HomeMy WebLinkAbout20100311Comments.pdfSCOTT WOODBURY
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
(208) 334-0320
BAR NO. 1895
RE eEl, \1 l~~ f)
iQt~ ~~\R \ \ PM 4: 04
Street Address for Express Mail:
472 W. WASHINGTON
BOISE, IDAHO 83702-5983
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF )
IDAHO POWER COMPANY TO ESTABLISH )
ITS BASE LEVEL FOR NET POWER SUPPLY )EXPENSES FOR 2010. )
)
)
CASE NO. IPC-E-I0-0l
COMMENTS OF THE
COMMISSION STAFF
COMES NOW the Staff of the Idaho Public Utilties Commission (Commission), by
and through its attorney of record, Scott Woodbur, Deputy Attorney General, and in response
to the Notice of Application, Notice of Modified Procedure and Notice ofComment/rotest
Deadline issued on January 28,2010 in Case No. IPC-E-I0-0l, submits the following comments.
BACKGROUND
Idaho Power Company (Idaho Power; Company) fied an Application on January 19,
2010, with the Idaho Public Utilties Commission (Commission) requesting an Order approving
an increase in the Company's base level of net power supply expense (NPSE). The base level
NPSE amount would be used prospectively to set both base rates and establish the base level of
net power supply expense for the Company's 2010-2011 Power Cost Adjustment (PCA)
calculations.
On January 13,2010, in Order No. 30978 issued in Case No. IPC-E-09-30, the
Commission approved a Settlement Stipulation (Stipulation) which included a moratorium on
STAFF COMMENTS 1 MARCH 11,2010
rate case filings by Idaho Power and certain other ratemaking provisions. The Stipulation
included a provision which addresses setting the base level for net power supply expenses.
Paragraph 7. 1 of the Stipulation reads as follows:
7.1. Setting the Base Level for Net Power Supply Expense. Prior to
implementing the June 1,2010, PCA and effective with the coincident PCA
rate change, the Company wil fie with the Commission a request to change
the base level for net power supply expenses to be used prospectively for both
base rates and PCA calculations. The Paries wil thereafter make a good-
faith effort to reach agreement on the maximum change of the base level for
net power supply expenses and submit any agreement to the Commission for
approval.
The Company's Application and requested change in this case is fied in compliance with
Section 7.1 of the Stipulation. A settlement conference of the paries was held on March 2,
2010. No agreement was reached.
Proposed Increase in Base Net Power Supply Expense
As reflected in the Company's Application, net power supply expense includes a number
of categories of variable power supply expenses. Modeled variable power supply expenses
include fuel expenses (FERC Accounts 501 and 547) and purchase power expenses (FERC
Account 555), not including purchases from qualifying facilties (QFs) under the Public Utilty
Regulatory Policies Act of 1978 ("PURP A"). To determine net power supply expense, surplus
sales revenues (FERC Account 447) are deducted. In addition to the modeled variable power
supply expenses categories, the base net power supply expense used for PCA computations also
includes PURP A expenses (FERC Account 555), third-pary transmission expense (FERC
Account 565), water leasing expense (FERC Account 536), and revenue from marginal cost-
based special contract pricing (FERC Account 442). The Company's base net power supply
expenses are usually established in general rate cases. The last time the base net power supply
expenses were reviewed and approved by the Commission was in the Company's 2008 general
rate case, IPC-E-08-10. In each anual PCA, the Company's forecast of variable power supply
expenses is compared to a normalized, approved variable power supply expense level and the
difference is the principal driver of the PCA.
STAFF COMMENTS 2 MARCH 11, 2010
Idaho Power has computed a 2010 test year NPSE and compared it to the normalized
variable power supply expenses that were approved in the Company's 2008 general rate case.
Based on that comparison, the Company has calculated that the difference between the 2008 and
2010 base level NPSE on a system basis would be $78.4 milion, while on an Idaho jurisdictional
basis, the difference would be $74.8 milion. This difference reflects the maximum adjustment
to base level NPSE that would be the subject of negotiations pursuant to paragraph 7.1 of the
Stipulation. Reference Application supporting testimony Exhibit 4.
STAFF ANALYSIS
Staff carefully reviewed each of the changes between Idaho Power's approved 2008
NPSE and its proposed 2010 NPSE. Attachment A shows by FERC account the approved 2008
NPSE, the proposed 2010 NPSE, and the differences between the two. The graph on page 2 of
Attachment A provides a quick visual reference to indicate the relative magnitudes of each
component.
The difference between Idaho Power's approved 2008 NPSE and its proposed 2010
NPSE is driven principally by increased coal costs for the Company's three coal-fired power
plants, increases in the payments the Company expects to make to PURP A facilties, and reduced
revenues from surlus sales due to decreased gas and electric market prices. Staff agrees with
some of the proposed changes, but disagrees with others.
First, Staff agrees with the proposed increase in Account 536, Water for Power. The
increase reflects the actual cost of water that wil be leased from the ShoBan Tribe in 2010 at a
contracted price. Staff reviewed analysis prepared by Idaho Power comparing the cost of the
leased water to the value of the energy that would be generated by passing the leased water
through the Company's Snake River generating plants. The analysis demonstrates that under
reasonable estimates for summertime electricity prices, the benefits of the leased water
substantially outweigh its cost.
Staff also agrees with the proposed increase in Account 565, Transmission. Idaho Power
forecasts third pary transmission expense using a combination of forward looking and historical
trending approaches. Staff reviewed the Company's approaches and believes they produce a
reasonable estimate of expected transmission costs.
To address the remaining accounts comprising NPSE as shown on Attchment A, Staff
wil discuss several issues separately below.
STAFF COMMENTS 3 MARCH 11,2010
Increased Coal Costs
The single biggest factor causing higher net power supply costs in 2010 is increased coal
costs at Bridger, Valmy and Boardman. In fact, higher coal costs account for approximately 43
percent of the proposed increase in NPSE. Coal contracts at Bridger and Valmy expired at the
end of2009, and new contracts that begin in 2010 reflect prices that are roughly 30 percent
higher than in the past. A new coal supply agreement at Boardman began in 2009, and it too
reflects much higher prices than before. Staff accepts the Valmy and Boardman prices, but as
explained below, withholds judgment on the Bridger coal costs pending completion of furter
analysis.
Shortly before preparing its comments in this case, Staff became aware of issues being
raised in Idaho Power's anual power cost adjustment (PCA) case in Oregon related to Bridger
coal costs. The Oregon Commission Staff is alleging that a portion of the coal purchased from
IERCO, an Idaho Power affliate, that is bured as fuel for the Bridger plant is priced higher than
market. In its initial testimony in the case, the Oregon Commission Staffhas recommended a
downward adjustment of$15,584,261 (system-wide) in Bridger coal costs. Oregon's share of the
downward adjustment would be $723,110.
The Idaho Commission Staff has been conducting its own investigation into the issue.
Staff is following the Oregon case, and reviewing all production requests and responses. The
Oregon case is not scheduled to conclude until May 28, 2010. Staff is also posing its own
production requests in Idaho, and continues to review responses from Idaho Power. Due to the
compressed schedule for this case and its direct link to Idaho Power's upcoming 2010 PCA
fiing, Staff has been unable to complete its review of this issue. Based on the information
received to date, Staff has not identified any justification for adjusting 2010 Bridger coal costs.
Consequently, Staff recommends that for now, Bridger coal costs be allowed at the level
proposed by Idaho Power in its Application, but that the Commission reserve the right to make
adjustments to Bridger coal costs allowed in base rates in the context of Idaho Power's 2010
PCA filing. The Company's anual PCA fiing is expected to be submitted on April 15, 2010,
with a final order due on May 15th in order to accommodate rate changes that would be effective
on June 1.
STAFF COMMENTS 4 MARCH 11,2010
Adjustment to PURPA Costs
Increased PURPA costs represent over $23 milion of the nearly $75 milion proposed
,
Idaho jurisdictional increase in NPSE. Idaho Power has signed 14 new PURP A contracts with
scheduled online dates in 2010.
To determine its proposed costs for Account 555 PURPA costs, Idaho Power totaled the
estimated anual payments for all of its existing PURP A contracts as well as contracts for all
projects expected to come online before the end of2010. In the past, individual PURPA contract
costs have been added to base NPSE in general rate proceedings once there was a signed power
sales agreement and a scheduled online date occurring before the end of the test year. Idaho
Power has followed the same past practice in this case. The logic in applying this criteria. was
that once there was a signed power sales agreement that obligated the project to a specified
online date, the costs were "known and measurable" and worthy of being included in base net
power supply costs.
In this case, Staff suggests that the mere existence of a signed power sales agreement,
despite its requirement of a scheduled online date, does not guarantee that a project wil actually
meet its scheduled online date. Staffs position is supported by the Company's recent QF
contract experience with wind projects. In the Company's application, Staff identified 11
PURPA contracts that it believes will have difficulty meeting scheduled online dates in 2010.
Attachment B is a list of all PURP A projects with contracts with Idaho Power that are either
already online or that have scheduled online dates in 2010. Those projects that are highlighted
represent proposed wind projects, all being developed by a single developer, with scheduled
online dates of September 1,2010. Collectively, these projects represent 50.2 aMW of new
capacity. The original scheduled online date for each of these projects was initially May 1,2007.
However, on June 4, 2008, the scheduled online dates for these projects was changed to
September 1,2010. On January 28,2010, Idaho Power notified Staff that the project developer
now believes the operation date for all of the projects wil be December 31, 2010. It remains to
be seen whether the revised scheduled online dates wil be met. Even if they are, there would be
little or no generation recorded for 2010.
Staff believes that it is reasonable to remove the expected costs of these projects from
base net power supply costs for 2010. If or when the projects do come online, Idaho Power can
track those contract costs as actual expenses, which wil be recoverable in annual PCA filings at
100 percent until those costs can be included in base rates in a subsequent general rate
STAFF COMMENTS 5 MARCH 11,2010
proceeding. Removal of the costs of these 11 contracts reduces Idaho Power's proposed NPSE
by $7,108,922.
Due to the considerable uncertainty of PURP A projects meeting their scheduled online
dates in the past, Staff proposes that in future proceedings, new PURP A contract costs only be
added for recovery in base rates once they have actually achieved online dates within the test
period.
Adjustment to Hoku Loads and Revenues
On March 16,2009, the Commission issued an Order approving Idaho Power's special
Energy Sales Agreement ("ESA") with Hoku Materials, Inc. ("Hoku"). See Order No. 30748.
Under the ESA, Idaho Power was supposed to begin providing up to 43 MW of electrical service
to Hoku beginning June 1,2009, and increasing to 82 MW beginning September 16,2009.
On May 28,2009, Idaho Power submitted a Motion for a Commission Order authorizing
a delay in the commencement of its ESA with Hoku. On June 23, 2009, Idaho Power submitted
a supplemental fiing seeking approval of an Amended and Restated Energy Sales Agreement
implementing the changes described in the Company's prior Motion to Delay the Start Date of its
ESA with Hoku and Letter Agreement. On July 24, 2009, the Commission issued an Order
approving the Amended Agreement. See Order No. 30869. Among other things, the parties
mutually agreed to the following changes to their original Agreement:
1. Delay the sta date of the ESA until December 1, 2009;
2. Hoku will receive service between June 1, 2009 and November 30, 2009 as a
Schedule 19T customer;
3. Hoku will limit its demand to no more than 5 MW during July 2009; 10 MW during
August 2009; and no more than 25 MW for each month thereafter until November 30,
2009.
Due primarily to worldwide economic conditions and difficulties obtaining financing,
Hoku has yet to complete construction of its plant and commence production. Based on
available information, Staff is unable to predict or confirm that Hoku wil begin taking service
from Idaho Power in 2010. Because of the considerable uncertainty, Staff proposes that both the
expected loads and the associated revenues attributable to Hoku be removed from Idaho Power's
proposed 2010 NPSE. The effect of removing Hoku's loads and revenues is a furher reduction
in NPSE of $3,992,955.
STAFF COMMENTS 6 MARCH 11,2010
Should Hoku complete its plant and begin taking service in 2010, Idaho Power would
track any increase in its NPSE for recovery in its PCA at 95 percent. Revenues from first block
energy sales to Hoku would also be tracked and applied as an offset to NPSE.
Other Changes in Load
Net power supply expenses also are affected by changes in the Company's loads. The
Company's anual normalized system load used in its last general rate case was 15.9 milion
megawatt-hours (MWhs). The Company's 2010 anual normalized system load based on the
2010 test year is 15.7 milion MWhs, a decrease of 200,000 MWhs. The decrease in loads from
2008, Staff believes, is consistent with the recent downturn in the economy. Notably, the load
forecast used by Idaho Power for 2010 is the same forecast the Company used in the recent
Langley Gulch case (IPC-E-09-03) and matches the Company's 2010 load forecast in its 2009
Integrated Resource Plan.
Non-PURPA Purchases and Surplus Sales Revenue
Under Idaho Power's proposal, a projected decrease in surplus sales revenue accounts for
an increase in NPSE of nearly $24 milion, almost one-third of the approximately $75 milion
total increase in NPSE (Idaho jurisdiction). The decrease in surplus sales revenue can be
attributed to much lower electric market prices, which in tur, are caused by much lower
assumed natual gas prices. In Idaho Power's 2008 general rate case, Henr Hub gas prices
during the 2009 pro forma year were assumed to be $7.74 per MMBtu. In this case, the
Company has assumed gas prices for 2010 to be $5.79.
Corresponding to the projected decrease in surplus sales revenue, Idaho Power's analysis
also projects an increase in non-PURPA purchases. With much lower natural gas prices
expected for 2010, and therefore much lower market prices, Idaho Power can purchase more
energy from the market at prices lower than it would otherwise incur if it generated the power
itself.
Staff reviewed Idaho Power's analysis in detail, including its Aurora (power supply
model) results. Each change in Aurora input data made by Idaho Power since its 2008 rate case
was identified by Staff, its effect on NPSE was estimated, and its reasonableness considered.
Staff performed multiple Aurora simulations using its own assumptions. Although Staffs results
differ from the Company's due to some of the issues discussed previously, Staffs results with
regard to surlus sales revenue and non-PURP A purchases are very similar to Idaho Power's
STAFF COMMENTS 7 MARCH 11,2010
results. Staff believes that the gas prices used by Idaho Power in its Aurora analysis are
reasonable, and agrees that surlus sales revenue is likely to decline significantly in 2010 and
that costs for non-PURPA purchases wil increase due to more market purchases.
Staff Proposed 2010 NPSE
Removal of the new PURP A wind contract costs and the Hoku loads and revenues
discussed above affects the costs and dispatch of Idaho Power's generating plants, as well as
purchases and sales as modeled in Aurora. The results from Staffs Aurora analysis are included
in the NPSE account totals shown on Attachment C. Staff proposes a total NPSE for 2010 of
$209,729,358. This represents an increase over 2008 authorized NPSE of $63,701,694. A
summar of Staffs Aurora analysis results is shown in Attachment D for reference puroses.
STAFF RECOMMENDATIONS
Staff recommends a 2010 NPSE increase of $63,701,694. Staff further recommends that
the Commission reserve the right to adjust Bridger coal costs allowed in base rates in the context
of Idaho Power's 2010 PCA fiing.
Respectfully submitted this / /1) day of March 2010.
Scott Woodbury
Deputy Attorney General
Technical Staff: Rick Sterling
i:umisc:commentslipce i 0.0 i swrpskhtc comments
STAFF COMMENTS 8 MARCH 11, 2010
Base NPSE (2008)System Allocation Idaho Jurisdiction
Account 501, Coal $133,454,723 94.79%$126,498,308
Account 536, Water for Power $67,519 95.04%$64,169
Account 547, Gas $6,125,180 94.79%$5,805,901
Account 555, Non-PURPA Purchases $57,231,921 94.79%$54,248,670
Account 565, Transmission $10,469,726 94.79%$9,923,985
Account 447, Surplus Sales $116,568,567 94.79%$110,492,354
Net of 95% Accounts $90,780,502 94.79%$86,048,679
Account 555, PURPA $63,269,889 94.80%$59,978,985
Net of 100% Accounts $63,269,889 94.80%$59,978,985
Total $154,050,391 94.79%$146,027,664
Forecast NPSE (2010)System Allocation Idaho Jurisdiction
Account 501, Coal $167,659,463 95.00%$159,271,580
Account 536, Water for Power $1,828,640 95.22%$1,741,299
Account 547, Gas $6,052,090 95.00%$5,749,320
Account 555, Non-PURPA Purchases $67,977,200 95.00%$64,576,374
Account 565, Transmission $8,262,000 95.00%$7,848,661
Account 447, Surplus Sales $91,332,412 95.00%$86,763,129
Account 442, Hoku Energy Revenue $15,771,838 95.00%$14,982,786
Net of 95% Accounts $144,675,143 95.00%$137,441,319
Account 555, PURPA $87,781,532 95.00%$83,389,916
Net of 100% Accounts $87,781,532 95.00%$83,389,916
Total $232,456,675 95.00%$220,831,235
I Difference $78,406,284 95.41%$74,803,571 I
System Allocation Idaho Jurisdiction
Account 501, Coal $34,204,740 95.00%$32,493,501
Account 536, Water for Power $1,761,121 95.22%$1,677,005
Account 547, Gas $(73,090)95.00%$(69,434)
Account 555, Non-PURPA Purchases $10,745,279 95.00%$10,207,704
Account 565, Transmission $(2,207,726)95.00%$(2,097,276)
Account 447, Surplus Sales $(25,236,155)95.00%$(23,973,612)
Account 442, Hoku Energy Revenue $15,771,838 95.00%$14,982,786
Net of 95% Accounts $53,894,641 95.00%$51,202,327
Account 555, PURPA $24,511,643 95.00%$23,285,352
Net of 100% Accounts $24,511,643 95.00%$23,285,352
Total $78,406,284 95.00%$74,803,571 Attchment A
Case No. IPC-E-I0~01
Staff Comments
03/11/10 Page lof2
System Allocation Idaho Jurisdiction
Account 501, Coal $34,204,740 95.00%$32,493,501
Account 536, Waterfor Power $1,761,121 95.22%$1,677,005
Account 547, Gas $(73,090)95.00%$(69,434)
Account 555, Non-PURPA Purchases $10,745,279 95.00%$10,207,704
Account 565, Transmission $(2,207,726)95.00%$(2,097,276)
Account 447, Surplus Sales $(25,236,155)95.00%$(23,973,612)
Account 442, Hoku Energy Revenue $15,771,838 95.00%$14,982,786
Net of 95% Accounts $53,894,641 95.00%$51,202,327
Account 555, PURPA $24,511,643 95.00%$23,285,352
Net of 100% Accounts $24,511,643 95.00%$23,285,352
Total $78,406,284 95.00%$74,803,571
Difference in NPSE Between 2010 and 2008
$40
$30
$20
oV $10i:
~
~$-
()~G)0 OJ OJ
$(10)OJ r+'"
..
0'..
$(20)0~
C'
$(30)
..
Attachment A
Case No. IPC-E-IO-01
Staff Comments
03/11/10 Page? of2
2010 Test Year
CSPP Projects
Total Annual Generation (kWh)Total Annual Payment New/Existing Online Date
Barber Dam 12,201,512 $611,665 Existing
Bennett Creek Wind 35,446,160 $1,933,598 Existing
Bettencourt Dry Creek 9,756,747 $292,044 New
Big Sky West 9,079,210 $574,963 New
Birch Creek 279,350 $25,403 Existing
Black Canyon #3 335,567 $23,060 Existing
Blind Canyon 3,966,837 $344,322 Existing
Box Canyon 1,683,941 $110,076 Existing
Briggs Creek 3,593,060 $240,633 Existing
Bypass 25,478,175 $1,356,053 Existing
Canyon Springs 776,221 $24,236 Existing
Cassia Gulch Wind Park 48,143,007 $2,799,366 Existing
Cassia Wind Farm 28,181,837 $1,652,665 Existing
Cedar Draw 4,905,199 $314,795 Existing
Clear Springs Trout 3,519,410 $296,651 Existing
CO-GEN CO 57,150,719 $3,017,652 New
Crystal Springs 7,773,775 $511,819 Existing
Curry Cattle Company 627,352 $44,544 Existing
Dietrich Drop 12,989,382 $707,359 Existing
Elk Creek 3,875,320 $265,465 Existing
Falls River 47,706,800 $3,064,117 Existing
Faulkner Ranch 3,141,897 $240,633 Existing
Fisheries Development Co 952,708 $29,628 Existing
Fossil Gulch Wind 24,303,596 $1,228,396 Existing
Geo Bon #2 3,320,259 $245,443 Existing
Hailey CSPP 124,112 $8,565 Existing
Hazelton A 21,742,251 $1,110,250 Existing
Hazelton B 21,504,060 $1,511,734 Existing
Hidden Hollow Landfill Gas 17,720,564 $960,002 Existing
Horseshoe Bend Hydroelectric 42,570,646 $2,912,930 Existing
Horseshoe Bend Wind Park 19,984,333 $1,027,607 Existing
Hot Springs Wind 46,390,007 $2,528,249 Existing
Jim Knight 1,292,224 $91,148 Existing
Kasel and Witherspoon 3,775,200 $289,596 Existing
Koyle Small Hydro 3,265,848 $266,395 Existing
Lateral # 10 $518,088 Existing
Lemoyne 630,822 $43,974 Existing
Little Wood Rvr Res 5,306,788 $389,901 Existing
Littlewood - Arkoosh 3,304,157 $245,053 Existing
Low Line Midway Hydro 7,730,575 $482,940 Existing
Lowline #2 9,106,730 $484,494 Existing
Lowline Canal 26,145,677 $1,866,652 Existing
Magic Reservoir 19,921,481 $989,132 Existing
Magic Valley 73,896,865 $4,777,162 -Existing
Magic West 72,048,283 $4,655,441 Existing
Malad River 1,879,896 $208,854 Existing
Marco Ranches 2,355,073 $154,572 Existing
Mile 28 3,945,889 $274,640 Existing
Mitchell Butte 6,354,759 $135,423 Existing
Mora Drop Hydro 4,767,518 $265,354 Existing
Mud Creek S&S 1,383,628 $100,216 Existing
AttachIent B
Case No. IPC-E-lO-Ol
Staff Comments
03/11/10 Page 1 of2
2010 Test Year
CSPP Projects
Total Annual Generation (kWh)Total Annual Payment New/Existing Online Date
Mud Creek White 427,239 $28,092 Existing
Owyhee Dam CSPP 29,752,348 $416,514 Existing
Pigeon Cove 7,596,697 $673,029 Existing
Pocatello Waste 1,435,624 $103,626 Existing
Pristine Springs #1 872,430 $48,571 Existing
Pristine Springs #3 1,364,706 $76,096 Existing
Reynolds Irrigation 1,326,613 $97,560 Existing
Rim View 1,316,640 $41,096 Existing
Rock Creek #1 8,297,172 $787,235 Existing
Rock Creek #2 6,644,822 $327,863 Existing
Sagebrush 1,000,564 $70,672 Existing
Sahko Hydro 1,040,578 $33,206 Existing
Schaffner 1,261,116 $93,093 Existing
Shingle Creek 807,529 $55,869 Existing
Shoshone #2 2,128,474 $145,851 Existing
Shoshone CSPP 1,832,869 $145,127 Existing
Simplot Pocatello 68,323,059 $3,780,214 Existing
Snake River Pottery 393,518 $26,358 Existing
Snedigar 1,222,312 $83,974 Existing
Tamarack CSPP 36,885,798 $2,453,204 Existing
T ASCO - Nampa 1,450,255 $42,885 Existing
TASCO - Twin Falls 242,358 $9,348 Existing
Tiber Dam 29,850,100 $1,445,910 Existing
Trout - Co 854,563 $59,242 Existing
Tunnel #1 17,036,939 $1,766,185 Existing
Vaagen Brothers Lumber Inc 20,882,800 $2,018,725 Existing
White Water Ranch 627,840 $42,316 Existing
Wilson Lake Hydro 24,518,355 $1,726,634 Existing
Total (kWh)1,483,351,098 $87,781,532
Total (aMW)169.3
New wind projects (kWh)439,707,825 $24,930,078
New wind projects (aMW)50.2
IWind Capacity in AURORA (aMW)119.1
Attadiient B
Case No. IPC-E-1O-01
Staff Comments
03/11/10 Page 2 of2
Base NPSE (2008)System Allocation Idaho Jurisdiction
Account 501, Coal $133,454,723 94.79%$126,498,308
Account 536, Water for Power $67,519 95.04%$64,169
Account 547, Gas $6,125,180 94.79%$5,805,901
Account 555, Non-PURPA Purchases $57,231,921 94.79%$54,248,670
Account 565, Transmission $10,469,726 94.79%$9,923,985
Account 447, Surplus Sales $116,568,567 94.79%$110,492,354
Net of 95% Accounts $90,780,502 94.79%$86,048,679
Account 555, PURPA $63,269,889 94.80%$59,978,985
Net of 100% Accounts $63,269,889 94.80%$59,978,985
Total $154,050,391 94.79%$146,027,664
Forecast NPSE (2010)System Allocation Idaho Jurisdiction
Account 501, Coal $167,718,084 95.00%$159,327,268
Account 536, Water for Power $1,828,640 95.22%$1,741,299
Account 547, Gas $6,062,472 95.00%$5,759,183
Account 555, Non-PURPA Purchases $66,689,601 95.00%$63,353,192
Account 565, Transmission $8,262,000 95.00%$7,848,661
Account 447, Surplus Sales $92,642,114 95.00%$88,007,308
Account 442, Hoku Energy Revenue $95.00%$
Net of 95% Accounts $157,918,683 95.00%$150,022,295
Account 555, PURPA $62,851,454 95.00%$59,707,063
Net of 100% Accounts $62,851,454 95.00%$59,707,063
Total $220,770,137 95.00%$209,729,358
I
Difference 63,701,6941$66,719,746 95.48%$
Attchment C
Case No. IPC~E~ 10-0 1
Staff Comments
03/11/10
Hy
d
r
o
e
l
e
c
t
r
i
c
G
e
n
e
r
a
t
i
o
n
(
M
W
h
)
Br
i
d
g
e
r
En
e
r
g
y
(
M
W
h
)
Co
s
t
(
$
x
1
0
0
0
)
Bo
a
r
d
m
a
n
En
e
r
g
y
(
M
W
h
)
Co
s
t
(
$
x
1
0
0
0
)
Va
l
m
y
En
e
r
g
y
(
M
W
h
)
Co
s
t
(
$
x
1
0
0
0
)
Da
n
s
k
i
n
En
e
r
g
y
(
M
W
h
)
Co
s
t
(
$
x
1
0
0
0
)
$
Fi
x
e
d
C
a
p
a
c
i
t
y
C
h
a
r
g
e
-
G
a
s
T
r
a
n
s
p
o
r
t
a
t
i
o
n
(
$
x
1
0
0
0
)
$
To
t
a
l
C
o
s
t
$
Be
n
n
e
t
t
M
o
u
n
t
a
i
n
En
e
r
g
y
(
M
W
h
)
Co
s
t
(
$
x
1
0
0
0
)
$
Fi
x
e
d
C
a
p
a
c
i
t
y
C
h
a
r
g
e
-
G
a
s
T
r
a
n
s
p
o
r
t
a
t
i
o
n
(
$
x
1
0
0
0
)
$
To
t
a
l
C
o
s
t
$
Pu
r
c
h
a
s
e
d
P
o
w
e
r
(
E
x
c
l
u
d
i
n
g
C
S
P
P
)
Ma
r
k
e
t
E
n
e
r
g
y
(
M
W
h
)
Co
n
t
r
a
c
t
E
n
e
r
g
y
(
M
W
h
)
To
t
a
l
E
n
e
r
g
y
E
x
c
l
.
C
S
P
P
(
M
W
h
)
Ma
r
k
e
t
C
o
s
t
(
$
x
1
0
0
0
)
Co
n
t
r
a
c
t
C
o
s
t
(
$
x
1
0
0
0
)
To
t
a
l
C
o
s
t
E
x
c
l
.
C
S
P
P
(
$
x
1
0
0
0
)
Su
r
p
l
u
s
S
a
l
e
s
En
e
r
g
y
(
M
W
h
)
Re
v
e
n
u
e
I
n
c
l
u
d
i
n
g
T
r
a
n
s
m
i
s
s
i
o
n
C
o
s
t
s
(
$
x
1
0
0
0
)
Tr
a
n
s
m
i
s
s
i
o
n
C
o
s
t
s
(
$
x
1
0
0
0
)
Re
v
e
n
u
e
E
x
c
l
u
d
i
n
g
T
r
a
n
s
m
i
s
s
i
o
n
C
o
s
t
s
(
$
x
1
0
0
0
)
Ho
k
u
F
i
r
s
t
B
l
o
c
k
R
e
v
e
n
u
e
s
Ne
t
P
o
w
e
r
S
u
p
p
l
y
C
o
s
t
s
(
$
x
1
0
0
0
)
To
t
a
l
E
n
e
r
g
y
(
M
W
h
)
ou
:
n
;
i
~i
:
~
i
:
_~
c
n
Q
)
..
"
"
(
'
n
~
n
Z
2
"
00
0
S
S.
(
'
=i
.
.
:
:
;:
"
'
-
g
n
ö
(¡
t
¡
..oio..
Ja
n
u
a
r
y
77
9
.
7
3
9
.
1
C:
\
A
R
l
i
p
c
e
2
0
1
0
N
P
S
E
1
2
0
1
0
S
G
P
-
I
P
C
O
u
t
p
u
t
R
e
p
o
r
t
s
H
o
u
r
l
y
O
r
i
g
i
n
a
l
G
a
s
N
o
H
o
k
u
N
o
P
U
R
P
A
W
i
n
d
.
x
l
s
IP
C
O
P
O
W
E
R
S
U
P
P
L
Y
C
O
S
T
S
F
O
R
2
0
1
0
N
O
R
M
A
L
I
Z
E
D
L
O
A
D
S
O
V
E
R
8
1
W
A
T
E
R
Y
E
A
R
C
O
N
D
I
T
I
O
N
S
Fe
b
r
u
a
r
y
84
9
,
1
3
1
.
2
Ma
r
c
h
86
3
,
7
5
1
.
2
8
7
6
,
3
4
7
.
8
8Q
AV
E
R
A
G
E
M§
99
8
,
3
2
6
.
7
Ju
n
e
90
0
.
2
5
9
.
4
.M 63
8
,
2
4
9
.
5
Au
g
u
s
t
Se
p
t
e
m
b
e
r
53
3
,
4
0
8
.
2
5
4
3
,
1
1
9
.
3
5
3
8
,
6
7
1
.
0
Oc
t
o
b
e
r
No
v
e
m
b
e
r
D
e
c
e
m
b
e
r
46
6
,
9
0
2
.
2
6
7
4
,
5
1
8
.
4
An
n
u
a
l
8,
6
6
2
,
4
2
3
.
8
44
0
,
3
8
4
.
7
3
9
8
,
2
0
5
.
0
4
1
6
,
2
8
7
.
1
3
1
1
,
7
1
0
.
9
3
1
3
.
0
8
3
.
2
3
6
0
,
6
0
9
.
4
4
6
9
,
0
5
9
.
5
4
7
2
,
1
1
3
.
2
4
4
2
.
7
4
3
.
1
4
6
6
,
4
9
7
.
8
4
5
8
,
3
0
7
.
5
4
7
3
,
3
4
1
.
8
5
.
0
2
2
,
3
4
3
.
2
$
9
,
3
9
1
.
9
$
8
,
4
9
3
.
3
$
8
,
8
8
9
.
6
$
6
,
6
6
1
.
8
$
6
,
7
0
5
.
9
$
7
,
7
4
0
.
9
$
9
,
9
5
7
.
8
$
1
0
.
0
1
7
.
8
$
9
,
4
1
6
.
5
$
9
.
9
0
7
.
4
$
9
,
7
2
2
.
7
$
1
0
.
0
4
2
.
0
$
1
0
6
,
9
4
7
.
6
29
.
9
9
8
.
4
2
8
.
7
5
4
.
2
3
4
,
1
1
1
.
6
3
0
,
7
6
2
.
6
$
5
5
4
.
3
$
5
2
6
.
6
$
6
1
7
.
9
$
5
6
3
.
1
$
15
4
,
2
1
2
.
6
1
4
1
,
4
1
1
.
2
1
5
3
.
1
5
0
.
6
9
4
,
1
8
3
.
4
$
4
,
7
1
2
.
5
$
4
,
3
1
8
.
4
$
4
,
6
8
3
.
2
$
2
,
8
8
2
.
9
$
0.3 0.
0
$
31
4
.
2
$
31
4
.
3
$
27
.
8
9
3
.
4
30
.
0
5
4
.
1
57
.
9
4
7
.
5
$$$
83
0
.
7
$
1.
5
9
3
.
0
$
2.
4
2
3
.
7
$
$$$$
22
4
,
4
0
3
.
7
7,
8
7
8
.
1
$
22
4
.
4
$
7.
6
5
3
.
7
$
0.
3
0.
0
$
28
6
.
3
$
28
6
.
3
$
$$$
3,6
8
9
.
2
23
.
1
9
3
.
1
26
,
8
8
2
.
3
10
6
.
8
$
1.
2
3
4
.
1
$
1.
3
4
1
.
0
$
38
7
,
4
7
1
.
8
13
,
4
3
7
.
5
$
38
7
.
5
$
13
,
0
5
0
.
1
$
$
0.3 0.
0
$
31
4
.
2
$
31
4
.
3
$
$$$
1.3
5
7
.
6
25
,
7
1
5
.
8
27
,
0
7
3
.
4
31
.
9
$
1,
0
0
8
.
9
$
1,
0
4
0
.
8
$
46
5
,
5
6
5
.
9
15
,
8
7
2
.
4
46
5
.
6
15
,
4
0
6
.
8
$
1.
3
0.
1
$
30
4
.
9
$
30
5
.
0
$
$$$
2.
0
2
8
.
1
27
,
0
8
6
.
1
29
,
1
1
4
.
2
59
.
4
$
1,
0
6
2
.
9
$
1,
1
2
2
.
4
$
39
6
.
0
0
5
.
7
$
1
2
,
5
0
2
.
7
$
$
3
9
6
.
$
$
1
2
,
1
0
6
.
6
$
$
9
,
7
4
3
.
0
$
1
,
9
1
5
.
6
$
1
3
9
.
0
$
(
5
7
1
.
4
)
$
1.
2
3
7
.
8
7
8
.
8
1
,
0
5
6
,
9
1
2
.
3
1
,
0
2
8
,
8
0
8
.
2
9
4
6
.
1
1
4
.
5
$
82
1
.
9
15
.
2
$
24
,
5
5
2
.
1
45
8
.
3
$
36
.
7
5
0
.
8
65
8
.
8
$
37
.
3
0
0
.
0
3
5
,
8
8
9
.
0
3
7
,
7
6
5
.
0
3
6
,
7
2
1
.
6
3
7
,
4
8
2
.
3
3
7
0
,
9
0
9
.
6
66
7
.
4
$
8
4
2
.
7
$
6
7
4
.
6
$
6
5
5
.
5
$
6
7
0
.
2
$
6
,
7
0
4
.
6
74
,
0
9
6
.
6
1
3
6
,
8
2
9
.
0
1
6
8
,
9
8
3
.
0
1
7
1
,
3
9
7
.
3
1
6
3
.
0
2
9
.
9
1
7
1
.
1
9
0
.
3
1
7
2
,
0
2
5
.
0
1
7
5
,
8
3
9
.
3
1
,
7
7
6
.
3
4
8
.
2
2,
2
7
3
.
4
$
4
,
1
9
4
.
5
$
5
,
1
3
0
.
4
$
5
,
1
9
8
.
3
$
4
,
9
5
1
.
6
$
5
.
1
9
3
.
1
$
5
,
2
0
4
.
0
$
5
,
3
2
3
.
5
$
5
4
.
0
6
5
.
9
$
31
4
.
2
$
31
4
.
2
$
$$$
22
,
1
3
0
.
7
30
.
8
0
6
.
6
52
.
9
3
7
.
3
88
2
.
7
$
1,
2
0
7
.
5
$
2.
0
9
0
.
2
$
31
3
,
6
4
4
.
7
8,
9
0
3
.
9
$
31
3
.
6
$
8,
5
9
0
.
3
$
$
2,
8
0
8
.
6
$
1,1
2
5
.
6
2
1
.
0
Th
e
r
m
a
l
G
e
n
e
r
a
t
i
o
n
(
M
W
h
)
(
B
r
,
B
o
.
V
)
Hy
d
r
o
G
e
n
e
r
a
t
i
o
n
(
M
W
h
)
Co
m
b
u
s
t
i
o
n
T
u
r
b
i
n
e
(
M
W
h
)
To
t
a
l
M
a
r
k
e
t
P
u
r
c
h
a
s
e
s
(
M
W
h
)
To
t
a
l
M
a
r
k
e
t
S
a
l
e
s
(
M
W
h
)
To
t
a
l
T
h
e
r
m
a
l
U
n
i
t
F
u
e
l
C
o
s
t
s
(
$
0
0
0
)
To
t
a
l
M
a
r
k
e
t
P
u
r
c
h
a
s
e
s
(
$
0
0
0
)
To
t
a
l
M
a
r
k
e
t
S
a
l
e
s
(
$
0
0
0
)
Ne
t
P
o
w
e
r
S
u
p
p
l
y
C
o
s
t
s
(
$
0
0
0
)
Co
a
l
Ga
s
pu
r
c
h
a
s
e
d
P
o
w
e
r
Su
r
p
l
u
s
S
a
l
e
s
7,
1
6
9
,
6
0
1
8,
6
6
2
,
4
2
4
42
.
5
5
2
66
1
,
2
1
3
2,
7
5
5
,
6
4
6
17
0
.
0
7
5
37
,
0
8
6
95
,
3
9
8
11
1
,
7
6
3
1.1 0.
1
$
30
4
.
9
$
30
5
.
0
$
$$$
49
.
7
7
0
.
7
63
,
9
1
9
.
2
11
3
,
6
8
9
.
8
1.
6
9
0
.
9
$
4.
7
0
1
.
6
$
6.
3
9
2
.
5
$
24
5
,
7
1
1
.
8
6,
8
6
3
.
2
$
24
5
.
7
$
6,
6
1
7
.
5
$
$
12
,
4
7
3
.
7
$
1,
2
9
0
.
2
2
9
.
2
14
,
6
9
9
.
4
80
1
.
0
$
31
4
.
2
$
1,
1
1
5
.
2
$
$$$
4.
6
5
1
.
7
25
4
.
7
$
$
25
4
.
7
$
21
1
,
8
3
2
.
5
67
.
6
3
6
.
3
27
9
,
4
6
8
.
8
14
,
0
7
5
.
5
$
5.
2
9
5
.
0
$
19
,
3
7
0
.
4
$
33
,
3
8
5
.
8
1,
1
7
1
.
9
$
33
.
4
$
1,
1
3
8
.
5
$
$
35
,
3
4
8
.
9
$
1,5
7
8
,
4
7
7
1
14
.
7
5
8
.
7
82
1
.
7
$
31
4
.
2
$
1,
1
3
6
.
0
$
7,3
8
0
.
4
41
0
.
9
$
$
41
0
.
9
$
21
1
,
8
1
1
.
0
61
,
2
7
7
.
4
27
3
.
0
8
8
.
5
11
,
9
3
3
.
6
$
4,
8
6
2
.
4
$
16
.
7
9
6
.
1
$
21
.
3
7
1
.
2
72
5
.
1
21
.
4
70
3
.
7
$
14
1
.
4
7.
9
$
30
4
.
9
$
31
2
.
8
$
25
.
7 1.
4
$
$
1.
4
$
61
,
7
3
0
.
4
22
,
0
1
0
.
0
83
,
7
4
0
.
4
3,
0
2
6
.
1
$
1,
1
8
0
.
4
$
4,
2
0
6
.
5
$
13
6
,
4
4
6
.
3
$
4
.
6
8
8
.
2
$
1
3
6
.
4
$
4
,
5
5
1
.
8
$
40
6
.
3
23
.
2
$
31
4
.
2
$
33
7
.
4
$
57
.
2 3.
3
$
$
3.
3
$
3.
2
5
2
.
9
31
,
1
8
4
.
2
34
,
4
3
7
.
1
16
7
.
5
$
1,
6
6
3
.
1
$
1,
8
3
0
.
5
$
24
4
.
0
9
8
.
6
$
9
,
6
1
7
.
4
$
$
2
4
4
.
1
$
$
9
,
3
7
3
.
3
$
$
19
6
.
6
14
.
5
$
30
4
.
9
$
31
9
.
4
$
27
.
4 2.
0
$
$
2.
0
$
21
,
1
6
9
.
1
29
.
7
4
3
.
0
50
,
9
1
2
.
1
1.
3
7
6
.
6
$
1.
9
0
4
.
4
$
3,
2
8
1
.
0
$
13
6
,
3
0
8
.
6
6,
1
8
8
.
1
13
6
.
3
6,
0
5
1
.
8
$
18
5
.
8
14
.
5
$
31
4
.
2
$
32
8
.
7
$
18
.
6
1.
5
$
$
1.
5
$
44
,
5
4
7
.
2
36
.
9
1
7
.
3
81
,
4
8
4
.
5
2,
9
0
4
.
0
$
2.
3
5
7
.
5
$
5.
2
6
1
.
6
$
15
1
,
2
3
2
.
6
$
7
,
5
4
9
.
3
$
$
1
5
1
.
2
$
$
7
.
3
9
8
.
0
$
$
30
.
3
9
1
.
5
1,
6
8
2
.
9
3.
7
0
5
.
8
5,
3
8
8
.
7
12
,
1
6
0
.
9
67
3
.
8
67
3
.
8
66
1
,
2
1
2
.
8
44
9
,
5
4
3
.
2
1.
1
1
0
,
7
5
6
.
0
37
,
0
8
5
.
7
28
,
0
7
0
.
9
65
,
1
5
6
.
6
2,7
5
5
,
8
4
6
.
4
'9
5
,
3
9
7
.
8
2,
7
5
5
.
6
92
.
6
4
2
.
1
$
33
.
5
2
2
.
7
$
1
4
,
9
7
9
.
8
$
8
,
5
7
3
.
0
$
1
3
.
1
3
2
.
8
$
1
4
,
2
2
9
.
4
1
$
1
4
6
,
2
9
5
.
0
I
1,
4
8
8
,
0
7
5
.
1
1
.
1
3
2
,
2
4
2
.
5
1
,
0
0
4
,
9
2
6
.
0
1
,
0
4
8
.
7
8
3
.
8
1
,
2
9
1
.
6
1
8
.
2
1
4
.
2
2
9
.
6
8
6
.
8
Ji
m
B
r
i
d
g
e
r
Va
l
m
y
Bo
a
r
d
m
a
n
Da
n
s
k
i
n
Be
n
n
e
t
t
M
t
20
0
3
N
o
r
m
a
l
i
z
e
d
C
o
s
t
(
$
0
0
0
)
Jim
B
r
i
d
g
e
r
Va
l
m
y
Bo
a
r
d
m
a
n
Da
n
s
k
i
n
Be
n
n
e
t
t
M
t
5,
0
2
2
,
3
4
3
1.
7
7
6
.
3
4
8
37
0
,
9
1
0
30
,
3
9
1
12
,
1
6
1
10
6
,
9
4
8
54
,
0
6
6
6,
7
0
5
1,
6
8
3
67
4
$
1
6
7
.
7
1
8
.
0
8
4
$
6
,
0
6
2
.
4
7
2
$
6
5
.
1
5
6
.
5
8
9
$
1
,
5
3
3
.
0
1
2
t
r
a
n
s
l
o
s
s
e
s
$
9
2
.
6
4
2
.
1
1
4
$
6
6
,
6
8
9
.
6
0
1
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 11TH DAY OF MARCH 2010,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. IPC-E-IO-01, BY MAILING A COpy THEREOF, POSTAGE PREPAID, TO
THE FOLLOWING:
BARTON L KLINE
LISA D NORDSTROM
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
E-MAIL: bkline(gidahopower.com
lnordstrom(ßidahopower .com
PETER J RICHARDSON
GREGORY ADAMS
RICHARDSON & O'LEARY
PO BOX 7218
BOISE ID 83702
E-MAIL: peter(ßrichardsonandolear.com
greg(ßrichardsonandoleary.com
GREGORY W SAID
DIRECTOR OF STATE REGULATION
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
E-MAIL: gsaid(ßidahopower.com
DR. DON READING
6070 HILL ROAD
BOISE ID 83703
E-MAIL: dreading(ßmindspring.com
Jo~_
SECRETAR
CERTIFICATE OF SERVICE