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Ashland City Council Packet
Imperatrice
6-15-15
I'm Bruce Fiero, one of a group of professionals who have worked 6 months to
accumulate compelling evidence to assist the Council in making a decision to develop a
small portion of the Imperatrice Property as a Renewable Energy Park. With over 40
years of combined experience in solar projects, we are well qualified to offer our data
and opinions to the Council. We have been doing this work without consideration of
compensation or future work.
According to the National Oceanographic and Atmosphere Administration, Ashland is
the best site in the Rogue Valley because of higher performance characteristics.
The Solar Advisor Model was developed by the Department of Energy and the National
Renewable Energy Lab as a tool to assist developers in forecasting financial models for
utility scale solar projects. The 16 megawatt hours of power produced annually by this
project will have a net retail value of roughly $3m per year based on the model. At
worst, at the end of a 15 or 20 year lease period of the site the City would inherit a fully
functional 10 megawatt generator requiring no fuel, still operating at 90% or better of
nameplate rating, producing more than $3m per year (because of rising energy prices)
and cost 2% of revenue for operation and maintenance. At best, the efficacy of the
technology would be recognized early on in the lease period and the City could begin to
plan for further energy development of the site to capitalize on the shifting regional and
national energy landscape.
We value the progressive idealism of Ashland and its ability to transform idealism into
reality by capitalizing on an unused resource. There can hardly be a more positive
statement or impression a city can make today than intermingling recreation,
agriculture, education and energy production all on one site. This is an action that
shows where the City's values stand similar to its recent endorsement of a state Carbon
Tax. Although this will require action rather than words and will show a visible presence
of City Values.
Thank you.
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Wholesale Electricity Price Forecast at Mid C - Sensitivity Cases
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LovvDemand Hlgh Fuel lInce
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The resulting levelized electricity prices over the planning horizon for the delayed federal CO2 case and
the social cost CO2 case were close in value. The delayed federal CO2 case assumes that a tax or
regulatory cost is assigned to C02 emissions. The C02 Cost curve is phased in beginning in 2015, ramps
up sharply, and then begins to level off around 2022. In the social cost CO2 case a cost to society from
CO2 emission is assumed. For modeling purposes in this forecasting cycle, the cost from emissions was
attached to the electricity price as if it were a tax or regulatory cost in order to compare it to the other CO,
regulatory cases. The forecast model also captures the typical seasonal and hourly pricing patterns at
the hub. Prices are damped most during the load low hours of the day, and during periods of surplus
hydro power.
Wholesale Electric Price Forecast Mid C All Conditions - Delayed Federal CO2 Case
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Average Annual Wholesale Electric Price Forecast ($/MWh 2010$)
Social No
Delayed Social Cost No Federal High Low
Year f Federal Cost C02 Federal & Low High Low Fuel Fuel
Demand Demand
C02 C02 Phased C02 CA Price Price
In C02
2012 15.84 30.22 15.82 15.86 15.86 15.79 15.81 13.12 10.56
2013 23.26 33.65 23.26 23.23 21.64 23.97 21.73 23.90 16.42
2014 28.73 39.20 28.76 28.73 27.31 29.87 26.43 31.21 21.01
2015 30.80 41.12 30.85 30.63 29.08 32.12 28.30 33.69 22.84
2016 32.19 41.16 32.20 30.37 28.80 33.49 29.57 35.61 2121
2017 36.35 42.43 36.35 31.42 29.90 37.42 33.92 41.04 26.15
2018 39.66 42.63 39.61 31.61 30.00 41.21 37.53 47.50 32.12
i
2019 43.82 43.15 42.60 32.42 30.73 45.52 41.39 52.03 35.02
2020 46.66 143.53 42.99 32.73 30.93 48.62 44.17 55.63 38.15
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2021 50.59 45.79 45.39 35.42 33.61 53.08 47.37 61.29 40.78
2022 53.30 46.72 46.20 35.99 34.36 55.99 49.35 64.50 42.52
2023 55.93 47.88 47.56 37.41 35.56 58.92 51.66 67.78 44.00
2024 57.33 48.52 48.08 37.88 36.02 60.67 52.49 69.90 44.62
2025 57.50 48.90 48.40 38.07 36.00 61.56 52.55 70.59 44.40
2026 58.34 50.25 49.67 39.55 37.27 63.47 52.94 73.35 44.32
2027 60.04 51.26 51.29 41.13 38.71 65.27 53.91 76.25 45.03
2028 61.26 52.30 52.29 41.74 39.37 66.90 54.53 77.02 45.37
2029 63.15 53.77 53.88 43.23 40.91 68.74 55.70 79.78 45.79
2030 64.39 54.88 54.99 44.19 41.65 70.12 56.27 81.60 46.04
2031 65.85 56.08 56.12 45.04 42.49 71.16 57.59 82.98 46.58
2032 65.78 56.21 56.84 45.41 42.81 71.63 57.97 83.52 46.92
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QUESTIONSAND ANSWERS.- A SOLAR F,, MM ON THE
IMPERATRICE PROPERTY
L Is the In3peratrice propQl°ty, a goad site for a utility-scale solar facility?
The Imperatrice property is generally south facing and leas a relatively gentle slope. These are
two important initial considerations for solar-povier generation biter;. A critical element -of site
selection has to do with the location and sire, of Elie electrical distribution infi-astnicture to get t1je
solar power onto the distribution grid. Two different traias~nissioi~ limes exist on or near the
property, but there are r?o adequately sued transformers or sub-stations on or close to the
property. The a'ias^ ,ice of inntercon Dection faciliti-Is thus rnakes the -aippratrice property less
desirable -that other properties with or near such facilities.
20 Would `u solar facility on the Iniperatii ices properor reduce Ashland's greenhouse gas
emissions and carbon footprint?
No. Ashland currently purchases 99% of its electricity af-om the Bonneville Power
Administration. (The remaining 1_%a is from a small hydro generator below Hosler Darr.)
Virtually noire of the BPA power sold to the City is from fossil fuel sources. (See BPA Fuel Mix
Summary for calendar year 2014, attached.) A solar farm on the Irnperatrice property will do
nothing to reduce Ashland's carbon footprint. It would presurnably reduce the global carbon
footprint by providing power to a locale somewhere else that currently gets its power from fossil
fuel sources, but it would have no impact on Ashland's carbons footprint-
3o Mould a solar farm on the Imperatrice property gener,"ate renewable power for
Ashiand?
While %ec-hruca lly feasible, it is zrnlikely that power generated tin the fmperatrice property would
be directed to the City of Ashland's electrical system. The site is outside of the City limits and in
Pacific Power's Utility servIc . 2~ ~ ei4?ri( whicta necessitates their purchase of the power grid costs,
associated with connecting to their grid for distribution.
As ex-ptained above, Ashland. already receives the overwhelming rnajority of its power from,
renewable energy sources. If the pourer front a solar farm were to be said to Ashland, it would
simply supplant the renewable energy we now purchase with a more expeiasive form of
renewable energy, thus puaing upward pressure on electric races.
To further explain, a solar array on the Inaperatrice property would be in Pacific Power's service
territory. Under state and federal lav,,, this solar farm would be a "qualifying facility" and the
power inust be sold to and purchased by Pacific Power. The, price Pacific Power pays for that
power is determined by an "opens access tariff' that establishes the avoided cost Pacific Power
pays. For calendar year 2015, the avoided cost rate is 3.94; per kilowatt hour. (Materials from
Pacific Power explaining qualifying facilities and showing avoided cost purchase prices over
time aE"e attached.) The projected wholesale cost of BPA power to Ashland is 3.750 per kilowatt
hour. But in order to get the power from the solar farm to Ashland, Pacific Power =would have to
"wheel" the power to Ashland and Pacific Pourer would charge F. "wheeling fee." The, wheeling
fee would have to be negotiate d, but a hest guess is that it -would raise the cost of that power to
Ashland to 8~, per kilowatt hour.
It is more likely that Pacific Power and a solar developer would wheel the power to C lifbrnua,
where electricity is much more expensive than it is in the Pacific Northwest. They could
command a higher price for it, thus 1naking it more profitable. As such, a solar array on the
Imperatrice property would provide renewable energy, but ii would not provide that power to
Ashland.
Wholesale electricity costs in the Northwest region served 1)y BPA (Oregon, Washington, Idaho
aFrzd Western Montana) are some. of the lowect in the nation and currently are substantially less
expensive tlraa solar energy production- It is reasonable to e2>pwc large scale solar, production
generation costs to continue to go down (likely at a slower rate than over the past 5-7 years) and
it is also reasonable to expect wholesale energy costs from BP A and the northwest energy market
to continue to rise in the fixture- This will inevitably lead to a point in time where solar
generation is cost competitive in the northwest as it is ahread'y in some energy markets in the US.
4. Would the City own the solar farm in 15-20 years if it's built now?
This is highly speculative and would be a component of any negotiation for development rights
of the prope cy. It is very nnuch ui-known at this point given that the financing elements of the
project are not yet detailed enough to even determine basic project viability. This kind of
ownership transfer is not uncommon in facility-specific. industrial/commercial solar Installations.
It's not known whether this woWd be feasible (or negotiable) in a atility-scale development.
'There are very fear utility-scale scalar developr gents to use for coinpamson purposes in orego_n~
Of the 182 approved -sol r facilities that meet the. Oregon Rene iabke Po-aflolxo Standard (11_ot all
or which are M Oregon), only fbur generate more than 1.5 megawatts.
Even if such a transfer of ownership agreement existed, a deveiopineilt that's more than 20 years
old would be in the latter half of its life expectancy and would thus be a rapidly depreciating
asset requiring millions of dollars ,,oith ofnpkeep and r€placernent. What's more, in the case of
the Irnperatrice property, the solar installation would still be in Pacific Power's service territory,
not the City's, creating the samie problem as described in 3., above.
5o Is an RFF is necessary? How could the City find out if anyone was interested in the
property for a lame scale solar far m?
One option has been proposed, which is for the City to conduct a comprehensive assessment. on
its own, using contracted services to develop a request for proposals (PFP) process for that
assessment, The City could also develop a solicitation document to distribute to the solar
development community (15-20 key organizations and developer/investors) with an 1nvitation to
sizbrcnit letters of interest/proposals. A third option would be to utilize the City's existing contract
for electrical engineering services to assist staff in developing the feasibility/assessment RFP.
Referring to the utility-scale developinents in 4., above, staff is not aware of an R'P or
solicitation having been issued for any of them.
6. Would a solar farm be compatible with other potential uses of the tmperagrice
property?
It is possible that im-n different rises could co-exist on the property, but it -may be premature to
make any such declaration until additional research and evaluation is done reg)-arding the
potential needs that led to the City's acquisition of the propeity III the first place; wastewater
treatment, Additionally, potential lane` conservation and recreation uses have been proposed that
may physically fit together on the property but may not b compatible in terms of the intended
user experience.
7. Do we ueed to act quictdy to tale add aniage of federal ta-K credits' t
It is trine that a federal tax credit for sonar developmcnt sunsets at the end of2016 (assuming
Congress doe: not extend it)_ The tax credit is available only to projects that are actually
generating electiicity by the end of 2016. If the tax credit sunsets, it does not necessarily mean
solar development win stop, although it may have the effect of slowing it down. It may also
have the effect of ey-pediting the development of other- forms of renewables, such as winch.
S. What about solar on snore re-ofteps inside the City instead of a large solar farm? h that
possible?
The City of Ashland currently has one of the highest, ifnot'the highest, number of solar systems
per capita of any city in Oregon. The. City supports this by being the first city in Oregon to adopt
a net metering policy that allows customers to maxi~ni/e the use of the energy they generate.
The City also has an incentive program that helps pay for the irzsta.llation of solar systems.
Placing solar systems oil rooftops Inside the City's electric grid has several basic advantages over
a dedicated solar faun;
1) There is no need to build a separate structure to connect the panels to they just go on top of
the roof:
2) Because most buildings have an electrical service and are consuming energy, the solar
energy offsets the consumption right at the source, rising every bit of the energy generated.
3) The solar energy being generated saves the customer more money because it is replacing
energy that they would have to buy at retail rates. A solar fa.rnl energy on the Imperatrice
property would not have any on-site energy consumption, so all of the energy generated vrill
come to the electric grid as wholesale power. This changes the value of the kilowatts from the
higher value retail rate to the less valuable wholesale rate.
BPA FUEL MIX PERCENT SUMMARY. CY 2014 DATA
zoo
Bior-ii sand Was*e 0.1%
Geothermal 00%
Small Hydrodectri;c 11%
Solar with RECs 0-0%
Wind lzb RECs 0.0%
Coal 0.0/0
Lame Hydroelectric 33.3%
Natural Gas 0.0°1/0
Nuclear 10.4%
Non Sl;ecitied PUrchases 4.4%
1'di11d 'Without RI C's
Total Ili!}.{jf t"Please Note. 6PP. Conveys its RECs to other Rarti?s and does not retre them.
Reporting ageneies in California and Washington assign Grcen !-louse Gas
emission to Wind Power Purchases that are not associated with retired RECS.
Prepared by K. Rohe Bonneville Power Administration. Bulk (Marketing 5/22/2015
N PACIFIC POWER OREGON
A DIVISION OF PACIFICORP SCHEDULE 37
AVOIDED COST PURCHASES FROM
QUALIFYING FACILITIES OF 10,000 KW OR LESS Page 1
Available
To owners of Qualifying Facilities making sales of electricity to the Company in the State of
Oregon.
Applicable
For power purchased from Qualifying Facilities with a nameplate capacity of 40,0W kW or less
or that, together with any other electric generating facility using the same motive force, owned
or controlled by the same person(s) or affifiated person(s), and located at the same site, has a
nameplate capacity of 10,000 kW or less. Owners of these Qualifying Facilities will be required
to enter into a written power sales contract with the Company.
Definitions
Cogeneration Facility
A facility which produces electric energy together with steam or other form of useful energy
(such as heat) which are used for industrial, commercial, heating or cooling purposes through
the sequential use of energy.
Qualifying Facilities
Qualifying cogeneration facilities or qualifying small power production facilities within the
meaning of section 201 and 210 of the Public Utility Regulatory Policies Act of 1978 (PURPA),
16 U.S.C. 796 and 824a-3.
Qualifying Electricity
Electricity that meets the requirements of "qualifying electricity" set forth in the Oregon
Renewable Portfolio Standards: ORS 469A.010, 469A.020, and 469A.025.
Renewable Qualifying Facility
A Qualifying Facility that generates Qualifying Electricity.
Wind Qualifying Facility
A Renewable Qualifying Facility that generates Qualifying Electricity using wind as its motive
force.
Baseload Renewable Qualifying Facility
A Renewable Qualifying Facility that generates Qualifying Electricity using any qualifying
resource other than wind or solar.
Small Power Production Facility
A facility which produces electric energy using as a primary energy source biomass, waste,
renewable resources or any combination thereof and has a power production capacity which,
together with other facilities located at the same site, is not greater than 80 megawatts.
On-Peak Hours or Peak Hours
On-Peak hours are defined as 6:00 a.m. to 10:00 p.m. Pacific Prevailing Time Monday through
Saturday, excluding NERC holidays.
Due to the expansions of Daylight Saving Time (DST) as adopted under Section 110 of the U.S.
Energy Policy Act of 2005, the time periods shown above will begin and end one hour later for
the period between the second Sunday in March and the first Sunday in April and for the period
between the last Sunday in October and the first Sunday in November.
(continued)
P.U.C. OR No. 36 First Revision of Sheet No. 37-1
Canceling Original Sheet No. 37-1
Issued August 11, 2014 Effective for service on and after August 20, 2014
R. Bryce Dalley, Vice President, Regulation Advice No. 14-007
N A DiVISIGN OF PACIFICORP PACIFIC POWER OREGON
SCHEDULE 37
AVOIDED COST PURCHASES FROM
QUALIFYING FACILITIES OF 10,000 KW OR LESS Page 2
Definitions (continued)
Off-Peak Hours
All hours other than On-Peak.
Excess Output
Excess Output shall mean any increment of Net Output delivered at a rate, on an hourly basis,
exceeding the Facility Nameplate Capacity. PacifiCorp shall pay Seller the Off-Peak Price as
described and calculated under pricing option 4 (Non-Firm Market Index Avoided Cost Price) for
all Excess Output.
Same Site
Generating facilities are considered to be located at the same site as the OF for which
qualification for the standard rates and standard contract is sought if they are located within a
five-mile radius of any generating facilities or equipment providing fuel or motive force
associated with the OF for which qualification for the standard rates and standard contract is
sought.
Person(s) or Affiliated Person(s)
A natural person or persons or any legal entity or entities sharing common ownership,
management or acting jointly or in concert with or exercising influence over the policies or
actions of another person or entity. Two facilities will not be held to be owned or controlled by
the same person(s) or affiliated person(s) solely because they are developed by a single entity.
Two facilities will not be held to be owned or controlled by the same person(s) or affiliated
person(s) if such common person or persons is a "passive investor" whose ownership interest in
the OF is primarily related to utilizing production tax credits, green tag values and MACRS
depreciation as the primary ownership benefit and the facilities at issue are independent family-
owned or community-based projects. A unit of Oregon local government may also be a
"passive investor" in a community-based project if the local governmental unit demonstrates that
it will not have an equity ownership interest in or exercise any control over the management of
the OF and that its only interest is a share of the cash flow from the OF, which share will not
exceed 20%. The 20% cash flow share limit may only be exceeded for good cause shown and
only with the prior approval of the Commission.
Shared Interconnection and Infrastructure
OFs otherwise meeting the separate ownership test and thereby qualified for entitlement to the
standard rates and standard contract will not be disqualified by utilizing an interconnection or
other infrastructure not providing motive force or fuel that is shared with other QFs qualifying for
the standard rates and standard contract so long as the use of the shared interconnection
complies with the interconnecting utility's safety and reliability standards, interconnection
contract requirements and Prudent Electrical Practices as that term is defined in the
interconnecting utility's approved standard contract.
Dispute Resolution
Upon request, the OF will provide the purchasing utility with documentation verifying the
ownership, management and financial structure of the OF in reasonably sufficient detail to allow
the utility to make an initial determination of whether or not the OF meets the above-described
criteria for entitlement to the standard rates and standard contract.
(continued)
P.U.C. OR No. 36 First Revision of Sheet No. 37-2
Canceling Original Sheet No. 37-2
Issued August 11, 2014 Effective for service on and after August 20, 2014
R. Bryce Dalley, Vice President, Regulation Advice No. 14-007
MIKE ~ A DIViSION OF PACIFICORP PACIFIC POWER OREGON
SCHEDULE 37
AVOIDED COST PURCHASES FROM
QUALIFYING FACILITIES OF 10,000 KW OR LESS Page 3
Dispute Resolution (continued)
Any dispute concerning a QF's entitlement to the standard rates and standard contract shall be
presented to the Commission for resolution.
Self Supply Option
Owner shall elect to sell all Net Output to PacifiCorp and purchase its full electric requirements
from PacifiCorp or sell Net Output surplus to its needs at the Facility site to PacifiCorp and
purchase partial electric requirements service from PacifiCorp, in accordance with the terms
and conditions of the power purchase agreement and the appropriate retail service.
Pricing Options
1. Standard Fixed Avoided Cost Prices
Prices are fixed at the tirne that the contract is signed by both the Qualifying Facility and the
Company and will not change during the term of the contract. Standard Fixed Avoided Cost
Prices are available for a contract term of up to 15 years and prices under a longer term
contract (up to 20 years) will thereafter be under the Firm Market Indexed Avoided Cost Price,
The Standard Fixed Avoided Cost pricing option is available to all Qualifying Facilities. The
Standard Fixed Avoided Cost Price for Wind Qualifying Facilities will reflect integration costs as
set forth on page 5.
2. Renewable Fixed Avoided Cost Prices
Prices are fixed at the time that the contract is signed by both the Renewable Qualifying Facility
and the Company and will not change during the term of the contract. Renewable Fixed
Avoided Cost Prices are available for a contract term of up to 15 years and prices under a
longer term contract (up to 20 years) will thereafter be under the Firm Market Indexed Avoided
Cost Price. The Renewable Fixed Avoided Cost pricing option is available only to Renewable
Qualifying Facilities. A Renewable Qualifying Facility choosing the Renewable Fixed Avoided
Cost pricing option must cede all Green Tags generated by the facility, as defined in the
standard contract, to the Company during the Renewable Resource Deficiency Period identified
on page 6, except that a Renewable Qualifying Facility retains ownership of all Environmental
Attributes generated by the facility, as defined in the standard contract, during the Renewable
Resource Sufficiency Period identified on page 6 and during any period after the first 15 years
of a longer term contract (up to 20 years).
3. Firm Market Indexed Avoided Cost Prices
Firm Market Index Avoided Cost Prices are available to Qualifying Facilities that contract to
deliver firm power. Monthly on-peak / off-peak prices paid are a blending of Intercontinental
Exchange (ICE) Day Ahead Power Price Report at market hubs for on-peak and off-peak prices.
The monthly blending matrix is available upon request.
4. Non-Firm Market Index Avoided Cost Prices
Non-Firm Market Index Avoided Cost Prices are available to Qualifying Facilities that do not
elect to provide firm power. Qualifying Facilities taking this option will have contracts that do not
include minimum delivery requirements, default damages for construction delay or, for under
delivery or early termination, or default security for these purposes. Monthly On-Peak / Off-Peak
prices paid are 93 percent of a blending of ICE Day Ahead Power Price Report at market hubs
for on-peak and off-peak firm index prices. The monthly blending matrix is available upon
request. The Non-Firm Market Index Avoided Cost pricing option is available to all Qualifying
Facilities. The Non-Firm Market Index Avoided Cost Price for Wind Qualifying Facilities will
reflect integration costs.
(continued)
P.U.C. OR No. 36 Second Revision of Sheet No. 37-3
Canceling First Revision of Sheet No. 37-3
Issued August 11, 2014 Effective for service on and after August 20, 2014
R. Bryce Dalley, Vice President, Regulation Advice No. 14-007
PACIFIC POWER OREGON
ADIVIS1ONOF PACIFICORP SCHEDULE 37
AVOIDED COST PURCHASES FROM
QUALIFYING FACILITIES OF 10,000 KW OR LESS Page 4
Monthly Payments
A Qualifying Facility shall select the option of payment at the time of signing the contract under
one of the Pricing Options specified above. Once an option is selected the option will remain in
effect for the duration of the Facility's contract.
Renewable or Standard Fixed Avoided Cost Prices
In accordance with the terms of a contract with a Qualifying Facility, the Company shall pay for
all separately metered kilowatt-hours of On-Peak and Off-Peak generation at the renewable or
standard fixed prices as provided in this schedule. On-Peak and Off-Peak are defined in the
definitions section of this schedule.
Firm Market Indexed and Non-Firm Market Index Avoided Cost Prices
In accordance with the terms of a contract with a Qualifying Facility, the Company shall pay for
all separately metered kilowatt-hours of On-Peak and Off-Peak generation at the market prices
calculated at the time of delivery, On-Peak and Off-Peak are defined in the definitions section
of this schedule.
(continued)
P.U.C. OR No. 36 Second Revision of Sheet No. 37-4
Canceling First Revision of Sheet No. 37-4
Issued August 11, 2014 Effective for service on and after August 20, 2014
R. Bryce Dailey, Vice President, Regulation Advice No. 14-007
"WS PACIFICoRPOWER OREGON
SCHEDULE 37
AVOIDED COST PURCHASES FROM
QUALIFYING FACILITIES OF 10,000 KW OR LESS Page 5
Avoided Cost Prices
Standard Fixed Avoided Cost Prices
Fixed Prices 0/kWh
Deliveries Base Load OF 1 Wind QF 2 Solar OF
During On-Peak Off-Peak On.-Peak Off-Peak On-Peak Off-Peak
Calendar Energy Energy Energy Energy Energy Energy
Year Price Price Price Price Price Price
(a) (b) (c) (d) (e) (f)
2014 3.98 2.62 3.71 2.35 3.98 2.62
2015 3.94 2.86 3.67 2.59 3.94 2.86
2016 3.85 2.84 3.58 2.57 3.85 2.84
2017 4.06 3.01 3.79 2.73 4.06 3.01
2018 4.33 3.20 4.04 2.92 4.33 3.20
2019 4.55 3.41 4.26 3.12 4.55 3.41
2020 4.78 3.84 4.48 3.54 4.78 3.84
2021 4.92 4.25 4.62 3.95 4.92 4.25
2022 5.58 4.83 5.28 4.53 5.58 4.83
2023 5.79 5.02 5.48 4.71 5.79 5.02
2024 6.97 3.91 3.72 3.59 4.32 3.91
2025 7.11 4.00 3.81 3.68 4.42 4.00
2026 7.31 4.13 3.94 3.80 4.56 4.13
2027 7.52 4.29 4.09 3.96 4.73 4.29
2028 7.74 4.44 4.24 4.11 4.89 4.44
2029 8.00 4.64 4.44 4.30 5.10 4.64
2030 8.25 4.83 4.62 4.48 5.30 4.83
2031 8.42 4.93 4.72 4.57 5.40 4.93
2032 8.59 5.03 4.81 4.66 5.51 5.03
2033 8.76 5.13 4.91 4.75 5.62 5.13
2034 8.94 5.23 5.01 4.85 5.74 5.23
2035 9.11 5.33 5.10 4.94 5.84 5.33
2036 9.30 5.44 5.21 5.05 5.97 5.44
2037 9.50 5.56 5.32 5.16 6.09 5.56
2038 9.70 5.68 5.44 5.27 6.22 5.68
2039 9.90 5.80 5.55 5.38 6.35 5.80
2040 10.11 5.91 5.66 5.48 6.48 5.91
(1) Capacity Contribution to Peak for Avoided Proxy Resource and Base Load Qualifying Facility
resource are assumed 100%.
(2) The standard avoided cost price for wind is reduced by an integration charge of $2.55/MWh
($2012). If Wind Qualifying Facility is not in PacifiCorp's balancing authority area, then no
reduction is required.
(continued)
P.U.C. OR No. 36 Second Revision of Sheet No. 37-5
Canceling First Revision of Sheet No. 37-5
Issued August 11, 2014 Effective for service on and after August 20, 2014
R. Bryce Dalley, Vice President, Regulation Advice No. 14-007
~ A DIV(SION OF PACIFICORP PACIFIC POWER OREGON
SCHEDULE 37
AVOIDED COST PURCHASES FROM
QUALIFYING FACILITIES OF 10,000 KW OR LESS Page 6
Avoided Cost Prices (Continued)
Renewable Fixed Avoided Cost Prices
Fixed Prices kWh
Deliveries Base Load Renewable OF 2) Wind QF 3,4 Solar QF 5
Peak
During On-Peak Off-Peak On-Peak Off-Peak On-Peak t~E",
Calendar Energy Energy Energy Energy Energy ergy
Year (1) Price Price Price Price Price e
(a) (b
) (c) (d) (e) (fl
2014 3.98 2.62 3.71 2.35 3.98 2.62
2015 3.94 2.86 3.67 2.59 3.94 2.86
2016 3.85 2.84 3.58 2.57 3.85 2.84
2017 4.06 3.01 3.79 2.73 4.06 3.01
2018 4.33 3.20 4.04 2.92 4.33 3.20
2019 4.55 3.41 4.26 3.12 4.55 3.41
2020 478 3.84 4.48 3.54 4.78 3.84
2021 4.92 4.25 4.62 3.95 4.92 4.25
2022 5.58 4.83 5.28 4.53 5.58 4.83
2023 5.79 5.02 5.48 4.71 5.79 5.02
2024 11.48 7.36 8.24 7.05 8.84 7.36
2025 11.70 7.49 8.39 7.17 9.01 7.49
2026 11.91 7.64 8.54 7.31 9.17 7.64
2027 12.14 7.78 8.71 7.45 9.34 7.78
2028 12.36 7.94 8.87 7.61 9.52 7.94
2029 12.58 8.11 9.02 7.77 9.68 8.11
2030 12.81 8.28 9.18 7.93 9.85 8.28
2031 13.05 8.46 9.34 8.10 10.03 8.46
2032 13.29 8.66 9.51 8.30 10.21 8.66
2033 13.53 8.87 9.68 8.50 10.39 8.87
2034 13.79 9.07 9.86 8.69 10.58 9.07
2035 14.04 9.27 10.03 8.89 10.78 9.27
2036 14.32 9.49 10.23 9.09 10.99 9.49
2037 14.59 9.72 10.42 9.32 11.19 9.72
2038 14.87 9.96 10.60 9.55 11.39 9.96
2039 15.15 10.21 10.80 9.79 11.60 10.21
2040 15.47 10.43 11.02 10.00 11.85 10.43
(1) For the purpose of determining: (1) when the Renewable Qualifying Facility is entitled to renewable avoided cost prices; and
(2) the ownership of Environmental Attributes and the transfer of Green Tags to PacifiCorp, the Renewable Resource Sufficiency
Period ends December 31, 2023, and the Renewable Resource Deficiency Period begins January 1, 2024.
(2) The renewable avoided cost price during the Renewable Resource Deficiency Period (2024-2040) has been increased by an
integration charge of $2.55/MWh ($2012).
(3) During the Renewable Resource Deficiency Period, the renewable avoided cost price for a Wind Qualifying Facility will be
adjusted by adding the difference between the avoided integration costs and the Qualifying Facility's integration costs. If the
Wind Qualifying Facility is in PacifiCorp's balancing authority area (BAA), the adjustment is zero (integration costs cancel each
other out). If the Wind Qualifying Facility is not in PacifiCorp's BAA, $2.55/MWh ($2012) will be added for avoided integration
charges.
(4) During Renewable Resource Sufficiency Period, the renewable avoided cost price for a Wind Qualifying Facility has been
reduced by an integration charge of $2.55/MWh ($2012) for Wind Qualifying Facilities located in PacifiCorp's BAA (in-system). If
a Wind Qualifying Facility is not in PacifiCorp's BAA, $2.55/MWh ($2012) will be added for avoided integration charges.
(5) The renewable avoided cost payment during the Renewable Resource Deficiency Period (2024-2040) has been
increased by an integration charge of $2.55/MWh ($2012).
(continued)
P.U.G. OR No. 36 Second Revision of Sheet No. 37-6
Canceling First Revision of Sheet No. 37-6
Issued August 11, 2014 Effective for service on and after August 20, 2014
R. Bryce Dalley, Vice President, Regulation Advice No. 14-007
~PA DIVISION OF ACIFIC ~ POWER OREGON
SCHEDULE 37
AVOIDED COST PURCHASES FROM
QUALIFYING FACILITIES OF 10,000 KW OR LESS Page 7
Qualifying Facilities Contracting Procedure
Interconnection and power purchase agreements are handled by different functions within the
Company. Interconnection agreements (both transmission and distribution level voltages) are
handled by the Company's transmission function (PacifiCorp Transmission Services) while
power purchase agreements are handled by the Company's merchant function (PacifiCorp
Commercial and Trading).
It is recommended that the owner initiate its request for interconnection 18 months ahead of the
anticipated in-service date to allow time for studies, negotiation of agreements, engineering,
procurement, and construction of the required interconnection facilities. Early application for
interconnection will help ensure that necessary interconnection arrangements proceed in a
timely manner on a parallel track with negotiation of the power purchase agreement.
1. Qualifying Facilities up to 10,000 kW
APPLICATION: To owners of existing or proposed QFs with a design capacity less
than or equal to 10,000 kW who desire to make sales to the Company in the state of Oregon.
Such owners will be required to enter into a written power purchase agreement with the
Company pursuant to the procedures set forth below.
1. Process for Completing a Power Purchase Agreement
A. Communications
Unless otherwise directed by the Company, all communications to the Company
regarding QF power purchase agreements should be directed in writing as follows:
PacifiCorp
Manager-QF Contracts
825 NE Multnomah St, Suite 600
Portland, Oregon 97232
The Company will respond to all such communications in a timely manner. If the
Company is unable to respond on the basis of incomplete or missing information from
the QF owner, the Company shall indicate what additional information is required.
Thereafter, the Company will respond in a timely manner following receipt of all
required information.
(continued)
P.U.C. OR No. 36 Second Revision of Sheet No. 37-7
Canceling First Revision of Sheet No. 37-7
Issued August 11, 2014 Effective for service on and after August 20, 2014
R. Bryce Dalley, Vice President, Regulation Advice No. 14-007
PACIFIC POWER OREGON
A DIVISION OF PACIFiCORP SCHEDULE 37
AVOIDED COST PURCHASES FROM
QUALIFYING FACILITIES OF 10,000 KW OR LESS Page 8
B. Procedures
1. The Company's approved generic or standard form power purchase
agreements may be obtained from the Company's website
at www.pacificorp.com, or if the owner is unable to obtain it from the website,
the Company will send a copy within seven days of a written request.
2. In order to obtain a project specific draft power purchase agreement the owner
must provide in writing to the Company, general project information required for
the completion of a power purchase agreement, including, but not limited to:
(a) demonstration of ability to obtain OF status,
(b) design capacity (MW), station service requirements, and net amount of
power to be delivered to the Company's electric system;
(c) generation technology and other related technology applicable to the
site,
(d) proposed site location;
(e) schedule of monthly power deliveries;
(f) calculation or determination of minimum and maximum annual
deliveries;
(g) motive force or fuel plan;
(h) proposed on-line date and other significant dates required to complete
the milestones-
(i) proposed contract term and pricing provisions as defined in this
Schedule (i.e.,standard fixed price, renewable fixed price);
Q) status of interconnection or transmission arrangements;
(k) point of delivery or interconnection;
3. The Company shall provide a draft power purchase agreement when all
information described in Paragraph 2 above has been received in writing from
the OF owner. Within 15 business days following receipt of all information
required in Paragraph 2, the Company will provide the owner with a draft power
purchase agreement including current standard avoided cost prices and/or
other optional pricing mechanisms as approved by the Public Utility
Commission of Oregon in this Schedule 37.
4. If the owner desires to proceed with the power purchase agreement after
reviewing the Company's draft power purchase agreement, it may request in
writing that the Company prepare a final draft power purchase agreement. In
connection with such request, the owner must provide the Company with any
additional or clarified project information that the Company reasonably
determines to be necessary for the preparation of a final draft power purchase
agreement. Within 15 business days following receipt of all information
requested by the Company in this paragraph 4, the Company will provide the
owner with a final draft power purchase agreement.
(continued)
P.U.C. OR No. 36 First Revision of Sheet No. 37-8
Canceling Original Sheet No. 37-8
Issued August 11, 2014 Effective for service on and after August 20, 2014
R. Bryce Dalley, Vice President, Regulation Advice No. 14-007
PACIFIC POWER OREGON
A DIVISION OF PACIFICORP SCHEDULE 37
AVOIDED COST PURCHASES FROM
QUALIFYING FACILITIES OF 10,000 KW OR LESS Page 9
B. Procedures (continued)
5 After reviewing the final draft power purchase agreement, the owner
may either prepare another set of written comments and proposals or
approve the final draft power purchase agreement. If the owner
prepares written comments and proposals the Company will respond in
15 business clays to those comments and proposals.
6. When both parties are in full agreement as to all terms and conditions
of the draft power purchase agreement, the Company will prepare and
forward to the owner within 15 business days, a final executable
version of the agreement. Following the Company's execution a
completely executed copy will be returned to the owner. Prices and
other terms and conditions in the power purchase agreement will not
be final and binding until the power purchase agreement has been
executed by both parties.
II. Process for Negotiating Interconnection Agreements
[NOTE: Section II applies only to QFs connecting directly to PacifiCorp's electrical
system. An off-system OF should contact its local utility or transmission provider to
determine the interconnection requirements and wheeling arrangement necessary to
move the power to PacifiCorp's system.]
In addition to negotiating a power purchase agreement, QFs intending to make sales to
the Company are also required to enter into an interconnection agreement that governs
the physical interconnection of the project to the Company's transmission or distribution
system. The Company's obligation to make purchases from a QF is conditioned upon
the QF completing all necessary interconnection arrangements. It is recommended that
the owner initiate its request for interconnection 18 months ahead of the anticipated in-
service date to help ensure that necessary interconnection arrangements proceed in a
timely manner on a parallel track with negotiation of the power purchase agreement.
Because of functional separation requirements mandated by the Federal Energy
Regulatory Commission, interconnection and power purchase agreements are handled
by different functions within the Company. Interconnection agreements (both
transmission and distribution level voltages) are handled by the Company's
transmission function (including but not limited to PacifiCorp Transmission Services)
while power purchase agreements are handled by the Company's merchant function
(including but not limited to PacifiCorp's Commercial and Trading Group).
(continued)
P.U.C. OR No. 36 First Revision of Sheet No. 37-9
Canceling Original Sheet No. 37-9
Issued August 11, 2014 Effective for service on and after August 20, 2014
R. Bryce Dalley, Vice President, Regulation Advice No. 14-007
~ A DIViSION OF PACIFIC POWER OREGON
OR
SCHEDULE 37
AVOIDED COST PURCHASES FROM
QUALIFYING FACILITIES OF 10,000 KW OR LESS Page 10
II. Process for Negotiating Interconnection Agreements (continued)
A. Communications
Initial communications regarding interconnection agreements should be directed to the
Company in writing as follows:
PacifiCorp
Director -Transmission Services
825 NE Multnomah St, Suite 1600
Portland, Oregon 97232
Based on the project size and other characteristics, the Company will direct the OF
owner to the appropriate individual within the Company's transmission function who will
be responsible for negotiating the interconnection agreement with the QF owner.
Thereafter, the QF owner should direct all communications regarding interconnection
agreements to the designated individual, with a copy of any written communications to
the address set forth above.
B. Procedures
Generally, the interconnection process involves (1) initiating a request for
interconnection, (2) undertaking studies to determine the system impacts associated
with the interconnection and the design, cost, and schedules for constructing any
necessary interconnection facilities, and (3) executing an interconnection agreement to
address facility construction, testing, acceptance, ownership, operation and
maintenance issues. Consistent with PURPA and Oregon Public Utility Commission
regulations, the owner is responsible for all interconnection costs assessed by the
Company on a nondiscriminatory basis. For interconnections impacting the Company's
Transmission and Distribution System, the Company will process the interconnection
application through PacifiCorp Transmission Services.
P.U.C. OR No. 36 First Revision of Sheet No. 37-10
Canceling Original Sheet No. 37-10
Issued August 11, 2014 Effective for service on and after August 20, 2014
R. Bryce Dalley, Vice President, Regulation Advice No. 14-007
5s S ' ` • n n1 AA L CL ~o ~ Yc•- t tor'
BORROW AREA
S%
r ✓ f 1/`~ - IF REQUIRED 1. UNLESS DETAILED, SPECIFIED, OR OTHERWISE INDICATED ON THE DRAWINGS,
` r CONSTRUCTION SHALL BE AS INDICATED IN THE APPLICABLE TYPICAL DETAILS AND
GENERAL NOTES TYPICAL DETALS SHALL APPLY EVEN THOUGH NOT REFERENCED AT
l~., ^Fr X SPECIFIC LOCATIONS ON THE DRAWINGS.
1 l~ a y~
g ^~•P \fi J + tl F' 2. WHERE NO CONSTRUCTION DETAIL ARE SHOWN OR NOTED FOR ANY PART OF WORK,
1~ UDti i ~i~~~ ' P DE -FCANA4> EHT~_ 4.6 °11 DETAILS SHALL BE THE SAME AS FOR OTHER SIMILAR WORK.
SEE . A il~ /rte/ } G- ~1 :J•, 1~,~ 3. THE CONTRACTOR SHALL EXPOSE ALL INTERFERENCES AHEAD OF CONSTRUCTION.
DRYING BEDS
~t , N 1~ P 4~ 111 v~"~ ~V 11
DWG 8-6 (1~~ x
~ ~ v • 4. THE CONTRACTOR SHALL COMPLY WITH ALL REQUIREMENTS OF THE PERMITS ISSUED
IA y~ BY THE DEPARTMENT OF ENVIRONMENTAL QUALITY, W DIVISION STATE LANDS, ARMY CORPS
111N OF ENGINEERS, JACKSON COUNTY ROADS SERIACE CES AND JACK KSON COUNTY PAVEMENTS
DEPARTMENT.
bye
'.LENT + S' c j 1 f //`=~„U rkp11A 1\ 5. PIPELINE CONSTRUCTION SHALL PROGRESS IN AN UPHILL FASHION UNLESS
°o °o R S p'O!R hC T r 57''i ~0 4a \
1" = 500' 01 ° N r +E 'U:W.G_8 OTHERWISE APPROVED BY ENGINEER.
M ER
10
n ro n i ~,W 1C> +
PRIOR TO THE ACCEPTANCE OF ANY SEWER LINE, THE CONTRACTOR SHALL CLEAN ALL
LINES WITH A WAYNE-TYPE SEWER CLEANING BALL UNDER HYDROSTATIC PRESSURE.
w w w ~W~-• - 1 - ANY STOPPAGE, DIRT OR FOREIGN MATTER SHALL BE REMOVED FROM THESE LINES.
N 214000
~ ~ ~ / - \b ✓ ~ t ~ -i ' 7, ALL CLEANING AND TESTING OF SEWER LINES SHALL TAKE PLACE AFTER ALL
CONSTRUCTION WORK IS COMPLETED, UP TO BUT NOT INCLUDING, THE FINAL PAVING.
PROPERTY THE SYSTEM WILL BE INSPECTED AFTER FINAL PAVING IS COMPLETED AND ANY
LINE ~j i 0 ~r~ \E~~ 1t
TALENT IRRIGATION DAMAGE TO THE SYSTEM DURING FINAL PAVING AND CLEANUP WILL BE CORRECTED BY
' / - 1 • 'Sl + N
DISTRICT CANAL THE CONTRACTOR BEFORE APPROVAL
Ali F, ' ~ j t l l +A \ B. CONSTRUCTION STAKING WILL 6E PERFORMED BY THE CONTRACTOR.
j~j
>fw4T^RiNG. WELLS ANO
SEE 9. REMOVAL OF TRENCH SAFETY SYSTEM TO PROCEED UNDER THE DIRECTION OF
4u , b Ai 71: f X219$ _ / zNC~ d71k E R.
/3Ty~
(V1 I CONTRACTOR'S COMPETENT PERSONS.
N 213000 + t ..;11ll~ll~i ;,1j~^~t-'1=--~~i~`'~ N ~I(~. 15 ✓
10. CONTRACTOR SHALL HAVE A "COMPETENT PERSON" MAINTAJN A COPY OF AND
IMPLEMENT OSHA TRENCHING SAFETY REGULATIONS AT THE WORKSITE.
l ll l 5
i l l /~~rt~~ l up l I i '~t
"5 11. TEMPORARILY REMOVE ANY OBSTRUCTION INCLUDING, BUT NOT LIMITED TO LANDSCAPING,
FENCING, PAVING, GRASS, ETC. FOR CONSTRUCTION OF PIPELINES, REPLACE
-n / I ,,.T w . w ITEMS AND SURFACING REMOVED IN KIND TO ORIGINAL CONDITION IMMEDIATELY UPON
! ! 2 i7 COMPLETION Of WORK IN VICINITY,
EXISTING
UNDERGROUND A"-BIOSOLIDS OVERHEAD HIGH PRESSURE
+ ! + I+ - I \ STORAGE LAGOONS. POWER UNES GAS LINE AND 12. WORK WITHIN EASEMENT SHALL INCLUDE VEHICLE CROSSINGS. IF VEHICLE CROSSINGS
ARE
SIPHON f!j! REQUIRED, CONSTRUCT A BERM OVER PIPE. PG&E WILL LOCATE PIPE AND PROVIDE
. l(I(~~I l ~(I I I . 1 1 SEE DWGS B-1
0 EASEMENT,
1 II E r I t V~, t~ 20 BM NO. 8 BEAM DETAIL
200 LOCATE GAS LINE q
N 210 A s t r / • - 1~ - N 212000 AND CONTACT PG&E GAS
EXCESS EXCAVATION AND 13. INSTALL PERMANENT BENCHMARK PER(D. EXACT LOCATIONS TO BE DETERMINED BY
+ 1 I 1 1 1 \ \ \ ROCK DISPOSAL AREA TRANSMISSION COMPANY
~li+ \ 1 \ \ ENGINEER IN FIELD.
PRIOR TO ANY WORK WITHIN
EASEMENT. SEE NOTE 12
PROPERLY 14. GROUNDWATER MONITORING WELLS AND INCLINOMETER TO BE INSTALLED BY FOUNDATIONS
LINE ENGINEERING, INC. PER SPEC SECTION 02001.
o
INSTALL CANAL CROSSING.
SEE DWG P-10
~T~~~ t?Y2 ctR 1
NTFc A^yti T, '-TALENT IRRIGATION
~~A \ \ oA,~ +-y DISTRICT CANAL
W2' ~I\ y N 211000
BENCHMARK DATA
in NSXL •'NET ' - /C',r-~ BM NO COORDINATES ELEVATION DESCRIPTION
NO yAyA~ t t6 3 N 207646.5376 E 21574.0552 1717.0194 FO BC BRIDGE
'-,o 4 N 207554.0072 E 22473.5863 1719.4281 N RIM3 BELL TBM3
r \ A k
5 N 208244.3782 E 22843.4917 1788.8803 N RIM TBM MH
6 N 208980.2344E 21774.1553 1801.5956 5/8- IRON ROD IN CONCRETE
7 N 210252.7993 E 23240.8666 2000.9815 5 8- IRON ROD IN CONCRETE
- f r B N 214041.4729 E 28024.3166 2566.2785 5/8 IRON ROD IN CONCRETE
U N,
N 270000.\~~.\~~.`j N 210000
t rf
\V~OOV ~0\~~
m \~V ~~1~',~vy\V g
EAGLE MILL ROAD A\ \ -'r - llV --BM NO. 7
` LEGEND;
~'-CONSTRUCT SITE
`o TELEPHONE PEDESTAL SW = SIDEWALK -K-%- - FENCE BRASS DISC
N 209000 ACCESS ROAD.
SEE DWC C-1 - POWER POLE EC EXTRUDED CURB e - WATER VALVE
o ✓ T' t 8 - FIRE HYDRANT AC - ASPHALT CONCRETE 1765x32 -SPOT ELEVATION
1 Y - -BURIED UNDERGROUND
BM NO 6~-"`~~
TELEPHONE & FIBER
8 TID - PROPERTY OPTIC LINES. CONTACT 0 - SANITARY SEWER MANHOLE S) - STORM SEWER MANHOLE ❑ - WATER METER FILL WITH GROUT
CANAL _ I I r LINE AT & i PRIOR TO = GUYWIRE TIEDOWN INV = INVERT ELEVATION RIM RIM ELEVATION
APPROX. LOCATION EXCAVATION o 2"0 GSP FILLED
ENGINEERS -V-V- OVERHEAD POWER LINE ■ = STORM DRAIN GRATE CC - CAST CONCRETE I WITH GROUT
` RAILER, SEE DWG ER-7
BEAR CREEK R
COP - CAST CONCRETE PIPE V+ m LIGHT POLE - IRRIGATION VALVE
n EAGLE MILL ROAD
v N 208000 -SS- - SANITARY SEWER LINE -G-G- - GAS LINE -W-W- - WATER LINE
I,: \ c N 205000
a ASHLAND CREEK Q/.,, N' -T-T- a SPRINT FIBER OPTIC LINE (FO) OR US WEST LINE (USYI)
EFFLUENT
E BM NO. 3 r = A -RESERVOIR NO. 1.
ASHLAND SEE DWG ER-1 ELEVATION DATUM: CITY OF ASHLAND BM#31. BRASS DISK IN SE CURB AT INTR. OAK STREET 6"0
' WASTEWATER SITE ACCESS & NEVADA STREET. ELEVATION: 1764.339 (NGVD 7929((56))
TREATMENT SHALL BE FROM
PLANT THIS LOCATION A DETAIL -BENCHMARK
o tr
y BM N0. 5 ONLY BASIS OF BEARINGS: GEODETIC BEARING BETWEEN STATION ASH & TALENT PER OREGON _ 1" - 1'-0"
m aat T ^7725 . '1 ~--~-BM NO. 4 STATE PLANE COORDINATE SYSTEM SOUTH ZONE BASED ON NOS PUBLISHED OCAL193
4,,'A,Y l BEAR CREEK COORDINATES ON FlL WITH JACKSON COUNTY SURVEYOR'S OFFICE.
+b ~ ,t0 e- %-1 ROTATE DEARINGS (01'30'36' TO OBTAIN GRID BEARINGS. DISTANCES
41+:... ASHLAND CREEK N 207000 ARE GROUND DIST ES.
N 207000* \\{i- 1 71 1
OAK STREET
r~ R T UNIT OF MEASUREMENT: FEET (GROUND) DATE: NOVEMBER 21, 1997
CONTOUR INTERVAL: 5 FOOT.
■in
DESIGNED w w BTU Eaor£S o Peat o4 AS CITY OF ASHLAND - BIOSOLiDS UTILIZATION YERTY SCALES roe NO.
o RJN i At' S 4-411D.10
z ~~S A~G1NPf4, ~4 ~SGI Na BAR IS ONE INCH ON
DRAWN F u 15,2E6 R' I DRAWING NO.
MJG w w a ca~■'o"O o AND EFFLUENT RECYCLING PROJECT ORIGINAL. DRAWING
G-3
z o GENERAL -3
CHECKED G
enGI eIs rs
CDH F NOT ONE INCH PN SHEET N0.
DATE BY DESCRIPTION DATE v e 30~yOVERALL SITE PLAN TMIS SHEET, AnJUSr
AEV o E%P 12 31/99 ONE QQ~ SCALES ACCORDINGLY 3 OF 85
FlLENNdE: 0(;A1003 JUNE 1999 -