20101216Widmer Revised Di.pdf

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- i 0-07
DIRECT TESTIMONY OF
MA T. WIMER
ON BEHAF OF
MONSANO
November 1, 2010
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1 TABLE OF CONTNTS
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i. INTRODUCTION AND QUALIFICATIONS
II. PURPOSE OF TESTIMONY AND SUMMARY OF ADJUSTMENTS
III. DETAILED ADJUSTMENTS
Adjustment 1 APS Supplemental
Adjustment 2 Wind Integration Costs
Adjustment 2a OATT Wind Integration Costs
Adjustment 2b Balancing Wind Integration Costs
Adjustment 3 Non-Firm Transmission
Adjustment 4 Dunlap Reserve Requirement
Adjustment 5 Reserve Shutdowns
Adjustment 6 Top of World
Adjustment 6a Top of World Incremental Wind Integration
Adjustment 7 Cal ISO
Adjustment 8 Colstrip Planed Outages
Adjustment 9 Energy Gateway Transmission
Adjustment 10 Cholla 4 Capacity
Adjustment 1 1 Morgan Stanley Calls Premiums
Adjustment 12 Bear River Hydro Normalization
Adjustment 13 Black Hils Shaping
Adjustment 14 Mona Market
Adjustment 15 Naughton 3 Outage
Appendix A
Exhbit 228 (MW - i )
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1 I. INTRODUCTION 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, AN ON WHOSE
BEHAF YOU AR TESTIFYG.
I am a utility regulatory consultant and Principal of Nortwest Energy Consulting, LLC
('"NWEC"). I am appearing on behalf of Monsanto.
PLEASE SUMZE YOUR QUALIFCATIONS AN APPEARCES.
With NWEC, I provide consulting services related to electric utility system operations,
energy cost recovery issues, revenue requirements, and avoided cost pricing for
qualifying facilities. Since forming NWEC, I have provided testimony in dockets
regarding recovery of net power costs though 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 paricipated in and filed
testimony on power cost issues in numerous dockets in Wyoming, Oregon, Uta,
Washington, Idaho, and California jurisdictions over a 10 plus year period. At the time
of my deparure 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 - Page 1
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PURPOSE OF TESTIMONY AN SUMMY OF ADJUSTMNTS
WHT is THE 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, 20 10.
PLEASE SUMZE YOUR TESTIONY.
My testimony presents fifteen NPC adjustments totaling $47.02 milion total Company
and $2.55 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 sumarzed on
Table 1 below and subsequently explained in more detail in the remainder of my
testimony.
Widmer, DI - Page 2
1
Table 1
Summary of Recommended Adjustments - $
Total
Company
Primary
Recommendation
Idaho Est.
Secondary
Recommendations
Idaho Est.
GRID (Net Variable Power Cost Issues)
PacifiCorp Request NPC 1,069,701,315 63,465,379
ADJUSTMENTS
1 APS Supplemental (Coal +Other)
2 Wind Integration Costs
2a OA TT Wind integration Costs
2b Balancing Wind Integration Costs
3 Non-Firm Transmission
p Reser. Requirement
5 Reser. Shutdowns
6 Top of World Wind
6a Top of World Incremental Wind Integration
7 Cal ISO
8 Colstrip Planned Outages
9 Energy Gateway Transmission
10 Cholla 4 Capacity
11 Morgan Stanley Call Premiums
12 Bear River Hydro Normalization
13 Black Hills Shaping
14 Mona Market
15 Naughton 3 Outage
Allocation True-UP
-1,942,838
-34,187,931
-6,361,99
-2,629,076
-2,432,988
127,222
-807,546
1,550,033
285,266
-3,713,698
-258,678
3,291,265
-1,113,498
-3,057,000 ,.
-2,181,474
-1,293,489
-438,529
-559,329
-115,269
-1,883,242
-15,347
195,271
-66,064
-168,395
-129,427
-76,743
-26,018
-33,185
69,851
Total Adjustments Primary Recommendation
Est. Allowed - NPC Primary Recommendation
2
Est. Idaho Jurisdiction
SE: 6.3575%
SG: 5.5085%
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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 Arizona Public Service ('"APS").
7 While the option is continually exercised durng actual operations, it is uneconomic as
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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 INGRATION 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
secondar adjustment 2a OA IT Wind Integrations Costs, so that the Company not be
allowed to recover wholesale wheeling customer wind integration costs from retail
customers though 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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responsibility of Idaho customers and should be removed from NPC. This adjustment
reduces NPC by $0.35 milion on an Idaho basis.
Adjustment 2b.BALANCING WI INTEGRATION COSTS
The Company double counted wind integration balancing costs durng the period
Januar 2010 through April 2010. This adjustment removes the double count and lowers
NPC by $0.14 milion on an Idaho basis.
Adjustment 3.NON-FIRM TRSMISSION
In actual operations the Company utilizes a signficant 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
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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 WID
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 INGRATION
If the Commission does not adopt my primar 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 - Page 6
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wholesale transactions included in the fiing. This adjustment reduces NPC by $.20
milion on an Idaho basis.
Adjustment 8.COLSTRI PLAND OUTAGES
This adjustment moves the planed outage starting 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.CHOLLA 4 CAPACITY
The Company's modeling understates Cholla 4 capacity. My adjustment corrects the
capacity and reduces NPC by $0.07 milion on an Idaho basis.
Adjustment 11.MORGAN STANEY CALL PREMIUMS
The Company's fiing includes two call option purchase power contracts that are
uneconomic. This adjustment removes both contracts and lowers NPC by $0.17 millon
on an Idaho basis.
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Adjustment 12.BEAR RIR HYRO NORMIZTION
The Bear River historical record was adjusted by the Company to remove flood
control years, which are years when surplus 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 Hi Sales Shaping
The Company bases its modeling of the Black Hils wholesale sales on the faulty
assumption that Black Hils wil 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. Ths
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 - 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 Paries adequate time to review the
significant amount of data tied to the stated update. Therefore, I recommend that the
Commission reject all Company proposed rebuttl 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 IMPORTANCE.
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 - Page 9
1 requirement components and establishes the ECAM baseline. NPC is calculated by the
2 Company's GRID production dispatch modeL.
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4 Adjustment 1.
5 ENERGY
PLEASE EXPLAI THE APS SUPPLEMENTAL ADJUSTMNT.6 Q.
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ARZONA PUBLIC SERVICE ("APS") SUPPLEMENTAL
Pursuat to the terms of the Long-Term Power Transactions Agreement between APS
and PacifiCorp, APS is required to offer PacifiCorp 219 GWH of Supplemental Coal
Energy and 876 GWH of Other Supplemental Energy though October 31, 2020, when
the contract expires. The Company has the option but not the requirement to purchase
either the Supplemental coal or Other Supplemental energy or both at prices offered by
APS for each product.
IS TH CONTRACT ECONOMIC AS MODELED IN GRI?
No. Both the Other Supplemental and the Supplemental Coal components are modeled
uneconomically in GRID.
HOW DID YOU DETERM THE CONTRACT WAS UNCONOMIC?
I ran the GRID model without the Supplemental Coal and Other Supplemental energy.
The runs 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 - Page 10
1 Q.HA THE COMPAN AGREED TO TIDS METHODOLOGY IN OTHR
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.
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6 Adjustment 2.
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WI INTEGRATION COSTS
HAS THE COMPAN MET ITS BUREN OF PROOF ON WI
INTEGRATION COSTS?
No. While the Company has done numerous forecasts of wind integration costs over the
last several years, which have vared 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 actual 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 actul 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 oveily burdensome
and would require the Company to perform analysis not previously performed.
Notwithstanding this objection, the Company states as follows.
The Company holds reserves to maintain reliability of its system in accordance
with standards 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 difficult to determine the
reasonableness of Company's requested recovery of $34.2 millon for wind integration
costs.
Widmer, DI - Page 11
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24 Q.
is THE COMPAN'S PROPOSED USE OF THE $6.50 PER MW COST OF
WI INGRATION RATE APPROVED BY THE IDAHO COMMSSION IN
CASE NO. PAC NO.-E-09-07, A REASONABLE SOLUTION TO TH
COMPAN'S LACK OF VERIFILE INORMTION?
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 facility 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 though the ECAM. Only this way can we be assured that actu wind integration
costs is recovered. Ths adjustment reduces NPC by $ 1 .88 milion on an Idaho basis. I
also recommend that the Commission adopt the premise of my secondar adjustment 2a
OA TT 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 HAVE A SECONDARY RECOMMENDATION?
Widmer, DI - Page 12
1 A.Yes. If the Commission rejects my recommendation for this adjustment I recommend
2 that the Commission accept my secondar proposed adjustments 2a OATT Wind
3 Integration Costs and 2b. Balancing Wind Integration Costs, which are discussed in my
4 following testimony.
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6 Adjustment 2a.OPEN ACCESS TRSMISSION TARF (OATTI - WID
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INGRATION
DOES TH COMPAN'S OATT TARF INCLUDE A CHAGE FOR WI
INEGRATION
CUSTOMERS?
TRSMISSIONEXPENSESFORWHOLESALE
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
responsibility and they have had over six years to make a fiing 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 fiing.
Widmer, DI - Page 13
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HAS THE COMPAN INICATED IF AN WHN THY PLAN TO MA A
FIING TO MODIFY ITS OATT TO INCLUDE CHAGES FOR WI
INEGRATION SERVICES TO NON-OWND WI FACILITIS?
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 fiing at a much earlier date.
AR WI INGRATION COSTS INCLUDED IN OTHER 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 Junper wind projects
and has included those costs in the wheeling expense.
HAS FERC PREVIOUSLY ADDRESSED MODIFCATION 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 tarff. 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 instance (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 Tarff. 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 - 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 fiing, 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 Tarff. NorthWestern asserts that its Tariff does not contan
6 a mechanism that allows it to recover generator regulation service costs associated
7 with transmission used to export energy from NortWestern's system, which
8 NorthWestern must incur to meet reliability 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.
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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 paries 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.
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25 Adjustment 2b.WI INEGRATION COSTS - BALANCING
26 Q.PLEASE EXPLAI TH COMPONENTS OF THE WI INGRATION
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.
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Intra-hour costs are the costs caring load following and regulation reserves for the
varability of wind generation. This adjustment focuses on the balancing component.
PLEASE EXPLAI HOW THE COMPAN BALANCES ITS SYSTEM FOR
WI INEGRATION.
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 FIING INCLUDE A DOUBLE COUN OF WI
INGRATION 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 actual 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 $6.50 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
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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 $6.50 per MWh. This produces a double count of$I.96 per MWh.
SHOULD THE $1.96 BE REDUCED FUTHR TO COMPENSATE FOR THE
PORTION OF BALANCING THAT is ACCOMPLISHED BY MEANS OTHR
TH HOURY FIRM WHOLESALE SALES TRASACTIONS INCLUDED IN
GRI?
A further 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 varous means identified above other than to place them in an
order of most to least. Since the Company has previously stated thtit most of its
balancing occurs through actual 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.
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19 Adjustment 3.
20 Q.
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22 A.
NON-FIRM TRSMISSION
DO YOU AGREE WI PACIFCORP'S EXCLUSION OF NON-FI
TRASMISSION FROM NPC?
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
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results. However, that is not the case. As shown below in Table 2 - PacifiCorp
Transmission Utilization, a substantial amount of non-firm transmission is utilized.
During 2009, non-firm transmission of energy exceeded STF transmission by over 2.69
milion MWh or by more than 6 times. It is rather obvious that non-firm transmission is
normally relied upon to balance and optimize the Company's system.
Table 2
Pacificorp Transmission Utilzation
Milions MWh
2.86
3.66
4.09
0.44
4.62
4.53
13.83
3.57
Year Avg.6.64
Excludes Cal intra bubble and transmission already modeled
WH DOES THE COMPAN UTLIZE NON-FIRRASMISSION?
Non-firm transmission is utilized to balance and optimize the Company's system. This
keeps NPC lower than it would be absent use of non-firm transmission. Lower NPC is
accomplished through more efficient use of generation and transmission assets in concert
with wholesale transactions and creates more benefits (earnings) for the Company and its
shareholders. Since these benefits are derived from assets and expenses already included
in rates, non-firm transmission should be included in NPC to match costs with benefits.
HA THE INCLUSION OF NON-FIRM TRSMISSION BEEN ADOPTD BY
OTHR COMMSSIONS OR BEEN AGREED TO BY THE COMPAN?
Widmer, DI - Page 18
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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 future fiings
using a four-year average.
WHT is YOUR RECOMMNDATION FOR NON-FIRM TRSMISSION?
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.
12
13 Adjustment 4.
14 Q.
15 A.
DUNAP RESERVE REQUIMENT
PLEASE EXPLAI THE DUNAP RESERVE REQUIMENT ADJUSTMNT.
The Company did not model the Dunlap wind project as having an operating reserve
16 requirement. This adjustment includes the operating reserve requirement for Dunlap and
17 increases NPC by $0.01 millon on an Idaho basis.
18
19 Adjustment 5.
20 Q.
21 A.
RESERVE SHUOWNS
PLEASE DEFI RESERVE SHUOWNS.
Reserve shutdown is a state in which a thermal unit was available for service but not
22 electrically connected to the grid for economic reasons.
23
Widmer, DI - Page 19
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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 planed 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 after planed 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.
Widmer, DI ~ Page 20
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WOULD ELIMATION OF TH RESERVE SHUOWN ADJUSTMENT
FROM THE DENOMINATOR OF TH COMPAN'S FORCED OUTAGE RATE
CALCULATION MEAN THT 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 SHUOWNS?
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 - Page 21
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Adjustment 6. TOP OF WORLD WI IN SERVICE DATE
Q. PLEASE EXPLAIN THE TOP OF WORLD WI ADJUSTMENT.
A. Durng 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 TIDS ADJUSTMNT.
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 will 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 durng 2010.
Adjustment 7. CAL ISO FEES
Q. DOES THE COMPAN'S FIING 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 - Page 22
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These fees are incurred when the Company uses the Cal iso system to balance and
optimize its system. In other words, the fees are incured 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-
341-EP-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 illquid. 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
THT COULD INCUR CAL ISO FEES AN PRODUCE A MATCHG
BENEFIT?
Yes. The filing included actual STF transactions from Janua 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 TH FILING INCLUDE AN WHOLESALE TRSACTIONS
THAT COULD INCU CAL ISO FEES?
Widmer, DI - Page 23
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A. 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 fiing 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 fiing. 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 fiing for the period May 4, 2010 though December 31, 2010 be excluded
from NPC. In addition, I recommend that actul 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 incured. This
adjustment reduces NPC by $0.20 millon on an Idaho basis.
Adjustment 8. COLSTR PLAD OUTAGES
Q. PLEASE EXPLAI HOW THE COMPAN DEVELOPS THRM PLAND
OUTAGE SCHEDULE INUTS FOR GRI.
A. The methodology employed by the Company to normalize planed outages uses 48-
month average of historical data for the period 2006-2009 to determine the amount of
time the plants are on outage. Historically, these outages are scheduled during the spring
and fall shoulder months when market prices tend to be lower so that replacement power
costs are kept low and ample energy is available from the marketplace to replace the
generation on outage. After the Company develops the amount of time the units were on
outage it develops a normalized outage schedule based on a varety of factors including
Widmer, DI - 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 TH COMPAN'S NORMIZD OUTAGE
SCHEDULE INCLUDED IN GRI?
Not completely. The staring point of Colstrip 3 and Colstrip 4 planed 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 TH PLAND OUTAGE SCHEDULE
RESULT IN AN EXCESSIV AMOUNT OF CAPACITY ON OUTAGE DURG
MAY?
No. The amount of capacity on outage is within a reasonable range based on a
comparson of actual planed outages compared to planed included in the Company's
fiing.
WHT IS YOU RECOMMNDATION?
I recommend that the Colstrip 3 planed outage be moved from September 18th to May
1 st 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 ADJUSTMNT.
Widmer, DI - 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 Compan's fiing as recommended by Monsanto
4 witness Dennis Peseau. This adjustment increases NPC by $0.20 millon on an Idaho
5 basis.
6
7 Adjustment 10.
8 Q.
9 A.
10
11
12
13
14 Q.
15 A.
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19
20
CHOLLA 4 CAPACIT
PLEASE EXPLAI HOW CHOLLA 4 CAPACIT 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 milion on an Idaho basis.
21
22 Adjustment 11.
23 Q.
MORGAN STANEY CALL PREMIMS
PLEASE DESCRIE TH TWO MORGAN STANEY CALL OPTION
24 CONTRACTS INCLUDED IN THE COMPAN'S FIING.
Widmer, DI - Page 26
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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 CONTCTS 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 TH
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 Staey
call option contracts lower NPC. For this reason, I recommend removal of Morgan
Stanley 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.
BEA RIR HYRO NORMIZATION
PLEASE EXPLAI HOW TH COMPAN IDSTORICALLY NORMIZD
22 HYRO GENERATION FOR SMAL HYRO PROJECTS LIK BEAR RIR.
23 A.Small hydro projects generally have no appreciable storage and are operated as ru of
24 river projects where stream flow in is equal to the stream flow out. For these small
Widmer, DI - 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
capability.
HOW DOES TH 30-YEAR NORMIZATION PROCESS WORK?
Thirty 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 fort 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.
HA THE COMPAN'S BEAR RIR NORMIZTION DEVITED 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 staring 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 probability of a flood control year is minimal for
the next thee years.
Widmer, DI - Page 28
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DO THE DROUGHT CONDITIONS PROVIE A LEGITIMATE BASIS FOR
EXCLUDING FLOOD CONTOL 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 included in the
Company's fiing 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 TH BEAR RIR ADJUSTMNT SYMTRCAL 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 facilities. My recommendation reduces NPC by approximately
$0.13 milion on an Idaho basis.
Widmer, DI - Page 29
1 Adjustment 13.
2 Q.
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BLACK HILS SHAING
PLEASE EXPLAI THE COMPAN'S MODELING FOR THE BLACKmLS
WHOLESALE SALES CONTRCT.
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 cure
GRID dispatches the contract durng the highest cost hours based on the assumption that
is what the purchasing entity would do.
DO YOU AGREE WIH TIDS ASSUMON?
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 oftpeak
deliveries is smaller (flatter) than the difference between the Company's modeled on and
off-peak deliveries.
Widmer, DI - Page 30
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Graph 1 - Black Hils Dispatch
60
~4-Yr. Avg Actual BHP
LlH
50
-lPAC- GRID BHP HlH
40
..PAC - GRID BHP lLH
30
20
Avg Actual BHP
HlH
10
o
1 2 3 4 5 6 7 8 9 10 11 12
AR YOU SURRISED BY TH SHAING DIFFERENCE?
No. The difference is not surprising 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 BLACKmLS CONTCT?
Yes. The delivery points for the contract are modeled based on actual information. The
purpose of using actul delivery points is to capture the expected cost of the sale because
Widmer, DI - Page 31
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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 OTHR
CONTCTS?
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.
WHT is YOUR RECOMMNDATION?
The Black Hils wholesale sales contract should be modeled based on a four a four-year
average of historical dispatch information. This adjustment reduces NPC by $0.08
milion on an Idaho basis.
16 Adjustment 14.
17 Q.
MONA MAT
PLEASE EXPLAI HOW PACIFCORP SIZD THE MONA WHOLESALE
18 MAT HU?
19 A.The Company modeled the market capacity as no graveyard market (the five hours ended
20 1:00 AM through 6:00AM Pacific time) and 75 MW in all other hours.
21
22 Q.DOES TH MONA WHOLESALE SALES MAT CONSIST SOLELY OF
23 SALES WITH A MONA POIN OF DELIVRY (POD) DESIGNATION?
Widmer, DI - Page 32
1 A.No. According to Confidential Attachment Monsanto 2.15, the Mona market consists of
2 Mona, Gonder, Red Butte, Sierra Pacific system (SPPC) and Nevada Utah Border (NUB)
3 PODs.
4
5 Q.GIVN TIDS INFORMTION, HAS PACIFICORP ADEQUATELY SIZED TH
6 MONA MAT?
7 A.No. As shown below in Table 3, the Company's Mona market capacity is considerably
8 understated based on a comparison wholesale sales volume for the 48-month period
9 ended December 31, 2009.
Table 3
Mona Market Size
A..rage Megawatts
January
February
March
April
May
June
July
August
Septembei
October
No..mber
December
PacifiCorp PacifiCorp
All Other Hours Gra..yard/1 0
o/1 0
/175 075 075 075 0
75 0
o75 0
Actual 48-Month Avg.
All Other Hours Gra..yard/1 27
/1/1 20
1575 17183 21229 26
44
36151 25
1167 17
10 /1 Not applicable because filing uses actual 2010 data
11
12 Q.WH DID YOU USE A 48-MONT AVERAGE FOR TH COMPARSON
13 SHOWN IN TABLE 3?
Widmer, DI - Page 33
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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 MAT?
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.
12 Adjustment 15.
13 Q.
NAUGHTON 3 OUTAGE
PLEASE EXPLAI THE CAUSE OF THE NAUGHTON 3 OUTAGE wmCH
14 STARTED MAY 8, 2009 AN ENDED MAY 26, 2009.
16 schedule per contract terms due to poor performance. The major reasons for the failure to
17
18
19
20
21 Q.
15 A.The Company's contractor Siemens failed to complete the Naughton 3 overhaul on
DID TH COMPAN RECIEVE COMPENSATION FROM SIEMENS FOR
22 FAILUR TO MEET CONTRACT TERMS?
Widmer, DI - Page 34
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20 Q.
21 A.
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 RETAI CUSTOMERS RECEIV AN ALLOCATED SHA OF
TH $500,000 PAYMNT?
No. The ECAM did not become effective until July 1,2009.
DO YOU AGREE WITH TH COMPAN'S INCLUSION OF TH 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 pursuat
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 TIDS CONCLUDE YOUR TESTIMONY?
Yes.
Widmer, DI - Page 35