20101122Widmer Corrrected Di.pdf

Jean D. Jewell
Commission Secretar
Idaho Public Utilities Commission
472 W . Washington
Boise,ID 83702
Re: Case No. PAC-E-IO-7
W. MARCUS W. NYE
RANDALL C. BUDGE
JOHN A. BAILEY, JR.
JOHN R. GOODELL
JOHN B. INGELSTROM
DANIEL C. GREEN
BRENT O. ROCHE
KIRK B. HADLEY
FRED J. LEWIS
MITCHELL W. BROWN
ERIC L. OLSEN
CONRAD J. AIKEN
RICHARD A. HEARN, M.D.
DAVID E. ALEXANDER
LANE V. ERICKSON
PATRICK N. GEORGE
SCOTT J. SMITH
STEPHEN J. MUHONEN
BRENT L. WHITING
JUSTIN R. ELLIS
JOSHUA D. JOHNSON
JONATHON S. BYINGTON
DAVE BAGLEY
CAROL TlPPI VOLYN
THOMAS J. BUDGE
CANDICE M. McHUGH
JONATHON M. YOLYN
MARK A. SHAFFER
JASON E. FLAIG
FI:RRELL S. RYAN
Dear Ms. Jewell:
LAW OFFICES OF
RACINE OLSON NYE BUDGE Be BAILEY
CHARTERED
POCATELLO OFFICE
201 EAST CENTER STREET
POST OFFICE BOX 1391
POCATELLO, IDAHO 83204
TELEPHONE: [phone]
FACSIMILE: (208) 232-6109101 SOUTH CAPITOL BOULEVARD
SUITE 208
BOISE, IDAHO 83702
IOAHO FALLS OFFICE
477 SHOUP AVENUE
SUITE 203A
IDAHO FALLS, 1083402
TELEPHONE: [phone]
FACSIMILE: [phone]
TELEPHONE [phone]
FACSIMILE [phone]
WWW.RACINELAW.NET
SENDER'S E-MAIL ADDRESS:
ELOCQRACIN ELAW.NET COEUR O'ALENE OFFICE
250 NORTHWEST
BOULEVARD, SUITE 106A
COEUR D'ALENE, IDAHO 83814
TELEPHONE: [phone]
ALL O....ICES TOLL FRIl
[phone]
LOuis F. RACINE (1917-2005)
WILLIAM D. OLSON, OF
COUNSEL
October 28, 2010 t;-c:
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Please find enclosed for fiing an original and nine copies of the following fied on behalf
of Monsanto Company:
1. Errata Sheet to Direct Testimony of Mark l. 'Widmer;
2. Confidential Corrected Direct Testimony of Mark T. Widmer;
3. Public Corrected Direct Testimony of Mark T. Widmer; and
4. Proof of Service.
The Confidential Testimony wil only be served on paries who signed the Confidentiality
Agreement. Also enclosed is a CD containing an electronic copy of these new filings.
Than you for your assistance.
RCBe
Enclosures
c: Service List
~incereiy, ¿ . .~£~~
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BEFORE THE IDAHO PUBLIC SERVICE COMMSSION
IN THE MATTER OF THE APPLICATION OF )
ROCKY MOUNTAIN POWER FOR )
APPROVAL OF A GENERAL RATE )INCREASE OF )
)
)
)
)
DOCKET NO. ID PAC-E-IO-07~~~;;
t1
ERRTA SHEET TO
DIRECT TESTIMONY OF
MAT. WIMER
ON BEHAF OF
MONSANO
This Errata Sheet is provided to set forth the corrections listed below to the Direct
Testimony of Monsanto Company Witness Mark Widmer. The Corrected Direct Testimony of
Witness Widmer is fied herewith to amend and supersede his Direct Testimony filed November
1, 2010 and reflect the corrections, to wit:
Page 3 - Table 1
Black Hils Shaping adjustment -1,321,425 should be changed to -1,293,489 and -78,400
should be changed to -76,743
Total Adjustments of -47,374,707 should be changed to -47.346,771 and -2,565,628 should
be changed to -2,563,970
Est. Allowed of 1,022,326,607 should be changed to 1,022,354,544 and 60,899,751 should
be changed to 60,901,409
Page 5 line 2 $0.38 should be changed to $0.35
Page 5 line 7 $0.16 should be changed to$0.14
Page 5 line 15 $0.65 should be changed to $0.14
Page 7 line12 $0.02 should be changed to $0.20
Page 18 line 33.1 should be changed to 2.69
Page 18 line 4 7 should be changed to 6
Page 24 line 7 5 should be changed to 4
Page 24 line8 5 should be changed to 4
Page 24 line 10 4 should be changed to 3
Page 26 lines 10 and 19390 should be changed to 395
Page 26 line 16369.6 should be changed to 374.3
Page 26 line17 362.5 should be changed to 367.2
Page 27 line 16 strike are not economic and
9-ø~.~
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BEFORE THE IDAHO PUBLIC SERVICE COMMSSION
IN THE MATTER OF THE APPLICATION OF )
ROCKY MOUNTAIN POWER FOR )
APPROV AL OF A GENERAL RATE )INCREASE OF )
)
)
)
)
DOCKET NO. ID PAC-E-IO-07
CORRCTED
DIRECT TESTIONY OF
MA T. WIMER
ON BEHAF OF
MONSANTO
November 1, 2010
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1.ri.e.-i
(
1 TABLE OF CONTENTS
2 i. INTRODUCTION AND QUALIFICATIONS
3
4 II. PURPOSE OF TESTIMONY AND SUMMARY OF ADJUSTMENTS
5
6 III. DETAILED ADJUSTMENTS
7
8 Adjustment 1 APS Supplemental
9 Adjustment 2 Wind Integration Costs
10 Adjustment 2a OATT Wind Integration Costs
11 Adjustment 2b Balancing Wind Integration Costs
12 Adjustment 3 Non-Firm Transmission
13 Adjustment 4 Dunlap Reserve Requirement
14 Adjustment 5 Reserve Shutdowns
15 Adjustment 6 Top of World
16 Adjustment 6a Top of World Incremental Wind Integration
17 Adjustment 7 Cal ISO
18 Adjustment 8 Colstrip Planed Outages
19 Adjustment 9 Energy Gateway Transmission
20 Adjustment 10 Cholla 4 Capacity
21 Adjustment 11 Morgan Stanley Calls Premiums
22 Adjustment 12 Bear River Hydro Normalization
23 Adjustment13 Black Hils Shaping
24 Adjustment 14 Mona Market
25 Adjustment 15 Naughton 3 Outage
26
27
28 Appendix A
29 Exhibit 228 (MW -1)
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i I. INRODUCTION AN QUALIFICATIONS
PLEASE STATE YOUR NAM AN BUSINESS ADDRESS.2 Q.
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My name is Mark T. Widmer and my business address is 27388 S.W. Ladd Hil Road,
Sherwood, Oregon 97140.
PLEASE STATE YOUR OCCUPATION, EMPLOYMNT, AND ON WHOSE
BEHAF YOU AR TESTIFYG.
I am a utilty regulatory consultant and Principal of Northwest Energy Consulting, LLC
("NWEC"). I am appearing on behalf of Monsanto.
PLEASE SUMZE YOUR QUALIFICATIONS AN APPEARCES.
With NWEC, I provide consulting services related to electric utilty system operations,
energy cost recovery issues, revenue requirements, and avoided cost pricing for
qualifying facilties. Since forming NWEC, I have provided testimony in dockets
regarding recovery of net power costs through general rate cases and power cost
adjustment mechanisms and avoided cost methodologies in Wyoming and net power
costs and the prudence of resource acquisitions in Washington. Prior to forming NWEC,
I was employed by PacifiCorp. While employed by PacifiCorp, I participated in and fied
testimony on power cost issues in numerous dockets in Wyoming, Oregon, Utah,
Washington, Idaho, and California jurisdictions over a 10 plus year period. At the time
of my depare from PacifiCorp, I was the Director of Net Power Costs. My full
qualifications and appearances are provided in Exhibit Monsanto 228 (MW -1).
Widmer, DI (corrected) - Page 1
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PURPOSE OF TESTIMONY AN SUMY OF ADJUSTMENTS
WHT is TH PUROSE OF YOUR TESTIMONY?
My testimony addresses PacifiCorp's Generation and Regulation Initiatives Decision
("GRID") model which was used to calculate normalized Net Power Costs ("NPC") for
the forecast test period ending December 31, 2010.
PLEASE SUMZE YOUR TESTIMONY.
My testimony presents fifteen NPC adjustments totaling $47.37 milion total Company
and $2.57 milion Idaho. As discussed in my following testimony, those adjustments are
made to reflect realistic operation of PacifiCorp's system, match costs with benefits,
make corrections and reflect reasonable results. My adjustments are summarized on
Table 1 below and subsequently explained in more detail in the remainder of my
testimony.
Widmer, DI (corrected) - Page 2
~
1
Table 1
Summary of Recommended Adjustments - $
Est. Allowed - NPC Primary Recommendation
Primary Secondary
Total Recommendation Recommendations
Company Idaho Est.Idaho Est.
1,069,701,315 63,465,379
-1,942,838 -115,269
-34,187,931 -1,883,242
-6,361,994 -350,450
-2,629,076 -144,823
-2,432,988 -144,349
127,222 7,548
-807,546 -47,912
1,550,033 91,963
285,266 15,714
-4,041,991 -222,653
-258,678 -15,347
3,291,265 195,271
-1,113,498 -66,064
-3,057,000 ,.-168,395
-2,181,474 -129,427
-1,293,489 -76,743
-438,529 -26,018
-559,329 -33,185
69,851
-2,563,970
60,901,409
GRID (Net Variable Power Cost Issues)
PacifiCorp Request NPC
ADJUSTMENTS
1 APS Supplemental (Coal +Other)
2 Wind Integration Costs
2a ÒATTWind integration Costs
2b Balancing Wind Integration Costs
3 Non-Firm Transmission
4 Dunlap Reserv Requirement
5 Reserv Shutdowns
6 Top of World Wind
6a Top of World Incremental Wind Integration7CaiiSO . .
. 8 Colstrip Planned Outages
9 Energy Gateway Transmission
10 Cholla 4 Capacity
11 Morgan Stanley Call Premiums
12 Bear Rii.r Hydro Normalization
13 Black Hils Shaping
14 Mona Market
15 Naughton 3 Outage
Allocation True-UP
Total Adjustilents Primary Re.commendation
2
Est. Idaho Jurisdiction
SÊ: 6.3575%
SG: 5.5085%
3
4 Adjustment 1.APS SUPPLEMENTAL OPTION
5 The Company has an option to purchase supplemental energy offered pursuant to
6 the Long Term Power Transaction Agreement with Arzona Public Service ("APS").
7 While the option is continually exercised during actual operations, it is uneconomic as
Widmer, DI (corrected) ~ Page 3
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modeled in GRID. Since the purchase is optional and uneconomic it should be excluded
from NPC. This adjustment reduces NPC by $0.12 milion on an Idaho basis.
Adjustment 2. WI INEGRATION COSTS
The Company used the wind integration rate of $6.50 per MWh that was adopted by the
Commission for avoided cost rates for qualifying facility contracts to calculate wind
integration costs. This rate has no basis on the Company's actual wind integration costs
and the Company has therefore, not met its burden of proof regarding recovery of wind
integration costs. Consequently, I recommend that the Commission reject recovery of
wind integration costs using the $6.50 per MWh rate and recommend that wind
integration costs be recovered through the Company's ECAM as it is the best solution to
recovering actual wind integration costs. This adjustment reduces NPC by $1.88 milion
on an Idaho basis. I also recommend that the Commission adopt the premise of my
secondary adjustment 2a OATT Wind Integrations Costs, so that the Company not be
allowed to recover wholesale wheeling customer wind integration costs from retail
customers through the ECAM. If the Commission does not adopt my proposed
recommendation, my secondar recommendation is to adopt the following adjustments
2a OATT Customer Wind Integration Costs and 2b Balancing Wind Integration Costs.
Adjustment 2a.OATT CUSTOMER WI INEGRATION COST
The Company included wholesale wheeling customer wind integration costs in
NPC because the Company has failed to request an adjustment to their OATT so that
these costs can be recovered from wholesale wheeling customers. These costs are not the
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responsibilty of Idaho customers and should be removed from NPC. This adjustment
reduces NPC by $0.35 milion on an Idaho basis.
Adjustment 2b.BALANCING WID INEGRATION COSTS
The Company double counted wind integration balancing costs during the period
Januar 2010 through April 2010. This adjustment removes the double count and lowers
NPC by $0.14 millon on an Idaho basis.
Adjustment 3.NON-FI TRASMISSION
In actual operations the Company utilzes a significant amount of non-firm
transmission to use of assets included in rates more efficiently in the system balancing
and optimization process. However, non-firm transmission was excluded from NPC,
thereby producing a suboptimal dispatch of the system and higher net power costs. I
recommend that non-firm transmission be included in GRID to match costs and benefits.
This adjustment reduces NPC by $0.14 milion on an Idaho basis.
Adjustment 4.DUNAP RESERVE REQUIMENT
This adjustment incorporates the costs of carring operating reserves for Dunlap,
which were omitted from the original fiing and increases NPC by $0.01 milion on an
Idaho basis.
Adjustment 5.RESERVE SHUDOWN EFOR COMPONENT
The Company's inclusion of reserve shutdowns in the GRID forced outage rate
calculation input causes an overstatement of generation lost due to forced outages
Widmer, DI (corrected) - Page 5
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because the calculation is inconsistent with how GRID calculates generation lost due to
forced outages. I recommend exclusion of reserve shutdowns from the forced outage rate
calculation for all plants except for natural gas peaker units. This adjustment reduces
NPC by $0.05 milion on an Idaho basis.
Adjustment 6.TOP OF WORLD WIND
During the discovery process the Company informed Monsanto that the expected
online date for the Top of the World wind project had been moved forward from
November 1, 2010 to October 1,2010. This adjustment includes the new online date and
increases NPC by $0.09 milion on an Idaho basis.
Adjustment 6a.TOP OF WORLD INCREMENTAL WI INEGRATION
If the Commission does not adopt my primary recommendation to recover wind
integration costs through the ECAM, this adjustment includes incremental integration
costs associated with moving the expected in service date from November 1, 2010 to
October 1,2010.
Adjustment 7.CAL iso EXPENSES
The filing includes a full year estimate of Cal ISO wheeling and service fees.
However, the filing does not include any transactions that would incur CAL iso fees'
beyond May 3, 2010. Accordingly, I recommend disallowance of all Cal ISO fees for the
period May 4,2010 through December 31,2010. i also recommend that actual Cal ISO
fees be included for the period prior to May 4, 2010 to match costs with the actual
Widmer, DI (corrected) - Page 6
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wholesale transactions included in the fiing. This adjustment reduces NPC by $.22
milion on an Idaho basis.
Adjustment 8. COLSTRIP PLAND OUTAGES
This adjustment moves the planed outage staring dates for Colstrip 3 and Colstrip 4
from September to May to better optimize the Company's system.
The revised planed outage dates reduce NPC on an Idaho basis by $0.02 milion.
.
Adjustment 9.ENERGY GATEWAY TRASMISSION
This adjustment removes the Energy Gateway transmission project from NPC to be
consistent with Mr. Peseau' Energy Gateway transmission adjustment and increases NPC
by $0.20 milion on an Idaho basis.
Adjustment 10.CROLLA 4 CAPACITY
The Company's modeling understates Cholla 4 capacity. My adjustment corrects the
capacity ånd reduces NPC by $0.07 milion on an Idaho basis.
Adjustment 11.MORGAN STANEY CALL PREMmS
The Company's filing includes two call option purchase power contracts that are
uneconomic. This adjustment removes both contracts and lowers NPC by $0.17 milion
on an Idaho basis.
Widmer, DI (corrected) - Page 7
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Adjustment 12.BEAR RIR HYRO NORMIZATION
The Bear River historical record was adjusted by the Company to remove flood
control years, which are years when surlus water was released from Bear Lake. The
Company believes the adjustment is reasonable because the region is currently impacted
by a long-term drought and a low water level at Bear Lake. This is one-sided because it
is different than the normalized methodology used to normalize all other hydro resources
and is not appropriate for normalized ratemaking. I recommend that the flood control
years excluded from NPC be included in NPC to be consistent with the modeling of other
hydro resources. My recommendation reduces the NPC by $0.13 milion on an Idaho
basis.
Adjustment 13. Black Hils Sales Shaping
The Company bases its modeling of the Black Hils wholesale sales on the faulty
assumption that Black Hils will dispatch the contract durng the highest costs hours.
Historical dispatch of the contract demonstrates that this is not the case. I recommend
that the contract be dispatched based on a four-year average of historical results. This
adjustment reduces NPC by $0.08 milion on an Idaho basis.
Adjustment 14. MONA MAT
The Company limited the size of the Mona wholesale market, allegedly based on
trading experience of their Front Office. Historical information shows that the Mona
market was significantly undersized. I recommend that the size of the Mona market be
corrected based on a four-year average of actual information. This adjustment reduces
NPC by $0.03 milion on an Idaho basis.
Widmer, DI (corrected) - Page 8
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Adjustment 15.NAUGHTON 3 OUTAGE
The Company collected liquidated damage payments from its contractor Siemens
for failure to complete a contract on schedule due to poor performance. The Company
seeks to recover the cost of this outage again by including it in GRID planed outage
inputs. Accordingly, I recommend that the planed outage be removed from GRID. This
adjustment removes the outage and reduces NPC by $0.03 milion on an Idaho basis.
Finally, in response to Monsanto data request 2.33 the Company stated:
Prior to its rebuttal the Company anticipates additional changes to various
components of the net power costs, including but not limited to the new Official
Forward Price Cure and new short-term firm electricity and natural gas
transactions.
This very late update does not provide the Parties adequate time to review the
significant amount of data tied to the stated update. Therefore, I recommend that the
Commission reject all Company proposed rebuttal updates to NPC except corrections
related to the original filing so that the Paries other than the Company are not
disadvantaged by the late update.
DETAILED ADJUSTMNTS
BEFORE YOU DISCUSS YOUR ADJUSTMENTS IN DETAI, PLEASE
EXPLAI NPC AN ITS IMORTANCE.
NPC is defined as the sum of purchased power expense, wheeling expense and fuel
expense less wholesale sales revenues. Review and determination of the appropriate
NPC is very important because it represents one of the Company's single largest revenue
Widmer, DI (corrected) - Page 9
1 requirement components and establishes the ECAM baseline. NPC is calculated by the
2 Company's GRID production dispatch modeL.
3
4 Adjustment 1.
5 ENERGY
6 Q.
7 A.
ARONA PUBLIC SERVICE (" APS") SUPPLEMENTAL
PLEASE EXPLAI THE APS SUPPLEMENTAL ADJUSTMENT.
Pursuant to the terms of the Long-Term Power Transactions Agreement between APS
8 and PacifiCorp, APS is required to offer PacifiCorp 219 GWH of Supplemental Coal
9 Energy and 876 GWH of Other Supplemental Energy through October 31, 2020, when
10 the contract expires. The Company has the option but not the requirement to purchase
11 either the Supplemental coal or Other Supplemental energy or both at prices offered by
12 APS for each product.
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IS THE CONTRACT ECONOMIC AS MODELED IN GRID?
No. Both the Other Supplemental and the Supplemental Coal components are modeled
uneconomically in GRID.
HOW DID YOU DETERM THE CONTCT WAS UNCONOMIC?
I ran the GRID model without the Supplemental Coal and Other Supplemental energy.
The rus reduced NPC by approximately $1.95 milion total Company. The contract is
therefore uneconomic for customers as modeled by the Company and should be excluded
from NPC. This adjustment reduces the NPC by $0.12 milion on an Idaho basis.
Widmer, DI (corrected) - Page 10
1 Q.HAS TH COMPAN AGREED TO TIS METHODOLOGY IN OTHER
2 JUSDICTIONS?
3 A.Yes. In the stipulation for Oregon Docket UE 216, the Company agreed to model the
4 APS Supplemental Coal and Other option contract only when economic for future filings.
5
6 Adjustment 2.
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WI INTEGRATION COSTS
HAS THE COMPAN MET ITS BUREN OF PROOF ON WI
INEGRATION COSTS?
No. While the Company has done numerous forecasts of wind integration costs over the
last several years, which have varied from a little over $1 per MWH to approximately $9
per MWh for 2011 in a recent draft study, they stil canot tell us what their actul wind
integration costs are. In WIEC Data Request 5.6 from Wyoming Docket No. 20000-352-
EP-09 the Company was asked to provide the actual reserve intra-hour reserve
requirement for wind generation located within their. control area. In response, the
Company stated:
The Company objects to this question on the basis that it is overly burdensome
and would require the Company to perform analysis not previously performed.
Notwthstanding this objection, the Company states as follows.
The Company holds reserves to maintain reliabilty of its system in accordance
with stadards set by the Western Electricity Coordinating CounciL. Reserves
held are not differentiated such that the Company can identify the intra-hour
reserve requirement isolated for wind generation.
Without knowing what the Company's actual costs are it is very diffcult to determine the
reasonableness of Company's requested recovery of $34.2 millon for wind integration
costs.
Widmer, DI (corrected) - Page 11
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24 Q.
is THE COMPAN'S PROPOSED USE OF THE $6.50 PER MW COST OF
WI INEGRATION RATE APPROVED BY THE IDAHO COMMSSION IN
CASE NO. PAC NO.-E-09-07, A REASONABLE SOLUTION TO THE
COMPAN'S LACK OF VERIFILE INFORMTION?
It is a solution, but it is not the best solution, because the adopted wind integration rate is
not based on the Company's system costs. The rate was adopted specifically to be used
in the determination of avoided cost rates. To date the Company has not entered any
Idaho based wind qualifying facilty contracts, so the adoption of the rate for avoided
costs has not placed customers at risk of paying too much. However, requesting recovery
of over $34 millon for wind integration costs in this case based on the $6.50 per MWh
rate is a different matter as it places customers at risk of paying too much.
WHT is YOUR RECOMMNDATION?
The Commission should reject the Company's request for recovery of wind integration
costs using the $6.50 per MWh rate approved for avoided cost rates because their burden
of proof has not been met. Due to the significant size of these costs, recovery should
occur through the ECAM. Only this way can we be assured that actual wind integration
costs is recovered. This adjustment reduces NPC by $1.88 milion on an Idaho basis. I
also recommend that the Commission adopt the premise of my secondary adjustment 2a
OATT Wind Integrations Costs, so that the Company not be allowed to recover
wholesale wheeling customer wind integration costs from retail customers through the
ECAM.
DO YOU BA VE A SECONDARY RECOMMENDATION?
Widmer, DI (corrected) - Page 12
1 A.Yes. If the Commission rejects my recommendation for this adjustment I recommend
2 that the Commission accept my secondary proposed adjustments 2a OATT Wind
3 Integration Costs and 2b. Balancing Wind Integration Costs, which are discussed in my
4 following testimony.
5
6 Adjustment 2a.
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OPEN ACCESS TRASMISSION TARFF (OATT) - WI
INTEGRATION
DOES TH COMPAN'S OATT TARF INCLUDE A CHAGE FOR WI
INTEGRATION
CUSTOMERS?
FOR WHOLESALE TRASMISSIONEXPENSES
No. Despite being aware of wind integration expenses for over six years, based on the
inclusion of such expenses in its 2004 IRP, the Company has not made a filing with the
Federal Energy Regulatory Commission requesting inclusion of such expenses in its
OATT. So, the Company is attempting to recover these costs from retail customers.
SHOULD RETAI CUSTOMERS BE REQUID TO PAY FOR THESE
COSTS?
Of course not. Recovery of these costs from OATT customers is the Company's
responsibilty and they have had over six years to make a filing with FERC that would
allow them to recover such costs. Retail customers should not be burdened with these
costs due to the Company's failure to make such a filing.
Widmer, DI (corrected) - Page 13
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HAS THE COMPAN INICATED IF AN WHN THEY PLAN TO MA A
FILING TO MODIF ITS OATT TO INCLUDE CHAGES FOR WI
INEGRATION SERVICES TO NON-OWND WI FACILITIES?
Yes. In the stipulation for Oregon Docket UE 216 the Company agreed to make a filing
before the Federal Energy Regulatory Commission in June 2011. While the Company
has finally decided to make this filing there is nothing that prevented them from making
the filing at a much earlier date.
AR WI INEGRATION COSTS INCLUDED IN OTHR TRASMISSION
PROVIERS OATT?
Yes. As a matter of fact, the Company pays Bonnevile Power Administration (BPA) for
wind integration costs associated with the Goodnoe and Leaning Juniper wind projects
and has included those costs in the wheeling expense.
HAS FERC PREVIOUSLY ADDRESSED MODIFICATION OF THE OATT?
Yes. In Docket No. ER09-1314-0000, the FERC ruled that applicant, Northwestern
Energy's proposal related to this issue was not superior to its proforma OATT taiff. The
FERC stated that:
Rather than proposing a generator regulation charge to recover capacity costs of
holding additional reserves necessar to meet generator imbalances,
NorthWestern's proposal seeks to eliminate any obligation under its Tariff to
offer such service in the first instace (at least with respect to intermittent
renewable generators exporting energy out of Northwestern's balancing authority
area), Accordingly, we find that Northwestern's proposal is neither consistent
with nor superior to the proforma Tariff. Our determination is without prejudice
to Northwestern proposing to remedy the cost allocation issues discussed in this
proceeding, consistent with the guidance set forth above.
Widmer, DI (corrected) - Page 14
1 Order Rejecting Proposed Tarff Revisions, FERC Docket No. ER09-1314-0000, Order
2 No. 20091110 at paragraph 27 (November 10,2009). The FERC also stated:
3 In its filing, NorthWestern describes a "gap" between its obligations as a
4 balancing authority and its opportunity to recover the costs associated with these
5 obligations under its Tariff. NorthWestern asserts that its Tariff does not contain
6 a mechanism that allows it to recover generator regulation service costs associated
7 with transmission used to export energy from NorthWestern's system, which
8 NorthWestern must incur to meet reliabilty standards. Moreover, Northwestern
9 contends that its native load customers should not be required to subsidize the
10 costs of providing generator regulation service to those generators that export
11 energy from NorthWestern's system. To the extent that NorthWestern is not
12 curently recovering the costs of providing generator regulation service to
13 exporting generators, we agree that a mechanism allowing it to recover those14 costs is appropriate.
15
16 FERC clearly does not believe that retail customers should pay for the costs of wholesale
17 customers either and suggested a mechanism should be allowed to solve the problem. In
18 the interim, retail customers should not be required to pay for these costs. Accordingly, I
19 recommend that such wind integration costs be excluded from NPC because the
20 Company has had ample opportity to request modification of its OATT to recover
21 these costs from the parties that caused the Company to incur these expenses and retail
22 customers should not be burdened for the Company's failure to act. This adjustment
23 reduces NPC by $0.35 milion on an Idaho basis.
24
25 Adjustment 2b.WI INEGRATION COSTS - BALANCING
26 Q.PLEASE EXPLAI THE COMPONENTS OF TH WI INTEGRATION
27 COSTS.
28 A.The wind integration cost is comprised of Inter-hour and Intra-hour costs. Inter-hour cost
29 is the balancing component and consists of pre-scheduling and hour-ahead balancing.
Widmer, DI (corrected) - Page 15
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21 Q.
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23 A.
24
Intra-hour costs are the costs caring load following and regulation reserves for the
variabilty of wind generation. This adjustment focuses on the balancing component.
PLEASE EXPLAI BOW TH COMPAN BALANCES ITS SYSTEM FOR
WI INTEGRATION.
The Company has a variety of options for balancing. In order of most frequent use
balancing is accomplished through hourly firm wholesale transactions, re-dispatch of
wholesale contracts with hourly flexibility, re-dispatch of generation resources, hourly
non-firm wholesale sales transactions and wind curtailment.
DOES TH COMPAN'S FILING INCLUDE A DOUBLE COUN OF WI
INEGRATION BALANCING COSTS?
Yes. The balancing cost component of wind integration is double counted because the
Company's fiing included actual short-term firm transactions for the period Januar 1,
2010 through May 4, 2010, which includes actul hourly firm wholesale transactions
used for wind integration balancing and the Company's separately calculated wind
integration costs using the $6.50 per MWH wind integration rate. This leaves the
question of how to allocate par of the $6.50 per MWh rate to balancing to determine the
amount of the double count.
HOW SHOULD A PORTION OF THE 56.50 MW RATE BE ALLOCATED TO
BALANCING?
The method should be straight forward and based on Company data. With that
clarification I believe we should look to the Company's last completed IRP to determine
Widmer, DI (corrected) ~ Page 16
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an allocation. In that IRP the Company calculated a total wind integration cost of $6.92
per MWH consisting of $2.09 per MWh for balancing and $4.83 for intra-hour
integration. Using this information the balancing component for the $6.50 per MWh rate
can be calculated by dividing $2.09 per MWh by $6.92 per MWh and multiplying that
result (30.2%) times $6.50 per MWh. This produces a double count of $1.96 per MWh.
SHOULD THE 51.96 BE REDUCED FURTHER TO COMPENSATE FOR THE
PORTION OF BALANCING THAT is ACCOMPLISHED BY MEANS OTHER
THA HOURY FIR WHOLESALE SALES TRASACTIONS INCLUDED IN
GRI?
A fuher adjustment could be reasonable if the information were available. However,
the Company stated that there is no official Company estimate of how much balancing is
accomplished through the various means identified above other than to place them in an
order of most to least. Since the Company has previously stated that most of its
balancing occurs through actul hourly wholesale sales transactions, which are included
in GRID, $1.96 per MWh should be used to remove the double count. This adjustment
reduces NPC by $0.14 milion on an Idaho basis.
18
19 Adjustment 3.
20 Q.
NON-FI TRASMISSION
DO YOU AGREE WITH PACIFICORP'S EXCLUSION OF NON-FIR
21 TRASMISSION FROM NPC?
22 A.No. Exclusion of non-firm transmission is not consistent with actual operations and does
23 not provide a match between costs and benefits. If the Company used an immaterial
24 amount of non-firm transmission it may be reasonable to exclude it from normalized
Widmer, DI (corrected) - Page 17
1 results. However, that is not the case. As shown below in Table 2 - PacifiCorp
2 Transmission Utilzation, a substantial amount of non-firm transmission is utilzed.
3 During 2009, non-firm transmission of energy exceeded STF transmission by over 2.69
4 milion MWh or by more than 6 times. It is rather obvious that non-firm transmission is
5 normally relied upon to balance and optimize the Company's system.
2
Transmission Utilzation
Milions MWh
Im
4.62
4.53
13.83
3.57
4 Year 2.76 6.64
6 bubble and transmission already modeled
7
8 Q.WH DOES TH COMPAN UTILIZE NON-FIRASMISSION?
9 A.Non-firm transmission is utilzed to balance and optimize the Company's system. This
10 keeps NPC lower than it would be absent use of non-firm transmission. Lower NPC is
11 accomplished through more effcient use of generation and transmission assets in concert
12 with wholesale transactions and creates more benefits (earnings) for the Company and its
13 shareholders. Since these benefits are derived from assets and expenses already included
14 in rates, non-firm transmission should be included in NPC to match costs with benefits.
15
16 Q.HAS THE INCLUSION OF NON-FIRM TRSMISSION BEEN ADOPTED BY
17 OTHER COMMSSIONS OR BEEN AGREED TO BY THE COMPAN?
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A. Yes. Inclusion of non-firm transmission has been adopted in the Company's two largest
jurisdictions, Utah and Oregon, The Utah Commission adopted non-firm transmission in
Docket No. 07-035-93. More recently, in the stipulation for Oregon Docket UE-216, the
Company agreed to include non-firm transmission links and costs in all futue fiings
using a four-year average.
Q. WHT is YOUR RECOMMNDATION FOR NON-FIR TRASMISSION?
A. Non-firm transmission links and costs should be modeled in GRID using the same four-
year average used to normalize thermal generation. This wil match costs and benefits
and thereby allow customers to receive the full benefits of the system they are paying for
in rates. The adjustment reduces NPC by $0.14 milion on an Idaho basis.
Adjustment 4. DUNAP RESERVE REQUIREMENT
Q. PLEASE EXPLAI THE DUNAP RESERVE REQUIMENT ADJUSTMENT.
A. The Company did not model the Dunlap wind project as having an operating reserve
requirement. This adjustment includes the operating reserve requirement for Dunlap and
increases NPC by $0.01 milion on an Idaho basis.
Adjustment 5. RESERVE SHUDOWNS
Q. PLEASE DEFI RESERVE SHUDOWNS.
A. Reserve shutdown. is a state in which a thermal unit was available for service but not
electrically connected to the grid for economic reasons.
Widmer, DI (corrected) - Page 19
1 Q.
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3 A.
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14 A.
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22 Q.
23
HOW AR RESERVE SHUDOWNS USED IN THE COMPAN'S
CALCULATION OF FORCED OUTAGE RATE INUTS FOR GRID?
The Company's forced outage rate calculation excludes reserve shutdown hours from the
denominator. The formula is as follows:
Forced outage rate = total lost hours / total possible hours less planned outages
and reserve shutdowns
Total lost hours is the sum of forced deratings, forced outages, maintenance deratings,
maintenance outages and planed deratings. Total possible hours is the sum of hours in
the period multiplied by the each thermal plants maximum dependable capacity.
DOES THE COMPAN'S RESERVE SHUDOWN ADJUSTMENT
COMPONENT OF THE FORCED OUTAGE RATE CALCULATION PRODUCE
REASONABLE RESULTS?
No. The Company's forced outage rates are inconsistent with GRID's calculation of
generation lost due to forced outages because of inconsistencies between the two
calculations. In GRID forced outage rates are applied to the units' total possible
generation before reserve shutdowns and afer planned outages, while the Company's
forced outage rates used as an input to GRID are calculated after reserve shutdowns and
planed outages. Due to this difference, the Company's proposed forced outage rates
produce too much lost generation when used as an input in GRID.
BA VE YOU PREPARD AN EXALE TO DEMONSTRATE HOW THE
OVERSTATEMENT OCCUR?
Widmer, DI (corrected) - Page 20
1 A.
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10 Q.
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14 A.
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19 Q.
20 A.
21
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24
Yes. The overstatement is demonstrated in the following example. Let us assume a
generation unit had lost generation of 8,000 MWh due to forced outages, total possible
generation of 87,600 MWh, no planed outages, and 3,000 MWh of reserve shutdown.
Using the Company's methodology this would produce a forced outage rate of 9.456%
(8,000/ (87,600-3,000)). However, in GRID the 9.456% forced outage rate would
produce lost (derated) generation of 8,284 MWh (87,600*9.456%) or 284 more MWh of
lost generation. The bottom line is that the Company's formula is not the appropriate
formula to calculate forced outage rates that will be used as an input to GRID.
WOULD ELIMATION OF THE RESERVE SHUOWN ADJUSTMNT
FROM THE DENOMIATOR OF THE COMPAN'S FORCED OUTAGE RATE
CALCULATION MEAN THAT RESERVE SHUDOWNS AR EXCLUDED
FROMNPC?
Not at all. The Company's daily screen modeling in GRID specifically identifies when
CCCTs are available but are not economic to ru and essentially places them on reserve
shutdown so they canot ru. Therefore, reserve shutdowns would stil be modeled in
NPC.
WHT IS YOUR RECOMMNDATION FOR RESERVE SHUDOWNS?
The Company's forced outage rate calculation is inconsistent with the GRID calculation
of generation lost due to forced outages and consequently produces too much lost
generation. To correct this problem the Company's forced outage rate calculation should
be revised by removing the adjustment for reserve shutdowns. This adjustment reduces
NPC by approximately $0.05 milion on an Idaho basis.
Widmer, DI (corrected) - Page 21
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Adjustment 6. TOP OF WORLD WID IN SERVICE DATE
Q. PLEASE EXPLAI THE TOP OF WORLD WI ADJUSTMENT.
A. During discovery the Company informed Monsanto that the in-service date for this
project was now expected to be October 1, 2010 instead of November 1, 2010. This
adjustment moves the in-service date to October 1, 2010 and increases NPC by $0.09
milion on an Idaho basis.
Adjustment 6a. TOP OF WORLD INCREMENTAL WI INEGRATION
Q. PLEASE EXPLAI TmS ADJUSTMENT.
A. As I previously discussed in this testimony, my primar recommendation is to remove
wind integration costs from the Company's filing so that they are recovered through the
ECAM. If my primar recommendation is not adopted this adjustment wil include the
incremental wind integration costs associated with the one additional month that the Top
of World wind project is expected to be in-service during 2010.
Adjustment 7. CAL iSO FEES
Q. DOES THE COMPAN'S FILING INCLUDE A FUL NORMIZED YEAR OF
CAL ISO WHELING AN SERVICE FEES?
A. Yes. NPC includes $4.7 milion of these fees on a total Company basis. However, as
explained later in my testimony, a significant portion of these fees are not economic
because there are no wholesale transactions that rely on the Cal iso beyond May 3, 2010.
Q. WH AN WHN DOES PACIFICORP INCUR THESE FEES?
Widmer, DI (corrected) - Page 22
1 A.
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20 Q.
21
22
23 A.
24
25
26
27 Q.
28
These fees are incurred when the Company uses the Cal iso system to balance and
optimize its system. In other words, the fees are incurred when PacifiCorp believes the
associated wholesale transactions produce an incremental benefit above the fees. Some
of the fees are related to the Company's strategy to hedge their long position at Four
Corners. As explained in Mr. Duvall's testimony from Wyoming Docket No. 20000-
352-ER-09:
Sales at SP-15 are made to hedge the Company's long position at Four Corners.
This occurs when the Company has a desire to hedge its fixed price exposure but
the Four Corners Market is iliquid. A portion of these transactions are financial
hedges and do not require physical delivery of power. However, if the hedges are
physical products, at a time closer to delivery when the Four Corners market
becomes more liquid, the Company would sell at Four Corners and buy at SP-15.
Alternatively, the Company may wheel power from Four Corners to SP-15 to
close the SP-15 physical positions in the hour-ahead market if transmission were
available and it is more economical to do so.
Fees can also be incured with other balancing and optimizing transactions with the Cal
iso.
DOES THE COMPAN'S NPC INCLUDE AN WHOLESALE TRASACTIONS
THAT COULD INCUR CAL iSO FEES AN PRODUCE A MATCIDG
BENEFIT?
Yes. The fiing included actual STF transactions from January 1,2010 through May 3,
2010. However, after May 3, 2010 the filing did not include any wholesale transactions
with the CAL iso.
WH DOESN'T THE FIING INCLUDE AN WHOLESALE TRASACTIONS
THAT COULD INCUR CAL ISO FEES?
Widmer, DI (corrected) - Page 23
1 A.
2
3
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10
11
12
Historical records reveal that most of the transactions with the Cal iso as a counter pary
are incurred shortly before or on the actual day of delivery. Due to the Company's use of
a forecast test period and the fact that the filing was made many months prior to the end
of the forecast test year, transactions that would incur Cal iso wheeling and service fees
had not occured in most months at the time of filing. As a result, NPC includes a full
year of Cal iso costs, but only wholesale transactions that would generate the Cal iso
expense prior to May 4, 2010. For this reason, i recommend that all Cal iso fees
included in the filing for the period May 4, 2010 through December 31, 2010 be excluded
from NPC. In addition, I recommend that actual Cal iso fees be used for the period
Januar 1, 2010 through May 3, 2010 to match with the actual wholesale transactions
already included in the fiing that caused the actual Cal iso costs to be incurred. This
adjustment reduces NPC by $0.22 milion on an Idaho basis.
13
14 Adjustment 8.
15 Q.
COLSTRIP PLAND OUTAGES
PLEASE EXPLAI HOW THE COMPAN DEVELOPS THERM PLAND
16 OUTAGE SCHEDULE INUTS FOR GRI.
17 A.The methodology employed by the Company to normalize planed outages uses 48-
18 month average of historical data for the period 2006-2009 to determine the amount of
19 time the plants are on outage. Historically, these outages are scheduled during the spring
20 and fall shoulder months when market prices tend to be lower so that replacement power
21 costs are kept low and ample energy is available from the marketplace to replace the
22 generation on outage. After the Company develops the amount of time the units were on
23 outage it develops a normalized outage schedule based on a variety of factors including
Widmer, DI (corrected) - Page 24
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market prices, historical outages and the amount of units or MW on outage at a given
point in time.
DO YOU AGREE WITH THE COMPAN'S NORMIZED OUTAGE
SCHEDULE INCLUDED IN GRI?
Not completely. The starting point of Colstrip 3 and Colstrip 4 planned outages should
be moved from September to May to better optimize the timing of the outages so that
NPC would be lower than it would be using the Company's outage schedule.
DOES YOUR PROPOSED CHAGE TO THE PLAND OUTAGE SCHEDULE
RESULT IN AN EXCESSIV AMOUN OF CAPACITY ON OUTAGE DURG
MAY?
No. The amount of capacity on outage is within a reasonable range based on a
comparison of actual planned outages compared to planned included in the Company's
filing.
WHT is YOU RECOMMNDATION?
I recommend that the Colstrip 3 planed outage be moved from September 18th to May
1st and the Colstrip 4 planed outage be moved from September 30th to May 13th. This
adjustment reduces proposed NPC by $0.02 milion on an Idaho basis.
22 Adjustment 9.
23 Q.
ENERGY GATEWAY TRASMISSION
PLEASE EXPLAI THE GATEWAY TRASMISSION ADJUSTMENT.
Widmer, DI (corrected) - Page 25
1 A.This adjustment removes the transmission capacity upgrades associated with the Energy
2 Gateway transmission project included in GRID as par of the adjustment to remove the
3 Energy Gateway project from the Company's filing as recommended by Monsanto
4 witness Dennis Peseau. This adjustment increases NPC by $0.20 milion on an Idaho
5 basis.
6
7 Adjustment 10.
8 Q.
9 A.
10
11
12
13
14 Q.
15 A.
16
17
18
19
20
CHOLLA 4 CAPACITY
PLEASE EXPLAI HOW CHOLLA 4 CAPACITY WAS MODELED.
The Company modeled Cholla 4 capacity at 387MW even though the capacity was
upgraded to 395MW not long ago. It appears the reasoning behind modeling the capacity
at 387MW is because the Company has 387 MW of firm transmission rights to move
Cholla 4 Generation.
DO YOU AGREE WITH MODELING CHOLLA 4 AT 387M?
No. Cholla is already derated below 387 MW for weekday and week-end forced outage
rates of 5.24% and 7.04%, which respectively produce a derated capacity of 374.3 MW
and 367.2 MW for Cholla 4. Since the derated capacity is already below the 387 MW of
firm transmission rights it is not necessar to derate the plant for firm transmission rights.
Cholla 4 capacity should be modeled at the full 395MW. This adjustment reduces NPC
by $0.07 millon on an Idaho basis.
21
22 Adjustment 11.
23 Q.
MORGAN STANEY CALL PREMIUMS
PLEASE DESCRIE THE TWO MORGAN STANEY CALL OPTION
24 CONTRACTS INCLUDED IN THE COMPAN'S FILING.
Widmer, DI (corrected) - Page 26
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12 Q.
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14 A.
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The Company entered two call option contracts with Morgan Stanley during November
2005 for the period June 1,2010 through August 31, 2010. Each contract provides the
right to call _ of firm super-peak product per hour, exercisable only on the
"WECC Pre-Scheduling Day" at an additional cost of _ per MWh for one contract
and _ per MWh for the second contract. For this right the Company paid a
premium of_ for one contract and _ for the second contract.
WERE EITHR OF THESE CALL CONTRACTS EXERCISED IN THE
COMPAN'S FILING?
No. Neither contract was dispatched because they were not economic for the test year.
HAS THE COMPAN PREVIOUSLY STATED A POSITION ON THE
INCLUSION OF CALL OPTION CONTRACTS THAT AR NOT ECONOMIC?
Yes. In Oregon Docket UE-191 the Company stated that call option contracts should be
removed from NPC if removal lowers NPC. In this case removal of both Morgan Stanley
call option contracts lower NPC. For this reason, I recommend removal of Morgan
Staley call option contracts p272153-6 and p272154-7. This adjustment lowers NPC by
$0.17 milion on an Idaho basis.
20 Adjustment 12.
21 Q.
BEAR RIR HYRO NORMIZATION
PLEASE EXPLAI HOW THE COMPAN mSTORICALLY NORMIZED
22 HYRO GENERATION FOR SMAL HYRO PROJECTS LIK BEAR RIR.
23 A.Small hydro projects generally have no appreciable storage and are operated as run of
24 river projects where stream flow in is equal to the stream flow out. For these small
Widmer, DI (corrected) - Page 27
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projects, normalized generation is based on an evaluation of 30 years of historical
generation capability. Bear River is somewhat different in that it does have some storage
capabiliy.
HOW DOES THE 30-YEAR NORMIZATION PROCESS WORK?
Thirt years of historical generation are used to develop a median hydro forecast. When
a new year of data becomes available it becomes the first year data and the prior first year
data becomes the second year data and so forth until the prior 29th year data becomes the
30th year data and the prior 30th year data is excluded. This provides customers and the
Company with a balanced recovery of generation benefits over the 30-year period.
HAS THE COMPAN'S BEAR RIR NORMIZATION DEVIATED FROM
THE 30-YEAR NORMIZATION METHOD IN RECENT YEAR?
Yes. The Company's calculation of normalized hydro generation for Bear River began to
exclude flood control years from the 30 year historical record starting in 2008. In
response to WIEC Data Request 8.24 in Docket No. 20000-333-ER-08, the Company
explained how they adjusted Bear River generation and explained their reasons for the
adjustments:
The inflow forecast for Bear River was recently reduced. Years in which surlus
water was released from Bear Lake ("flood control years") were removed from
the historical data set from which the Bear River generation forecast is derived.
Flood control years provide additional water for Bear River generation. However,
the region is curently impacted by long-term drought conditions and based on the
low water level in Bear Lake the probabilty of a flood control year is minimal for
the next three years.
Widmer, DI (corrected) - Page 28
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DO TH DROUGHT CONDITIONS PROVIE A LEGITIMATE BASIS FOR
EXCLUDING FLOOD CONTROL YEAR FROM THE CALCULATION OF
NORMIZED GENERATION?
No. Arbitrarily removing flood control water year data from the historical record because
drought conditions are expected to persist is not consistent with the 30- Year
normalization methodology employed by the Company for other small projects or the
methodology employed for other larger projects. The Bear River methodology is clearly
a case of cherr picking, which produces higher NPC because it excludes the nine highest
generation years from the thirt-year normalization period. Those nine years have a
median anual generation of 563,114 MWh. In contrast, the years inclnded in the
Company's filing have a median generation forecast of205,576 MWh. Put another way,
the Company's Bear River generation normalization transfers customer's benefits of
higher hydro generation to shareholders.
IS THE BEAR RIR ADJUSTMENT SYMTRICAL FROM THE
PERSPECTIV OF PREVIOUS HYRO ADJUSTMENTS OR FILINGS?
No. To the best of my knowledge, the Company has never volunteered adjustments to
increase hydro generation and decrease NPC based on an expectation of a good water
year. For the reasons explained above, I recommend that the Company's Bear River
normalization should be revised to use the same 30-year normalization methodology used
for other small hydro facilties. My recommendation reduces NPC by approximately
$0.13 milion on an Idaho basis.
Widmer, DI (corrected) - Page 29
1 Adjustment 13.
2 Q.
3
4 A.
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6
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11 A.
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29
30
BLACK mLLS SHAING
PLEASE EXPLAI TH COMPAN'S MODELING FOR THE BLACKlLLS
WHOLESALE SALES CONTRACT.
The contract is classified as a call option contract in GRID and the contract terms for
energy such as hourly, daily weekly, monthly and anual take and delivery points are
inputs to GRID. Based on this information and the Company's forward price curve
GRID dispatches the contract during the highest cost hours based on the assumption that
is what the purchasing entity would do.
DO YOU AGREE WITH TIS ASSUMTION?
No. While the assumption may be reasonable for some contracts it really depends on the
requirements and assumptions of the purchasing entity. In the case of Black Hils, the
actual delivery shape of the sale is much flatter than it is modeled in GRID. As shown
below in Graph 1, Black Hils Dispatch, the difference between actual on and off-peak
deliveries is smaller (flatter) than the difference between the Company's modeled on and
off-peak deliveries.
Widmer, DI (corrected) - Page 30
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Graph 1 - Black Hils Dispatch (Redacted)
AR YOU SURRISED BY THE SHAING DIFFERENCE?
No. The difference is not surrising because the Company simply does not know what
Black Hils system requirements and assumptions are. In this case, the assumption that
Black Hils would do exactly what the Company thinks they would do is incorrect and
results in a higher contract cost in GRID than occurs on an actual basis. To correct this
problem the energy shape should be modeled using the actual delivery shape.
DOES THE COMPAN USE AN ACTUAL INORMTION TO MODEL
OTHER ASPECTS OF THE BLACKlLS CONTRACT?
Yes. The delivery points for the contract are modeled based on actual information. The
purose of using actual delivery points is to capture the expected cost of the sale because
the energy can be delivered on both the east and west side of the Company's system.
This fact also suggests that the energy shape should use actual information.
DOES THE COMPAN USE ACTUAL INORMTION TO MODEL OTHER
CONTRACTS?
Yes. Actual information is also used to model other contracts. For example, energy for
the Gem State contract is modeled for the months of May, June, July and August based
on historical information despite the fact that the contract states that deliveries are
expected to occur during June, July and August. The Company also uses actual data for
varous inputs of other contracts and GRID inputs such GP Camas, APS, Biomass and
forced and planed outages etc.
Widmer, DI (corrected) - Page 31
1 Q.
2 A.
WHT is YOUR RECOMMNDATION?
The Black Hils wholesale sales contract should be modeled based on a four a four-year
3 average of historical dispatch information. This adjustment reduces NPC by $0.08
4 milion on an Idaho basis.
5
6 Adjustment 14.
7 Q.
8
9 A.
10
11
12 Q.
13
14 A.
15
16
17
18 Q.
19
20 A.
21
22
MONA MAT
PLEASE EXPLAI HOW PACIFICORP SIZED THE MONA WHOLESALE
MAT HU?
The Company modeled the market capacity as no graveyard market (the five hours ended
1 :00 AM through 6:00AM Pacific time) and 75 MW in all other hours.
DOES THE MONA WHOLESALE SALES MAT CONSIST SOLELY OF
SALES WITH A MONA POIN OF DELIVRY (POD) DESIGNATION?
No. According to Confidential Attachment Monsanto 2.15, the Mona market consists of
Mona, Gonder, Red Butte, Sierra Pacific system (SPPC) and Nevada Utah Border (NUB)
PODs.
GIVN TIßS INORMTION, HAS PACIFICORP ADEQUATELY SIZED THE
MONA MAT?
No. As shown below in Table 3, the Company's Mona market capacity is considerably
understated based on a comparison wholesale sales volume for the 48-month period
ended December 31, 2009.
Widmer, DI (corrected) - Page 32
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5 A.
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9 Q.
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11 A.
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Table 3
Mona Market Size Compaison
A-.rage Megawatts
PacifiCorp PacifiCorp Actual 48-Month A"9.
All Other Hours Gra-.yard/1 27o
15
17
21
o 75
1
229
296
240
151
132
167
44
36
25
24
17
o
October
No-.mber
75
75
75
o
o
WH DID YOU USE A 48-MONTH AVERAGE FOR THE COMPARSON
SHOWN IN TABLE 3?
I used a 48-month average to be consistent with the Company's normalization of thermal
generation, STF transmission capacity and graveyard market caps, which all use a 48-
month normalization period.
WHT is YOUR RECOMMNDATION FOR CURG THE CONSIDERALE
UNERSTATEMENT OF THE MONA MARKT?
The Mona market capacity needs to be sized appropriately to provide a proper match of
costs and benefits. I recommend that the Mona market capacity be corrected by using the
48-month average capacities shown above in Table 3. This adjustment reduces NPC by
approximately $0.03 milion on an Idaho basis.
Widmer, DI (corrected) - Page 33
1 Adjustment 15.
2 Q.
3
4 A.
5
6
7
8
9
10 Q.
11
12 A.
13
14
15
16 Q.
17
18 A.
19
20 Q.
21
22 A.
23
24
NAUGHTON 3 OUTAGE
PLEASE EXPLAI THE CAUSE OF THE NAUGHTON 3 OUTAGE wmCH
STARTED MAY 8, 2009 AN ENDED MAY 26, 2009.
The Company's contractor Siemens failed to complete the Naughton 3 overhaul on
schedule per contract terms due to poor performance. The major reasons for the failure to
meet contract terms include failure to achieve good alignment of the HP and LP turbine,
lack of experienced and skiled journeyman and craft supervision and poor quality control
resulting in many items being reworked.
DID THE COMPAN RECIEVE COMPENSATION FROM SIEMENS FOR
FAIUR TO MEET CONTRACT TERMS?
Yes. Pursuant to the terms of the contract the Company received a $500,000 liquidated
damages payment in June 2009 that was booked to FERC account 555 purchase power
expense.
DID IDAHO RETAIL CUSTOMERS RECEIV AN ALLOCATED SHA OF
THE $500,000 PAYMNT?
No. The ECAM did not become effective until July 1,2009.
DO YOU AGREE WITH TH COMPAN'S INCLUSION OF THE OUTAGE
EVENT IN NPC?
No. The outage was caused by poor performance of the Company's contractor (Siemens)
and is therefore an imprudent outage that should not be included in the calculation of
NPC. Furhermore, the Company has already been compensated for the outage pursuant
Widmer, DI (corrected) - Page 34
1
2
3
4
5
6
7 Q.
8 A.
to the terms of their contract through the $500,000 liquidated damage payment it
received. Inclusion, of the outage in NPC would result in the Company collecting outage
costs twice, once from customers and once from Siemens. For these reasons, I
recommend that the outage be removed from the calculation of NPC. This adjustment
reduces NPC by approximately $0.03 milion on an Idaho basis.
DOES THIS CONCLUDE YOUR TESTIMONY?
Yes.
Widmer, DI (corrected) - Page 35
..
Randall C. Budge, ISB No. 1949
RACINE, OLSON, NYE, BUDGE &
BAILEY, CHARTERED
P.O. Box 1391; 201 E. Center
Pocatello, Idaho 83204-1391
Telephone: [phone]
Fax: [phone]
rcbêracinelaw.net
Attorneys for Intervenor Monsanto Company
n- "rhJ:\.d::r-1~ .:
10lONOV 22 AM 9: 34
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF )
ROCKY MOUNTAIN POWER FOR APPROVAL)
OF CHANGES TO ITS ELECTRIC SERVICE )
SCHEDULES AND A PRICE INCREASE OF )
$27.7 MILLION, OR APPROXIMATELY )13.7 PERCENT )
)
Case No. PAC-E-IO-07
PROOF OF SERVICE
I HEREBY CERTIFY that on this 19th day of November, 2010, I served a true, correct
and complete copy of the Errata Sheet and Corrected Direct Testimony of Mark T. Widmer on
Behalf of Monsanto, to each of the following in the maner indicated:
Jean D. Jewell, Secretary (original and 9)
Idaho Public Utilties Commission
472 West Washington Street
Boise, Idaho 83702-5918
Ted Weston
Rocky Mountain Power
201 South Main, Ste 2300
Salt Lake City, Utah 84111
Paul J. Hickey
Hickey & Evans, LLP
1800 Carey Ave., Ste 700
Cheyenne, WY 82003
PROOF OF SERVICE - 1
Overnight Mail
Overnight Mail
Overnight Mail
Mark C. Moench
Daniel Solander
Rocky Mountain Power
201 S. Main Street, Ste 2300
Salt Lake City, Utah 84111
Overnight Mail
Katie Iverson
Brubaker & Associates
17244 W. Cordova Cour
Surrise, Arizona 85387
U.S. Mail
James R. Smith
Monsanto Company
P.O. Box 816
Soda Springs, Idaho 83276
U.S. Mail
Eric L. Olsen
Racine, Olson, Nye, Budge & Bailey
P.O. Box 1391
Pocatello, Idaho 83204-1391
Hand Delivered
Anthony Yanel
29814 Lake Road
Bay Vilage, Ohio 44140
U.S. Mail
Tim Buller
Jason Hars
Agrium, Inc.
3010 Conda Road
Soda Springs, Idaho 83276
U.S. Mail
Benjamin 1. Otto
Idaho Conservation League
P.O. Box 844
Boise, Idaho 83702
U.S. Mail
Dr. Don Reading
6070 Hil Road
Boise, Idaho 83703
U.S. Mail
PROOF OF SERVICE - 2
, ,
Melinda J. Davison
Davison VanCleve, PC
333 SW Taylor, Ste 400
Portland, Oregon 97204
Overnight Mail
Ronald L. Wiliams
Willams Bradbur, PC
1015 W. Hays Street
Boise, Idaho 83702
Overnight Mail
Brad M. Purdy
Attorney at Law
2019 N. 17th Street
Boise, Idaho 83702
Overnight Mail
RACINE, OLSON, NYE, BUDGE &
BAILEY, CHARTERED
B~~Kd4£hr2Irll!i RANDALL C. BUDGE '
PROOF OF SERVICE - 3