20120329Avista to Staff 1-6, 9-10.pdf

RECEIVED
2012 MAR 29 PM L 7
IDAHO PUE3L MWiMMISION
47IfISTir
Corp.
Wc Utilities Commission
•ashington Street
93702
Avista Corporation's Partial Response to First Production Request of the
Commission Staff to Avista Corporation
IPUC Case No. GNR-E-11-03
Dear Ms. Jewell:
Please find enclosed Avista Corporation's responses to requests 1-6, 9-10 of the First
Production Request of Commission Staff to Avista Corporation ("First Production Request") in
the above-referenced proceeding. Avista will respond to the remaining requests in the First
Production Request on or before April 9, 2012. Please let me know if you have any questions
regarding this filing.
Sincerely,
Michael G. Andrea
Senior Counsel
Enclosures
cc: Service List
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: IDAHO DATE PREPARED: 3/22/2012
CASE NO: GNR-E-1 1-03 WITNESS: Clint Kalich
REQUESTER: IPUC Staff RESPONDER: Clint Kalich
TYPE: Production Request DEPARTMENT: Energy Resources
REQUEST NO.: Staff-i TELEPHONE: [phone]
REQUEST:
In his direct testimony at page 10, lines 10-15, Mr. Kalich states,
When the utility is in a surplus position, it will not avoid any costs as a
result of the QF purchase; at most, the actual value of the QF purchase
to the utility is only the avoided fuel costs at existing facilities. A more
generous interpretation of the PURPA obligation is to compensate a QF
developer in times of system surplus at the market price received for the
sale of the energy net of delivery costs to a market trading hub.
In addition, he states the following at page 16 at lines 7-11:
Where no costs are avoided by the utility with the addition of a QF, the
QF does not reduce the utility's system costs. In the most basic
interpretation, the utility would pay nothing for QF power where no
costs were avoided; however, another policy position could be that
where a market exists for selling surplus energy from the QF, the QF is
paid the market value for its energy.
Finally, on page 27, lines 22-24, he states the following:
Q. What is the net value of the QF energy when the utility is surplus
and does not avoid any costs by its purchase?
A. The value should reflect the market.
Based on the testimony above, it does not appear that Avista has taken a firm position on whether
a QF should be compensated for energy delivered when the utility is energy surplus and when a
market exists for selling surplus energy. What is Avista's position in this circumstance?
RESPONSE:
While avoided costs should be made equal to those directly avoided on our electricity system,
Avista would not object to payments that reflect the market value of energy, net of delivery costs to
a market trading hub. Accordingly, were the Commission to decide that PURPA developers
should receive payments equal to the market value of energy, such payments should be reduced for
transmission costs associated with delivering the surplus QF power to a market hub, as proposed in
my direct testimony. Alternatively, the methodology proposed by Idaho Power Witness
Bokenkamp in his direct testimony beginning at line 1 of page 19, and continuing through line 8 of
page 22, would be acceptable to Avista.
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION:
CASE NO:
REQUESTER:
TYPE:
REQUEST NO.:
1117,11159[S
GNR-E-1 1-03
IPUC Staff
Production Request
Staff-2
DATE PREPARED:
WITNESS:
RESPONDER:
DEPARTMENT:
TELEPHONE:
3/22/2012
Clint Kalich
Clint Kalich
Energy Resources
[phone]
REQUEST:
In reference to the surplus energy condition described in Request No. 1, Idaho Power witness
Bokenkamp, at page 14 line 21 through page 15, line 14 of his direct testimony maintains that there
are times when the incremental cost with Idaho Power's proposed methodology goes to zero. Does
Avista believe there may be times when QF power delivered to its own system would have zero
value? Does Avista agree with the methodology proposed by Idaho Power for determining the
energy value of power delivered by QFs, particularly during surplus energy periods? If not, please
explain why.
RESPONSE:
Avista agrees that there will be times where QF power has zero or negative value. The examples
provided by Mr. Bokenkamp are reasonable. While there are many possible approaches for fairly
compensating QF developers, the methodology proposed by Mr. Bokenkamp, starting at line 1 of
page 19, and ending at line 8 of page 22, would be acceptable for determining avoided costs under
the IRP methodology for non-published rate applications.
The only concern/modification Avista would have to Idaho Power's proposal when applied to the
IRP method is that when in a surplus position, a resource other than a thermal resource (e.g.,
hydro) could be displaced. Payments to QF resources should therefore reflect the marginal
resource, irrespective of its fuel.
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: IDAHO
CASE NO: GNR-E-1 1-03
REQUESTER: IPUC Staff
TYPE: Production Request
REQUEST NO.: Staff-3
DATE PREPARED: 3/22/2012
WITNESS: Clint Kalich
RESPONDER: Clint Kalich
DEPARTMENT: Energy Resources
TELEPHONE: [phone]
REQUEST:
Avista proposes to continue limiting published rate eligibility for wind and solar generation to 100
kW, and to 10 aMW for all other resource types. Please compute the avoided cost rates for the
solar, wind, geothermal, and hydro sample projects analyzed previously in this proceeding using
both the IRP methodology and the SAR methodology as proposed by Avista for project sizes of
100 kW for wind and solar and 10 aMW for the other project types. Please compare the rates
computed under each methodology for each corresponding resource type. Discuss the
reasonableness of any substantial price differences that may be attributable to differences in the
methodologies. To the extent possible, use comparable assumptions for the analysis under each
methodology (fuel prices, plant costs, O&M costs, etc.).
RESPONSE:
The following table details the rates using the SAR methodology with Avista-proposed changes
and Avista's IRP Methodology. The rates are substantially similar using either methodology.
2013 QF Prices
20-Year Levelized $/MWh
Resource SAR IRP Difference
Geothermal 56.04 55.42 -0.62
Canal Hydro 46.56 45.45 -1.11
Solar 36.62 38.08 1.46
Wind 34.75 37.07 2.32
To arrive at comparable values, and as directed by the production request, the following key
assumptions were updated in the SAR model for consistency. In other words, the SAR model
assumptions were changed to equal the IRP Methodology assumptions. The largest difference is in
fixed O&M costs. This difference results from the fact that Avista' s IRP includes fixed O&M
costs for firm natural gas transportation (—$15/kW-year) and electrical interconnection
($ 1 5/k W-yr). These costs have in the past not been included in the SAR model.
Assumption SAR IRP % Difference
2012-30 Nominal Levelized Gas Price 6.03 5.70 -5.5%
CCCT Capital Cost (2008$) 1,313 1,028 -21.7%
Variable O&M Cost (2008 $/MWh) 1.77 1.98 11.9%
Fixed O&M Cost (2008 $IkW-year) 1 14.571 49.101 237.0%
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: IDAHO DATE PREPARED: 3/22/2012
CASE NO: GNR-E-1 1-03 WITNESS: Clint Kalich
REQUESTER: IPUC Staff RESPONDER: Clint Kalich
TYPE: Production Request DEPARTMENT: Energy Resources
REQUEST NO.: Staff-4 TELEPHONE: [phone]
REQUEST:
Mr. Kalich's direct testimony does not explain the details of how Avista proposes to compute the
energy component of avoided cost rates under the IRP methodology, however, based on its
presentation at the December 15, 2011 meeting to discuss and present IRP models, Staff
understands that Avista's proposed method uses both the Aurora model and Avista's PRISM
model. If Avista's proposed methodology is accepted by the Commission, please explain whether
and how Commission Staff and developers would have access to the PRiSM model to review
Avista's assumptions and computations. Please identify any additional software needed to run the
PRiSM model.
RESPONSE:
PRiSM is a proprietary model of Avista. It has been used in IRPs for nearly 10 years. Avista is not
proposing that it be used by Idaho Power or Rocky Mountain Power. Given its reliance on a 3rd
party software vendor (WhatsBest! by Lindo Systems) for the linear programming algorithm, the
best solution would be to provide the Commission and interested developers access to the
software, either on-site at Avista headquarters in Spokane, or through using our computer systems
combined with internet technology enabling 3rd party remote operation of our software.
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: IDAHO DATE PREPARED: 3/22/2012
CASE NO: GNR-E-1 1-03 WITNESS: Clint Kalich
REQUESTER: IPUC Staff RESPONDER: Clint Kalich
TYPE: Production Request DEPARTMENT: Energy Resources
REQUEST NO.: Staff-5 TELEPHONE: [phone]
REQUEST:
In his direct testimony at page 22, Table 3, and also at page 25, Table 4, Mr. Kalich computes the
annual capacity payment that would be made under his proposed method for various resource
types. In his example, the annual capacity payment for geothermal and canal hydro would be
equal to the annual capacity cost of the SAR ($206,000/MW). Does Avista believe that one MW
of capacity from a geothermal or canal hydro QF would have the same value as one MW of
capacity from a CCCT, considering that a CCCT is fully dispatchable while a geothermal or canal
hydro QF would not be dispatchable? If Avista agrees that dispatchability has some value, is the
value of it (or lack of value in this case) reflected in Avista's proposed method for determining
avoided cost rates?
RESPONSE:
Avista does not believe that the capacity from a geothermal or canal hydro QF has the same value
as a utility-controlled CCCT. The current SAR does not account for the lack of dispatchability.
Avista presently is building tools to assist it in estimating this value difference, but results likely
will not be available within the timeframe of this proceeding. Avista' s proposed method does not
account for the difference. In any event, introducing such a discount would entail calculations
external to the SAR model where the energy payments in any given hour would be capped at the
wholesale market price. In other words, when the wholesale market price fell below the fuel and
variable operating costs of the SAR resource in a given hour, the market price would be used for
valuing QF power in such hours rather than the operating costs of the SAR.
Even with this approach, the SAR would not capture 100% of the dispatch value because a
utility-owned CCCT can provide operating and other reserve products (e.g., wind integration).
However, this approach would capture the majority of the dispatchability value.
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: IDAHO DATE PREPARED: 3/22/2012
CASE NO: GNR-E-1 1-03 WITNESS: Clint Kalich
REQUESTER: IPUC Staff RESPONDER: Clint Kalich
TYPE: Production Request DEPARTMENT: Energy Resources
REQUEST NO.: Staff-6 TELEPHONE: [phone]
REQUEST:
In his direct testimony beginning on page 27, line 9 and continuing to page 30, line 12, Mr. Kalich
recommends that QF developers receive lower energy payments during utility surplus periods to
reflect the costs of transmitting surplus power to market. When Avista builds a new generation
resource or acquires new generation through a PPA, does it reserve transmission for the purpose of
moving surplus generation from the plant to market? Once the Palouse Wind project is completed
and Avista begins taking power under a PPA, does Avista anticipate that there will be times when
Avista will be forced to take power from the project when Avista is surplus, and consequently be
forced to move the surplus generation to market?
RESPONSE:
When Avista builds a new generation resource or acquires new generation through a PPA a
transmission path is not always required; however, if the resource is off-system and the power will
serve native load, a transmission reservation is made. This is because we generally consider
off-system resources "firm" only if paired with firm transmission. Surplus power does not require
firm transmission because transmission generally is not required to ensure system reliability. The
resource (or another resource) can be backed down or shut down to maintain system reliability.
Once the Palouse Wind project is completed, Avista does anticipate there will be times when we
will accept electricity when we are surplus. A transmission path is required to move the excess
system power to the wholesale marketplace. However, we have contractual rights to interrupt the
Palouse Wind project and not take its power, when there is no transmission path.
It is important to distinguish between a dispatchable utility resource and a QF purchase. Under
existing PURPA rules, Avista is obligated to pay QF developers for power during all hours,
irrespective of its need. The payment is locked in ahead of time and the QF developer benefits
from price certainty. This is very different from non-QF contracts like Palouse Wind. In the case
of Palouse Wind, the output can be curtailed. The QF, on the other hand, continues to receive a
guaranteed payment based on assumed avoided cost rates, and takes no delivery risk. If Avista's
customers must accept the delivery and price risk, a transmission path to ensure delivery of the
excess system power to the wholesale marketplace is required.
,%,4 &IS[OU1IAI
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: IDAHO DATE PREPARED: 3/22/2012
CASE NO: GNR-E-1 1-03 WITNESS: Clint Kalich
REQUESTER: IPUC Staff RESPONDER: Clint Kalich
TYPE: Production Request DEPARTMENT: Energy Resources
REQUEST NO.: Staff-9 TELEPHONE: [phone]
REQUEST:
In his direct testimony at page 34, lines 1-19, Mr. Kalich recommends that SAR gas prices should
be updated annually using the Energy Information Administration's Annual Energy Outlook.
Using the 2011 Annual Energy Outlook (or the 2012 AEO if it becomes available before the
response to this request is due), please identify exactly which prices Avista proposes be used.
Please specify the AEO table and page number where the data can be found. Please also include
the data description and the actual data values for each year of the forecast.
RESPONSE:
The 2012 Annual Energy Outlook is presently available. Table 19 of that report provides a
forecast of natural gas prices for the Pacific Northwest region's electric power sector and is the
forecast Avista recommends the Commission use. This table may be found at the following URL:
http://www.eia.gov/oiaf/aeo/supplement/suptabl 9 .xlsx. Reference line 52 in the link's
spreadsheet. It is attached in the file "AE020 12_Table_i 9.xlsx.
ref2012.0210111b 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Report Annual Energy Outlook 2012 Early Release
Scenario ref2012 Reference case
Datekey d121011b
Release Date January 2012
19. Energy Prices by Sector and Source
(2010 dollars per million Btu, unless otherwise noted)
Pacific-09
Sector and Source 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Residential
Liquefied Petroleum Gases 29.02 30.34 32.94 32.33 31.67 32.27 32.75 32.43 32.75 32.96 33.14 33.29 33.48 33.75 33.99 34.20 34.40
Distillate Fuel Oil 18.39 21.70 26.94 27.15 23.67 24.50 25.59 26.07 26.42 26.44 26.68 26.90 27.23 27.39 27.74 28.23 28.61
Natural Gas 10.31 10.21 9.62 9.96 9.72 9.36 9.58 9.71 9.92 10.18 10.36 10.50 10.87 11.27 11.48 11.59 11.64
Electricity 36.01 36.06 36.42 36.35 36.58 36.32 36.46 36.22 36.14 36.06 35.97 36.49 36.98 37.16 37.09 36.83 36.63
Commercial
Liquefied Petroleum Gases 22.64 24.46 23.89 23.36 25.57 26.17 26.65 26.33 26.65 26.86 27.04 27.18 27.38 27.65 27.89 28.10 28.30
Distillate Fuel Oil 16.69 21.30 26.46 26.67 21.31 22.26 23.38 23.90 24.24 24.20 24.52 24.74 25.03 25.17 25.56 26.17 26.65
Residual Fuel 10.59 11.84 16.73 17.00 16.74 17.80 18.77 19.03 19.31 19.38 19.60 19.85 19.97 20.33 20.63 20.75 20.87
Natural Gas 8.89 8.85 8.60 8.83 8.61 8.39 8.61 8.74 8.94 9.20 9.39 9.55 9.93 10.33 10.55 10.66 10.70
Electricity 34.66 33.95 33.81 33.57 33.27 32.77 32.78 32.63 32.60 32.62 32.63 33.39 34.25 34.63 34.72 34.67 34.64
Industrial 1/
Liquefied Petroleum Gases 24.77 26.91 28.91 28.61 35.72 36.49 37.12 36.70 37.12 37.40 37.63 37.81 38.07 38.41 38.73 39.00 39.26
Distillate Fuel Oil 16.76 21.13 26.24 26.45 21.86 22.90 24.05 24.60 24.95 24.87 25.24 25.47 25.73 25.86 26.29 26.99 27.55
Residual Fuel Oil 14.76 11.81 16.68 16.95 16.74 17.80 18.77 19.03 19.31 19.38 19.80 19.85 19.97 20.33 20.63 20.75 20.87
Natural Gas 2/ 5.77 5.95 5.22 4.82 4.83 4.87 5.04 5.11 5.28 5.48 5.62 5.71 6.03 6.38 6.54 6.63 6.64
Metallurgical Coal - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
Other Industrial Coal 3.52 3.47 3.64 3.67 3.61 3.66 3.69 3.68 3.73 3.79 3.83 3.88 3.91 3.96 4.01 4.06 4.09
Coal to Liquids - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
Electricity 23.20 21.90 20.58 20.68 20.23 19.84 19.85 19.77 19.91 20.05 20.14 20.80 21.38 21.71 21.91 21.85 21.92
Transportation
Liquefied Petroleum Gases 3/ 24.99 29.51 31.98 31.40 30.08 30.67 31.15 30.83 31.14 31.35 31.52 31.66 31.85 32.11 32.35 32.55 32.75
E854/ 23.60 26.60 33.65 32.53 28.78 29.63 30.80 31.33 30.49 30.57 28.32 27.81 27.80 27.64 31.46 32.23 32.91
Motor Gasoline 5/ 20.38 23.70 29.57 28.59 27.82 28.67 29.68 30.21 31.22 31.26 32.38 34.26 34.46 34.55 32.41 32.67 33.19
Jet Fuel 6/ 12.63 16.08 22.13 21.54 21.42 22.22 23.31 23.96 24.30 24.35 24.68 24.89 25.08 25.28 25.54 26.11 26.51
Diesel Fuel (distillate fuel oil) 7/ 18.12 22.02 27.92 27.54 26.54 27.66 28.98 29.74 30.34 30.68 31.32 31.96 32.17 32.28 32.72 32.88 32.81
Residual Fuel Oil 10.59 13.68 19.30 19.62 18.47 19.53 20.51 20.75 21.04 21.10 21.33 21.58 21.70 22.06 22.36 22.68 22.95
Natural Gas 8/ 12.11 11.07 10.35 9.95 9.97 9.98 10.12 10.16 10.30 10.46 10.57 10.62 10.90 11.20 11.33 11.39 11.38
Electricity 29.90 30.02 28.89 28.62 28.12 27.48 27.30 26.99 26.83 26.67 26.54 27.19 28.01 29.11 29.93 30.41 30.93
Electric Power 9/
Distillate Fuel Oil 14.76 18.60 23.09 23.28 19.23 20.04 21.12 21.58 21.92 21.94 22.17 22.38 22.71 22.86 23.20 23.69 24.07
Residual Fuel Oil 10.40 15.25 21.65 20.84 25.23 26.28 27.26 27.51 27.79 27.86 28.09 28.34 28.45 28.82 29.11 29.34 29.54
Natural Gas 4.47 4.82 4.08 3.90 3.71 3.60 3.78 3.86 4.02 4.25 4.41 4.48 4.80 5.14 5.31 5.38 5.37
Steam Coal 2.03 1.99 2.12 2.15 2.21 2.29 2.59 2.37 2.42 2.41 2.44 2.47 2.51 2.53 2.56 2.59 2.61
Average Price to All Users 101
Liquefied Petroleum Gases 23.79 25.59 27.61 27.26 27.54 28.00 28.39 27.98 28.21 28.26 28.40 28.46 28.56 28.77 28.88 29.03 29.20
E8541 23.60 26.60 33.65 32.53 28.78 29.63 30.80 31.33 30.49 30.57 28.32 27.81 27.80 27.64 31.46 32.23 32.91
Motor Gasoline 5/ 20.36 23.64 29.46 28.53 27.82 28.67 29.68 30.21 31.22 31.26 32.38 34.26 34.46 34.55 32.41 32.67 33.19
Jet Fuel 12.63 16.08 22.13 21.54 21.42 22.22 23.31 23.96 24.30 24.35 24.68 24.89 25.08 25.28 25.54 26.11 26.51
Distillate Fuel Oil 17.84 21.84 27.58 27.33 25.71 26.84 28.13 28.86 29.42 29.70 30.33 30.89 31.12 31.25 31.68 31.93 31.96
Residual Fuel Oil 10.61 13.97 19.78 19.84 19.91 20.93 21.91 22.17 22.46 22.54 22.77 23.03 23.15 23.52 23.82 24.13 24.39
Natural Gas 8.69 6.92 6.35 6.18 6.07 5.94 6.12 6.23 6.37 6.60 6.73 6.88 7.22 7.58 7.76 7.84 7.87
Metallurgical Coal - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
Other Coal 2.42 2.33 2.47 2.49 2.58 2.71 3.03 2.79 2.84 2.74 2.76 2.81 2.90 2.93 2.97 3.00 3.03
Coal to Liquids - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
Electricity 32.71 32.16 31.98 31.93 31.69 31.23 31.22 31.02 31.00 31.01 31.01 31.67 32.36 32.66 32.74 32.65 32.60
Non-Renewable Energy Expenditures by Sector
(billion 2010 dollars)
Residential 26.87 26.57 27.25 27.48 26.52 26.07 26.22 26.21 26.44 26.71 26.94 27.34 27.93 28.38 28.63 28.77 28.90
Commercial 24.81 24.15 24.43 24.21 24.02 23.93 24.33 24.61 25.01 25.46 25.89 26.73 27.71 28.36 28.81 29.19 29.57
Industrial 14.73 14.14 14.22 13.75 13.54 14.33 15.15 15.58 16.07 16.36 16.62 16.97 17.40 17.76 17.90 18.06 18.21
Transportation 76.77 94.24 117.69 115.53 113.49 118.45 123.67 126.89 127.55 125.92 127.13 131.34 131.71 132.01 129.49 132.57 135.09
Total Non-Renewable Expenditures 143.19 159.09 183.59 180.99 177.57 182.78 189.37 193.29 195.07 194.44 196.57 202.38 204.74 206.51 204.84 208.58 211.77
Transportation Renewable Expenditures 0.01 0.01 0.02 0.02 0.02 0.03 0.03 0.03 2.96 5.11 6.74 7.03 7.44 7.81 7.96 6.70 6.31
Total Expenditures 143.20 159.11 183.60 181.00 177.59 182.81 189.40 193.33 198.04 199.55 203.31 209.41 212.19 214.32 212.79 215.28 218.09
Prices in Nominal Dollars
Residential
Liquefied Petroleum Gases 28.69 30.34 33.60 33.28 32.95 34.14 35.30 35.65 36.69 37.64 38.60 39.55 40.59 41.75 42.91 44.06 45.22
Distillate Fuel Oil 18.18 21.70 27.48 27.95 24.62 25.92 27.59 28.65 29.59 30.19 31.07 31.97 33.01 33.89 35.01 36.37 37.60
Natural Gas 10.19 10.21 9.81 10.26 10.11 9.90 10.33 10.67 11.12 11.62 12.07 12.48 13.18 13.94 14.49 14.94 15.30
Electricity 35.60 36.06 37.14 37.43 38.06 38.43 39.29 39.81 40.48 41.17 41.89 43.36 44.84 45.97 46.82 47.46 48.15
Commercial
Liquefied Petroleum Gases 2238 24.46 24.37 24.05 26.60 27.68 28.72 28.94 29.86 30.67 31.49 32.30 33.19 34.20 35.20 36.20 37.20
Distillate Fuel Oil 16.50 21.30 26.99 27.46 22.17 23.55 25.19 26.26 27.15 27.64 28.55 29.40 30.34 31.14 32.27 33.72 35.03
Residual Fuel 10.47 11.84 17.06 17.51 17.42 18.83 20.24 20.91 21.63 22.13 22.83 23.59 24.21 25.15 26.04 26.74 27.43
Natural Gas 8.79 8.85 8.78 9.09 8.96 8.88 9.27 9.60 10.02 10.51 10.94 11.35 12.04 12.78 13.32 13.73 14.06
Electricity 34.26 33.95 34.48 34.57 34.61 34.67 35.33 35.86 36.52 37.25 38.00 39.67 41.53 42.84 43.83 44.67 45.53
Industrial 1/
Liquefied Petroleum Gases 24.48 26.91 29.49 29.45 37.15 38.60 40.00 40.34 41.58 42.70 43.82 44.93 46.15 47.53 48.89 50.25 51.61
Distillate Fuel Oil 16.57 21.13 26.76 27.23 22.74 24.22 25.92 27.04 27.94 28.39 29.40 30.27 31.19 32.00 33.19 34.78 36.21
Residual Fuel Oil 14.59 11.81 17.01 17.45 17.42 18.83 20.24 20.91 21.63 22.13 22.83 23.59 24.21 25.15 26.04 28.74 27.43
Natural Gas 2/ 5.71 5.95 5.33 4.96 5.03 5.15 5.43 5.62 5.91 6.26 6.55 6.79 7.32 7.89 8.26 8.54 8.72
Metallurgical Coat - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
Other Industrial Coal 3.48 3.47 3.71 3.78 3.75 3.86 3.98 4.05 4.18 4.33 4.46 4.61 4.74 4.90 5.07 5.23 5.38
Coal to Liquids - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
Electricity 22.94 21.90 20.99 21.29 21.05 20.99 21.39 21.73 22.30 22.89 23.45 24.71 25.92 26.86 27.66 28.14 28.81
Transportation
Liquefied Petroleum Gases 3/
E85 4/
Motor Gasoline 5/
Jet Fuel 6/
Diesel Fuel (distillate fuel oil) 7/
Residual Fuel Oil
Natural Gas 81
Electricity
Electric Power 91
Distillate Fuel Oil
Residual Fuel Oil
Natural Gas
Steam Coal
Average Price to All Users 101
Liquefied Petroleum Gases
E85 4/
Motor Gasoline 5/
Jet Fuel
Distillate Fuel Oil
Residual Fuel Oil
Natural Gas
Metallurgical Coal
Other Coal
Coal to Liquids
Electricity
Non-Renewable Energy Expenditures by Sector
(billion nominal dollars)
Residential
Commercial
Industrial
Transportation
Total Non-Renewable Expenditures
Transportation Renewable Expenditures
Total Expenditures
24.70 29.51 32.62 32.33 31.29 32.45 33.57 33.88 34.88 35.79 36.71 37.62 38.61 39.73 40.83 41.94 43.05
23.33 26.60 34.32 33.50 29.93 31.34 33.19 34.44 34.15 34.91 32.99 33.05 33.71 34.19 39.72 41.53 43.26
20.15 23.70 30.15 29.44 28.93 30.33 31.99 33.21 34.97 35.69 37.71 40.71 41.78 42.75 40.91 42.09 43.63
12.49 16.08 22.57 22.18 22.29 23.51 25.12 26.33 27.22 27.80 28.74 29.58 30.41 31.28 32.24 33.64 34.85
17.91 22.02 28.48 28.36 27.60 29.26 31.24 32.69 33.98 35.03 36.47 37.97 39.00 39.94 41.30 42.36 43.13
10.47 13.68 19.68 20.21 19.22 20.66 22.10 22.81 23.56 24.10 24.84 25.65 26.31 27.30 28.23 29.22 30.17
11.97 11.07 10.56 10.25 10.37 10.56 10.91 11.17 11.53 11.95 12.31 12.62 13.21 13.86 14.30 14.67 14.96
29.56 30.02 29.46 29.47 29.25 29.08 29.42 29.66 30.05 30.45 30.91 32.31 33.95 36.01 37.78 39.18 40.65
14.59 18.60 23.55 23.97 20.00 21.20 22.76 23.72 24.56 25.05 25.81 26.59 27.53 28.28 29.28 30.52 31.64
10.28 15.25 22.08 21.46 26.24 27.80 29.38 30.23 31.13 31.81 32.71 33.67 34.49 35.65 36.75 37.80 38.83
4.42 4.82 4.16 4.01 3.86 3.80 4.08 4.24 4.51 4.85 5.13 5.33 5.81 6.36 6.70 6.93 7.06
2.01 1.99 2.17 2.22 2.30 2.42 2.79 2.60 2.71 2.75 2.84 2.94 3.04 3.13 3.24 3.34 3.43
23.51 25.59 28.16 28.07 28.65 29.63 30.60 30.75 31.60 32.27 33.07 33.82 34.63 35.59 36.45 37.41 38.38
23.33 26.60 34.32 33.50 29.93 31.34 33.19 34.44 34.15 34.91 32.99 33.05 33.71 34.19 39.72 41.63 43.26
20.12 23.64 30.05 29.37 28.93 30.33 31.99 33.21 34.97 35.69 37.71 40.71 41.78 42.75 40.91 42.09 43.63
12.49 16.08 22.57 22.18 22.29 23.51 25.12 26.33 27.22 27.80 28.74 29.58 30.41 31.28 32.24 33.64 34.85
17.64 21.84 28.13 28.15 26.74 26.39 30.31 31.72 32.96 33.92 35.32 36.70 37.73 38.66 40.00 41.13 42.01
10.48 13.97 20.18 20.43 20.71 22.14 23.62 24.36 25.16 25.73 26.52 27.37 28.06 29.10 30.07 31.08 32.07
6.61 6.92 6.47 6.36 6.31 6.29 6.60 6.85 7.14 7.54 7.83 8.17 8.75 9.37 9.80 10.11 10.35
2.39 2.33 2.52 2.66 2.69 2.86 3.26 3.06 3.18 3.13 3.22 3.34 3.52 3.62 3.75 3.86 3.98
32.34 32.16 32.62 32.88 32.97 33.03 33.65 34.10 34.73 35.41 36.12 37.64 39.23 40.41 41.33 42.06 42.85
26.57 26.57 27.79 28.30 27.58 27.58 28.26 28.80 29.62 30.49 31.37 32.49 33.86 35.11 36.14 37.06 37.99
24.53 24.15 24.92 24.93 24.99 25.32 26.23 27.05 28.02 29.07 30.15 31.77 33.59 35.09 36.37 37.60 38.87
14.56 14.14 14.50 14.16 14.08 15.17 16.33 17.12 18.00 18.68 19.35 20.16 21.09 21.97 22.60 23.27 23.94
75.89 94.24 120.04 118.96 118.05 125.31 133.29 139.47 142.88 143.78 148.05 156.07 159.68 163.32 163.46 170.79 177.57
141.55 159.09 167.24 186.36 184.71 193.37 204.11 212.44 218.52 222.02 228.93 240.49 248.22 255.50 258.58 268.72 278.37
0.01 0.01 0.02 0.02 0.02 0.03 0.03 0.04 3.32 5.84 7.85 8.36 9.02 9.66 10.05 8.64 8.30
141.56 159.11 187.26 186.37 184.73 193.40 204.14 212.48 221.84 227.86 236.77 248.85 257.24 265.16 268.62 277.36 286.67
1/ Includes energy for combined beat and power plants, except those whose primary business is to sell electricity, or electricity and heat,
to the public.
21 Excludes use for lease and plant fuel.
31 Includes Federal and Stale taxes while excluding county and local taxes.
4/ E85 refers to a blend of 55 percent ethanol (renewable) and 15 percent motor gasoline (nonrenewable). To address cold starling issues,
the percentage of ethanol nodes seasonally. The annual average ethanol content of 74 percent is used for thie forecast.
/ Sales weighted-average price for all grades. Includes Federal, State, and local taxes.
6/Kerosene-type jet feel. Includes Federal and State taxes while excluding county and local taxes.
71 Oiesel fuel for on-road use. Includes Federal and State taxes while excluding county and local taxes.
B/ Compressed natural gas used as a vehicle fuel. Includes estimated motor vehicle fuel taxes and estimated dispensing costs or charges.
9/ Includes electricity-only and combined heat and power plants whose primary business is to sell electricity, or electricity and heat, to the
public.
10/ Weighted averages of end-use fuel prices are derived from the prices shown in each Sector and the corresponding sectoral consumption.
Bra = British thermal unit.
- - Not applicable.
Note: Data for 2009 and 2010 are model results and may differ slightly from official EIA data reports.
Sources: 2009 and 2010 prices for motor gasoline, distillate fuel oil, and jet fuel are based on prices
in the U.S. Energy Information Administration (EtA). Petroleum Marketing Annual
2009, DOE/ElA-0487(2009) (Washington, DC, August 2010).
2009 residential and commercial natural gas delivered prices: EIA,
Natural Gas Annual 2009 DQE/EIA-0131(2009) (Washington, DC, December 2010). 2010 residential and commercial natural gas
delivered prices: EIA, Natural Gas Monthly, DOE/EIA-0130(2011107) (Washington, DC, July 2011).
2009 and 2010
industrial natural gas delivered prices are estimated based on: EIA, Manufacturing Energy Consumption Survey and
industrial and wellhead prices from the Natural Gas Annual 2009, DOE/EIA-0131(2009) (Washington, DC, December 2010)
and the Natural Gas Monthly, DOE/EIA-0130(201 1107) (Washington, DC, July 2011).
2009 transportation sector natural gas delivered prices are based on: EtA, Natural Gas Annual
2009, DOEJSIA-0131 (2009) (Washington, DC, December 2010) and estimated State taxes, Federal taxes, and dispensing Casts or charges.
2010 transportation sector natural gas delivered prices are model results.
2009 and 2010 electric power prices based on: EIA, Monthly Energy Review, DOE/EIA-0035(201 0/09)
(Washington, DC, September 2010). 2009 and 2010 E85 prices
2009 and 2010 electric power sector natural gas prices: EIA. Electric Power Monthly,
April 2010 and April 2011, Table 4.2, and EtA, State Energy Data System
2009, DOE/EIA-0214(2009) (Washington, DC, Jane 2011).
2009 and 2010 coal prices based no: EIA, Quarterly Coat Report,
October-December 2010, DOEIEIA-0121(2010/4Q) (Washington, DC, May 2011) and EIA,AE02012 National Energy Modeling System me ref2012.d121011b.
2009 and 2010 electricity prices: EtA, Annual Energy Review
2010. DOEIEIA-0384(2010) (Washington, DC. October 2011).
2009 and 2010 E85 prices derived from monthly prices in the Clean Cities
Alternative Fuel Price Report. Projections: EIA, AE02012 National Energy Modeling System run ret2012.d121011b.
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5.54 5.64 5.69 5.72 5.81 6.09 6.31 6.54 6.71 6.97 1.5%
2.64 2.66 2.68 2.70 2.73 2.75 2.78 2.81 2.84 2.87 1.5%
29.38 29.57 29.64 29.73 29.89 30.06 30.29 30.47 30.68 30.91 0.8%
33.04 33.07 33.03 33.58 34.22 33.77 34.06 34.54 34.81 35.08 1.1%
33.24 33.45 33.66 34.03 34.52 33.92 34.12 34.36 34.58 34.84 1.6%
26.78 26.95 27.18 27.41 27.73 28.01 28.35 28.56 28.80 29.01 2.4%
31.99 32.28 32.50 32.78 33.16 32.67 32.81 32.57 32.71 33.00 1.7%
24.64 24.85 25.09 25.22 25.27 25.38 25.17 25.10 25.24 25.40 2.4%
8.03 8.12 8.16 8.16 8.22 8.41 8.59 8.79 8.97 9.22 1.2%
3.06 3.09 3.11 3.14 3.17 3.20 3.23 3.27 3.30 3.33 1.4%
32.51 32.02 31.34 30.95 30.65 30.33 30.16 30.15 30.22 30.65 -0.2%
29.15 29.19 29.10 29.11 29.20 29.37 29.58 29.86 30.20 30.81 0.6%
29.94 29.96 29.81 29.90 30.10 30.30 30.63 31.08 31.61 32.45 1.2%
18.42 18.43 18.34 18.30 18.38 18.45 18.62 18.73 18.96 19.37 1.3%
136.25 136.58 136.66 139.29 142.58 143.05 145.29 148.20 150.53 152.90 2.0%
213.76 214.16 213.91 216.60 220.25 221.17 224.12 227.87 231.30 235.53 1.6%
6.15 7.40 8.90 8.42 7.90 7.01 6.69 5.27 4.99 4.99 27.3%
219.91 221.56 222.81 225.02 228.15 228.18 230.81 233.15 236.29 240.52 1.7%
46.46 47.70 48.82 49.93 51.17 52.54 53.92 55.22 56.63 58.07 2.6%
38.87 39.93 41.08 42.07 43.06 4421 45.35 45.24 46.26 47.52 3.2%
15.88 16.38 16.80 17.17 17.86 18.39 19.09 19.79 20.48 21.29 3.0%
48.85 49.10 49.07 49.37 49.77 50.11 50.65 51.42 52.38 53.97 1.6%
38.28 39.35 40.31 41.26 42.32 43.53 44.74 45.88 47.11 48.38 2.8%
36.33 37.40 38.52 39.56 40.71 41.27 42.32 42.48 43.45 44.66 3.0%
28.08 28.89 29.66 30.32 31.07 31.30 31.33 32.89 33.94 34.93 4.4%
14.60 15.04 15.43 15.75 16.20 16.86 17.52 18.19 18.85 19.63 3.2%
46.30 46.40 46.10 46.32 46.69 46.98 47.51 48.30 49.23 50.72 1.6%
53.08 54.54 55.85 57.15 58.61 60.25 61.89 63.43 65.10 66.82 3.7%
37.58 38.74 39.89 41.04 42.36 42.57 43.60 44.03 45.03 46.26 3.2%
28.08 28.89 29.66 30.32 31.07 31.30 31.33 32.89 33.94 34.93 4.4%
9.11 9.44 9.68 9.86 10.15 10.67 11.16 11.66 12.12 12.72 3.1%
5.56 5.73 5.91 6.09 6.28 6.44 6.61 6.79 6.96 7.13 2.9%
29.42 29.59 29.59 29.90 30.29 30.66 31.32 32.04 32.85 34.11 1.8%
44.24 45.43 46.50 47.56 48.74 50.07 51.39 52.64 53.99 55.38 2.5%
44.31 45.24 46.06 47.74 49.60 49.87 51.23 52.91 54.30 55.68 3.0%
44.57 45.76 46.94 48.38 50.02 50.08 51.33 52.62 53.93 55.30 3.4%
35.92 36.86 37.90 38.97 40.19 41.37 42.65 43.75 44.92 46.05 4.3%
43.94 45.21 46.38 47.67 49.18 49.31 50.42 50.97 52.13 53.52 3.6%
31.13 32.02 32.99 33.81 34.51 35.38 35.74 36.13 36.94 37.83 4.2%
15.42 15.87 16.20 16.46 16.84 17.44 18.02 18.60 19.14 19.82 2.4%
42.09 43.00 43.53 44.40 45.38 46.30 47.25 48.57 49.90 51.75 2.2%
32.78 33.71 34.74 35.60 36.46 37.49 38.51 38.28 39.17 40.30 3.1%
39.84 40.90 41.97 42.93 43.86 44.64 45.05 46.20 47.33 48.48 4.7%
7.43 7.71 7.94 8.13 8.42 8.99 9.50 10.01 10.47 11.06 3.4%
3.54 3.64 3.74 3.84 3.96 4.06 4.18 4.31 4.44 4.56 3.4%
39.40 40.44 41.34 42.26 43.33 44.39 45.56 46.67 47.86 49.07 2.6%
44.31 45.24 46.06 47.74 49.60 49.87 51.23 52.91 54.30 55.68 3.0%
44.57 45.76 46.94 48.38 50.02 50.08 51.33 52.62 53.93 55.30 3.5%
35.92 36.86 37.90 38.97 40.19 41.37 42.65 43.75 44.92 46.05 4.3%
42.90 44.15 45.33 46.60 48.06 48.25 49.36 49.89 51.02 52.38 3.6%
33.04 33.99 34.99 35.86 36.63 37.48 37.87 38.45 39.36 40.32 4.3%
10.77 11.11 11.38 11.60 11.92 12.41 12.92 13.46 14.00 14.64 3.0%
4.10 4.22 4.34 4.46 4.60 4.72 4.86 5.01 5.15 5.29 3.3%
43.60 43.80 43.70 44.01 44.43 44.78 45.37 46.19 47.13 48.64 1.7%
39.09 39.93 40.59 41.38 42.31 43.37 44.50 45.74 47.10 48.91 2.5%
40.15 40.98 41.58 42.52 43.63 44.74 46.07 47.61 49.30 51.51 3.1%
24.70 25.20 25.57 26.02 26.64 27.25 28.01 28.68 29.57 30.74 3.2%
182.73 186.82 190.59 198.05 206.65 211.24 218.56 227.01 234.79 242.71 3.9%
286.67 292.93 298.32 307.97 319.22 326.61 337.14 349.04 360.76 373.87 3.5%
8.25 10.12 12.42 11.97 11.45 10.35 10.07 8.08 7.78 7.91 29.7%
294.91 303.05 310.74 319.94 330.67 336.95 347.21 357.12 368.54 381.78 3.6%
ref2Ol2.dl21011b 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Report Annual Energy Outlook 2012 Early Release
Scenario ref2012 Reference case
Datekey d121011b
Release Date January 2012
20. Macroeconomic Indicators
(billion 2005 chain-weighted dollars, unless otherwise noted)
Indicators 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Real Gross Domestic Product 12703 13088 13291 13572 13916 14398 14870 15343 15768 16162 16566 16954 17348 17783 18225 18692 19176
Components of Real Gross Domestic Product
Real Consumption 9037 9221 9401 9578 9775 9989 10216 10461 10684 10893 11110 11326 11561 11824 12095 12381 12687
Real Investment 1454 1715 1781 1886 2019 2273 2449 2593 2701 2767 2849 2922 2986 3074 3179 3302 3427
Real Government Spending 2540 2557 2494 2430 2382 2361 2358 2363 2376 2389 2399 2411 2415 2431 2455 2481 2507
Real Exports 1494 1663 1797 1937 2095 2261 2434 2617 2802 2992 3191 3389 3600 3818 4024 4239 4461
Real Imports 1853 2085 2189 2239 2339 2446 2531 2621 2712 2787 2878 2972 3077 3205 3346 3503 3669
Energy Intensity
(thousand Btu per 2005 dollar of GDP)
Delivered Energy 5.42 5.45 5.36 5.19 5.07 4.95 4.82 4.72 4.62 4.52 4.43 4.34 4.25 4.15 4.06 3.97 3.88
Total Energy 7.45 7.50 7.40 7.13 6.95 6.75 6.57 6.42 6.31 6.19 6.07 5.95 5.84 5.72 5.59 5.48 5.37
Price Indices
GDP Chain-type Price Index (20051.000) 1.097 1.110 1.132 1.143 1.155 1.174 1.196 1.220 1.243 1.267 1.293 1.319 1.346 1.373 1.401 1.430 1.459
Consumer Price Index (1982-84=1.00)
All-urban 2.15 2.18 2.25 2.28 2.31 2.36 2.41 2.47 2.52 2.58 2.64 2.70 2.76 2.82 2.88 2.95 3.02
Energy Commodities and Services 1.93 2.12 2.42 2.39 2.37 2.46 2.57 2.65 2.73 2.79 2.87 2.95 3.03 3.11 3.19 3.28 3.37
Wholesale Price Index (1982=1.00)
All Commodities 1.73 1.85 2.00 1.98 2.00 2.04 2.09 2.13 2.16 2.20 2.23 2.26 2.30 2.34 2.37 2.41 2.44
I Fuel and Power 1.59 1.86 2.13 2.07 2.09 2.15 2.25 2.30 2.37 2.44 2.51 2.59 2.67 2.77 2.86 2.96 3.04
Metals and Metal Products 1.87 2.08 2.23 2.13 2.21 2.33 2.42 2.48 2.52 2.54 2.56 2.57 2.58 2.58 2.58 2.59 2.59
Industrial Commodities excluding Energy 1.76 1.83 1.92 1.92 1.95 2.00 2.04 2.08 2.11 2.13 2.15 2.17 2.20 2.22 2.23 2.25 2.27
Interest Rates (percent, nominal)
Federal Funds Rate 0.16 0.18 0.11 0.07 0.09 1.53 3.65 4.26 4.34 4.44 4.59 4.68 4.66 4.68 4.68 4.83 4.59
10-Year Treasury Note 3.26 3.21 2.90 2.66 2.79 3.65 4.77 5.02 5.08 5.14 5.25 5.33 5.34 5.36 5.35 5.34 5.31
AA Utility Bond Rate 5.75 5.24 4.93 4.71 4.84 5.73 6.80 6.90 6.96 7.06 7.23 7.39 7.41 7.48 7.53 7.55 7.53
Value of Shipments (billion 2005 dollars)
Service Sectors 19996 20602 21076 21075 21374 21948 22544 23189 23779 24301 24841 25340 25843 26382 26904 27436 27979
Total Industrial 5667 5838 6016 6031 6248 6562 6836 7068 7242 7378 7497 7583 7658 7734 7789 7864 7946
Agriculture, Mining, and Construction 1615 1578 1557 1552 1618 1760 1888 1981 2039 2074 2099 2116 2121 2136 2153 2183 2211
Manufacturing 4052 4260 4459 4478 4831 4801 4948 5088 5203 5303 5398 5467 5536 5598 5636 5681 5735
Energy-Intensive 1508 1594 1624 1594 1622 1652 1682 1718 1752 1778 1804 1830 1855 1874 1884 1897 1912
Non-Energy-Intensive 2544 2665 2835 2884 3009 3149 3265 3369 3451 3525 3594 3637 3681 3724 3752 3784 3823
Total
Population and Employment (millions)
Population, with Armed Forces Overseas
Population, aged 16 and over
Population, over age 65
Employment, Nonfarm
Employment, Manufacturing
Key Labor Indicators
Labor Force (millions)
Nonfarm Labor Productivity (2005=1.00)
Unemployment Rate (percent)
Key Indicators for Energy Demand
Real Disposable Personal Income
Housing Starts (millions)
Commercial Floorspace (billion square feet)
Unit Sales of Light-Duty Vehicles (millions)
25664 26440 27092 27106 27622 28509 29379 30257 31021 31678 32338 32923 33501 34115 34693 35300 35926
307.8 310.8 313.8 316.9 319.9 323.0 326.2 329.3 332.5 335.6 338.8 342.0 345.2 348.4 351.6 354.9 358.1
241.8 244.3 248.8 249.3 251.7 254.1 256.5 259.0 261.6 264.2 266.8 269.4 272.0 274.6 277.3 280.0 282.6
39.7 40.4 41.4 42.8 44.2 45.6 47.1 48.5 50.0 51.6 53.3 56.1 56.8 58.6 60.4 62.3 64.2
130.7 129.8 131.5 132.7 134.7 137.4 140.1 142.7 144.8 146.2 147.4 148.4 149.1 149.8 150.7 151.9 153.3
11.8 11.5 11.8 11.9 11.9 12.1 12.4 12.4 12.4 12.4 12.4 12.3 12.2 12.1 11.9 11.6 11.4
154.2 153.9 153.4 153.8 155.0 156.4 157.9 159.3 160.7 161.8 162.8 163.7 164.6 165.5 166.4 167.4 168.3
1.06 1.10 1.11 1.11 1.12 1.14 1.16 1.18 1.20 1.22 1.24 1.27 1.30 1.33 1.36 1.39 1.42
9.28 9.63 9.10 9.05 8.60 7.83 7.11 6.54 6.17 5.97 5.81 5.73 5.71 5.64 5.60 5.55 5.52
9883 10082 10221 10430 10558 10843 11157 11484 11772 12073 12391 12716 13040 13388 13725 14088 14474
0.60 0.63 0.66 0.75 1.05 1.46 1.76 1.94 2.01 2.00 1.98 1.95 1.89 1.87 1.88 1.91 1.94
80.3 81.1 81.7 82.3 82.8 83.4 84.1 85.0 86.0 87.0 88.1 89.1 90.1 91.1 92.1 93.0 93.9
10.40 11.55 12.49 13.65 15.36 16.02 16.35 16.68 16.65 16.43 16.50 16.49 16.60 16.78 16.90 17.13 17.36
GOP = Gross domestic product.
Btu = British thermal unit.
- - Not applicable.
Sources: 2009 and 2010: HIS Global Insight, Global Insight Industry and Employment models,
August 2011. Projections: U.S. Energy Information Administration, AE0201 2 National Energy Modeling System run W2012.02101 1b.
2026 2027 2028 2029 2030 2031 2032 2033 2034 2035
2010-
2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2035
19676 20171 20666 21185 21736 22294 22856 23426 24023 24639 2.6%
13009 13338 13669 14001 14348 14711 15078 15448 15829 16221 2.3%
3565 3892 3802 3924 4066 4213 4352 4493 4653 4825 4.2%
2534 2563 2592 2622 2655 2682 2713 2745 2779 2813 0.4%
4681 4905 5140 5391 5656 5929 6212 6509 6820 7142 6.0%
3846 4031 4213 4395 4593 4805 5023 5249 5490 5740 4.1%
3.80 3.72 3.64 3.57 3.50 3.44 3.37 3.30 3.23 3.17 -2.1%
5.25 5.14 5.04 4.94 4.84 4.75 4.65 4.56 4.47 4.38 -2.1%
1.489 1.518 1.548 1.578 1.609 1.639 1.670 1.700 1.731 1.762 1.9%
3.09 3.16 3.22 3.30 3.37 3.44 3.51 3.59 3.66 3.74 2.2%
3.47 3.56 3.64 3.73 3.82 3.88 3.96 4.04 4.14 4.27 2.8%
2.48 2.52 2.55 2.58 2.61 2.65 2.68 2.71 2.75 2.79 1.7%
3.14 3.24 3.31 3.38 3.47 3.57 3.67 3.76 3.88 4.00 3.1%I
2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.59 2.59 0.9%
2.29 2.31 2.33 2.35 2.36 2.38 2.39 2.41 2.42 2.44 1.1%
4.56 4.53 4.46 4.40 4.36 4.25 4.21 4.15 4.11 4.07 --
5.29 5.26 5.20 5.16 5.13 5.05 5.01 4.97 4.94 4.93 - -
7.52 7.52 7.49 7.46 7.46 7.41 7.39 7.37 7.37 7.38 - -
28557 29137 29700 30265 30815 31365 31910 32430 32911 33359 1.9%
8027 8090 8143 8212 8300 8387 8457 8531 8618 8707 1.6%
2243 2263 2274 2290 2317 2346 2365 2382 2408 2437 1.8%
5784 5827 5869 5921 5983 6041 6092 6149 6210 6270 1.6%
1924 1937 1952 1968 1982 1996 2009 2023 2038 2052 1.0%
3860 3890 3918 3953 4001 4045 4083 4125 4173 4218 1.9%
36584 37228 37843 38476 39115 39753 40366 40962 41529 42065 1.9%
361.3 364.5 367.7 370.9 374.1 377.3 380.5 383.7 386.9 390.1 0.9%
285.3 288.0 290.7 293.5 296.2 298.9 301.6 304.3 306.9 309.6 1.0%
65.9 67.6 69.2 70.8 72.3 73.4 74.5 75.5 76.5 77.7 2.6%
154.9 156.5 158.0 159.5 161.1 162.3 163.5 164.6 165.6 166.7 1.0%
11.2 10.9 10.6 10.4 10.2 10.0 9.7 9.5 9.3 9.1 -0.9%
169.3 170.4 171.5 172.7 174.0 175.5 177.0 178.6 180.0 181.3 0.7%
1.45 1.48 1.51 1.55 1.58 1.62 1.65 1.68 1.72 1.76 1.9%
5.47 5.43 5.43 5.46 5.48 5.50 5.52 5.53 5.56 5.58 --
14835 15229 15613 15974 16359 16749 17115 17477 17857 18252 2.4%
1.95 1.92 1.90 1.88 1.89 1.88 1.86 1.85 1.87 1.89 4.5%
94.8 95.6 96.5 97.3 98.2 99.0 99.9 100.9 101.9 103.0 1.0%
17.55 17.69 17.82 17.92 18.03 18.16 18.25 18.31 18.43 18.57 1.9%
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: IDAHO DATE PREPARED: 3/22/2012
CASE NO: GNR-E-1 1-03 WITNESS: Clint Kalich
REQUESTER: IPUC Staff RESPONDER: Clint Kalich
TYPE: Production Request DEPARTMENT: Energy Resources
REQUEST NO.: Staff- 10 TELEPHONE: [phone]
REQUEST:
For the gas forecast data provided in response to request No. 9, please describe, quantify, and
apply any adjustments, interpolations or extrapolations Avista believes may be appropriate or
necessary to obtain delivered, nominal forecast prices representative of those that would be
experienced by an SAR located in Avista's, Idaho Power's, and PacifiCorp's service territories and
therefore appropriate for direct use in the SAR model.
RESPONSE:
The figures in Table 19 are stated in 2010-year dollars. I recommend that the Commission use the
Fuel and Power Wholesale Price Index included in the 2012 Annual Energy Outlook. This
escalator averages 3.1% over the 2010-2025 period. This table maybe found at the following
URL: http://www.eia.gov/forecasts/aeo/er/excel/aeotab_20.xlsx . Reference line 36 in the link's
spreadsheet. It is attached in the file "AE02012 Table 20.xlsx.
CERTIFICATE OF SERVICE
I hereby certify that on this 27th day of March 2012, true and correct copies ofthe
foregoing Responses of Avista Corporation to Requests 1-6 and 9-10 of the First
Production Request of the Commission Staff to Avista Corporation were delivered to the
following persons via Email (unless otherwise indicated).
Jean Jewell
Idaho Public Utilities Commission
472 W. Washington St.
Boise, ID 83702
Email: [e-mail]
(via Email and Regular Mail)
Donald L. Howell, II
Kris Sassar
Deputy Attorneys General
Idaho Public Utilities Commission
472 W. Washington St.
Boise, ID 83702
Email: don.howel1puc.idaho.gov
[e-mail]
Dean J. Miller, Esq.
McDevitt, & Miller, LLP
P0 Box 2564
Boise, ID 83701-2564
[e-mail]
Daniel B. Solander
Senior Counsel
Rocky Mountain Power
201 S. Main Street, Suite 2300
Salt Lake City, UT 84111
Email: [e-mail]
Donovan E. Walker
Lisa Nordstrom
Idaho Power Company
P0 Box 70
Boise, ID 83707-0070
Email: [e-mail]
[e-mail]
Peter Richardson
Gregory M. Adams
Richardson & O'Leary
515 N. 27th St.
P0 Box 7218Boise, ID 83702
Email: [e-mail]
[e-mail]
Magan Walseth Decker
Senior Staff Counsel
Renewable Northwest Project
917 SW Oak St., Suite 303
Portland, OR 97205
Email: [e-mail]
R. Greg Ferney
Mimura Law Offices, PLLC
2176 E. Franklin Rd., Suite 120
Meridian, ID 83642
Email: gregmimura1aw.com
Page 1—CERTIFICATE OF SERVICE
Ted S. Sorenson, P.E.
Sorenson Engineering, Inc.
5203 South 11th East
Idaho Falls, ID 83404
Email: [e-mail]
Glenn Ikemoto
Margaret Ruger
Idaho Windfarms, LLC
672 Blair Ave.
Piedmont, CA 94611
E-mail: [e-mail]
[e-mail]
Shelley M. Davis
Barker Rosholt & Simpson, LLP
1010 W. Jefferson St., Ste. 102
P.O. Box 2139
Boise, ID 83701-2139
Email: [e-mail]
Ronald L. Williams
Williams Bradbury, P.C.
1015 W. Hays St.
Boise ID, 83702
Email: ronwi1liamsbradbury.com
Dana Zentz
VP, Summit Power Group, Inc.
2006 E. Westminster
Spokane, WA 99223
Email: [e-mail]
Robert D. Kahn
Executive Director
Northwest and Intermountain Power
Producers Coalition
1117 Minor Ave., Suite 300
Seattle, WA 9810
Email: [e-mail]
Thomas H. Nelson
Attorney for Renewable Energy Coalition
P0 Box 1211
Weiches, OR 97067-1211
Email: [e-mail]
Bill Piske, Manager
Interconnect Solar Development, LLC
1303 E. Carter
Boise, ID 83706
Email: [e-mail]
Bill Brown, Chair
Board of Commissioners of Adams County,
Idaho
P0 Box 48
Council, ID 83612
Email: [e-mail]
Scott Montgomery
President, Cedar Creek Wind, LLC
668 Rockwood Drive
North Salt Lake, Uta 84054
Email: scottwesternenergy.us
Wade Thomas
General Counsel, Dynamis Energy
776 B. Riverside Drive, Suite 15
Eagle, ID 83616
Email: wthomasdynamisenerg.com
Page 2—CERTIFICATE OF SERVICE
James Carkulis
Managing Member
EXERGY DEVELOPMENT GROUP OF
IDAHO, LLC
802 West Banock Street, Ste. 1200
Boise, Idaho 83702
[e-mail]
Robert A. Paul
Grand View Solar II
15960 Vista Circle
Desert Hot Springs, CA
Email: robertapau1gmail.com
John R. Lowe
Consultant to Renewable Energy
Coalition
12050 SW Tremont Street
Portland, OR 97225
Email: [e-mail]
Twin Falls Canal Company
do Brian Olmstead, General Manager
P.O. Box 326
Twin Falls, Idaho 83303-0326
Email: [e-mail]
C. Thomas Arkoosh
Capitol Law Group, PLLC
205 North 10th 4' Floor
P0 Box 2598
Boise, ID 83701-2598
Email: [e-mail]
Arron F. Jepson
Blue ribbon Energy LLC
10660 South 540 East
Sandy, UT 84070
Email: arronesqao1.com
Don Sturtevant
Energy Director
J. R. Simplot Company
ONE CAPITAL CENTER
999 Main Street, P.O. Box 27
Boise, Idaho 83707-0027
Email: [e-mail]
North Side Canal Company
do Ted Diehl, General Manager
921 N. Lincoln St.
Jerome, Idaho 83338
Email: [e-mail]
MJ Humphries
Blue Ribbon Energy LLC
4515 S. Ammon Road
Ammon, ID 83406
Email: blueribbonenergygmai1.com
Mary Lewallen
Clearwater Paper Corporation
601 W. Riverside Ave., Suite 1100
Spokane, WA 99201
Email: [e-mail]
Page 3—CERTIFICATE OF SERVICE
Benjamin J. Otto Ken Miller
Idaho Conservation League Clean Energy Program Director
710 N. 6th St. Snake River Allance
P.O. Box 844 Box 1731
Boise, Idaho 83702 Boise, 10 83701
Ph: [phone] x 12 Email: kmi11erstakerivera11iance.org
Fax: [phone]
Email: bottoidahoconservation.org
Arron F. Jepson
Blue Ribbon Energy LLC
10660 South 540 East
Sandy, UT 84070
Email: arronesg(aol.com
Energy Integrity Project
do Tauna Christensen
769 North 1100 East
Shelley, ID 83274
Email: [e-mail]
91-c–h—ael
Page 4—CERTIFICATE OF SERVICE