet the new requirements may or may not
have any bearing on the State RPS standards that the City is required to meet.
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CITY OF
ASHLAND
4. Q - Should the clarified goals and intent of the ordinance be incorporated into the Climate and
Energy Action Plan (CEAP) or remain as a stand-along ordinance?
A-The CEAP Committee voted to include a reference to the 10x20 ordinance in the draft CEAP.
Due to the timing and yet-to-be-clarified policy issues of the ordinance, the committee did not
vote to incorporate the ordinance directly into any particular action item, but recognized its
place within several focus area strategies with the plan.
5. Q - How does the ordinance fit in with the other goals of the CEAP? Should it take precedence
both financially and in priority or should it be reviewed and evaluated equally with the other
strategies and actions within the plan?
A -Again, the timing and unknown policy issues of the ordinance prevented the committee
from being able to directly compare the 10x20 action with other actions being developed in the
CEAP, both in terms of potential carbon mitigation and cost per unit of carbon mitigated versus
other potential actions in the plan. The committee did recognize and note that the 10x20
initiative does generally fit as a potential implementing action within several strategy
statements in the Buildings and Energy focus area of the plan document.
6. Q - What would the impacts of this ordinance be on low income residents/customers in our
community?
A - It is difficult to anticipate the impacts on low income residents/customers until the details
of ordinance implementation and effects on utility energy costs are determined. As discussed
in the recent study session on the cost of service study, low income does not mean low use. In
fact, low income customers are often higher usage customers because they are less able to
afford weatherization projects and energy efficient appliances. An increase to the
consumption component of electric rates would clearly more severely impact high usage
customers than low usage customers. The Council could, as a matter of policy, expand or
enhance the Low Income Energy Assistance Program. However, doing so would require
additional money from some source, which would presumably be all other ratepayers who do
not qualify for that program.
7. Q - How does the ordinance impact the existing BPA contract?
The ordinance, if implemented through a generation resource, will displace Tier 1 BPA power
and will trigger the "take or pay" provision of the BPA contract. As a result, the City will still be
responsible for the BPA charges (energy and transmission) that are displaced by the ordinance.
Total BPA charges will remain relatively unchanged.
8. Q - What is the total renewable energy potential in the City?
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CITY OF
-ASHLAND
A - While there are no complete data sets that would provide this answer, the City GIS staff has
worked with the Energy Conservation Division to develop an online solar site assessment tool to
provide individual homeowners with a snapshot of the solar potential for their home or
business. Staff is working on calculating an aggregate number to provide an estimate of the
total solar (not total renewable) resource based on the existing roof systems in Ashland. This
will not include the potential ground mount solar system opportunities, nor micro-hydro, wind
or other renewable energy potential.
The City did participate with Rogue Valley Council of Governments in 2010-11 in the
development of a Renewable Energy Assessment (REA) for Jackson and Josephine County. The
project inventoried the renewable energy potential in the two-county boundary and was
completed by The Good Company (same consultant that did the City's Greenhouse Gas
Inventory). Those results indicated that, by a significant degree, energy efficiency had the
highest renewable energy potential in the region and also at the lowest cost. This report is
available on the City's website at www.ashland.or.uw/rea
9. Q -How would implementation of this ordinance impact future GHG emissions as defined and
calculated in the City's GHG Inventory
A - See question #1- local generation of 10% of the total electric consumption within the City of
Ashland would result in the mitigation of just over 5,000 metric tons of C02 equivalent.
4
OREGON Summary of Oregon's Renewable Portfolio Standard
DEPARTMENT Of
ENERGY
The Renewable Portfolio Standard (RPS) requires that all utilities and electricity service
suppliers (ESSs)' serving Oregon load must sell a percentage of their electricity from qualifying
renewable energy sources. The percentage of qualifying electricity that must be included varies
over time, with all utilities and ESSs obligated to include some renewable resources in their
power portfolio by 2025.
For current information on Oregon eligible facilities, please visit www.oregon-Kps.org.
Table 1 summarizes the percentage targets for the RPS.
Table 1: Summa of RPS Targets and Timelines
RPS obligations on all utilities and electricity service suppliers
Percent of Applicable Targets in Year:
Oregon's Utilitiesz
Total Retail and ESSs 2011 2015 2020 2025
Electric Sales
Large Three percent Portland General Electric,
Utilities or more PacifiCorp, Eugene Water & 5% 15% 20% 25%
Electric Board
At least one and Central Lincoln PUD, Idaho
a half percent Power, McMinnville W&L, o
Small but less than Clatskanie PUD, Springfield 10%
Utilities three percent Utility Board, Umatilla No Interim Targets
Electric Cooperative
Below one and a All other utilities (31 5%
half percent consumer-owned utilities)
Electricity If an ESS sells electricity in the
Service Any sales in Any Electricity Service service area of more than one utility
Suppliers Oregon Supplier (ESS) its targets may calculated as an
(ESSs) aggregate of electricity sold in its
territory.
Conditional Targets
There are two conditions when a small utility would be required to meet the large utility standard
regardless of their size if purchase coal power (ORS 469A.055 (4) or if they annex utility
territory (ORS 469A.0555 (5)). In the case that a small utility's load increases to exceed three
percent of the state load for a period of three consecutive years they would also be subject to the
standard as a large utility (ORS 469A.052 (2).
' Oregon's deregulation law allows non-utility power sellers (called ESSs) to sell power to non-residential
customers. Currently, this applies only to Portland General Electric and PacifiCorp service territory.
2 Based on 2010 Oregon Public Utility Commission (OPUC) utility data. See the Statistics Book:
http•//www puc state or us_p/ uc/Pa ese /Oregon Utility Statistics Book aspx.
January 20141
Exemptions to RPS Targets
Utilities are not required to comply with an RPS target to the extent that compliance will:
• Lead to a utility expending more than four percent of its electricity-related annual
revenue requirement in order to comply with the RPS.
• Displace firm Federal Base System (FBS) preference power rights from the Bonneville
Power Administration (BPA) for a consumer-owned utility.
• Result in acquisition of power resources in excess of their load requirements in a given
compliance year.
• Result in the displacement of a non-fossil-fueled power resource.
• Unavoidably displace hydropower contracts with Mid-Columbia River dams until such a
time when those contracts cannot be renewed or replaced.
Eligible Resources and Facility Eligibility Date
Qualifying electricity for Oregon's RPS must be derived from the sources and types of facilities
listed in Table 2. Qualifying facilities must also be located within the Western Electricity
Coordinating Council's territory. Note that where multiple fuels are used to power a generating
facility only the proportion of output that uses qualifying resources can count toward the RPS.
Table 2: Eligible Resource Types Based on Facility Operational Date
From Generating Facilities in From Generating Facilities That Became Operational
Operation Before January 1, 1995 On or After January 1, 1995
Up to 90 average megawatts Hydropower, if located outside of certain state, federal, or
(aMW) per utility per compliance NW Power & Conservation Council protected water areas.
year of low-impact certified Wind
hydropower, capped at 50 aMW Solar Photovoltaic and Electricity from Solar Thermal
owned by an Oregon utility and 40 Wave, Tidal, and Ocean Thermal
aMW not owned by a utility but
located in Oregon. Geothermal
Biomass and biomass byproducts; including but not
The increment of improvement limited to organic waste, spent pulping liquor, woody
from efficiency upgrades made to debris or hardwoods as defined by harvesting criteria,
hydropower facilities, although if agricultural wastes, dedicated energy crops and biogas
the improvement is to a federally- from digesters, organic matter, wastewater, and landfill
owned BPA facility only Oregon's gas. Under certain conditions, municipal solid waste may
share of the generation can qualify. qualify. The burning of biomass treated with chemical
preservatives disqualifies any biomass resource.
The increment of improvement Other resources as determined to qualify through ODOE
from capacity or efficiency rulemaking. However, nuclear fission and fossil fuel
upgrades made to facilities other sources are prohibited in all cases as qualifying resources.
than hydropower facilities. Electricity from hydrogen derived from any of the above
resources.
January 20142
Renewable Energy Certificates
Compliance with the RPS requires proof of generation of the qualifying electricity. Like many
states, Oregon requires proof in the form of a Renewable Energy Certificate (REC). Oregon
Administrative Rule states that a REC is a unique representation of the environmental, economic
and social benefit associated with the generation of electricity from renewable energy sources
that produce Qualifying Electricity. Each REC represents one megawatt-hour (MWh) of
generation of qualifying electricity. By rule, all RECs must be issued by the Western Renewable
Energy Generation Information System (WREGIS).
Oregon recognizes two types of Renewable Energy Certificates (RECs) in the RPS. Initially, all
RECs are "bundled" together with their associated electricity that is produced at the renewable
electricity generation facility. When both a REC and the electricity associated with that REC are
acquired together, one has acquired a "bundled" REC.
A generator or REC owner may decide to "unbundle" the REC from the electricity associated
with that REC by using or selling the two components separately. In doing so the purchaser of
the power loses the ability to claim that the power is renewable energy. The "unbundled" REC
may be used by its new owner to comply with the RPS.
To meet an RPS target obligated utilities or ESSs must permanently retire the number of RECs
equivalent to the target load percentages. For example, if a utility is subject to a 10% target and
sold 100,000 MWh to Oregon customers, then it must retire 10,000 RECs to meet its compliance
target.
For large utilities, no more than 20 percent of their compliance target in a given year may be met
through the use of unbundled RECs, although large consumer-owned utilities such as EWEB
have a limit of 50 percent until 2020. RECs from PURPA facilities in Oregon are exempt from
this limit.3
RECs may be banked indefinitely and used in future years. Older RECs must be used before
newer RECs, called the "first in first out" principle.
Implementation Plans and Compliance
The Oregon Renewable Portfolio Standard compliance schedule for the state's three largest
utilities began in 2011. In 2012, Eugene Water and Electric Board, PacifiCorp, and Portland
General Electric will demonstrate REC retirement in an amount equivalent to five percent of its
2011 retail sales, unless otherwise exempted (see Exemptions to RPS Targets, above).
Every two years, large utilities submit implementation plans detailing how they expect to comply
with the standard.' The plans include annual targets for acquisition and use of qualifying
3 PURPA is a federal law that requires utilities to purchase the output of smaller energy projects.
4 EWEB reports its plan to comply with the RPS in its Integrated Energy Resource Plan.
January 20143
electricity and the estimated cost of meeting the annual targets. Prudently incurred costs
associated with RPS compliance are recoverable in rates.
Investor-owned utilities and ESSs must submit their annual compliance reports to the OPUC.
Consumer-owned utilities report compliance to their customers, boards, or members.
Consumer Protection and Cost Controls
There are two mechanisms that serve as cost protections for Oregon consumers: an alternative
compliance payment mechanism and an overarching "cost cap" on utility RPS expenditures.
Alternative Compliance Payment: In lieu of acquiring a REC to comply with a portion of the
RPS, a utility or ESS may instead pay a set amount of money per megawatt-hour (MWh) into a
special fund that can be used only for acquiring renewable energy resources in the future, or for
energy efficiency and conservation programs. This mechanism sets an effective cap on the cost
of complying with the RPS on a per MWh basis.
Cost Cap: Utilities are not required to comply with the RPS to the extent that the sum of the
incremental costs of compliance with the RPS (as compared with fossil-fuel power), the costs of
unbundled RECs, and alternative compliance payments exceed four (4) percent of a utility's
annual revenue requirement in a compliance year. Consumer-owned utilities may also include
R&D.costs associated with renewable energy projects in this calculation. As of 2012, the
incremental cost of compliance for all Oregon utilities has been well below the four percent cap.
January 20144
ORDINANCE NO.3 131
AN ORDINANCE REQUIRING THE CITY OF ASHLAND TO PRODUCE
10 PERCENT OF THE ELECTRICITY USED IN THE CITY FROM NEW,
LOCAL AND CLEAN RESOURCE BY THE YEAR 2020 AND AN
EMERGENCY IS DECLARED TO TAKE EFFECT ON ITS PASSAGE
RECITALS:
P
WHEREAS climate change is caused in large part by human action.
WHEREAS Ashland citizens have a responsibility to contribute to slowing of climate change.
i
WHEREAS Ashland owns its own electric utility.
SECTION 1. The City of Ashland shall cause at least 10 percent of the electricity used in the
City to be produced from new, local and clean'resources from and after the year 2020.
ti
SECTION 2. The City of Ashland shall enact such ordinances and resolutions, and appropriate
such funds and take necessary actions as are necessary to implement the requirements of Section
1 above.
X
ii SECTION 3. This Ordinance being necessary to meet the requirements set by Oregon State
Elections Law, an emergency is declared to exist, and this Ordinance takes effect on its passage.
The foregoing ordinance was first read by title only ijaordance with Article X,
Section 2(C) of the City Charter on the day of 2016,
and dul PASSED and ADOPTED this day o, 2016.
Barbara M. Christensen, City Recorder
SIGNED and APPROVED this day of , 2016.
1
Jo Stro berg, Mayor
4 ReT)*ed as to form:
I; avid H. Lo an, City Attorney
~I
Ordinance No. Page 1 of 1
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2115/2017 City of Ashland, Oregon -Agendas And Minutes
City of Ashland, Oregon / City Council
City Council -Minutes View Agenda
Tuesday, November 15, 2016
MINUTES FOR THE REGULAR MEETING
ASHLAND CITY COUNCIL
November 15, 2016
Council Chambers
1175 E. Main Street
CALL TO ORDER
Mayor Stromberg called the meeting to order at 6:00 p.m. in the Civic Center
Council Chambers.
ROLL CALL
Councilor Voisin, Morris, Lemhouse, and Rosenthal were present. Councilor
Seffinger arrived at 6:04 p.m. Councilor Marsh was absent.
CONTINUATION OF DISCUSSION FROM NOVEMBER 1, 2016
1. Discussion of policy questions to be addressed regarding the 10x20
ordinance
Mayor Stromberg explained there were three kinds of clean power, solar, wind,
and hydro. Management Analyst Adam Hanks would provide the best case for
each during the discussion. Complex resolutions or topics that could not be
resolved during the meeting would go on a list for further review and action at the
next Council meeting.
Wind
Mr. Hanks explained part of using wind power was getting inventories where
there were enough flows. A renewal energy assessment from 2011 indicated one
location of scale on the backside of Shale City due to its close proximity to
connect to larger lines. There was talk regarding Mt. Ashland but wind volume
and how it would connect were unknown at this time. Wind was most likely not
viable. Mayor Stromberg moved it to the list.
Hydro
Hydro required the right flow, head, and diameter pipe. There were a few
locations in the City's system that had potential but the scale of production would
not meet the 10x20 ordinance requirements. The item moved to the list.
Mayor Stromberg explained the City defined the 10% clean energy as 10% of the
annual electric power usage of the City of Ashland. Mr. Hanks clarified 10% of
the 170,000,000 kilowatt hours used per year would mean 17,000,000-kilowatt
hours coming from a clean energy source. It equated to .017 gigawatts. A solar
industrial plant would have be a 12 to 15 megawatt facility to produce that
annually.
Solar
There were three options for solar power. Option 1 would put a solar farm on the
Imperatrice property. .Thesecond option would add solar panels to City owned
facilities like rooftops, parking lots, and covering the reservoir. Staff was currently
conducting a site inventory. Option 3 would place community solar on
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commercial and residential buildings. It would require new incentive packages to
form various utility City partnerships.
Mayor Stromberg added the following concerns regarding solar to the list for
future discussion:
• Potential issues with tree shading to cool the affluent may affect the use of
the Imperatrice property
• Environmental concerns on using 150 acres for a 12-15 megawatt facility
• Ordinance requiring local energy - the City defined local as wherever the
facility was located it connected directly into an Ashland electric utilities
distribution grid
There were two ways to fund a solar power system. One way was determine the
cost to build a facility and recoup the expense through user rates. Another way
was entering into a power purchase agreement (PPA) with an entity or
organization that would build the facility, operate it, and sell the electricity to the
City with the city assuming ownership after a 20-year period.
Mr. Hanks explained the carbon mitigation component was indirect regarding a
solar power system in that the less hydro purchased left more available in the
grid and offset the need for other generation opportunities regionally. However,
the way the greenhouse gas inventory was calculated worked to the City's
advantage from a climate action planning perspective because it calculated it on
the regional grid. Alternately, if it was just a carbon concern then a PPA from a
facility within the grid itself either locally or regionally was more feasible.
The City was committed to purchasing a certain amount of electricity from the
Bonneville Power Administration (BPA). If the City was generating some of their
own through the 10x20 ordinance it could drop total usage with BPA and cause
the City to pay for both. Mayor Stromberg acknowledged this as a potential issue
and set it aside for future review.
Mr. Hanks addressed having a solar farm system on the Imperatrice property.
The City could send out a request for proposal (RFP) for a 12-megawatt solar
installation on the Imperatrice property. The RFP could include a request for a
PPA estimate but was not necessary. It would take staff 30-45 days to develop
the RFP. It/Electric Director Mark Holden added the RFP would include
connection to the distribution site at the Mountain Avenue station. It would need
a substantial transformer and lead to purchasing the Mountain Avenue station
from BPA prior to updating the equipment.
Council majority directed staff to create an RFP with a review by Council prior to
sending it out for bid.
Council went on to discuss postponing agenda item #2 Discussion of removing
public art review and approval requirements from Chapter 18 of the
Ashland Municipal Code under New and Miscellaneous Business to the
January 17, 2017 Council meeting.
Councilor Lemhouse/Rosenthal m/s to postpone this item until January 17,
2017, or a date that accommodates both the Historic and the Public Arts
Commission. Voice Vote: All AYES. Motion passed.
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2115/2017 City of Ashland, Oregon- Agendas And Minutes
MAYOR'S ANNOUNCEMENTS
Mayor Stromberg announced vacancies on the Housing & Human Services,
Public Arts, and Tree Commissions.
APPROVAL OF MINUTES
The minutes of the Study Session of October 31, 2016, the Executive Session of
October 31, 2016, and the Business Meeting of November 1, 2016 were
approved as presented.
SPECIAL PRESENTATIONS & AWARDS
1. Annual presentation by the Housing and Human Services Commission
Housing and Human Services Commission (HHSC) vice Chair Rich Rohde and
Commissioner Tom Buechele provided the annual update for the HHSC. Vice
Chair Rohde commented on the housing emergency crisis in Ashland. Medford
and Ashland had become the fastest growing unaffordable housing cities in the
country.
This year the HHSC worked on the Housing Trust Fund, developing a funding
strategy chart, student fair housing, and recommendations for Community
Development Block Grant (CDBG) funding. HHSC created nine goals that
included donation boxes, affordable housing, inclusionary zoning, diversity, more
Porta-Potties, developing resources for middle-income work force housing,
increase shelter nights, ongoing rental research, and housing solutions that
included the aging community.
PUBLIC FORUM
Michael Molitch-Hou/1151 Tolman Creek Road/Recently spoke with Unite
Oregon in Medford who reported there were 70 counts of hate speeches and acts
following the election directed towards Latino and Muslim Americans. He wanted
to know if any similar acts had occurred in Ashland, if the City had a process in
place to deal with racial harassment, and if there was a specific group a person
could contact. He suggested Ashland become a Sanctuary City.
City Attorney Dave Lohman explained Ashland was already a sanctuary city and
Oregon was a sanctuary state. City Administrator Dave Kanner encouraged
anyone experiencing any form of hate speech to call the police. Police Chief
Tighe O'Meara was not aware of any hate speech since the election and
reiterated anyone experiencing that behavior should call the police.
Huelz Gutcheon/2253 Hwy 99/Spoke on solar energy.
.Shane Elder/830 Carol Rae, Medford OR/Asked Council to amend the
ordinance that prohibited address number painting on curbs. Ashland allowed
this form of painting until two years ago. He went on to note the benefits of
having addresses painted on curbs.
City Attorney Dave Lohman confirmed the issue came up two years prior where it
was determined prohibitive. Council could change the ordinance. Mr. Lohman
would follow up with Mr. Elder.
CONSENT AGENDA
1. Minutes of boards, commissions, and committees
2. Approval of a resolution titled, "A resolution adopting guidelines for the
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creation and installation of murals"
3. Medford Water Commission water delivery contract
Councilor"Voisin pulled Consent Agenda item #3 for further discussion. Public
Works Director Mike Faught explained the only change to the agreement
removed using Talent Ashland Phoenix (TAP) water for emergency purposes
under Article 3. The new agreement would last five years with three five-year
extensions. Talent, Ashland, and Phoenix could sell excess water to each other if
a city exceeded their allotment. Each city had their own meter.
Councilor Seffinger/Rosenthal m/s to approve the Consent Agenda items.
Voice Vote: all AYES. Motion passed.
Engineering Services Manager Scott Fleury provided an update on the
Grandview Drive shared road project. Public Works and Electric department staff
determined a strategy to install the storm drain, the electrical conduit, the new
transformer, paving, and cleanup regarding the retaining wall. The location of the
new transformer required extending the guardrail 20-feet and partial relocation of
the old guardrail to accommodate the radius. Mr. Fleury confirmed the City did
not require an encroachment permit since it was a City contract and staff did the
work. They would install the electrical conduit that week followed by paving and
cleanup work. Once that was completed, they would set up speed limit and
share the roadway signs. They targeted the second week of December for
completion of the first phase. Council expressed concern they were not notified
of the guardrail extension prior to. it happening. Public Works Director Mike
Faught took responsibility for the oversight. Staff followed policy regarding
notifying neighbors within the project site. After the project finished, staff would
itemize the expenditures, determine overall costs, and forward that information to
Council.
PUBLIC HEARINGS - None
UNFINISHED BUSINESS - None
NEW AND MISCELLANEOUS BUSINESS
1. Council review of questions for downtown behavior study
Management Analyst Ann Seltzer explained the City contracted with Southern
Oregon University Research Center (SOURCE) to conduct a survey of downtown
businesses to determine the effectiveness of the ordinances that went into effect
over.the summer. Director of SOURCE, Dr. Eva Skuratowicz explained the
process in measuring downtown activities involved people who were in that area
consistently over time. She decided to focus on the 194 businesses in the
downtown, primarily street level businesses. It was also important to be clear on
activities that took place in the front, side and back of the business. SOURCE
would mail out the survey twice with research assistants calling businesses to get
an accurate sense of how these behaviors have shifted, changed, reduced, or
increased. Dr. Skuratowicz would follow up with any business in person who
failed to respond to all of SOURCE's attempts to gather information. She may
talk to the Oregon Shakespeare Festival (OSF) separately.
Council discussed the question regarding the occurrence of ATM users solicited
for money. Dr. Skuratowicz would remove the question, call the banks instead,
and replace it with another question relating to smoking in the alley or sidewalk
areas.
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2/15/2017 City of Ashland, Oregon - Agendas And Minutes
2. Discussion of removing public art review and approval requirements
from Chapter 18 of the Ashland Municipal Code
Item delayed to the January 17, 2017.meeting.
ORDINANCES. RESOLUTIONS AND CONTRACTS
1. First reading by title only of an ordinance titled, "An ordinance
amending AMC 14.04.060 Water Connections Outside City The Limits" and
move to second reading.
City Attorney Dave Lohman noted the ordinance currently stated no premises
located outside the City of Ashland may be connected to the City water system
with some provisions for Council to make specific approvals. The wording, "may
be" could be misunderstood. He proposed changing the language to read, "no
premises located outside the City of Ashland may be connected to the city.
water system or make use of water obtained through a direct or indirect
connection to the city water system." Exceptions were narrowly defined but .
lacked clarity. For 14.04.060(C)(3)(i-v), the punctuation, did not make it clear that
all five criteria needed to be met. Mr. Lohman proposed changing 14.04.060(C)
(3) to read, "Connections authorized under subsection (13)(3) above shall be
made only after all the criteria in subsection (13)(3) and the following have
been met."
Under 14.04.060(E), Mr. Lohman suggested removing the current language and
adding, "Any person who violates any provision of this Chapter shall be
punished as set forth in Section 1.08.020 of the Ashland Municipal Code, in
addition to other legal and equitable remedies to the City of Ashland,
including restriction or termination of service." Termination of service was
already in 14.05.070 where the City could disconnect service connection from the
water supply line if the equipment using the water did not comply with all city,
state, and federal laws or standards. He reiterated this was not a change in
policy or direction, just clarification.
John Benson/1120 South Mountain/Questioned whether premises had to have
a structure on the property. Oregon state law said he could water a half acre
from a city connection into a county lot. Last Thursday, Mike Faught and Steve
Wilson came to his mother's house who had recently come home from the
hospital, and informed her she needed to cut the line extending to county
property. He claimed the City had given them approval to.use city water in 1970,
1990 and in 2009. His neighbor below him had the same zoning and the City had
not talked to them. The Oregon state law he referred to was on the Oregon
Medical Marijuana Program (OMMP) website. He could get a pump from Talent
Irrigation District (TID), or drill a well but that actually violated OMMP rules. He
went on to talk about the complaint process, traffic to neighbor's homes and false
statements that he had armed guards and vicious dogs. He confirmed he had
two lots, one county, and the other had the city limits boundary running through
the lot.
Council confirmed the proposed changes clarified the ordinance and that Mr.
Benson had brought up points he wanted Council to consider. Mr. Lohman
added Council could make changes to the ordinance and Mr. Benson could
appeal his water issues through the appeals process.
The term premise did not mean a structure or building. Councilor Morris noted a
situation on his property that meant he too was violating the ordinance. His lot
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was half in the City and half in the county.
Mr. Lohman clarified they had researched the claims the Benson's received
permission to use city water three times in the past and did not find anything
indicating there was an agreement to that effect. Nor had the City received any
documentation from the Benson's confirming permission. The ordinance did not
provide for an exception. Mr. Benson's family could have received a verbal ok
but that still did not comply with the ordinance.
Councilor Lemhouse/Rosenthal.m/s to approve the first reading of an
Ordinance titled, "An Ordinance Amending AMC 14.04.060 Water
Connections Outside the City Limits."
DISCUSSION: Councilor Lemhouse did not think Council could make a value
judgment on what occurred on someone's property to determine whether to
enforce or clarify the code. He did not want the trees to die but the code was
there for a reason. Making an exception set a precedence of value judgments.
The code did not provide water outside the city unless the request matched the
exceptions criteria. Councilor Rosenthal expressed concern about wading into a
neighborhood relations issue and that Council was potentially revising an
ordinance that may have unintended consequences. He did not know if clarifying
the language clarified the implementation of the ordinance.
Councilor Morris recused himself from the matter.
Councilor Voisin did not think it was a water supply issue because the City
supplied water to the Welcome Center and would supply water to the 550
residential units in the Normal Neighborhood Plan. The issue was
accommodating residents living on the edge of town who may bring their
properties into city limits in the future. She suggested extending the ordinance to
include the urban growth boundary. Councilor Seffinger was not comfortable with
the possible unintended consequences of changing the ordinance at this point.
She wanted a different way to address the neighborhood concerns regarding the
use of the property. It was.unknown how the clarifications would affect other
properties. Mayor Stromberg noted the ordinance was not changing and
questioned how it would affect anyone differently.
Roll Call Vote: Councilor Rosenthal and Lemhouse, YES; Councilor
Seffinger and Voisin, NO. Mayor Stromberg broke the tie with a YES vote.
Motion passed 3-2.
OTHER BUSINESS FROM COUNCIL MEMBERS/REPORTS FROM COUNCIL
LIAISONS
Councilor Seffinger announced the Red Cross had a program that provided
smoke detectors for citizens that may need financial assistance or help with
installation.
ADJOURNMENT OF BUSINESS MEETING
Meeting adjourned at 8:20 p.m.
Dana Smith, Assistant to the City Recorder John Stromberg, Mayor
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