20110628PAC to Staff 1-8.pdf

~ROCKY MOUNTAINPORA DIISl OF PAFl
201 South Main, Suite 2300
Salt Lake City, Utah 84111
RECEIVED
iOI i JUN 28 AM 10: 21
June 27, 2011 ( ~-..)
VIA EMAIL
AND OVERNIGHT DELIVERY
Neil Price
Idaho Public Utilities Commission
472 W. Washington
Boise, ID 83702-5918
N eil.priceØjpuc.idaho. gov
RE: ID PAC-E-11-10
IPUC Production Data Request (1-8)
Please find enclosed Rocky Mountain Power's responses to IPUC Production Data Requests 1-8.
If you have any questions, please feel free to call me at [phone].
Sincerely,
;;--r~tl~/~
J. Ted Weston
Manager, Regulation
Enclosure
C.c.: Jean JewelVIPUC (3 copies)
..PAC-E-l 1-07/Rocky Mountain Power
June 27, 2011
IPUC Production Data Request 1
IPUC Production Data Request 1
What assumptions are made regarding load growth in service territories
throughout the West during the IRP timeline? How do these assumptions affect
market purchase availability?
Response to IPUC Production Data Request 1
Load growth in each jurisdiction is based on various factors and assumptions.
The Company used the most recently available economic drivers from IHS Global
Insights at the time of preparation of the load forecast. Major drivers of the
residential models are heating and cooling related variables, end-use information
such as equipment shares, satuation levels and effciency trends, and economic
drivers such as household size, income and energy price. For the commercial
class, sales are forecasted using regression analysis techniques with employment
as the major economic driver in addition to weather-related variables. The
industrial forecast is developed based on direct input of the customers, forecasted
load factors, and the probabilty of the project occurence. For more information
on the assumptions, please refer to the modeling and methodology overview
sections of Appendix A of the 2011 Integrated Resource Plan. Pages 5-l0 of
same appendix has more detailed explanation of the assumptions driving load
growth in each state.
The availability of market purchases are based upon the amount of firm
transmission rights to market hubs and assumed market depth limitations. The
factors and assumptions driving load growth in each jurisdiction have no
influence on the availability of market purchases.
Recordholder:
Sponsor:
Peter C. Eelkema / Rick Link
Peter C. Eelkema / Rick Link
-,PAC-E-11-07/Rocky Mountain Power
June 27, 2011
IPUC Production Data Request 2
IPUC Production Data Request 2
Does PacifiCorp currently have the transmission or transmission rights to procure
the level of market purchases listed in the preferred portfolio?
Response to IPUC Production Data Request 2
Yes. Firm transmission rights are incorporated in the IRP models so these rights
may serve as an availability constraint for market purchases.
Recordholder:
Sponsor:
Pete Waren
Pete Waren
P AC- E-11-07/Rocky Mountain Power
June 27, 20l 1
IPUC Production Data Request 3
IPUC Production Data Request 3
What natural gas price forecast (low, medium, high) does the market reliance
'stress test' included in Appendix H utilize?
Response to IPUC Production Data Request 3
The Company used the June 2008 Official Forward Price Cure for the stress test,
corresponding to a "medium" forecast at the time the forecast was made.
Recordholder:
Sponsor:
Pete Waren
Pete Waren
PAC-E-l l-07/Rocky Mountain Power
June 27, 2011
IPUC Production Data Request 4
IPUC Production Data Request 4
For utility solar projects, is it accurate to say that the IRP incorporates both the
30% investment tax credit (Emergency Economic Stabilzation Act of 2008) or
cash grant in lieu of the ITC and production tax credits extended in 2009?
Response to IPUC Production Data Request 4
As a simplifying assumption, the Company assumed the availability of just the
production tax credit for utility solar projects.
Recordholder:
Sponsor:
Pete Waren
Pete Waren
PAC-E-11-07/Rocky Mountain Power
June 27,2011
IPUC Production Data Request 5
IPUC Production Data Request 5
Why was a heat rate of 11,750 BtuWh selected as the heat rate for gas backup
of solar?
Response to IPUC Production Data Request 5
The 11,750 Btu/Wh heat rate is a best-case heat rate for a natural gas fired boiler
and was suggested by solar vendors a number of years ago and has been caried in
the Supply Side Resource table since 2007. PacifiCorp's experience with natual
gas boilers has indicated somewhat higher heat rates than this estimate (13,000 to
15,000) at our Gadsby units but the value of 11,750 is considered possible with an
optimized design and the presence of supplemental heat from the incoming solar
fluids.
Recordholder:
Sponsor:
Jim Lacey
Jim Lacey
)P AC-E-11-07/Rocky Mountain Power
June 27, 2011
IPUC Production Data Request 6
IPUC Production Data Request 6
With regard to Action Item 6 on page 261, what is the capacity savings associated
with the 499,059 MWh savings from Class 2 DSM?
Response to IPUC Production Data Request 6
The Company calculates, during the integrated resource plan ("IRP") modeling
process, the approximate capacity impact of Class 2 demand-side management
("DSM") resource selections (forecasted energy savings from energy effciency
projects) based on the load shape of the resources selected (see page 257,2008
IRP Action Plan noting that for 430 to 480 average megawatts of energy
("aMW") equates to roughly 900 to 1 000 megawatts ("MW") of capacity
reduction). However, the Company doesn't explicitly compute, other than for
Class 2 DSM energy savings acquired within the business sectors (all states
except Oregon), the actual or realized impact of Class 2 DSM energy savings as
they are acquired. Using the energy to capacity conversion factor calculated
durng the development ofthe Company's 2008 IRP (roughly 2.08 MW per aMW
of acquired energy savings) as a proxy the capacity reduction resulting from
acquiring 499,059 megawatt hours of energy would equate to approximately 118
MWs.
Recordholder:
Sponsor:
Pete Waren
Pete Waren
PAC-E-11-07/Rocky Mountain Power
June 27, 2011
IPUC Production Data Request 7
IPUC Production Data Request 7
Please provide further explanation of how interrptible industrial loads are treated
in load forecasting. Are the interrptible products assumed to be available
through the planing horizon, and if so, at what cost?
Response to IPUC Production Data Request 7
Firm industrial loads with curilment contract provisions are treated in the load
forecast as if there was no interrption.
Curailment products are assumed to be available for the duration of the 20-year
planng horizon (2011 through 2030). They are modeled with no cost assigned
since they are treated as existing resources rather than future resource options.
They are dispatched by the IRP models up to the maximum fixed annual energy
limits assigned to each contract to the extent the contract decreases the overall
system cost.
Recordholder:
Sponsor:
Peter C. Eelkema / Rick Link
Peter C. Eelkema / Rick Link
P AC-E-11-07/Rocky Mountain Power
June 27, 2011
IPUC Production Data Request 8
IPUC Production Data Request 8
How does PacifiCorp address within the 2011 IRP the risk associated with the
loss of one or several interrptible products provided by industrial customers?
Response to IPUC Production Data Request 8
The 13% capacity planing reserve margin is intended to account for
unanticipated load changes. Although the loss of industrial interrptible products
is not explicitly modeled as a risk scenario, both the System Optimizer and
Planng and Risk production cost simulation modeling account for load
excursions above expected levels; the former on the basis of a high deterministic
load growth scenario, and the later on the basis of stochastic Monte Carlo random
sampling of daily loads.
Recordholder:
Sponsor:
Pete Warnen
Pete Waren