20090911Application.pdf

~~l.~OUAIN REt;i:!\/t:. . . . ii- :. ~ w to:
September 11, 2009
VI OVERNIGHT DELIVERY
2009 SEt' l f AM 9: 29 201 South Main, Suite 2300Salt Lake City. Utah 84111
IDAHO PUBU(~ ....
UTILITIES COMMISSION
Idaho Public Utilties Commission
472 West Washington
Boise, il 83702
Att: Jean Jewell
Commission Secreta
Re: Rocky Mountain Power's Request to Revise its Wind Integration Rate
(JA--£ -09 - 07
Dear Ms. Jewell:
Please find enclosed the original and seven (7) copies, along with a compact disk, of
PacifiCorp's petition to revise its wid integration rate.
Rocky Mounta Power, a division of PacifiCorp (''te Company"), pursuat to the Rule 31,
IDAP A 31.01.0 1.031, hereby petitions the Idao Public Utilities Commssion ("Commission") to
issue an Order increasing the published avoided cost integration rate applicable to purchases by
Rocky Mountan Power of electrc power from wind-powered QFs from $5.10 to $9.96 per
MWH, which amount represents the integration costs of that wid power, to be applied against
published avoided cost rates except in those circumstaces where the QF developer agrees in the
power purchae agreement with Rocky Mountain Power to deliver QF output to Rocky Mountain
Power on a firm hourly schedule.
It is respectfuly requested that all formal correspondence and Sta requests regarding this fiing
be provided to the Company in a Microsoft Word document, addressed to the following:
Bye-mail (preferred):
By reguar mail:
dataeguest~pacificorp.com
Data Request Response Center
PacifiCorp
825 NE Multnomah, Suite 2000
Portland, OR 97232
Please direct any inormal inquiries to Ted Weston, Idaho Reguatory Affais Manger, at (801)
220-2963.
Sincerely,
~~)Ar
Jeffrey K. Larsen
Vice President, Reguation
Danel E. Solander
Sr. Counel
Rocky Mounta Power
201 South Main, Suite 2300
Salt Lae City, Uta 84111
Telephone: [phone]
Facsimle: 801-220-3299
RECEiVED
i009 SEP \ \ ~M 9: 29
\01\110 PU¥Mi~'''I''~N
\JTIUi\t:S cm.il v~IV
Attorney for Rocky Mountain Power
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE PETITION OF )
ROCKY MOUNTAI POWER FOR AN )
ORDER REVISING THE WIN ) No. PAC-E- O'ì-O'7
INTEGRATION RATE FOR WID- )
POWERED SMALL POWER GENERATION) PETITION
QUALIFYIG FACILITIES )
)
)
Rocky Mounta Power, a division of PacifiCorp (''te Company"), puruat to the Rule
31, IDAPA 31.01.01.031, hereby petitions the Idao Public Utilties Commssion
("Commission") to issue an Order increasing the published avoided cost integration rate
applicable to purchases by Rocky Mountan Power of electrc power from wind-powered QFs
from $5.10 to $9.96 per MWH, which amount represents the integration costs of that wid
power, to be applied against published avoided cost rates except in those circumstaces where
the QF developer agrees in the power purchase agreement with Rocky Mountan Power to
deliver QF output to Rocky Mountain Power on a firm hourly schedule.
With respect to the costs of integrtig wid generation into existing utility
systems, the Commssion found in Order No. 29839, Cas No. IPC-E-05-22 tht the supply
characteristics of wid generation and related integration costs could provide a basis for
adjustment of the published avoided cost rates, an adjustment that may be different for each
PETITION OF ROCKY MOUNTAI POWER - 1
utilty. In a subsequent Order No. 30497, Case No. PAC-E-07-07, the Commssion approved
Settlement Stipulation filed in Case No. PAC-E-07-07. In that Settlement Stipulation, Section III
(a) of the Stipulation states, "....Rocky Mountain Power shall hereafer file notice with the
Commssion of any changes to its wind integration charge as reflected in subsequent changes to
its IR....."
Puuat to that Stipulation, the Company's recommendation is that published avoided
cost rates for purchases by Rocky Mountain Power be reduced by $9.96 per MWh, which
amount represents the integration costs of that wind power, to be applied against scheduled
avoided cost rates in those circumstaces, except where the QF developer agees in the power
purchase agreement with Rocky Mounta Power to schedule and deliver, via a transmission
provider, the QF output to Rocky Mountan Power on a firm hourly basis. The $9.96 per MWh
represents the wid integration cost included in the Company's latest IRP (the 20081R).
I.
BACKGROUN
Rocky Mountain Power filed a Petition with the Commssion on April 23, 2007,
in Case No. PAC-E-07-07 requesting Commission approval of utility-specific wind integrtion
adjustments to the published avoided costs rates. The Commission reviewed the facts and the
Settlement Stipulation of ths case and determed that a utility-specific wind integration cost
adjustment to that utility's published avoided costs, among other adjustments, was appropriate.
As a result, the Company makes a $5.10 per MWh reduction to its published avoided cost prices.
This discount captues the cost of integrting wind generation into the Company's electrcal
system.
PETITION OF ROCKY MOUNTAI POWER - 2
II.
INTEGRATION COSTS OF WI POWER TO BE REFLECTED
IN AN ADJUSTMENT TO PUBLISHED AVOIDED COST RATES
As par of the Settlement Stipulation in Case No. PAC-E-07-07, the Company is
reuired to file notice with the Commission of any changes to its wind integration chage as
reflected in subsequent changes to its IRP. Rocky Mounta Power submits herein as Exhbit A
to ths Petition, an excerpt from PacifiCorp's 2008 IR Appendix F - "Wind Integration Costs
and Capacity Planng Contrbutions" in which PacifiCorp provides a description of the
methodology used and the results derived from PacifiCorp's analysis of the wind integrtion cost
issue. The 2008 IR was originally filed on May 29, 2009 (Case No. PAC-E-09-06). Rocky
Mounta Power recommends that the published avoided cost rates applicable to purhaes by
Rocky Mounta Power of electrc power from wid-powered QFs be reduced by $9.96 per
MWh to account for the cost to integrate wid.
In compliance with the Settlement Stipulation and Order No. 30947 in Case No. PAC-E-
07 -07, Rocky Mountain Power recommends that the applicable wind integrtion charge
reduction be applied to the published avoided cost rates to determe a purchase and sale price
that will be established for the durtion of the power purchase agreement with the Qualifying
Facilty. Rocky Mounta Power recommends ths approach in order to assure that QFs tht
deliver less than 10 aMW have a predictable rate.
III.
COMMUNICATIONS
Communcations respectig ths matter should be addressed to:
Danel E. Solander
Sr. Counel
Rocky Mountain Power
Ted Weston
Manager, Idao Reguatory Affais
Rocky Mounta Power
PETITION OF ROCKY MOUNTAI POWER - 3
201 South Main, Suite 2300
Salt Lake City, Uta 84111
Telephone: [phone]
Fax: [phone]
E-mail: danei.solander~pacificorp.com
201 South Main Street, Suite 2300
Salt Lake City, UT 84111
Telephone: [phone]
Fax: [phone]
E-mail: ted.weston~pacificorp.com
IV.
MODIFIED PROCEDURE
Rocky Mounta Power respectfully requests that the Commission consider this Petition
in accordace with Rule 201, et seq., allowing for disposition by Modified Procedure. IDAPA
31.01.01.201 et seq. Rocky Mountain Power is receptive to fuer proceedings, if the
Commission believes based on comments received, that fuer proceedings would be
advantageous.
WHREFORE, Rocky Mountan Power respectfuly petitions the Commssion to issue
an Order:
Reducing the published avoided cost rates applicable to purchases by Rocky Mountan
Power of electrc power from wid-powered QFs by $9.96 per MWh, which amount represents
the integrtion costs of that wind power, to be applied against scheduled avoided cost rates in
those circumstaces, except where the QF developer agres in the power purchase agreement
with Rocky Mountain Power to schedule and deliver, via a tranmission provider, the QF output
to Rocky Mountain Power on a firm hourly basis.
RESPECTFULL Y SUBMITTED this 11th day of September 2009.
Rocky Mountan Power
By~)uklDanel E. Solander, Sr. Counsel
Rocky Mountan Power
PETITION OF ROCKY MOUNTAIN POWER - 4
Exhibit A
PacifCorp - 2008 IRP Appendix F - Wind Integration Cost Update
APPENDIX F - WIN INTEGRATION COSTS AND CAPACITY
PLANG CONTRIUTIONS
This appendix summarzes the results ofPacifiCorp's latest wind integration cost analysis, which
will continue to be refined and expanded. This appendix also presents updated wind capacity
contrbution values using a statistical estimation methodology that was applied for the first time
in the Company's 2007 IRP.
For the wind integration cost study, PacifiCorp developed a methodology to support the costs
associated with resource portfolio analysis for the IR as well as costs used in the evaluation of
cost effective renewable resources. This approach decomposes the estimation of inter-hour (hour
to hour) and intra-hour (with the hour) costs to integrate intermittent renewable resources. For
inter-hour costs, these components include day-ahead and hour-ahead wid forecast varability,
or what was referred to as system balancing costs in the 2007 IRP.1 For intra-hour costs, the
components include actul forecast varation, "regulation up" requirements, and "regulation
down" requiements. These latter costs pertai to operational assessment and plang of wind
variability down to 10-minute intervals. or less. In addition to ths cost breakdown, PacifiCorp
reports integration costs for wid added in the PacifiCorp eastern balancing authority area
(PACE), the PacifiCorp west balancing authority area (P ACW), and a system weighted-average
based on installed capacity in each control area.
The wid integration cost section first provides background on these cost components and then
describes the estimation methodologies and cost results. Study caveats and areas for fuer
research are also sumarzed. The costs results are expressed as a fuction of the amount and
timing of wind included in the 20081R preferred portfolio as well as existig wid (Table F.1).
The section concludes with a discussion on futue tools, approaches, and external coordination
opportties that PacifiCorp is actively considering or exploring to address the consequences of
adding large quatities of wind.
Table F.l - 2008 IR Preferred Portolio Wind Resource Additions by Year
lè; ......
. .èyeå.. .......è (MW);';.CapacitvFactor Ð..¡i;~.....;;.. .... ... .....
Existing and
Planed 1,284 --System
though 2010
2011 100 29%Walla Walla
2011 100 29%Yaka
2012 100 35%Southwest Wyoming
2013 100 35%Southwest Wyoming
2014 100 35%Aeolus Wyoming
2015 150 35%Aeolus Wyoming
2016 100 35%Aeolus Wyoming
2017 100 35%Southwest Wyomig
1 PacifiCorp, 2007 Integrted Resource Plan, Appendix J, pp. 193-4.
269
PacifCorp - 2008 IRP Appendix F - Wind Integration Cost Update
......· Year
./Capacity Additions(M.CapacitvFactor Remon
2018 50 35%Southwest Wyoming
2019 200 35%Southwest Wyoming
2020 200 35%Southwest Wyomig
2021 150 35%Southwest vv
.
TOTAL .,',i.,.:1;...............;e".;;......................... .................0i?:?'....2,734 ,......)..../..........,.., ......
Due to a number of project schedules, this wid study was not completed in time to be
incorporated into the 2008 IR portfolio modeling. As discussed in Chapter 7 of Volume 1, a
value of $11.75/MWh-based on Portland General Electrc Company's latest wind integration
study-was used for IRP capacity expansion optimization modeling puroses. Whle the
Company acknowledged the differences between the PacifiCorp and PGE systems and the
caveats associated with the PGE study, PacifiCorp believed that the PGE value represented a
reasonable proxy until its own study could be completed. If the wind integration cost study yields
a significantly different total value, the Company commts to perform a sensitivity study with the
System Optimizer capacity expansion model and the 2008 IR preferred portfolio modeling
assumptions to determine the wid resource selection impact of the updated cost value.
Background
In power planng and dispatch, any period in which load or generation varies from a steady
value results in an increased cost for the 'utility to balance out this variation. Variations in the
load and wind generation forecasts are managed with balancing activities. Once the hour-ahead
schedule is given to the real-time staf, actual varation in load and wid generation with the
hour is balanced using system generation resources. Curent balancing activities treat wind
forecast varations similarly to load forecast deviation; however, special attention is requied for
the greater percentage variability and near-term volume growth of wid generation.
The components of wind varability which give rise to integration costs can be divided into two
groups: inter-hour and intra-hour. The inter-hour components of wind variabilty are:
. Day-ahead forecast varation: deviation of the long-term wind forecas (prior energy
expectations) to the day-ahead forecast for the day prior to power delivery.
. Hour-ahead forecast variation: deviation of hour-ahead forecast from day-ahead forecast
for the hour prior to delivery.
The rebalancing or closure of open positions generated as new load and wind forecast data
becomes available requires the payment of transaction costs.
The other set of costs to be considered is associated with the intra-hour (withn the hour)
components of wind varability:
270
PacifCorp - 2008IRP Appendix F - Wind Integration Cost Update
. Actual forecast varation: deviation of actual hourly average energy from the hour-ahead
forecast,
. Regulate down: deviation of hourly maximum energy from the energy at the beging of
the hour, measured with ten minute granularty,
. Reguate up: deviation of hourly minimum energy from the energy at the beginnng of the
hour, measured with ten miute granularty,
. Automatic Generation Control (AGC): fine scale varation of energy over a one to two
minute time scale.
These intra-hour factors require the holding of additional reserves above the standard
requirement of 5 percent on wind generation. Due to the small impact, yet large analytical
requirement, to determine reserves for AGC, ths cost component is not addressed in the wind
integration study; however, ths issue may be pursued in the futue as the company gais more
experience in this area.
These inter- and intra-hour factors do not include long-term shaping effects. While benefits or
costs may arse due to the hourly difference between expected futue energy in moving from a
flat-dispatched unt such as geothermal to a shaped profile unit such as wind, on a longer-term
view, these differences are only the effect of different hourly prices or expected value on the
forecasted futue energy; therefore, no actual costs are incured from balancing a new long-term
wid pattern with system resource redispatch.
Determination of Incremental Reserve ("Intra-Hour") Requirements
Before all reserve costs can be estimated, the megawatt (MW quatity of reserves required to
maintain system reliability as additional wind in the Eastern and Western balancing authority
areas of PacifiCorp's service region must be calculated. In previous wind integration studies,
PacifiCorp has not captured the increased load-following reserve requiements caused by wind
forecast error within the hour. Increasing the magnitude of wind resources on the system results
in an increased reserve requirement due to the fact that wid forecasts are inerently inaccurate,
paricularly at within-hour granularty. Intra-hour wid variability requires the dispatch of
existing units to balance the system as there is no intra-hour market.
Actual Variation
The deviation of the actual hourly average energy from the hour-ahead forecast can be computed
given the historical hour-ahead wind generation forecast and actu hourly energy values. This
produces statistical hourly distributions of the forecast versus actul energy. If this was the only
source of the intra-hour uncertaity, the quantities of reserves may be easier to estimate by tang
the 97.5th percentile of the variation distrbution which represents two stadard deviations of
forecast error and the approximate PacifiCorp performance under Control Performance Standard
II (CPS 11)2). Reporting levels of reserves required with a 97.5% confidence interval adds an
importt reliability dimension to the calculation. Whle actual day-to-day balancing operations
may require less reserves than suggested in this study, attention to tail events is an important
consideration for overall system reliability. Additional considerations include the correlation
2 The CPS II stadard refers to the compliance bounds for the IO-minute average of the Area Control Error.
271
PacifCorp - 2008 IRP Appendix F - Wind Integration Cost Update
between forecast error and two additional sources of intra-hour uncertainty: "regulate down" and
"regulate up".
Regulate Down
For the puroses of this study, regulate down is the difference between the maximum wind
energy with the hour (using 10-miute interval wid generation data) and the energy at the
beginng of the hour. When wind energy moves up withn an hour, other generation resources
are required to reduce their output to compensate for ths intra-hour energy deviation. The
analysis of 10-minute interval wind generation data yields a statistical distrbution of the
difference between the wind energy at the beginng of the hour and the ten-minute period of
maximum energy within the hour. Takng two stadard deviations of the resultant statistical
distribution allows reserves associated with ths factor to be estimated at a confdence interval
consistent with PacifiCorp's CPS II standard.
Regulate Up
For the puroses of ths study, reguate up is the difference between the minium wind energy
withn the hour (using 10-minute interval wind generation data) and the energy at the beginng
of the hour. wnen wind energy moves àown withi an hour, other resources on the system are
required to increase output to compensate for this intra-hour energy deviation. The analysis of
10-minute interval wid generation data yields a statistical distrbution of the difference between
the wid energy at the begining of the hour and minimum energy withn the hour. Takng two
stadard deviations of the resultat statistical distrbution allows reserves associated with ths
factor to be estimated at a confdence interval consistent with PacifiCorp's CPS II standard.
These three intra-hour factors for different locations are not independent of each other and tend
to exhbit some positive and negative correlations that are taken into account when measurg the
standard deviation of the simultaneous and combined effect of these factors. Before estimating
the tota reserves requirement for intra-hour integration, correlations are estimated and applied to
determe the total combined uncertty on a regional leveL. Two stadard deviations for the
total probability distrbution allowed for computation of reserves associated with all intra-hour
factors in the Eastern and Western control areas.
System Balancing ("Inter-Hour") Cost Calculation
The shape of a wind energy delivery pattern is different than the delivery patterns of other
generation resources. The wind is intermittent and varable, so a wind pattern that is input as a
forecast of expected generation differs considerably from the actual generation delivered.
Alternatively, a dispatchable resource, like a CCCT, does maintan a flat schedule of energy
delivery so generation units on the system do not have to redispatch and balancing activities do
not have to occur to compensate for a block of flat energy. When a short-term wid forecast is
created and compared to a longer-term wid energy expectation, balancing activities may have to
occur to balance the deviation between the wid forecasts and realized output.
Day-ahead Variation
Because a day-ahead forecast of hourly wind energy always differs from the expected futue
energy level by some amount, the ideal of delivering a balanced energy profile on a day-ahead
basis requires some adjustment in the energy position via trsactional balancing. Whle
272
PacifCorp - 2008 IRP Appendix F - Wind Integration Cost Update
deviation from a perfectly balanced schedule is normal, estimation of the impacts are assumed to
be eliminated by balancing activities to the extent possible.
Fixing the imbalance in real-time is generally more expensive and, to this end, this study
assumes that all forecast imbalances are addressed in the day-ahead market. This is limited by
the sÌze and availability of stadard 25 MW blocks for standard 16-hour or 8-hour (on-peak and
off-peak) delivery patterns. PacifiCorp incurs transaction costs every time it trades a block of 25
MW. These transaction costs may var depending on the time of day and location and are
curently estimated to be about $0.50 per MW over market for purchases to cover a shortfall in
forecast, and under market for sales to cover a forecast excess durng most transactional hours.
This internal assumption is generally accepted by balancing sta and is consistent with the
assumption used in Portland General Electric's wind integration study. Given the hourly
difference between the long-term expected wind generation and the historical wind generation
forecasts at the day-ahead horizon, these costs may be estimated.
To calculate the transactional costs associated with balancing the hourly long-term expected
wind generation to the hourly day-ahead wind schedule, the varation was calculated as the
absolute value of the difference between the two forecasts. For October 2008 though April
2009, a sample week of hourly data from all existg wind plants on the system (for which data
was available) was chosen for each month3. The distinction of costs between the Eastern and
Western side of the system is reflective of different degrees of forecast accuracy. The existing
data was scaled up to reflect the planed East and West additions to the system, 200 and 1,250
MW, respectively, for a total of 773 MW on the West and 1,784 MW on the East. The total
deviation was found for each day for both heavy load and light load hours.
For example, on Day 1, the deviation for all heavy-load hours was added. The same was done
for light-load hours. The resulting totas were rounded up to the nearest 25 MW increment to
reflect actual transaction sizes available in the day-ahead market. The tota daly variation was
added up for each sample week and multiplied by an estimated bid-ask spread of $0.50 per
MWh. PacifiCorp's front offce provided . this bid-ask spread estiate. The total transaction
costs incurred for all sample weeks was divided by the tota MWh of long-term expected
generation for the same sample weeks and presented on a $/expected MWh basis provided in
Table F.2. Tranaction costs in the table below are lower in the Easern control area and may be
the result of more accurate forecasting, a more unform wid pattern, and higher locational
diversity.
Table F.2 - Wind Inter-hour Day-Ahead Balancing Transaction Costs
West
East
$0.41
$0.23
3 This period was chosen due to limited data availabilty.
273
PacifCorp - 2008 IRP Appendix F - Wind Integration Cost Update
Hour-ahead variation
Simiar to the day-ahead variation, the rebalancing of energy to close open positions due to the
change in forecasted wind energy from the day-ahead schedule to the hour-ahead schedule also
adds transaction costs. Hour-ahead transactions assume transactions in 1 MW increments, but
transactions costs are up to twenty-five percent of the per-MWh energy costs. The precise
percentage depends on then-eurent market conditions and the amount of energy traded.
In order to derive the hour-ahead forecast used by real-tie for scheduling, a persistence
methodology was used. When the real-time traders schedule wid for the upcomig hour, it is
assumed that the actual wind generation level from the previous hour will persist for the next
hour. In this study, the hour-ahead schedule was based on persistence. The existing October
2008 through April 2009 data was scaled up to reflect the planed East and West additions to the
system, 200 and 1,250 MW, respectively, for a total of 773 MW on the West and 1,784 MW on
the East. The tota deviation was found for each day for both heavy load and light load hours.
The day-ahead to hour-ahead balancing transaction costs were calculated in largely the same
fashion with the exception of the bid-ask spread used. Transactions underten to correct an
imbalance, due to varations between the day-ahead and hour-ahead forecast, are of higher cost,
which is dependent upon the quantity of power needed and market conditions. Figure F.1 shows
the hourly frequency of varous imbalance sizes based on 1,300 hourly deviations, which is
constitutes the tota number of sample hours.
Figure F.I-Hour-Ahead Variation Frequency Distribution
Wind Inter-hour Integration:
Size of Hour-ahead Rebalancing Trades
900 i
800 ~¡/ \If700/\i
::600 i0/\i:i-5000 I i \\,
..400 i
Q)/ /\\\-I.c
E 300 i I \'.I::
~~,:=
iz
i~~.~..e
0 100 200 300 400 500 600 700 800 900 1000 1100 1200
Size of Rebalance Trade (MW)
I-+ West - East I
274
PacifCorp - 2008 IRP Appendix F - Wind Integration Cost Update
It is also generally accepted in the hour-ahead market that, as the size of the tranaction
increases, the costs associated with transactions increases. Based on the frequency distrbution
above, a smaller cost is requied for transactions of about 50 MW, which are transacted much
more frequently. The distrbution also indicates that, in general, transaction costs on the west
portion of the system will be higher due to lower forecast accuracy. Specific transaction
assumptions are listed in Table F.3.
Table F.3 - Inter-hour Hour-Ahead Balancing Transaction Cost Ranges
Transa.ction ..Cost(Bid-ask)
Percenta e b Re 'onWest East5% 5%10% 10%25% 15%
Lower Bound
o
101
201
erBollnd
100
200
1,000
Table F.3 indicates that as more wind projects are added to the system, forecast improvements
are necessar in order to prevent large varations which come with a higher market transaction
cost. Consider, on an average basis, if a 100 MW wid project is added to the system, the shape
of the distribution of the size of hourly errors wil be about the same. As the distrbution of error
increases in a linear fashion, the cost associated with rebalancing does not. Since costs are
greater as the size of transactions increases, the distrbution of errors may increase on a linear
basis, but costs will increase faster.
Once the hourly varance from the day-ahead forecast to the hour-ahead forecast has been
calculated, the specific hourly varance is applied to the corresponding hourly real-time price
from an independent energy information company that publishes hourly wholesale power
indices. For PACE, Four Corners was used and for PACW, Mid-Columbia was used. The size of
the varance determines the transaction cost, which is the product of the hourly price and the
corresponding variance percentage. In Table FA below, the day-ahead to hour-ahead tranaction
cost is presented along with the tota inter-hour cost for the east and west balancing authority
areas.
Table FA - Wind Inter-hour Hour-Ahead Balancing Transaction Costs
Determination of Incremental Reserve ("Intra-Hour") Requirements
The indicated MW of additional reserves needed to balance the tota intr-hour wind generation
varations on PacifiCorp's system due to incremental wid addition is unque to each region of
4 Values expressed are representative of the average cost to transact for the October 2008 though April 2009 period.
275
PacifCorp - 2008 IRP Appendix F - Wind Integration Cost Update
PacifiCorp's system. These values were derived by multiplying the within-hour standard
deviation from all wid projects in each of the three regions in this study by a Z score of 1.96
(which is representative of the 97.5% confdence interval and PacifiCorp's CPS II requirement)
and is inclusive of all three sources of inter-hour variation discussed. Table F.5 presents the
corresponding reserve volumes for each region in the system and reflects fixed volumes of new
anual wind projects spread through 2021 consistent with the company's general long-term wid
acquisition strategy.
Table F.5 - Total Wind System Intra-hour Reserve Requirement (MW
Existing and
Planned
throu h 2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
Capacity
Additions
Total Reserve
Re uirement
1,284 295.4
200
100
100
100
150
100
100
50
200
200
150
17.3
18.5
7.9
9.9
18.8
12.6
4.6
16.9
18.9
12.3
19.7
17.3
35.8
43.7
53.6
72.4
85.0
89.7
106.6
125.5
137.7
157.5
312.7
331.2
339.1
349.1
367.8
380.5
385.1
402.0
420.9
433.2
452.9
Incremental Reserve ("Intra-Hour") Cost Calculation
The previous section described the calculation of MW quatities associated with adding wid
generation resources. In this section, the calculation of the cost associated with wind additions is
described.
As the company installs larger volumes of wind resource generation, the company's cost to
integrate these intermttent resources is anticipated to increase. Ths is because more and more
non-wid resources must be held back to allow flexibility to follow the intra-hour volatilty of
the wind generation. Resources with greatest dispatch flexibility that are not already in use to
serve load are typically used for integration.
The hour-to-hour dispatch of non-wind resources is not a trvial decision. The company's owned
hydro plants with storage capability and the Mid-Columbia hydro contracts often provide the
needed flexibility. However, these hydro resources are not of adequate size to integrate all of the
anticipated wind varability. Parially loaded gas tubines provide additional flexibility. Due to
its low cost, it is economically preferable that coal is fuly utilized to serve load rather than
backed off to provide wind integration.
276
PacifCorp - 2008 IRP Appendix F - Wind Integration Cost Update
The study assumes that PacifiCorp would balance the intermittency of the wind by holding
additional reserves on existing and future flexible resources. A reserve resource stack model was
developed that is used to estimate both in-the-money and out-of-the-money reserve costs. The
modeling of reserves added the requirements for load and reduced the requirement for hydro and
contract réserves in the valuation. In-the-money reserve costs are measured by calculating
market prices less the cost of thermal dispatch (fuel, varable O&M, C02 emission costs, and
802 emission costs). Out-of-the-money reserve costs are estimated by calculating the above-
market operating costs of a unt dispatched at minimum capacity divided by the total amount of
reserve capability available once at minimum load. The reserve requirement is then filled by the
lowest cost in-the-money or out-of-the-money thermal resource considering the resource reserve
capacities and unt ramp rates. PacifiCorp used market prices at Mona, Mid-Columbia, and Four
Comers with the $45 CO2 October 2008 price cure (2013 is the assumed star of C02
reguation).
The wind reserve results reported in Table F.6 are at the system level and include both existing
and incremental wid projects. The reserve results are levelized on a real basis (with ination
effects removed) for the study period 2009 to 2030 by dividing the reserve cost by the wid
expected megawatt-hour generation. The existing reserve available data ended in April 2014 so
the data was escalated using the prior thee-year average. The reserve study considered heavy
load and light load hour for the analysis but was limited by the wind reserves calculated on an
anua basis.
Table F.6 - Costs for Wind Intra-hour Incremental Reserves
2,734 $9.40
To determne the cost impact of using a lower C02 cost, PacifiCorp estimated the intra-hour
reserve cost assuming an $8 CO2 ta. The wind reserve costs dropped to $7.51/MWh, expressed
in $2009, representing a 20-percent decline relative the cost under the $45 CO2 cost study. It is
not necessarily tre; however, that increasing the cost of CO2 equates to a higher reserve cost.
This relationship may be a fuction of near-term natual gas price cur~s.
Conclusion
The wind integration cost results are presented in Table F.7, and range from $9.96/MWh to
$11.85/MWh for PacifiCorp's system in 2009 dollars, depending on the C02 ta level scenaro.
The inter-hour wind results were developed by weighting the P ACW inter-hour wind costs by
30% (the PACW MW shae of the system total) and the PACE wind costs by 70%, then adding
the system wind reserves.
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PacifCorp - 2008 IRP Appendix F - Wind Integration Cost Update
Table F.7 - Wind Integration Costs (2009 Dollars)
SvstemBalancinl! Cost anter-hour)
EXPected to Day-Day-Ahead to Hour..Total Cost Intra-hour Cost Total .
COiCost Ahead Cost Ahead Cost ($/Expected ($/Expected ($/Expected
Scenario ($/xpected Mwh). ($/ExpectedMWh)MWh)MWh)MWh)
$8 tax $0.28 $2.17 $2.45 $7.51 $9.96
$45 tax $0.28 $2.17 .$2.45 $9.40 $11.85
The system wid integration costs are in line with the $11.75/MWh proxy value used for 2008
IRP portfolio modeling. Consequently, PacifiCorp did not conduct a wid resource sensitivity
study using PacifiCorp's updated values.
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