20101014Falkenberg Di (redacted).pdf

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lDAliO F iHd, ¡
BEFORE THE IDAHO PUBLIC UTILITIESCOMMsSioWTIES CO¡"'¡¡)¡¡t~SIO¡J
IN THE MATTER OF THE )APPLICATION OF ROCKY )
MOUNTAIN POWER FOR APPROVAL)
OF CHANGES TO ITS ELECTRIC )
SERVICE SCHEDULES AN A PRICE )
INCREASE OF $27.7 MILLION OR )
APPROXIMATELY 13.7 PERCENT )
CASE NO. PAC-E-I0-07
Direct Testimony of Randall J.
Falkenberg
DIRECT TESTIMONY OF RANDALL J.F ALKENBERG
ON BEHALF OF
THE PACIFICORP IDAHO INDUSTRIAL COMSUMERS
REDACTED VERSION
October 14, 2010
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PLEASE STATE YOUR NAME AN BUSINESS ADDRESS.
Randall J. Falkenberg, PMB 362, 8343 Roswell Road, Sandy Springs, GA
30350.
BY WHOM AR YOU EMPLOYED?
I am President of RFI Consulting, Inc. ("RFI"). I am appearing in this
proceeding as a witness for the PacifiCorp Idaho Industrial Customers
("PIIC"). My qualifications are in Exhibit No. 605. I have been involved in
PacifiCorp (or "the Company") power cost related cases for more than ten
years in California, Oregon, Utah, Washington and Wyoming.
WHAT KIND OF CONSULTING SERVICES AR PROVIDED BY
RF?
RFI provides consulting services in the electric utilty industry. The fir
provides expertise in system planing, financial analysis, cost of service,
revenue requirements, rate design, and energy cost recovery issues.
I. INTRODUCTION AND SUMARY
WHAT IS THE PUROSE OF TilS TESTIMONY?
My testimony addresses PacifCorp's GRID study of normalized net power
costs ("NPC") for the December 31, 2010 test period. I identify certain
problems in the GRID model that overstate PacifiCorp's proposed Idaho
revenue requirements. I also address a related issue concerning combined
cycle plant Operations & Maintenance ("O&M"). Because Idaho uses a true-
up mechanism for PacifiCorp, I am not presenting a complete analysis of NPC
modeling issues. Instead, I am concentrating more effort on issues that also
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have an implication for the Energy Cost Adjustment Mechanism true-up, or
revenue requirements not subject to the true-up. I am discussing some
important modeling issues as it is important to set the NPC baseline as
accurately as possible.
PLEASE SUMARIZE YOUR TESTIMONY.
I have identified and quantified certain adjustments. to the Company's GRID
model study. These adjustments are shown on Table 1 and are summarized
below. All adjustments are addressed in more detail later in this testimony.
Following Table 1 is a summary explaining the basis for all proposed
adjustments and other recommendations.
Conclusions and Recommendations
PacifiCorp's requested 2010 NPC of $1,070 milion (tota Company) in
NPC is overstated by at least $25 milion. My corrections result in a
reduction to Idaho jurisdictional NPC of $1.51 milion. I also recommend
additional reductions of $29 thousand to the Idaho allocation revenue
requirements related to reductions to combined cycle plant O&M. As I
explained earlier, I have not done a complete analysis of the Company's
NPC in this case, and additional reductions to the Company's NPCs may
well be warranted.
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Table 1
Summary of Recommended Adjustents
SE
SG
Es.ID
Jurisdiction
6.36%
5.51%
Totl
Company
I. GRID (Net Variable Power Cost Isses)
PacifiCorp Request NPC
A. GRID Commitment Logic Error and Start Up Cost
1 Commitment Logic Screens1/
2 Start Up Energy 2J
B. Long Term Contract Modling
3 SMUD Contract Delivery Pattern
C. OATT Wind Integration Cost
4 Non-Qwned Inter Hour Wind
5 Non-Qwned Intra Hour Wind
D. Outage Modeling and Other NPC Adjustments
6 Lake Side Outage
7 Colstrip Outge
8 JBFuel Adjustments
9 Naughton Outage
10 Heat Rate Adjustment
E. Transmisson Isses
11 DC Intertie Cost
12 Populus to Ben Lomond Line Losss
13 Idaho Power PTP Contract
Notes
1/ Adjustment ¡neresed If Adjustment 14 Is not approved. In that case Adj. 1:
2J Adjustment assumes Co. Screens. Adjustment If ICii screens adopted:
1,069,701,315 69,200,00
(588,429)(34,912)
(1,676,474)(99,46)
(1,56,786)(92,957)
(2,041,963)(121,150)
(4,320,0311 (256,307)
(2,163,834)(128,38)
(1,300,710)(77,171)
(2,460,37)(145,954)
(700,273)(41,547)
(1,831,473)(108,661)
(4,766,40)(282,791)
(1,146,067)(67,996)
(842,38)(49,979)
(25,40,86)(1,507,271)
1,04,29,452 67,6~,729
(49,000)(29,072)
(25,894,863)(1,536,342)
(1,259,760)(74,742)
(1,393,200)(82,659)
Subtotal NPC Baseline Adjustments-
Allowed - Final GRID Result*
G. Other Adjustments
14 Combined Cyle O&M Adjustent
Total Adjustents
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GRID Commitment Logic Error and Start Up Costs
Adjustment 1. The Company acknowledges that GRID
contains a logic error that results in incorrect start up and
shut down decisions for gas-fired resources. This error
produces an upward bias on NPC. The Company attempts
to correct this error with a "screening" methodology.
However, the Company's correction is ineffective. I
ilustrate a more effective solution to this problem as
applied to the Currant Creek unit.
Adjustment 2. The Company includes the cost of fuel used
to start up gas plants, but ignores energy generated in the
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process. I recommend reflecting the value of start-up
energy in the test year.
Long Term Contract Modeling
Adjustment 3. The Company incorrectly models the
Sacramento Municipal Utilty District ("SMU") sales
contract by assuming the counterparty wil tae power only
during the highest cost months. Actual contract delivery
data shows the contract should be modeled to reflect a
lower cost delivery pattern.
C.OATTWind Integration Adjustments
Adjustments 4-5. The Company includes various costs
related to integration of non-owned wind resources. These
costs should be excluded because the Company is not
compensated for providing these integration services. The
Company has already acknowledged that it does not need
to provide inter-hour wind integration services for non-
owned wind farms. The Commission should also make
comparable adjustments in true-up proceedings.
D.Outage Rate Adjustments
Adjustments 6-7. These adjustments cap exceptionally long
outages at Lake Side and Colstrip 4 at 28 days in the four-
year average outage rate calculation. It is unrealistic to
assume such an extreme event wil occur once every four
years.
Adjustment 8. This adjustment addresses the high cost and
low quality of the Bridger fuel supply. Fuel quality
problems result in inordinately high levels of lost
production as compared to other plants.
Adjustment 9. The Company includes an outage at the
Naughton plant that was due to the negligence of a
subcontractor. The costs of such events should be assigned
to the Company rather than customers.
Adjustment 10. GRID biases average heat rates due to its
modeling of forced outage rates as capacity derations.
When GRID models a unit at its derated maximum
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capacity, the heat rate normally. exceeds the full loading
average heat rate. This adjustment corrects this problem.
Transmission Issues
Adjustment 11. It appears the Company includes no
transactions that utilze the DC Intertie in the test year. I
recommend removal of intertie costs to match costs and
benefits in the test year. I further recommend the
Company be required to demonstrate the prudence of its
management of this contract.
Adjustment 12. I don't take any position on including the
Populus to Ben Lomond transmission line in the test year.
However, if included, I recommend an adjustment to reflect
reductions in losses the line wil produce.
Adjustment 13. The Company includes an expiring
transmission contract that wil no longer be needed after
completion of the Populus to Ben Lomond line. If the new
line is included in the test year, transmission wheeling
expense should be reduced to remove the cost of this
contract.
F.Non Fuel Start up O&M
Adjustment 14. My proposed screening adjustment
reduces the number of starts of combined cycle plants in
the test year, overstating O&M costs. If this adjustment is
not adopted, a higher value for Adjustment 1 should be
used as is shown in Table 1.
G.Filng Requirements
I recommend the Company be required to file specific
GRID workpapers in future cases. The Company has
agreed to these requirements in other states. It should not
be diffcult for the Company to comply with this
requirement.
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1 GRID COMMTMENT LOGIC ERROR
2 Adjustment 1: Commitment Logic Screens
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PLEASE PROVIDE SOME BACKGROUND CONCERNING TilS
ISSUE.
5 A.GRID has a logic error that results in improper unit commitment and dispatch
6 decisions for gas units and call options. The Company acknowledges the
7 problem exists in GRID. This problem has existed since the model was
8 developed, and has been acknowledged by the Company in numerous recent
9 cases in the various states.
10 Absent user-supplied workarounds, GRID frequently fails to develop
11 the least cost sequence of star-ups and shut-downs of gas-fired resources.
12 Left alone, there are many hours when gas-fired generators fail to operate
13 economically within the modeL. This has a spilover effect on coal-fired
14 generation because the uneconomic operation of gas plants forces lower cost
15 coal units to have their output curiled.
16 The problem occurs because the logic în GRID separates the decision
17 to commit (star up or to not shut down) a resource from the operating
18 constraints (transmission and market capacity limits) imposed by other model
19 inputs. However, these operating constraints are used later to determine the
20 optimal dispatch of resources. The model unealistically assumes there is
21 always a market for energy when making the commitment (star up or shut
22 down) decision, but once the units are ruing GRID assumes there is no
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market for the energy these resources could otherwise sell due to the
previously ignored constraints.
EXPLAIN YOUR INVOL VMNT IN TilS ISSUE.
I have addressed this issue in testimony in several states. I first brought it to
the Company's attention in Wyoming Public Service Commission docket No.
20000-277-ER-07 in January 2008. Since that time both the Company and I
have addressed various solutions in cases in Oregon, Washington, Wyoming
and Utah. The Utah Public Service Commission ("Utah Commission")
adopted my proposed adjustments related to this issue in Docket Nos. 07-035-
8911 and 09-035-23.Y All of the other cases where this matter was at issue
resulted in settlements that did not adopt any specific adjustment related to
this problem.
HAS THE COMPANY ATTEMPD TO ADDRESS TilS PROBLEM
IN ITS FILING?
Yes. Dr. Shu has included a daily "screening adjustment," which is intended
to correct this problem. In the response to Monsanto Data Request ("DR")
2.8, the Company provided the workpapers used to develop the screens.
Essentially, this methodology forces a specific daily schedule or screen for gas
plants if it can reduce NPC relative to the GRID model's internal logic.
Otherwise, the Company allows GRID to develop its own schedule, using the
II Re Rocky Mountain Power 2007 General Rate Case, Utah Commission Docket No. 07-035-
93, Report and Order on Revenue Requirements at 30 (August 11,2008).
Re Rocky Mountain Power 2009 General Rate Case, Utah Commission Docket No. 09-035-
23, Report and Order on Revenue Requirements, Cost of Service and Spread of Rates at 29
(Feb. 18,2010).
Y
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flawed logic. The Company's method is an improvement over its prior
efforts. However, it can and should be improved upon to eliminate as much of
the error induced cost as possible.
is THE COMPANY'S NEW SOLUTION ONE THAT YOU HAVE
PREVIOUSL Y PROPOSED?
No. The Company's proposal was developed in response to my previous
proposal to use daily screens; however, the Company's approach differs from
my recommended solutions and from the solutions previously accepted by
regulators.
HOW CAN THE COMPANY'S SCREENS BE IMPROVED?
Two basic improvements are required. The Company should turn off the
GRID commitment logic entirely. It has become apparent that the internal
logic is more flawed than previously thought. In the past, it was assumed that
the only problem in GRID was that it sometimes allowed plants to run when
they should have been shut down. However, it is now apparent that at times,
the logic may actually shut down plants when they should be allowed to run.
Consequently, relying on the internal logic as the staring point fails to
identify the optimaL solution. However, solving this problem requires only
that the cycling units be modeled on a must ru basis in the preliminary run
used to develop the screens.
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WHAT OTHER PROBLEMS EXIST IN THE COMPANY'S DAILY
SCREENS?
The Company method examines only a limited number of possible daily
screens or schedules. For example, the Company examines 18 possible
screens for Curant Creek. This limits the number of star-up/shut down
choices. For example, a 10 PM shutdown of 6, 7, or 8 hours is considered, but
not a longer and more accurate shutdown period. Consequently, one problem
is the infexibilty of the Company approach and its failure to examine more
optimal schedules.
ARE THERE OTHER PROBLEMS IN THE COMPANY'S ANALYSIS?
Yes. Another problem with the Company's methodology is that it may be
using an erroneous assumption regarding star up O&M costs. The Company
assumes that staring up of a combined cycle plant requires a specific amount
of fuel be burned and that other, incremental non-fuel O&M expenses wil be
incured as well. In principle, I agree on both counts. However, the Company
fails to recognize the energy produced during the star up sequence in its test
year, and it appears that the Company may not be accounting for the
incremental effect of these non-fuel O&M expenses in the preparation of its
test year. If so, then both problems need to be addressed.
DESCRIBE THE METHODOLOGY YOU PROPOSE.
The proposed methodology is similar, but more flexible. First, the GRID
internal logic is turned off by invoking the must run status for each cycling
unit screened. Consequently, when the screening method is applied, it
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determines each hour of the year when cycling units should be ruing or not.
The Company recently agreed to make this change along with other
improvements to its screening method in OPUC Docket No. UE 216.1' Rather
than limiting the analysis to 18 screens per day, it examines 168 daily screens,
and considers the possibilty of a star-up or shut down every hour of the day.if
The method also wil allow a single screen to run for days or even weeks in
succession if that is the optimal choice.
EXPLAIN THE ADJUSTMENTS YOU COMPUTED IN TABLE 1.
In Table 1, I estimate the effect of implementing more optimal screens for the
Currant Creek plant. Because my screens result in a much smaller number of
star-ups than the Company screens, there is also change in the amount of
incremental star-up fuel and fixed (non-variable NPC) O&M expenses
included in the test year. I have identified the star up O&M component of
cost on Table 1, as Adjustment 14, while the fuel and purchased power cost
impacts are included in Adjustments 1 and 2.
HAS THE COMPANY APPLIED ITS SCREENING METHOD TO ALL
RESOURCES SUBJECT TO THE LOGIC ERROR?
No. The Company did not apply its correction to the duct firing capabilty of
Currant Creek or Lake Side, nor to call options. In the case of Lake Side this
is a substantial problem, as the capabilty is invoked many hours (1048) when
it is uneconomic to ru. Considering the resource is only economic to run for
'J Re PacifiCorp's 2011 Transition Adjustment Mechanism, OPUC Docket No. VB 216,
Stipulation at 3-4 (July 7, 2010).
It is not diffcult to expand the number of screens further and I would not object to doing so.1/
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1 1683 hours, this means GRID produces an incorrect dispatch 38% of the time.
2 In fact, there are four entire months when it would be less costly if the GRID
3 model never used the Lake Side duct firing. I have also corrected this
4 problem in Table 1. The Commission should require the Company to address
5 this problem as welL.
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WHY DON'T YOU DEVELOP SCREENS FOR ALL OF THE
PACIFICORP GAS-FIRED PLANTS?
8 A.The final screens wil depend on the adjustments adopted by the Commission
9 and any other updates or corrections. My purpose in this case is to explain
10 and ilustrate the correct way to develop the screens, and recommend the
11 Commission require this approach in its final order. I recommend the
12 Commission require the Company to implement my proposed screening
13 method after the Company models all Commission approved adjustments as a
14 "final" GRID run for this case.
15 Adjustment 2: Start Up Energy
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DR. SHU TESTIFIES ON PAGE 8 THAT SHE INCLUDED START UP
GAS COSTS IN GRID. DO YOU AGREE WITH INCLUSION OF
START-UP GAS COSTS IN NPC?
19 A.Yes, these are legitimate net power costs. However, the Company only
20 considers the cost of fuel required to tae the unit from a war shut-down
21 state to minimum load but ignores the energy produced during this process.
22 During the period the units are ramping up (about 2 hours), the power output
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HAS THE COMPANY OPPOSED TilS ADJUSTMENT IN OTHER
STATES?
Yes. The Company has argued varous points including: 1) Within an hour
there is no market for the energy; and 2) Star-up energy imposes additional
reserve requirements on the system.~ Based on these kinds of qualitative
arguents, the Company argues no value should be ascribed to star-up
energy.
DO YOU AGREE WITH THESE CRITICISMS?
No. Were the Company to apply the same arguents to wind energy, it would
suggest that wind energy has zero value, or worse - that integration costs
actually exceed the dispatch benefits of wind resources. All of these concerns
apply more directly to wind energy than to star-up energy. For example,
star-up energy is far more predictable on a day ahead, hour ahead, and intra-
hour basis than is wind energy. While dispatchers do not know if wind wil
blow the next day or the next hour, suddenly quit, or ramp up unexpectedly,
this is not the case for combined cycle plant start-up energy. Gas plant
schedules area plan made a day in advance, while a "wind schedule" is
merely a weather forecast. One can predict combined cycle star energy far
more reliably than wind power. The arguments concerning the lack of an
intra-hour market apply to wind energy even more-so than star-up energy.
'j See Utah Commission Docket No. 09-035-23, Rebuttal Testimony of Gregory N. Duvall at
15-16 (Nov. 14,2009). Mr. Duvall also made an argument concerning minimum down times
which I have addressed in my analysis in this case.
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DID YOU ALSO CONSIDER THE CONCERNS REGARING THE
NEED TO INCREASE RESERVES TO COVER THE RAM UP OF
THE COMBINED CYCLE PLANTS IN YOUR ANALYSIS?
Yes. The approach I have taken is to conservatively assume that star up
5 energy results in a back-down of coal generation which is then used for load
6 following and providing reserves. This provides a floor on the value of star-
7 up energy, which should be reflected in the test year.
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HAVE OTHER EXPERTS SUPPORTED TilS TYPE OF POWER
COST ADJUSTMENT?
Yes. In the 2009 Utah General Rate Case (Utah Commission Docket No. 09-
11 035-23), the Utah Division of Public Utilties power cost expert, Mr. George
12 Evans, proposed a similar adjustment. Mr. Evans also testified in response to
13 one of the Commissioner's questions that modeling of star-up energy was the
14 industry standard approach.QI Mr. Evans has testified in numerous cases
15 throughout the US and has approximately 30 years experience in power cost
16 modeling.
17 Adjustment 14: Start Up O&M
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EXPLAIN WHAT IS MEANT BY START UP O&M.
The Company assumes that staring up a gas combined cycle plant wil result
in incremental non-fuel O&M expenses. The logic used in its screening
method considers this cost before allowing these units to restar afer a
shutdown. I agree with this, in principle, and have included the same kinds of
Q/Re 2009 Utah General Rate Case, Utah Commission Docket No. 09-035-23, Transcript at 549
(Dec. 14, 2009).
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1 costs in my screening method. Because my proposed screens are more
2 efficient, they result in 95 fewer star ups for Curant Creek than the Company
3 screens allow. This implies lower non-fuel O&M costs should result for the
4 unit. The Company's screening method actually increases the number of
5 stars relative to the case with no screens, suggesting an increase to non-fuel
6 O&M would is waranted if one accepts Dr. Shu's screens. Consequently,
7 Adjustment 14 provides my calculation of the benefits of the reduced non-fuel
8 O&M expense for the Curant Creek plant. When coupled with the
9 Company's generation overhaul cost for Curent Creek (see McDougal
10 Exhibit NO.2 at 4.10.1), it would lower the Curant Creek overhaul costs to a
11 level closer to that of Lake Side and Chehalis for the test year. Consequently,
12 I recommend this adjustment to the test year as well.
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DOES THE COMPANY ACTUALLY INCLUDE ANY ADJUSTMENT
TO THE TEST YEAR TO ACCOUNT FOR THE CHANGE IN START
UP O&M DUE TO ITS SCREENS?
16 A.It appears they may not be doing so. I don't see any adjustment to account for
17 the start up O&M in either the Net Power Cost adjustments or the Generation
18 Overhaul expense adjustments. If so, then it may not be appropriate to make
19 the reduction to non-fuel O&M recommended in Adjustment 14. However, if
20 that's the case, then the assumption the Company uses in setting its screens
21 (which includes a non-fuel star up O&M cost of per s tar) is
22 most certainly wrong, and should be eliminated. Either the cost is real (and
23 should be included in the test year) or its not (and should not be used in
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computing the screens). Only one of these choices can be correct. If it's the
former, the Adjustment 14 is appropriate. If it's the later, then a different
screen is optimal and the reduction to NPC in Adjustment 1 would be
substatially greater as shown on the footnote to Table 1. This is because the
lower star up costs result in more economic stars, and a bigger impact from
the use of a proper screen as compared to the Company rus. In either case
the test year revenue requirements are lower than proposed by the Company.
B. LONG TERM CONTRACT ADJUSTMENTS
DOES GRID MODEL PURCHASE AND SALES CONTRACTS?
Yes. GRID includes the costs and energy produced by its long-term and
short-term contracts, along with its thermal generation resources.
Adjustment 3: SMU Contract Delivery Pattern
WHAT is A CALL OPTION CONTRACT?
This is a contract that allows the purchaser the right to pre-schedule energy
deliveries based on expected market prices and/or the purchaser's
requirements. The Company is both a buyer and seller of call option
contracts. The Company models a "call option sale" contract for the SMUD
in the GRID modeL.
EXPLAIN THE MODELING OF CALL OPTION SALES IN GRI.
In GRID, inputs specify contractual energy limits on an hourly, daily, weekly,
monthly or anual basis. For sales with anual contract energy limits, such as
the SMUD contract, GRID schedules the contract energy during the highest
cost hours of the year. Because the contract has an anual energy limit of
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1 approximately 350,400 MWh (with a 100 MW maximum hourly take), the
2 Company assumes SMUD wil call the energy from the contract during the
3 highest cost1l 3504 hours.8 in the year. For SMUD,GRID assumes the
4 counterpary finds the most costly way possible to use the energy available
5 under the contract. In effect, the Company's modeling assumes the "worst
6 case" scenario.
7 Q.is TilS REALISTIC?
8 A.No. In fact, it simply does not happen in actual operation. Figure 1, below,
9 compares the actual monthly delivery patterns of the SMUD contract to the
10 GRID assumptions. Generally, SMUD use this resource in a maner that is
11 far less costly than assumed by the Company. While the Company assumes
12 SMUD wil never take power during low cost months such as April through
13 June, in reality SMUD takes substantial deliveries during those months.
1J
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Based on COB market prices.
350,400/1 00= 3504.
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Figure 1: SMUD Monthly Sales Jan 2006-Dec 2009
60,000
50,000
40,000
'".!iaVI 30,000:i -Actual
==:!-GRID
20,000
10,000
1 2 3 4 5 6 7 8 9 10 11 12
There are many reasons why this is be the case. First, SMUD is not
using the same forward price cures as the Company. It is safe to assume that
SMU has no specific knowledge of the Company's forward price curves or
vice-versa. Differences in delivery location, transmission constraints,
availability of the SMUD's own generation and many other factors wil drive
decisions to use the available energy. In the end, SMUD is interested in
serving its own. customers at the leåst possible cost (subject to its own
constraints), not in maximizing the cost to PacifiCorp. The Company's
approach does not represent "normalization" of the contract, but rather the
very worst possible outcome for the Company.
DOES THE COMPANY USE HISTORICAL DATA IN THE
MODELING OF OTHER CONTRACTS?
Yes. The Company uses historical data to compute varous inputs for the
various contracts including APS, Black Hils Power, GP Camas, small
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purchase contracts, and reserve requirement inputs for non-owned generation
located in its service area. Further the market caps used in GRID are based on
historical data as well. Use of historical data is common in the Company's
modeling of contracts.
IN UTAH COMMSSION DOCKET NO. 07-035-93, YOU PROPOSED
THE SAME NORMLIZATION ADJUSTMENT FOR THE SMU
CONTRACT. WHAT WAS THE OUTCOME OF THAT CASE?
The Utah Commission accepted the adjustment,21 The Utah Commission also
declined to act on the Company's request for reconsideration regarding the
matter. Finally, in Docket 09-035-23, the Utah Commission reaffirmed its
support of this adjustment. 101 As in the case of the screens, this issue has not
been resolved in other states. Despite all this, the Company stil disagrees
with the adjustment and does not apply it in any other state. The Company
has made a number of different arguents regarding this issue. In other
testimony, the Company suggested that if it were correct to not use the actual
data in determining the dispatch of call option sales contracts, one should
assume the Company would not make the least cost decisions concerning its
own purchase agreements such as the Hermiston purchase or the Bonnevile
Power Administration ("BP A") contract.
'l Re Rocky Mountain Power 2007 General Rate Case, Utah Commission Docket No. 07-035-
93, Report and Order on Revenue Requirements at 23 (August 11,2008).
Re Rocky Mountain Power 2009 General Rate Case, Utah Commission Docket No. 09-035-
23, Report and Order on Revenue Requirements, Cost of Service and Spread of Rates at 36
(Feb. 18,2010).
1Q
18
Falkenberg, Di
PacifiCorp Idaho Industrial Customers
1 Q.
2 A.
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
DO YOU AGREE WITH THESE ARGUMNTS?
No. Based on such reasoning, one would not depar from the "highest cost"
modeling of SMUD unless one abandoned the least cost modeling of
Hermiston, BP A or other resources. Such arguments miss the fundamental
point of this analysis and of power cost modeling in general. The Company
decides when to use, or not use the BP A and Hermiston purchases and does so
to minimize costs, subject to the constraints the Company is facing. In the
case of SMUD, the Company simply does not know and has not modeled any
of the loads, constraints or forward prices curves used by SMUD. Were the.
Company able to do so, it might make sense to model them in GRID without
any adjustments derived from historical data. In effect, GRID is "flying
blind" when it comes to the counterparies and has no reasonable basis for
assuming the counterparties can even use the power available at all the highest
cost hours. History shows they simply do not do so. In the end, the
adjustments I make to the SMUD delivery pattern are simply a proxy for the
constraints and other assumptions related to the SMUD contract that are
unown and probably unkowable to PacifiCorp. I recommend that
Commission adopt Adjustment 3, to implement a more realistic shape for the
SMUD contract.
19 "
Falkenberg, Di
PacifiCorp Idaho Industrial Customers
1
2 Q.
3
4
5 A.
C. NON -OWND ("OATT") WIND INTEGRATION COSTS
DOES THE COMPANY INCLUDE WID INTEGRATION COSTS
FOR ANY NON-OWNED WIN FARM LOCATED IN ITS SERVICE
AREA?
Yes. The projects are generally transmission customers takng service under
6 the terms and conditions of the Company's Open Access Transmission Tariff
7 ("OATT").
8 Q.
9
10 A.
DOES PACIFICORP'S OATT INCLUDE ANY CHARGES FOR WIND
INTEGRATION SERVICES?
No. While the OATT does provide for charges for reserves for transmission
11 customers, it does not provide any charges for wind integration service. As a
12 result, the Company is providing integration services to these customers
13 without compensation. Unfortunately, retail customers wil be required to
14 subsidize wholesale transmission service, if this is allowed by the
15 Commission.
16 Q.
17
18 A.
DO OTHER TRANSMISSION PROVIDERS INCLUDE WIND
INTEGRATION CHARGES IN THEIR OATT?
Yes. BPA includes such charges in its OATT, and PacifiCorp pays BPA for
19 wind integration services. The Company has included these charges in its
20 GRID test year for sometime. There is no reason why the Company should
21 not seek approval to include such charges in its OATT. Until such approval is
22 granted, the Company should not be allowed to charge retail customers for
23 providing services to its wholesale transmission customers.
20
Falkenberg, Di
PacifiCorp Idaho Industrial Customers
1 Q.
2
3
4
5 A.
is THERE ANY REASON WH THE COMPANY COULD NOT
HAVE ALREADY MADE A FILING AT THE FERC SO THAT IT
COULD HAVE INCLUDED WIND INTEGRATION CHAGES IN ITS
OATT, OR IMPLEMENT SOME OTHER MECHANISM?
No. The Company has expected since at least the time of its 2004 IRP that it
6 would experience substantial costs for wind integration. Its 2004 IRP
7 supported a value of $4.64/MWH.ll By January 1,2011, the Company wil
8 have had more than six years to have made the appropriate fiings with the
9
10
11
12
13
14
15
16 Q.
17 A.
18
19
20
21
22
23
ll
PERC to recover wind integration costs from transmission customers. Furer,
the Company has conducted numerous meetings relative to its jurisdictional
allocation procedures for the past decade. There is no reason why the
Company should not have engaged the PERC in this process to address an
equitable solution to the OATT wind integration issue. The Company' slack
of dilgence is no excuse to charge retail customers such costs.
Adjustment 4: Non-Owned Wind Farm Inter':Hour Integration Costs
PLEASE EXPLAIN THE BASIS FOR TilS ADJUSTMENT.
The Company models a charge of $6.50IMH for wind integration costs in
GRID. This includes both intra and inter-hour integration costs for non-
owned wind farms for which it provides transmission services. The Company
did not differentiate between these two kinds of costs in this case, but has
done so in its IRP studies.
Adjustment 4 removes the cost of inter-hour wind integration from
GRD for non-owned generators. This is much the same as the case of the
Re PacifiCom Large OF A voided Cost Case, Utah Commission Docket No. 03-035-14,
Report and Order at 23 (Oct. 31,2005).
21
Falkenberg, Di
PacifiCorp Idaho Industrial Customers
1
2
3
4
5
6
7
8
9
10
11
12 Q.
13 A.
14
15
16
17 Q.
18
19 A.
20
21
22
11
Goodnoe and Leaning Juniper projects which are located on the BPA
transmission system. The Company assumes it must provide its own inter-
hour integration for these wind fars, and that BP A wil not do so. Likewise,
it stands to reason that non-owned projects located on the PacifiCorp
transmission system should not require or be provided inter-hour integration
from PacifiCorp. The Company recently indicated in an Oregon discovery
response that it agrees with this position.I21 I estimated this adjustment by
removing the Company's estimated 2010 inter-hour wind integration cost
($2.09/M) from the Company's assumed total wind integration cost used
in this case ($6.50IMWH).
Adjustment 5: Non Owned Intra Hour Wind Farm Integration Costs
PLEASE DISCUSS TilS ADJUSTMENT.
This adjustment completes the disallowance of the cost of integrating OA TT
customer wind fars by removing the intra-hour cost component. It is
computed by taking the residual of the figures quoted above ($6.50-$2.09)
times the OATT wind far MWH.
DOES THIS ADJUSTMENT HAVE AN IMPLICATION FOR THE
TRUE-UP PROCEEDING?
Yes. The true up should make a parallel adjustment for OATT wind farms to
eliminate the actual cost of providing integration services to these entities. If
this is not done, retail customers wil be charged for providing service to
wholesale transmission customers.
Exhibit No. 607 at 1 (Response to OPUC DR 22, OPUC Docket No. UE 216).
22
Falkenberg, Di
Pa~ifiCorp Idaho Industrial Customers
1 D. OUTAGE RATE MODELING ISSUES
2 Q.
3 A.
EXPLAIN THE USE OF THERMAL DERATION FACTORS IN GRID.
In GRID, thermal deration factors (also called unplaned outage rates) control
4 the amount of generation available from thermal units. The more energy
5 available, the lower net variable power costs. If a generator has an average
6 unplaned outage rate of 20%, GRID assumes a thermal deration factor of
7 80%. This means that only 80% of the unit's capacity is available to produce
8 energy. The remaining capacity is assumed to be permanently unavailable.
9 The Company computes thermal deration factors based on a four year moving
10 average of outage rates. This calculation includes all outage events that
11 occurred during the four year period (2006-2009). This provides a mechanism
12 for the Company to recover costs associated with prior outages, albeit at
13 curent market prices.
14 Q.
15
ARE UNLANNED OUT AGES AN IMPORT ANT DRIVER IN
OVERALL NET POWER COSTS?
16 A.Yes. Any increase in unplaned outages increases NPc. Consequently, it is
17 important to review unplaned outages to determine if they were prudent or
18 reasonable to included in a four year moving average.
19 Adjustment 6-7: Lake Side and Colstrip 4 Extreme Outage Events
20 Q.PLEASE EXPLAIN THIS ADJUSTMENT.
21 A.In reviewing Dr. Shu's workpapers, I noticed that Lake Side had an extremely
22 high outage rate modeled in GRID. Based on the historical data period used
23 by the Company, Lake Side had an outage rate of". In examining the data
23
Falkenberg, Di
PacifiCorp Idaho Industrial Customers
1
2
3
4 Q.
5 A.
6
7
8
9
10
11
12 Q.
13
14 A.
15
16
17
18
19
20
21 Q.
22 A.
23
supporting this figure, I found that more than .of the lost energy was due
to a single event starting
PLEASE DISCUSS THE LONG OUTAGE AT COLSTRIP 4 IN 2009.
A problem was discovered during the 2009 planned outage of Colstrp 4,
which prevented the units' retur to service in May. The outage extended for
_ before the equipment could be repaired. This single event was
responsible for. of the lost generation at the plant in the entire four year
period. As a result, the Company computes an average outage rate for
Colstrip 4 of _. For 2009 this equates to an outage rate in
for the unit.
SHOULD THE ENTIRE DURATION OF THESE EVENTS BE
REFLECTED IN RATES?
No. These were extremely rare events and not ones likely to recur once every
four years, as is assumed in the Company's four year moving average
calculation. It is very unikely that these events are representative of
conditions in the rate effective period. As a result, it is quite likely that
including these events in the test year outage rate wil produce an inaccurate
forecast. Furer, the extreme lengt of these events suggests a prudence
investigation should be undertaken in the appropriate true up proceeding.
WHAT IS YOUR RECOMMNDATION?
I recommend these outages be capped at 28 days in the outage rate
calculation. This approach was recently recommended by a Company witness
24
Falkenberg, Di
PacifiCorp Idaho Industrial Customers
1
2
3
4
5 Q.
6 A.
7
8
9
10
11
in a recent OPUC docket, UM 1355, and provides a reasonable method for
dealing with extremely long outages. The figue below ilustrates in par, why
this is the case.
Figure 2
PacifCorp Thermal Plant Outage Duration: 2004-2008
720
~ .. .. .. .. .... .. .. .. .. .. ... .. .. .. .. .. ... .. .. .. .. .... . .. .. .. .. .... .. .. .. .. .. .. .. ... .... ..... .. ... .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .... .. .. .. .. .. ... .. .. .. .. .. .. ... . . . . . . . . . ... .......... .. ... ... . .... . .... . ... ........
640 .....r......r.....-r......¡......1......1.......r......¡......1......r...... .......
560 :::::i::::::1:::: ::::::::: I:::::: i:::::: :::::::: i: ::::: I:::::: i::::::i::::::: :::::::
! :: .....~......j.......l......l......J......j.......l......l......J......l...... .......
~ 320 ¡ ¡ ¡ ¡ ¡ ¡ : ¡ ¡ ¡ :._....:~......:..._....:-........:;.......:.._......:..........:...........:.......:........;..;.... :-........... .... . .. .. ... . ... .. ... .. .... .. ... .. .. , . . , . . . , . ....... "."~.""""" ...............,............. ~............ 'I".......... "0".......... -;-............ r............ 'I.......................... l'............... . .. ... . .. ... . " ... . .. ... , .. ... . ... ... . . .. . . . . . . ...................................................................................................... ................ ....,.... ......... ......,.. ........ ........ .... ... .. .
240
160
80
o
o 60 96728412243648
Percentile
PLEASE EXPLAIN THE FIGUR ABOVE.
This char shows the cumulative percentage offorced outages occurring as a
function of outage duration. The data was based on all forced outages at
PacifiCorp phints from July 2004 to June 2008.13/ For example, more than
half of these events were lasted for five hours or less. Ninety percent were 51
hours or less duration. Virually all of the events that occurred (99.8%) were
less than 672 hours (28 days) duration. This clearly establishes that outages
lJ This data was used because it is now considered "non-confidential" by the Company.
25
Falkenberg, Di
PacifiCorp Idaho Industrial Customers
1
2
3 Q.
4
5
6 A.
7
longer than 28 days are extremely rare and simply won't occur once every
four years for a specific resource.
PLEASE ELABORATE ON YOUR COMMNT THAT PACIFICORP
SUPPORTED THE CAPPING OF OUTAGES AT 28 DAYS IN A
RECENT OREGON CASE.
Oregon Docket UM 1355 was a generic investigation into methods to improve
outage rate forecasts. Varous proposals were made by the paries.
8 PacifiCorp's final proposal was a "collar" mechanism that would eliminate
9 extremely high or low outage rates from the four year average calculation.
10 However, prior to applying its collar, PacifiCorp proposed to cap outage
11 durations at 28 days. 141 If the anual average outage rate for the resource was
12 stil outside of a range based on historical data, the Company would fuher
13 reduce the outage rate under its collar proposal.
14 Q.
15
16 A.
17
18
19
20
21
22
AR YOU ADOPTING THE ENTIRE PACIFICORP OREGON
COLLAR PROPOSAL?
No, the PacifiCorp proposal has not been accepted by regulators, and has.
various other unelated defects. In the Oregon case there are several other
competing alternatives and a decision is pending. In any case, capping the
long outages at 28 days would result in an outage rate for 2009 that would be
unlikely to require adjustment based on the PacifiCorp proposal. If any of the
UM 1355 collar proposals were applied, however, it would only serve to
further reduce the Lake Side and Colstrip outage rates.
l4 Re OPUC Investigation Into Forecasting Forced Outage Rates for Electric Generating Units,
OPUC Docket No. UM 1355, Supplemental Testimony of David J. Godfrey, PPL Exhibit No.
i 02 at 9 (July 24, 2009).
26
Falkenberg, Di
PacifiCorp Idaho Industrial Customers
1 Q.
2
3 A.
WAS TilS TREATMENT OF LONG OUTAGES PREVIOUSLY
REQUIRED BY THE OREGON COMMSSION?
Yes. In the final order in Oregon Docket UE 191, the OPUC stated as
4 follows:
5 The Company documents show that the anticipated duration of
6 the resulting outage was five to seven weeks. An outage of that
7 duration, no matter what the cause, is anomalous, and raises
8 issues regarding its inclusion in normalized rates. In this case,
9 we find that a 28-day period is a reasonable limit on the lengt
10 of the outage for the purose of calculating the TAM
11 adjustment factor. To the extent the actual outage exceeded 28
12 days, the Company should make an appropriate adjustment to
13 the outage rate used in ruing the GRID model.15/
14 Q.
15
16 A.
WILL CAPPING FORCED OUTAGES AT 28 DAYS RESULT IN
IMPROVED ACCURACY FOR OUTAGE RATE FORECASTS?
Yes. This issue was analyzed also in Oregon Docket UM 1355. Based on an
17 analysis of four year moving average forecast of outage rates for PacifiCorp
18 plants from 1989 to 2008, the use of the 28 day cap reduced the sum squared
19 forecast error by more than 9% as compared to use of four year moving
20 average based on the uncapped data. I also performed statistical tests to
21 determine the validity of this accuracy gain. The results indicate that the
22 accuracy improvement is statistically signficant at the 99% percent
23 confidence leveL.
24 Q.
25 A.
26
WHAT IS YOUR RECOMMNDATION?
I recommend the Commission limit the long 2009 Lake Side and Colstrip
outages to 28 days. The impact of this adjustment is shown on Table 1.
12 Re PacifiCorp's 2008 Transition Adjustment Mechanism, OPUC Docket No. UE 191, Order
07-446at21 (Oct. 17,2007).
27
Falkenberg, Di
PacifiCorp Idaho Industrial Customers
1 Adjustment 8: Bridger Fuel Quality
2 Q.
3
CAN FUEL PROBLEMS CAUSE GENERATOR OUTAGES OR
DERATIONS?
4 A.Yes. Fuel problems can result in a reduction to capacity, or a complete
5 shutdown of a plant. Some problems, such as frozen or wet coal are caused
6 by bad weather and are beyond the Company's control. However, fuel quality
7 testing is a normal practice at all power plants and is intended to prevent
8 output reductions, violation of air quality standards or damage to power
9 plants. Utilities report to Nort American Electric Reliabilty Council
10 ("NERC") the instances where fuel quality problems result in lost energy due
11 to outages or derations.
12 Q.
13
DOES IT APPEAR THAT PACIFICORP HAS PROBLEMS WITH
FUEL QUALITY AT ANY OF ITS PLANTS?
14 A.There appears to be an inordinate number of derations at the Bridger plant
15 related to fuel quality problems. Review of data from 2006-2009 shows that
16 on average, the Company loses far more energy due to fuel quality issues at
17 Bridger than any other plant. In fact, 78% of all energy lost due to fuel quality
18 problems occurred at Bridger. Bridger fuel quality losses are more than twice
19 the NERC average for comparably sized plants.
20 Q.WHAT IS YOUR RECOMMNDATION?
21 A.Bridger coal is produced at a Company owned captive mine. The level of fuel
22 quality losses is excessive and both the production of coal and the operation of
23 the plant are under the Company's direct control. Absent justification for
28
Falkenberg, Di
PacifiCorp Idaho Industrial Customers
1
2
3 Q.
4
5 A.
these circumstances in its rebuttal case, I recommend the Commission
disallow the additional costs resulting from this problem.
HAVE YOU REVIWED THE COMPANY'S COST INORMATION
FOR THE BRIDGER PLANT?
Yes. The Company also has included substantial costs in the test year related
6 to management bonuses, employee meals and gifts and donations as par of
7 the Bridger coal costs. Given the fuel quality issues at this plant, I believe it
8 would be reasonable to require the Company to absorb these costs until it can
9 demonstrate that its overall performance has improved. Adjustment 8 on
10 Table 1 includes both of these adjustments.
11 Adjustment 9: Naughton 3 Outage
12 Q.
13 A.
14
15
16
17
18
19
20
21
22
w
11
PLEASE EXPLAIN THE BASIS FOR ADJUSTMENT 18.
This adjustment removes outage events that occured at Naughton Unit 3 in
April and May 2009 from the historical record used to compute outage rates
for GRID. Exhibit 607 (page 2) is a copy of a recent discovery request16!
concerning this event. Exhibit 608 (pages 6-9) is a copy of confidential
discovery information from another discovery response17! demonstrating that
the Company's contractor,
According to the Company, the contractor
See Exhibit 607 at 2 (Response to ICNU DR 2.5).
See Exhibit 608 at 6-9 (Response to ICNU DR 2.3).
29
Falkenberg, Di
PacifiCorp Idaho Industrial Customers
1
2
3
4
5
6
7
8
9
10
11 Q.
12
13 A.
14
15
16
17 Q.
18 A.
19
20
21
22
23
Because the
Company was compensated by Siemens for these problems, imprudence
and/or negligence is not debatable.
Consequently, I made adjustments to both planed and forced outages.
DOES THE LIQUIDATED DAMGES PAYMENT COMPENSATE
CUSTOMERS FOR TilS EVENT?
No. Replacement power costs were much higher and if the outage is included
in the historical record for the next four years it would result in customers
bearing substantially greater costs, at current market price levels.
Adjustment 10: Heat Rate Deration Adjustment
WHAT IS THE PURPOSE OF ADJUSTMENT 10?
This adjustment adjusts heat rates so they are not arificially inflated due to
the deration of unit maximum capacities used to model forced outages in
GRID. A modeling technique designed to eliminate this problem is already
used by at least one other regional utility, Portland General Electric ("PGE"),
in its power cost model, MONET. I believe this represents standard industry
practice, as do other experts. For example, in Utah Commission Docket No.
30
Falkenberg, Di
PacifiCorp Idaho Industrial Customers
1
2
3
4
5
6
7
8 Q.
9 A.
10
11
12
13
14
15
16
17
18
19
20
w
12
07-035-93, another power cost modeling expert, Mr. Philp Hayet, testified
that the technique is well accepted in the community of production cost
modeling experts.181 Furer, this technique was recommended for application
to PacifiCorp by OPUC Staf witness, Kelcey Brown in OPUC Docket UM
1355. 191 Finally, PacifiCorp itself uses the same technique for modeling of
fractionally owned units, such as Bridger and Colstrip. The adjustment I
propose in this case is a simplification intended to partially address this issue.
WHY is AN ADJUSTMENT NECESSARY?
In GRID, and some other power cost models, forced outages are modeled by
"shrinking" the capacity to account for outages. For example, a 100 MW unit
with a 20% forced outage rate is seen as an 80 MW unit.
A problem with the GRID modeling is that when the capacity of units
is derated to model outages, there is a mismatch with the heat rate curve. The
char below shows what happens when a heat rate curve sized for a 100 MW
unit is applied to the now shrnken 80 MW unit. The unit arificially "moves
up the heat rate cures" and efficiency appears to be reduced. As the forced
outage rate increases for a unit, its heat rate normally increases in the GRID
modeling. This, however, is highly umealistic, as lengthening the period of a
forced outage should have no effect on the resources average heat rates. The
GRID method also "rewards" the Company for having high outage rates.
Re Rocky Mountain Power 2007 General Rate Case, Utah Commission Docket No. 07~035-
93, Direct Testimony of Philp Hayet, Exhibit No. CC.S 5D at 25 (April 7, 2008).
Re OPUC Investigation Into Forecasting Forced Outage Rates for Electric Generating Units,
OPUC Docket No. UM 1355, Supplemental Reply Testimony of Kelcey Brown, Staff Exhibit
No. 300 at 20 (August 13, 2009).
31
Falkenberg, Di
PacifiCorp Idaho Industrial Customers
Figure 3
::~ 8.0
3'i- 7.5i:
:E
:E 7.0
6.5
GRID Heat Rate Penalty
9.0
8.5
-Average Heat Rate Curve 10% fOR
6.0
60 64 68 72 76 80 84 88 92 96 100
MWCapacíty
1 Q.DO YOU HAVE ANY DATA THAT ILLUSTRATES TilS PROBLEM?
2 A.Yes. When the long outage for the Lake Side plant, discussed above, was
3 removed from the GRID database, the average heat rate for Lake Side was
4 decreased by .9%. However, it stands to reason that the time spent when a
5 plant is sitting idle should have no impact on its average heat. The fact that it
6 does in GRID, is proof that this problem is reaL.
7 Q.
8
HAS THE COMPANY ALREADY CONCEDED THERE IS VALIDITY
TO TilS ARGUMENT?
9 A.In Oregon Docket UM 1355, the Company's witness, Mr. Gregory N.
10 Duvall's testimony indicated he agreed that at least at the derated maximum
11 capacity of a unit, the criticism was valid. Mr. Duvall testified that the
12 solution I propose was not correct below the derated maximum capacity and
32
Falkenberg, Di
PacifiCorp Idaho Industrial Customers
1
2
3
4
5
6
7
8 Q.
9 A.
10
11
12 Q.
13
14 A.
15
16
17
18
19
20
21
that "the issue that ICNU is trg to address (i.e. the heat rate to use at the
derated capacity level) is near zero in this example, and is not nearly as large
as the error they create. ,,201 His testimony addressed different aspects of this
problem, for which I proposed a more comprehensive solution in the Oregon
case using the techniques alluded to above. The reference to the adjustment
being "near zero" was based on the heat rate cure for a single plant, which
was unrepresentative.
DO YOU AGREE WITH THE COMPANY ABOUT TilS?
No. However, for puroses of this case, I wil concentrate solely on the
impact of the. problem when generators are modeled as ruing at the derated
maximum capacity, which the Company has apparently conceded.
CAN YOU PROVIE AN EXAMPLE wmCH ILLUSTRATES TilS
PROBLEM?
Yes. The Confidential table below ilustrates the problem. It shows the heat
rate equation used in GRID for Bridger Unit 2. Based on the data used in
GRID, the capacity of Unit 2 is approximately _. However, there are
parial outage derations that occur, that lower the available capacity to .
. on average. These events do not result in shutdown of the plant, but do
degrade the average heat rate in the field and should do so in GRID as well.
Based on the average _ capacity loading, the heat rate for the unit is
.. MMBTUIMWh.
lJ Re OPUC Investigation Into Forecasting Forced Outage Rates for Electric Generating Units,
OPUC Docket No. UM 1355, Supplemental Testimony of Gregory N. Duvall, PPL Exhibit
No. 405 at 19 (July 24,2009).
33
Falkenberg, Di
PacifiCorp Idaho Industrial Customers
1 In GRID, however, full forced outages are assumed to reduce the
2 maximum available capacity of the unit by an additional. MW, resulting
3 in a maximum derated capacity in GRID of" MW. When the GRID heat
4 rate cure is applied, the result is _ MMBTUIM.When the Bridger
5 fuel cost difference is applied to the difference between the two heat rates, the
6 resulting error is close to. This may seem like an inconsequential amount,
7 however this problem occurs thousands of hours per year for nearly every unit
8 and can become a very substantial sum of money.
9 Q.
10
HAVE YOU PERFORMD AN ANALYSIS USING GRI THAT
ISOLATES THE IMPACT OF TilS PROBLEM?
11 A.Yes. I isolated the effect based on only the hours wheIl units were dispatched
12 to the maximum derated capacity in GRID. I computed the hourly cost
34
Falkenberg, Di
PacifiCorp Idaho Industrial Customers
1 differences in the same maner as shown above. The result is the amount
2 shown on Table 1.
3 Q.ARE THERE OTHER ASPECTS OF THIS PROBLEM?
4 A.Yes, as I mentioned above. This adjustment only isolates the problem at the
5 high end of the heat rate cure. A similar problem exists at lower loadings.
6 Further, the Company reduces the maximum capacity of units in GRID to
7 model outages, but does not do so for the minimum loading levels. It is
8 possible to implement a more comprehensive adjustment in GRID to address
9 these issues. However, given the presence of a true-up which tends to mute
10 the importance of modeling issues, and because Adjustment 10 captures the
11 majority of the effect, I have not included the other components of this
12 adjustment, in the interest of economy.
13 E. TRANSMISSION ISSUES
14 Adjustment 11: DC Intertie Costs
15 Q.
16 A.
WHAT IS THE PURPOSE OF THE DC INTERTIE CONTRACT?
17
18
19
20
21
il Exhibit 608 at 1 (WUTC Docket No. UE-100749, Response to ICND DR 1.3).
35
Falkenberg, Di
PacifiCorp Idaho Industrial Customers
1
2
3
4
5
6 Q.
7 A.
8
9
10
11
12
13
14
15
16
17
18
WHAT is YOUR RECOMMNDATION?
This contract should be removed from the test year to match costs and
benefits. There are few, if any, transactions that rely on this contract.
Presumably, in actual practice the Company would not make such purchases
unless they resulted in cost savings. The contract may provide compensating
benefits, but because the test year is largely based on projected data there are
none that can be identified and included at this time. However, it is possible
that if the contract is not really useful to the Company any longer, it may be
the Company should consider sellng its rights, or seeking to escape from it.
Transmission capacity in the region is limited, and it is hard to imagine that
this important link has no value. The Company should be required to
demonstrate the prudence of its management of this contract in the next
ECAM true-up.
w Exhibit 609 (WUTC Docket No. UE-lOO749, Response to ICNU DR 10.3).
36
Falkenberg, Di
PacifiCorp Idaho Industrial Customers
1 Adjustment 12 - Populus to Ben Lomond Line Loss Adjustment
2 Q.
3
4
5 A.
ARE YOU TAKING A POSITION REGARING THE RATE
TREATMENT OF THE POPULUS TO BEN LOMOND LINE IN THIS
CASE?
No. The issues related to timing, prudence and used and usefulness of the line
6 are beyond the scope of my testimony and presumably wil be addressed by
7 other witnesses. However, if the Commssion chooses to include the line in
8
9 Q.
10 A.
11
12
13
14
15
16
17
18 Q.
19 A.
20
21
rates, there are certain issues that should be addressed.
WILL THE POPULUS TO BEN LOMOND LINE REDUCE LOSSES?
Yes. The Company agrees that the line would produce a reduction in losses,z3/
One of the advantages of using higher voltages is that losses are reduced.
This follows from the equation PLoss = P2RN2. However, the above equation
is appropriate for a single line viewed in isolation~ but is not directly
applicable in the case of a complex transmission network.MI The Company
has produced an estimate indicating that at a 700 MW loading, savings in
losses with the Ben Lomond line in place would amount to 10.8 MW based on
a load flow study.~
HOW DID YOU QUANTIFY THE LOSS REDUCTIONS?
I assumed that most of the savings were the result of higher voltages on the
segment covered by the Populus to Ben Lomond line. I therefore computed
the reduction in losses based on the squared ratio of loadings on the line. For
lJ See Exhibit 606 (Utah Commission Docket No. 10-035-89, Response to OCS DR 2.5, 6.5,
and 6.7).
Id.
Id.
w
'l
37
Falkenberg, Di
PacifiCorp Idaho Industrial Customers
1 example, when the line was loaded to 700 MW,the loss reduction was 10.8
2 MW. If the loading was 600 MW, the loss reduction was (6001700i*10.8.261
3 I computed these savings on an hourly basis outside of GRID, though I expect
4 results using GRID would be quite close. The results are shown on Table 1. I
5 believe this is a reasonable, if not conservative, approach, but would certainly
6 welcome input from the Company on this matter.
7 Adjustment 13: Transßlission Contract Adjustment
8 Q. DOES COMPLETION OF THE POPULUS TO BEN LOMOND LINE
9 REDUCE THE NEED FOR PURCHASED TRANSMISSION
10 CAPACITY?
11 A. Yes. The Company wil no longer need some of the short term firm and
12 contract capacity it is purchasing, once the new line is completed. There is a
13 61MW contract that expires of the
14 new transmission line.
15 Q.
16
IS THE 61 MW CONTRACT NEEDED AFTER COMPLETION OF
THE POPULUS TO BEN LOMOND LINE?
17 A.No, for two reasons. First, it produces no economic benefits in the GRID
18 study. Second, if capacity were actually needed for reliabilty puroses, it
19 would be far more cost effective to purchase 61 MW of STF capacity.27
20 Q.
21 A.
DID YOU EXPLORE TilS ISSUE IN DISCOVERY?
Yes. While the Company does not agree that the new line eliminates the need
22 for the 61 MW contract, it does not indicate the contract would be extended.
23 Instead the Company merely indicated it would study whether the additional
2§
nJ
This method turs out to be more conservative than simply using the ratio of the loadings.
See Exhibit 606 at 2 (Response to DeS DR 6.2).
38
Falkenberg, Di
PacifiCorp Idaho Industrial Customers
capacity was needed in the future.
28/ Conversely, in other discovery
responses,291 the Company clearly indicated it would require additional
capacity if the Populus to Ben Lomond line was delayed. I believe that this
demonstrates the avoidance of this high cost transmission contract is one of
the benefits of the line that should be included as a par of the pro-forma
adjustment to reflect all of the costs and system benefits of the project,
assuming it is included in the test year. The impact of this adjustment is
shown on Table 1.
F. NON FUEL START UP O&M
is ADJUSTMENT 14 DISCUSSED ABOVE A NPC ADJUSTMENT?
No. It is a reduction to non-fuel O&M ,and is not in one of the accounts
included in the definition of NPc. For this reason, it is included at the bottom
of Table 1, and not par of the NPC adjustments listed. However, these are
legitimate test year costs, so they should be reflected in the test year, as
discussed above.
G. RECOMMNDED FILING REQUIREMENTS AND WORKPAPERS
DOES ICNU HAVE ANY OTHER RECOMMNDATIONS?
Yes. In stipulations in Oregon Docket UE 199, Washington Docket UE-
090205 and Wyoming Docket 20000-341-EP-09, PacifiCorp has agreed to
provide certain workpapers and supporting documents at specific times, as
well as immediate access to the GRID model with its fiings. Experience with
Id.
See Exhibit 606 at 3 (Response to OCS DR 6.3).
39
Falkenberg, Di
PacifiCorp Idaho Industrial Customers
1 these requirements in other states has become increasingly positive as time
2 passes. Exhibit 609 provides a copy of the documents agreement related to
3 the fiing requirements from Washington. I recommend comparable
4 workpaper filngs be required for Idaho as well.
5 Q.
6 A.
DOES THIS CONCLUDE YOUR TESTIMONY?
Yes.
40
Falkenberg, Di
PacifiCorp Idaho Industrial Customers
Case. No. PAC-E-l 0-07
Exhibit No. 605
Witness: Randall J. Falkenberg
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
PACIFICORP IDAHO INDUSTRIAL CUSTOMERS
Exhibit Accompanying Direct Testimony of Randall J. Falkenberg
Qualifications of Randall J. Falkenberg
October 14, 2010
PacifiCorp Idaho Industrial Customers
Exhibit No. 605 Page 1 of 11
Witness: Randall J. Falkenberg
QUALIFICATIONS OF RANDALL J. FALKENBERG, PRESIDENT
EDUCATIONAL BACKGROUN
I received my Bachelor of Science degree with Honors in Physics and a minor in mathematics from Indiana
University. I received a Master of Science degree in Physics from the University of Minnesota. My thesis
research was in nuclear theory. At Minnesota I also did graduate work in engineering economics and
econometrics. I have completed advanced study in power system reliabilty analysis.
PROFESSIONAL EXPERIENCE
After graduating from the University of Minnesota in 1977, I was employed by Minnesota Power as a Rate
Engineer. I designed and coordinated the Company's first load research program, I also performed load
studies used in cost-of-service studies and assisted in rate design activities.
In 1978, I accepted the position of Research Anlyst in the Marketing and Rates deparent of Puget Sound
Power and Light Company. In tht position, I prepared the two-year sales and revenue forecasts used in the
Company's budgeting activities and developed methods to perform both near. and long-term load
forecasting studies.
In 1979, I accepted the position of Consultant in the Utilty Rate Departent of Ebasco Service Inc. In
1980, I was promoted to Senior Consultat in the Energy Management Services Department. At Ebasco I
performed and assisted in numerous studies in the areas of cost of service, load research, and utilty
planning. In particular, I was involved in studies concerning analysis of excess capacity, evaluation of the
planing activities of a major utilty on behalf of its public service commission, development of a
methodology for computing avoided costs and cogeneration rates, long-term electricity price forecasts, and
cost allocation studies.
At Ebasco, I specialized in the development of computer models used to simulate utilty production costs,
system reliabilty, and load patterns. I was the principal author of production costing software used by
eighteen utilty clients and public service commissions for evaluation of marginal costs, avoided costs and
production costing analysis. I assisted over a dozen utilties in the performance of marginal and avoided
cost studies related to the PURPA of 1978. In this capacity, I worked with utilty planers and rate
specialists in quantifying the rate and cost impact of generation expansion alternatives. This activity
included estimating carrying costs,O&M expenses, and capital cost estimates for future generation.
In 1982 I accepted the position of Senior Consultant with Energy Management Associates, Inc. and was
promoted to Lead Consultant in June 1983. At EMA I trained and consulted with planners and financial
analysts at several utilties in applications of the PROMOD and PROSCREEN planning models. I assisted
planers in applications of these models to the preparation of studies evaluating the revenue requirements
RFICONSULTING, INC.
PacifiCorp Idaho Industrial Customers
Exhibit No. 605 Page 2 of 11
Witness: Randall J. Falkenberg
QUALIFICATIONS OF RANDALL J. FALKENBERG, PRESIDENT
and financial impact of generation expansion alternatives, alternate load growth patterns and alternate
regulatory treatments of new baseload generation. I also assisted in EMA's educational semiars where
utilty personnel were trained in aspects of production cost modeling and other modern techniques of
generation planing.
I became a Principal in Kennedy and Associates in 1984. Since then I have performed numerous economic
studies and analyses of the expansion plans of several utilties. I have testified on several occasions
regarding plant cancellation, power system reliabilty, phase-in of new generating plants, and the proper
rate treatment of new generating capacity. In addition, I have been involved in many projects over the past
several years concerning the modeling of market prices in varous regional power markets.
In January 2000, I founded RFI Consulting, Inc. whose practice is comparable to that of my former firm,
J. Kennedy and Associates, Inc.
The testimony that I present is based on widely accepted industry standard techniques and methodologies,
and unless otherwise noted relies upon information obtained in discovery or other publicly available
information sources of the type frequently cited and reliedupon by electric utilty industr experts. All of
the analyses that I perform are consistent with my education, training and experience in the utilty industry.
Should the source of any information presented in my testimony be unclear to the reader, it wil be
provided it upon request by callng me at 770-379-0505.
PAPERS AND PRESENTATIONS
Mid-America Regulatory Commissioners Conference - June 1984: "Nuclear Plant Rate
Shock - Is Phase-In the Answer"
Electric Consumers Resource Councll - Annual Seminar, September 1986: "Rate Shock,
Excess Capacity and Phase-in"
The Metaurgical Society - Annual Convention, Februar 1987: "The Impact of Electric
Pricing Trends on the Aluminum Industry"
Public Utilties Fortnightly - "Future Electricity Supply Adequacy: The Sky Is Not
Fallng" What Others Think, January 5, 1989 Issue
Public Utilties Fortnightly - "PoolCo and Market Dominance", December 1995 Issue
RFI CONSULTING, INC.
PacifiCorp Idaho Industrial Customers
Exhibit No. 605 Page 3 of 11
Witness: Randall J. Falkenberg
QUALIFICATIONS OF RANDALL J. FALKENBERG, PRESIDENT
APPEARNCES
3/84 8924 KY
5/84 830470-FLEI
10/84 89-07-R CT
11/84 R-8426S1PA
2/85 i-840381 PA
cancellation of
3/85 Case No. KY
9243
3/85 R-842632 PA
3/85 3498-U GA
5/85 84-768-WV
E-42T
7/85 E-7,NC
SUB 391
7/85 9299 KY
8/85 84-249-UAR
1/86 8S-09,.12 CT
1/86 R-8501S2 PA
2/86 R-8S0220 PA
5/86 86-081-wv
E-GI
5/86 3554-U GA
9/86 29327/28 NY
Ai rco carbide
Florida Industrial
Power Users Group
Connecti cut ind.
Energy Consumers
Lehigh valley
phila. Area ind.
Energy users' Group
Kentucky Industri a 1
uti 1 i ty Consume rs
west Penn
Power IndustrialIntervenors
GeorQia publi.c .
Service commissionStaff
West vi rgi ni a
MUl ti pleintervenors
Carolina industrialGroup for Fai ruti 1 i ty Rates
Kentucky
industrial utilityConsumers
Arkansas El ectri c
Energy Consumers
Connecti cut Ind.
Energy Consumers
phi 1 ade 1 phi a Area
industrial Energy
users' Group
West Penn PowerindustrialIntervenors
Loui svi lleGas & El ectri c
Fla. power Corp.
connecti cut
Light & power
pennsylvani a
Power committee
Electric Co.
Loui svi 11 e Gas
& Electric Co.
West Penn PowerCo.
Georgia Power Co.
Monongahela Power
Co.
Duke Power Co.
CWiP in rate base.
phase~in of coal unit. fuel
savi ngs basi s, costallocation.
Excess capaci ty.
phase-i n of nucl ear uni t.
Power & Light Co.
phi lade 1 phi a Economi cs ofnuclear generating units.
Economi cs of cance 11 i ng fossi 1gene rati ng uni ts .
Economi cs of pumped storage
gene rati ng uni ts i opti mal
res. margi n , excess capaci ty .
NUcl ear uni t cance 11 ati on iload and energy forecasting,
gene rati on econom; cs .
Economi cs - pumped storage
generating units, reserve
margi n, excess capaci ty.
NUcl ear economi cs, fuel costproj ect; ons.
Union Light, Heat interruptible rate design.& Power Co.
Arkansas Power & Prudence revi ew.
Light Co.
connecti cut Light Excess capaci ty, fi nanci a 1& Power Co. impact of phase-in nuclearplant.
phi 1 ade 1 phi a phase-i nand economi cs of
Electric Co. nuclear plant.
West Penn Power optimal reserve margins,
prudence, off-system salesguarantee plan.
West virginia Energy Monongahela Powerusers' Group Co.
Attorney General & Georgia Power Co.
GeorQia public.
Se rvi ce Commi s s i onStaff
occi dental Chemi cal Ni agara MohawkCorp. Power Co.
Generation planning study,
economics prudence of a pumpedstorage hydroelectric unit.
Cancellation of nuclearplant.
Avoided cost, production
cost models.
RF CONSULTING, INC.
Expert Testimony Appearances
of
Randall J. Falkenberg
Date Case Jurisdict. Part
9/86 E7- NC NC industrialSub 408 Energy Committee
12/86 9437/
613
KY
5/87 86-524-
E-SC
wv
6/87 u-17282 LA
6/87 puc-87- MN
013-RDE002/E-015-PA-86-722
7/87 Docket KY
9885
8/87 3673-u GA
10/87 R-850220 PA
10/87 870220-EI FL
10/87 870220-EI FL
1/88 Case NO. KY
9934
3/88 870189-EI FL
5/88 Case No. KY
10217
7/88 Case No.
325224
LADiv. i19thJudicial
Di stri ct
10/88 3780-u GA
10/88 3799-U GA
12/88 88-171- OH
El-AIR
88-170- OH
EL-AIR
Attorney General
of Kentucky
Utilty
Duke Power Co.
Big Rivers Elect.corp.
West virginia Energy Monongahela Power
Users i Group
Louisiana
public service
Commission staff
Eve 1 eth Mi nes
& usx Corp.
Attorney General
of Kentucky
GeorQia public.
se rvi ce Commi s s i onstaff
PacifiCorp Idaho Industrial Customers
Exhibit No. 605 Page 4 of 11
Witness: Randall J. Falkenberg
Subject
incentive fuel adjustmentclause.
Power system reliability
analysis, rate treatment ofexcess capaci ty.
Economi cs and rate treatment
of Bath county pumped storagecounty pumped Storage pl ant.
Gulf States prudence of River Bend
Util i ti es NUcl ear pl ant.
Minnesota powerl sale of generatina
Northern States unit and reliabilityPower requi rements.
Big Rivers Elec. Financial workout plan forcorp. Big Rivers.
Georgia Power Co.
wPP Industrial West Penn PowerIntervenors
occi denta 1 chemi cal Fl a. Powe r corp.
occidental chemical Fla. Power corp.
Kentucky industrial Louisville Gas &Uti 1 i ty Consumers El ectri c Co.
occidental Chemical Fla. power Corp,
Corp.
Nuclear plant prudence audit,vogtl e buyback expenses.
Need for power and economi cs,county pumped Storage pl ant
Cost allocation methods and
interruptible rate design.
Nuclear plant performance.
Revi ew of the current status
of Tri mb 1 e county Uni t i.
Methodo 1 oayfor evaluating
interruptible load.
National southwire Big Rivers Elec. Debt restructuringAluminum Co., corp. agreement.
ALCAN Alum Co.
Loui si ana Pub 1 i c
service commissionStaff
Gulf Statesutilities prudence ofNuclear plant.River Bend
GeorQia public. Atlanta Gas Light weather normalization gasService Commission Co. sales and revenues.staff
Georaia public. United Cities Gas weather normalization of gasService Commission Co. sales and revenues.Staff
Ohio Industrial
Energy Consumers
Toledo Edison co., Power system reliability
cl eveland El ectri c reserve margi n.
illuminating Co.
RFI CONSULTING, INC.
Expert Testimony Appearances
of
Randall J. Falkenberg
Date Case Jurisdict.Party Utilty
1/89 I-880052 PA philadelphia Area phi ladelphi a
industrial Energy Electric Co.
users' Group
2/89 10300 KY Green River Steel K Kentucky Uti 1 .
3/89 P-870216 PA Armco Advanced West Penn Power283/284/286 Materials cor1"All egheny Lud um Corp.
5/89 3741-U GA Geor~ia public,Geo rgi a Powe r Co.
Servi ce Commi ssi onstaff
8/89 3840-u GA Geor~ia public Georgia Power Co.
Service Commissionstaff
10/89 2087 NM Attorney General of public service Co.
New Mexico of New Mexi co
10/89 89-128-u AR
11/89 R-891364 PA
1/90 u-17282 LA
4/90 89-1001-0H
EL-AIR
4/90 N/A N.O.
7/90 3723-u GA
9/90 8278 MD
9/90 90-158 KY
12/90 u-9346 MI
5/91 3979-u GA
7/91 9945 TX
Arkansas Electri c Arkansas PowerEnergy Consumers Light Co.
phi lade 1 phi a Area phi 1 ade 1 phi aindustrial Energy Electric co.
users' Group
Louisiana public Gulf statesservi ce commi ssi on Uti 1 i ti esstaff
Industrial Energy ohio Edison Co.
Consumers
PacifiCorp Idaho Industrial Customers
Exhibit No. 605 Page 5 of 11
Witness: Randa:i J. Falkenberg
Subject
Nuclear plant outage,
replacement fuel costrecovery.
Contract termi nati on cl auseand i nte r rupti b 1 e rates,
Reserve margi n, avoi dedcosts.
prudence of fuel procurement.
Need and economi cs coal &
nuclear capacity, power systemplanning.
Power system planning,
economi c and re 1 i abi 1 i t¥
anal ysi s, nucl ear p 1 anni n9,prudence.
Economic impact of asset
transfer and stipulation andsett 1 ement ag reement.
sale/leaseback nuclear plant,
excess capaci ty, phase-i n
delay imprudence.
Sal ell easeback nucl ear powerplant.
power suppl y reli abi 1 i ty,
excess capacity adjustment.
New Orleans New orleans public Municipalization of investor-Business Counsel Service Co. owned utility, generation
planning & reliability
Geor~ia public. Atlanta Gas Light weather normalizationService commission Co. adjustment rider.staff
Maryland industrial Baltimore Gas & Revenue requi rements gas &Group Electric Co. electric, CWIP in rate base.
Kentucky industrial Louisville Gas & Power system planning study.
uti 1 i ty cons ume rs El ect ri c Co.
Association of Consumers PowerBusi nesses Advocati n9
Tariff Equity (ABATE)
Geor~ia public.
Service CommissionStaff
offi ce of publ i c
utility counsel
Georgia Power Co.
El paso Electricco.
DSM pol i cy Issues.
DSM, load forecasting
and IRP.
Power system planning,quanti fi cati on of damagesof imprudence,envi ronmental cost of
RF CONSULTING, INC.
Date
8/91
Expert Testimony Appearances
of
Randall J. Falkenberg
Case Jurlsdict. Party
4007-U GA GeorQia public.
Service Commissionstaff
11/91 10200 TX
12/91 u-17282 LA
1/92 89-783- WVA
E-C
3/92 91-370 KY
5/92
6/92
91890 FL
4131-U GA
9/92 920324
10/92 4132-U GA
FL
10/92 11000 TX
11/92 u-19904 LA
11/92 8469 MD
11/92 920606 FL
12/92 R-009 PA
22378
1/93 8179 MD
2/93 92-E-0814 NY88-E-081
3/93 u-19904 LA
4/93 EC92 FERC
21000ER92-806-000
office of public
Louisiana Public
servi ce Commi ssi onStaff
West vi rgi ni a
Energy Users Group
Newport Steel Co.
Utilty
Georgia Power co.
PacifiCorp Idaho Industrial Customers
Exhibit No. 605 Page ~ of i 1
Witness: Randall J. Falkenberg
Subject
el ectri city
Integrated resource planning,
regulatory risk assessment.
Imprudence disallowance.
Power Co.
Year-end sales and customeradj ustment, juri sdi cti ona 1allocation.
Monongahela power Avoided cost, reserve margin,Co. powe r plan t economi cs .
union Light, Heat interruptible rates, design,& Power Co. cost allocation.
Texas-New Mexi couti 1 i ty counsel
Gulf StatesUtilities
occi dental chemi ca 1 Fl a. Powe r Corp.corp.
Georgia Textile Georgia power Co.
Manufacturers Assn.
Florida industrial
power Users Group
Georgi a Texti 1 e
Manufacturers Assn.
office of publicUti 1 i ty counsel
Louisiana public
service commissionstaff
Westvaco corp.
incenti ve regul ati on,
jurisdictional separation,
interruptible rate design.
integrated resource planning,
DSM.
Tampa Electric Co. Cost allocation, interruptible
rates decoupling and DSM.
Georgi a Power Co.Resi denti al conservati on
program certification.
Ce rti fi cati on of uti 1 i tycogeneration project.
producti on cost savi ngs
from merger.
Houston Li ghti ng
and Powe r Co.
Entergy /Gul fStates uti 1 i ti es
(Di rect)
Potomac Edison Co. Cost allocation, revenuedi stri buti on.
Florida industrial statewide
Power Users Group Rulemaki ng
Armco Advanced west Penn powerMaterials
Eas talco A 1 umi num/westvaco Corp.
occi dental Chemi calcorp.
Loui si ana Publ i c
service Commissionstaff
Decoupling, demand-sidemanagement, conservati on,
performance incentives.
Energy allocation ofproducti on costs.
potomac Edi son Co. Economi cs of QF vs. combi ned
cycle power plant.
Ni agara Mohawk
Power corp.
Entergy/GulfStates Uti 1 i ti es(surrebuttal)
special rates, wheeling.
producti on cost savi ngs frommerger.
Louisiana public Gulf States GSU Merger prodcution cost
service Commission Utilities/Entergy savingsstaff
RFI CONSULTIG, INC.
Date Case Jurisdict.
6/93 9300 55-!t1i'fJ
9/93 92-490,KY
92-490A,90-360-C
9/93 4152-U GA
4/94 E-015/MN
GR-94-001
4/94 93-465 KY
4/94 4895-u GA
4/94 E-015/MN
GR-94-001
7/94 94-0035-wv
E-42T
8/94 8652 MD
1/95 94-332 KY
1/95 94-996-OH
EL-AIR
3/95 E999-CI MN
4/95 95-060 KY
11/95 1-940032 PA
11/95 95-455 KY
12/95 95-455 KY
6/96 960409-EI FL
3/97 R-973877 PA
3/97 970096-EQ FL
6/97 R-973593 PA
7/97 R-973594 PA
PacifiCorp Idaho Industrial Customers
Exhibit No. 60S Page 7 of 11
Witness: Randall J. Falkenberg
Expert Testimony Appearances
of
Randall J. Falkenberg
Party Utilty Subject
stockholder incentives foroff-system sales.
prudence of fuel procurementdecisions.
Florida Industrial statewidepower Users i Group Rulemaking
Kentucky industrial Big Rivers Elec.Uti 1 i ty Customers corp.
& Attorney General
Georgia Textile Georgia power Co. Cost allocation of pollutionManufacturers Assn. control equipment.
Large Power Minn. Power Co. Analysis of revenue req.Intervenors and cost allocation issues.
Kentucky industrial Kentucky Utilities Review and critique proposedUti 1 i ty Customers envi ronmental surcharge.
Georgia Textile Georgia Power Co purchased power agreementManufacturers Assn. and fuel adjustment clause.
Large PowerIntervenors
Rev. requi rements, i ncenti ve
compensati on.
Revenue annual i zati on. ROE
performance bonus, and costallocation.
Potomac Edi son Co. Revenue requi rements, ROEperformance bonus i and
revenue distribution.
West vi rgi ni aEnergy Users i
Group
westvaco Corp.
Mi nnesota PowerLight co.
Monongahela Power
Co.
Kentucky industri alUti 1 i ty Customers
industri al Energy
Users of ohio
Louisville Gas Environmental surcharge.
& El ectri c company
ohio power company cost-of-service, rate design,demand all oca ti on of powe r
Mi nnesota pub 1 i c Envi ronmenta 1 Costsutilities Comm. of electricity
Kentucky Utilities six month review ofCompany CAA surcharge.
statewi de - oi rect Access vs. pool co,
all utilities market power.
Large PowerIntervenor
Kentucky industrial
Uti 1 i ty Customers
The industri a 1
Energy Consumers ofpennsylvania
Kentucky industri al Kentucky Uti 1 ; ti es clean Ai r Act surcharge,
Kentucky industri al Loui svi 11 e Gas cl ean Ai r Act compl i ance
utility Customers & Electric company Surcharge.
Florida industrial Tampa Electric Co. polk county Power plantPower Users Group Rate Treatment Issues.
PAIEUG.PECO Energy stranded Costs & Marketprices.
FIPUG
PAIEUG
Fla. Power Corp. Buyout of QF Contract
PECO Energy Market pri ces, strandedCost
PPLICA PP&L Market pri ces, strandedCost
RF CONSULTING, INC.
Date Case Jurisdict.
8/97 96-360-u AR
10/97 6739-u GA
10/97 R-974008 PA
R-974009
11/97 R-973981 PA
11/97 R-974104 PA
2/98 APse 97451 AR
97452
97454
7/98 APse 87-166 AR
9/98 97-035-01 UT
12/98 19270 TX
4/99 19512 TX
4/99 99-02-05 eT
4/99 99-03-04 eT
6/99 20290 TX
7/99 99-03-36 CT
7/99 98-0453 WV
12/99 21111 TX
2/00 99-035-01 UT
5/00 99-1658 OH
6/00 UE-111 OR
9/00 22355 TX
10/00 22350 TX
10/00 99-263-U AR
12/00 99-250-u AR
01/01 00-099-U AR
02/01 99-255-U AR
03/01 UE-116 OR
6/01 01-035-01 UT
Expert Testimony Appearances. of
Randall J. Falkenberg
Party
AEEe
GPse Staff
MIEUG
PICA
WPII
DIl
AEEe
AEEC
DPS and CCS
OPC
'OPC
CIEC
CIEC
OPC
CIEC
WVEUG
OPC
CCS
AK steel
ICNU
OPC
OPC
Tyson Foods
Tyson Foods
Tyson Foods
Tyson Foods
ICNU
DPS and CCS
Subject
Market pri ces and StrandedCosts, Cost Allocation,
Rate Design
pl anni ng prudence of pumpedStorage Power pl ant
Market pri ces, St randedCosts
Market pri ces, Stranded
Costs
Duquesne Light co. Market prices, strandedCosts
Utilty
Entergy Ark. Inc.
Georgi a Power
Metropolitan Ed.
PENELEC
West Penn Power
Generi c Docket
Entergy Ark. Inc.
pacificorp
HL&P
SPS
CL&P
UI
CP&L
CL&P
AEP & APS
EGSI
pacifiCorp
CG&E
pacifiCorp
Re 1 i ant Ene rgy
TXU El ectri c
SW El ec. Coop
Ozarks El ec. coop
SWEPCO
Ark. valley coop
pacifiCorp
pacificorp
PacifiCorp Idaho Industrial Customers
Exhibit No. 605 Page 8 of 11
Witness: Randall J.. Falkenberg
Regul ated vs. Market Rates,
Rate unbundling, Timetable
for competi ti on
Nucl ear decommi ssi ani ngcost estimates & ratetreatment.
Net Power Cost Stipulation,
production Cost Model Audit
Reliability, Load Forecasting
Fue 1 Reconci 1 i ati on
stranded costs, Market pri ces
stranded Costs, Market pri ces
Fue 1 Reconci 1 i ati on
interim Nuclear Recovery
Stranded Costs, Market pri ces
Fue 1 Reconci 1 i ati on
Net Power Costs, productionCost Modeling issues
Stranded costs, Market pri ces
Net Power costs, Producti on
Cost Modeling Issues
stranded cost
Stranded cost
cost of servi ce
Cost of Servi ce
Rate unbundl i ng
Rate unbundl i ng
Net Power Costs
Net Power Costs
RFI CONSULTING, INC.
Date Case Jurisdict.
7/01 A.01-03-026 CA
7/01 23550 TX
7/01 23950 TX
8/01 24195 TX
8/01 24335 TX
9/01 24449 TX
10/01 20000-EP WY01-167
2/02 UM-995 OR
2/02 00-01-37 UTplant
4/02 00-035-23 UT
4/02 01-084/296 AR
5/02 25802 TX
5/02 25840 TX
5/02 25873 TX
5/02 25874 TX
5/02 25885 TX
7/02 UE-139 OR
8/02 uE-137 OP
10/02 RPu-02-03 IA
11/02 20000-Er WY02-184
12/02 26933 TX
12/02 26195 TX
1/03 27167 TX
1/03 UE-134 OR
1/03 27167 TX
1/03 26186 TX
2/03 uE-02417 WA
2/03 27320 TX
2/03 27281 TX
2/03 27376 TX
Expert Testimony Appearances
of
Randall J. Falkenberg
Party
Roseburg FP
ope
ope
ope
ope
ope
WIEe
ieNU
ees
ecs
AEEe
ope
ope
ope
OPC
ope
ieNU
ICNU
May tag , et al
WIEe
ope
ope
ope
ieNU
ope
oPC
ICNU
oPC
oPC
oPC
Utilty
pacificorp
EGSI
Re 1 i ant Ene rgy
CP&L
WTU
SWEPeO
paci fi corp
pacifieorp
pacifieorp
pacifieorp
Entergy Arkansas
TXU Energy
Re 1 i ant Energy
Mutual Energy CPL
PacifiCorp Idaho Industrial Customers
Exh!bit No. 605 Page 9 of 11
Witness: Randall J. Falkenberg
Subject
Net Power Costs
Fue 1 Reconci 1 i ati on
price to beat fuel factor
price to beat fuel factor
price to beat fuel factor
pri ce to beat fuel factor
Power cost Adjustment
Excess power Costs
Cost of Hydro Defi cit
eertifi cati on of peaki ng
Cost of plant Outage, Excess
Power Cost Stipulation.
Recovery of Ice Storm Costs
Escalation of Fuel Factor
Escalation of Fuel Factor
Escalation of Fuel Factor
Mutual Energy WTU Escalation of Fuel Factor
Fi rs t ehoi ce
portland General
portland General
Interstate P&L
pacifiCorp
Re 1 i ant Ene rgy
centerpoint Energy
Fi rst choi ce
paci fi Corp
Fi rst choi ce
SPS
pacifieorp
Reliant Energy
TXU Energy
CPL Retail Energy
Escalation of Fuel Factor
Power Cost Modeling
Power Cost Adjustment clause
Hourly Cost of Service Model
Net Power Costs,
Deferred Excess Power Cost
Escalation of Fuel Factor
Fue 1 Reconci 1 i ati on
Escalation of Fuel Factor
West valley CT Lease payment
Escalation of Fuel Factor
Fue 1 Reconci 1 i ati on
Rate plan stipulation,
Deferred Power Costs
Escalation of Fuel Factor
Escalation of Fuel Factor
Escalation of Fuel Factor
RFI CONSULTING, INC.
Date Case
2/03 27377
3/03 27390
4/03 27511
4/03 27035
05/03 03-028-U
7/03 UE-149
8/03 28191
11/03 20000-ER-03-198
PacifiCorp Idaho Industrial Customers
Exhibit No. 605 Page 10 of i 1
Witness: Randall J. Falkenberg
Expert Testimony Appearances
of
Randall J. Falkenberg
Jurlsdict.Part Utilty Subject
TX OPC WTU Retail Energy Escalation of Fuel Factor
TX OPC Fi rst choi ce Escalation of Fuel Factor
TX OPC Fi rst Choi ce Escalation of Fuel Factor
TX OPC AEP Texas Central Fuel Reconciliation
AR AEEC Entergy Ark., Inc.Power sal es Transacti on
OR ICNU Portland General Power Cost Modeling
TX OPC TXU Energy Escalation of Fuel Factor
WY WIEC pacifiCorp Net Power Costs
2/04 03-035-29 UT CCS paci fi corp certi fi cati on of ccer power
plant, RFP and Bid Evaluation
6/04 29526 TX OPC centerpoi nt stranded cost true-up.
6/04 UE-161 OR ICNU portland General power Cost Modeling
7/04 UM-1050 OR ICNU paci fi Corp Juri sdi ctional A llocati on
10/04 15392-u GA calpine Georgia power/Fai r Market value of combi ned
15392-U SEPCO cycle Power Plant
12/04 04-035-42 UT CCS pacifiCorp Net power costs
02/05 UE-165 OP ICNU portland General Hydro Adjustment Clause
05/05 UE-170 OR ICNU pacificorp Power Cost Modeling
7/05 UE-172 OR ICNU portland General Power Cost Modeling
08/05 UE-173 OR ICNU paci fi Corp Power Cost Adjustment
8/05 UE-050482 WA ICNU Avista Power Cost modeling,
Energy Recovery Mechani sm
8/05 31056 TX OPC AEP Texas central St randed cost true-up.
11/05 UE-05684 WA ICNU pacificorp Power Cost modeling,Jurisdictional Allocation, PC
2/06 05-116-u AR AEEC Entergy Arkansas Fuel Cost Recovery
4/06 UE-060181 WA ICNU Avista Energy Cost Recovery Mechani sm
5/06 22403-U GA GPSC staff Georgia Power Fuel Cost Recovery Audi t
6/06 UM 1234 OR ICNU portland General Deferral of outage costs
6/06 UE 179 OR ICNU pacificorp Power Costs, PCAM
7/06 UE 180 OR ICNU portland General Power Cost Modeling,PCAM
12/06 32766 TX OPC sps Fuel Reconci 1 i ati on
1/07 23S40-u GA GPSC staff Georgia power Fuel Cost Recovery Audi t
2/07 06-101-U AR AEEC Entergy Arkansas Cost Allocation and Recovery
2/07 uE-061S46 WA ICNU/public counsel pacifiCorp Powe r Cost Mode 1 i ng ,Jurisdictional Allocation, PC
RFI CONSULTING, INC.
PacifiCorp Idaho Industrial Customers
Exhibit No. 605 Page 11 of 11
Witness: Randall J. Falkenberg
Expert Testimony Appearances
of
Randall J. Falkenberg
Date Case Jurisdict.Party Utilty Subject
2/07 32710 TX OPC EGSI Fuel Reconci 1 i ati on
6/07 UE 188 OR ICNU portland General Wind Generator Rate Surcharge
6/07 UE 191 OR ICNU pacificorp power Cost Modeling
6/07 UE 192 OR ICNU portland General Power Cost Modeling
9/07 UM 1330 OR ICNU PGE,pacificorp Renewable Resource Tariff
10/07 06-152-u AR AEEC EAI CA Ri der, pl ant Acqui si ti on
10/07 07-129-U AR AEEC EAI Annual Earni ngs Revi ew Tari ff
10/07 06-152-u AR AEEC EAI purchase of combined cycle
power plant.
04/08 26794 GA GPSC staff Georgia Power Fuel Cost Recovery Case
04/08 07-035-93 UT CCs pacificorp Power cost Modeling
07/08 UE 200 OR ICNU pacificorp Renewable Adjustment Clause
08/08 20000-315 WY WIEC paci fi corp Power Cost Adjustment-EP-08 Mechanism
01/09 20000-333 WY WIEC Pacificorp Power Cost Modeling/wind
-ER-08 resource prudence
02/09 08-035-38 UT CCS paci fi corp Powe r Cost Model i ng/wi nd
resource prudence
04/09 UM 1355 OR ICNU PGE/paci ficorp Outage Rate Model i ng
04/09 UM 1396 OR ICNU PGE/paci fi corp Avoi ded Costs
06/09 UE 199 OR ICNU Pacificorp Power Cost Modeli ng
07/09 UE 207 OR ICNU pacificorp Power Cost Modeling
07/09 UE 208 OR ICNU PGE Power Cost Modeling
07/09 UE 210 OR ICNU pacifiCorp Transi ti on Adjustment
Mechanism
10/09 UM 1442/OR ICNU PGE/paci fi Corp Avoi ded Costs
1443
10/09 09-035-23 UT OCS paci fi Corp Power Cost Modeling
12/09 UM 1465 ICNU pacificorp Power Cost Deferral
1/10 20000-352-ER-09 WY WIEC pacificorp Power Costs i windResources
2/10 09-084-U AR AEEC Entergy AR Rate spread i Formula Rateplan
3/10 20000-363-ep-10 WY WIEC pacificorp pCA
4/10 10-035-13 UT ocs pacificorp power impact of Majorpl ant Addi ti ons
RF CONSULTING, INC.
Case. No. PAC-E-lO-07
Exhibit No. 606
Witness: Randall J. Falkenberg
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
PACIFICORP IDAHO INDUSTRIL CUSTOMERS
Exhibit Accompanying Direct Testimony of Randall J. Falkenberg
Rocky Mountain Power Data Responses to OCS
October 14,2010
1 0-035-89/Rocky Mountain Powe
September 7, 2010
OCS Data Request 2.5
PacifiCorp Idaho Industrial Customers
Exhibit No. 606 Page 1 of 5
Witness: Randall 1. Falkenberg
OCS Data Request 2.5
Does the Company expect that the Populus to Ben Lomond link wil reduce
losses? If so, please quantify the amount of annual energy loss savings expected.
Please provide supporting details.
Response to OCS Data Request 2.5
Yes. New transmission capacity wil reduce system losses as it also reduces path
impedance. Losses are calculated on an annual system basis using averages for
loads, generation, and system wheeling values. A new system loss study wil be
completed later this year. At this time definitive information as requested is not
available.
1 0-035-89/Rocky Mountain Power
September 27,2010
OCS Data Request 6.2
PacifiCorp Idaho Industrial Customers
Exhibit No. 606 Page 2 of 5
Witness: Randall J. Falkenberg
OCS Data Request 6.2
Please refer to the answers to OCS 2.2. Does the Company agree that owing to
the completion of the Populus to Ben Lomond link, it wil no longer need the 61
MW contract? Please provide the termination date for the contract. Please fully
explain your answer.
Response to OCS Data Request 6.2
No. The Company wil evaluate its need of long term wheeling rights based on
obligation to serve load and the FERC requirement not to use allocated network
transmission for wholesale trasactions. Please refer to the confidential
attachment provided in the Company's response to OCS 6.1, for information
regarding the contract.
10-035-89/Rocky Mountain Power
September 27,2010
OCS Data Request 6.3
PacifiCorp Idaho Industrial Customers
Exhibit No. 606 Page 3 of 5
Witness: Randall J. Falkenberg
OCS Data Request 6.3
Please refer to the answers to OCS 2.2. If the Populus to Ben Lomond line were
delayed for two years, is it likely that the Company would continue to purchase
capacity from the market, if it were possible to extend both the STF contracts and
the 61 MW contract?
Response to OCS Data Request 6.3
Yes.
1 0-035-89/Rocky Mountain Power
September 27,2010
DCS Data Request 6.5
PacifiCorp Idaho Industrial Customers
Exhibit No. 606 Page 4 of 5
Witness: Randall J. Falkenberg
OCS Data Request 6.5
Please refer to the answers to DCS 2.5. This answer is not responsive. A request
was made for quantification of the expected savings in losses attributable to the
Populus to Ben Lomond link. Please provide the Company's best estimate.ofthe
benefit in terms of loss reductions, attributable to the new line.
Response to OCS Data Request 6.5
Losses are measured based upon actual hourly power flows across the entire
PacifiCorp network over time. Generation, loads, and actual line path flows vary
hourly through time as generation and load pattern conditions change. System
losses are also affected by the electrical reconfiguration of the system necessary to
interconnect Populus, Ben Lomond and Terminal substations to all the new and
existing 345 kV lines. The time period under which losses are incurred may vary
as well; from one hour to one year, to 30 or more years.
The Company has created an estimate of loss reduction based upon the following
assumptions. A power flow simulation was performed for year 20 I 0 heavy
summer load configuration without the Populus to Ben Lomond project. A one
hour power flow simulation was conducted for a simulated power transfer of700
MW across path C in the North to South direction. The load and system losses
for the portion of the system between Populus and Terminal substations were
calculated for that single hour resulting in Load + System Losses = 1300.7 MW.
A second power flow simulation was conducted using the same year 2010
configuration and assumptions using the same power flow model with the
Populus to Ben Lomond project now included. The load and system losses for the
portion of the system between Populus and Terminal were calculated for that hour
resulting in Load + System Losses= 1289.9 MW. The loads in the models were
held constant.
The difference between the two study results 1300.7 MW - 1289.9 MW = 10.8
MW which is the resulting system loss reduction in this part ofthe system for that
hour.
The actual system operation and transmission line loading will vary significantly
overthe life of the project and power flows will be higher and lower than the 700
MW in any particular hour and over a wide range of load and generation dispatch
scenarios.
To review the Path C one-line diagrams, please refer to Attachment DCS 6.5.
1 0-035-89/Rocky Mountain Power
September 27,2010
OCS Data Request 6.7
PacifiCorp Idaho Industrial Customers
Exhibit No. 606 Page 5 of 5
Witness: Randall 1. Falkenberg
OCS Data Request 6.7
Please provide a formula (such as Ploss = P2R1V2J that would apply to the current
lines used for the Populus to Ben Lomond links vs. the new line. Explain why
this formula could not be used to compute loss savings from the new line. If such
a formula could be used, please provide the calculation ofloss savings from the
new line.
Response to OCS Data Request 6.7
The formula above is correct for calculation of a discrete line loss value for a
specific line or sets of lines carring a fixed power flow. It does not however
provide a value of "line loss" savings. It can be used to compare one discrete line
loss value to another when calculated for different power flows. This calculation
was performed in the Company's Response to OCS Data Request 6.5 for a one
hour period.
Case. NO.PAC-E-1O-07
Exhibit No. 607
Witness: Randall J. Falkenberg
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
PACIFICORP IDAHO INDUSTRIAL CUSTOMERS
Exhibit Accompanying Direct Testimony of Randall J. Falkenberg
PacifiCorp Data Responses to OPUC and ICNU
in OPUC Docket Nos. UE-216 and UE-100749
October 14, 2010
UE-216/PacifiCorp
April 20, 2010
OPUC Data Request 22
PacifiCorp Idaho Industrial Customers
Exhibit No. 607 Page 1 of 3
Witness: Randall J. Falkenberg
OPUC Data Request 22
The Company has stated that it is including the inter-hour wind integration costs
for its two projects in the BPA control area. (PPL(TAM)/lOO, Duvall/I7, Lines
11-14)
a) If BPA is not required to provide the inter-hour wind integration services for
PacifiCorp's facilties located in its control area, why is the Company
including inter-hour wind integration services for those facilties located in its
control area, e.g. Long Hollow?
b) Using PacifiCorp's logic, wouldn't those facilties located in its control area,
of which PacifiCorp is not the contracted recipient, have to provide there own
inter-hour wind integration?
Response to OPUC Data Request 22
a) The Company does not incur day-ahead or hour-ahead (inter-hour) costs for
wind facilities located in its control area if the output of the plant is not
included in the Company's resource portfolio. .
b) Yes.
. Ii
UE-2 i 6/PacifiCorp
March 22, 20 i 0
lCNU 2nd Set Data Request 2.5
PacifiCorp Idaho Industrial Customers
Exhibit No. 607 Page 2 of 3
Witness: Randall J. Falkenberg
ICNU Data Request 2.5
Refer to the Naughton 3 outage staring on May 26, 2009. Was this event one that
resulted in a liquidated damages payment? If so, please explain whether the
various outage and deration events staring on May 26,2009 through June 2, 2009
were also consequence of the original event.
Response to ICNU Data Request 2.5
Please refer to the Company's response to lCNU Data Request 2.3, specifically
Confidential Attachment ICNU 2.3. The overhaul outage was contracted with
Siemens to be completed on April 25, 2009. As the turbine I generator was
released to PacifiCorp for operations on May 26, 2009, liquidated damages were
recovered. The outage and duration events from May 26 through June 2 were not
a consequence of the original event, but would be considered normal procedures
completed subsequent to an overhauL.
UE- i 00749/PacifiCorp
September 8, 20 i 0
i CNU Data Request i 0.3
PacìfiCorp Idaho Industrial Customers
Exhibit No. 607 Page 3 of 3
Witness: Randall J. Falkenberg
ICNU Data Request 10.3
Please refer to Attachment ICNU 1.33, tab "Cont'. Please identify all
transactions in the test year that rely upon this contract for delivery of power into
the P ACW as represented in the WCA modeL.
Response to ICNU Data Request 10.3
Please refer to the Company's response to ICNU Data Request i o. i. Purchases at
the Nevada-Oregon Border (NOB) have relatively high prices, so they are one of
the last options used to serve the Company's retail loáds. Since this capabilty is
unlikely to be used under the normalized circumstaces contained in the
Company's WCA GRID model, no purchases are modeled at NOB during the test
year.
PREP ARR: Hui Shu
SPONSOR: Gregory N. Duvall
. 'j
Case. No. PAC-E-I0-07
Exhibit No. 60S
Witness: Randall 1. Falkenberg
BEFORE THE IDAHO PUBLIC UTILITIES COMMSSION
PACIFICORP IDAHO INDUSTRIAL CUSTOMERS
Exhibit Accompanying Direct Testimony of Randall J. Falkenberg
REDACTED VERSION
PacifiCorp Data Responses to.ICNU
in WUTC Docket No. UE-I00749
October 14, 2010
UE-l 00749/PacifiCorp
June 7, 2010
ICNU Data Request 1.33
PacifiCorp Idaho Industral Customers
Exhibit No. 60S Page 1 of9
Witness: Randall 1. Falkenberg
I CNU Data Request 1.33
For each of the Firm Transmission contracts whose costs are included in GRID,
please identify the purpose of the transaction, why it is used and useful in the Test
Year, the amount of capacity or type of transmission service it provides, and
where the capacity or service provided by this contract is modeled in GRID.
Response to ICNU Data Request 1.33
Please refer to Confdential Attachment ICNU 1.33. The second tab in the
attachment is considered non-public information and canot be shaed with
PacifiCorp marketing affliate employees. This information is confdential and is
provided subject to the terms and conditions of the protective order in thisproceeding .
PREP ARER: Hui Shu / Jim Portouw / Ken Houston
SPONSOR: Gregory N. Duvall
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Exhibit No. 608 Page 2 of9
Witness: Randall J. Falkenberg
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Exhibit No. 608 Page 3 of9
Witness: Randall 1. Falkenberg
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Exhibit No. 608 Page 4 of9
Witness: Randall J. Falkenberg
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Exhibit No. 60S Page 5 of 9
Witness: Randall J. Falkenberg
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UE-216lPacifiCorp
March 22, 2010
ICNU 2nd Set Data Request 2.3
PacifiCorp Idaho Industral Customers
Exhibit No. 60S Page 6 of9
Witness: Randall 1. Falkenberg
ICNU Data Request 2.3
Were liquidated damages payments made relative to any outages at any power
plants which PacifiCorp has an ownership interest during the 4 year period? If so,
explain the reasons for the payments, the amount and provide all relevant
supporting documentation.
Response to ICNU Data Request 2.3
Yes. Please refer to Confidential Attachment ICNU 2.3 for information on
liquidated damages paid relating to boiler outages at the Jim Bridger Plant and a
turbine overhaul at the Naughton plant. Confidential information is provided
subject to the terms and conditions of the protective order in this proceeding.
(Page 1 of 1)
PacifiCorp Idaho Industrial Customers
Exhibit No. 60S Page 7 of 9 Invoice
Witness: Randall J. Falkenberg Pagel of 1
PacifiCorp Idaho Industral Customers
Exhibit No. 608 Page 8 of 9
Witness: Randall 1. Falkenberg
PacifiCorp Idao IndustrarCustomers
Exhibit No. 608 Page 9 of 9
Witness: Randall J. Falkenber
Case. No. PAC-E-1O-07
Exhibit No. 609
Witness: Randall J. Falkenberg
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
PACIFICORP IDAHO INDUSTRIAL CUSTOMERS
Exhibit Accompanying Direct Testimony of Randall J. Falkenberg
Net Power Cost Workpapers and Supporting Documents,
Attachment to Settlement Stipulation to Order 9
in WUTC Docket No. 090205
October 14, 2010
PacitiCorp Idaho Industria;l Custom~rs
Exhibit No. 609 Page i of 4
Witness: Randall J. Falkenberg
Net Power Costs Workpapers and Supportng Documents
Agreement Beteen PaclfiCorp and ICNU
Net Power Costs stuy workpapers ar defined as thosè documents which show the source,
calculations and detls supportng the testmony and other exhibits includig the documents
. used to develop the final inputs to GRI and thè fina modeling in GRI on the west control
area basis. The data relied upon to sUpport. the . cost detls in the filin may include
contracts, emails, white pape, studies, PacifiCorp computer progrs, Excel spradsheets,
Word documents or pdf and text fies. .
In cases where systems change or are replaced in the futu, PacifiCoip will' continue to .
provide substatially the same informtion as provided in data request responses in
.PacifCorp's 2009 General Rate Case as long as these filing requirements remai operative.,
PacifiCorp and ICN. agee to contiue the curent practice of providing all ~isc()ver
response answer~, workpapers, including any other documents produced purant to this
agreement via email (for non-confidential documents) and overnight mail (for confidential
documents). All attachments provided though discovery that involves calculations will be
provided electronically and in the case of Excel spreadsheets with all cells and formulas
intact.
If there are any special circumstaces where the Company ha not provided documents or
information withn the workpapers. listed below because it believes special hadling
procedures are necessar for tht informtion, the Company will either:
a. Redact the information from the document indicating where such information has
been redacted.
b. Identify the document(s) not provided, and provide the name of the appropriate
person for ICNU to contact regarding access to the document(s).
A. Initial Filng by the Company
PacifiCorp wil provide ICNU with workpapers and supportng documents as
described below.
i. Concurent with the Initial Study:
a) Workpapers tht show the source. and calculations pertainng to the
Company Net Power Cost Study(s). The workpapers will include, at a
minimum, copies of the net power cost report in Excel and the net power
cost model database. Access to the power cost model will also be
provided.
b) Identification of the "Time Period" used to determine outage rates and
other input items in the.net power cost modeL.
PacifiCorp Idaho Industrial Customers
Exhibit No. 609 Page 2 of 4
Witness: Randall J. Falkenberg
c) A list and explantion of all modelig or logic changes or enhancements
to the net power cost model tht have been implemented since the last
Washigton case in which the Company prposed to change net power
costs. Ths wil include a sttement of the dirtion and amount of
chage in net power costs resulting from each such change and
documentation descn'bing each chage as well as net power cost model
rw and workpapers auantifying the impac of these changes.
2. Withn five business days, afer the Intial Filing, the Company will deliver to
ICN the following:
a) Workpapers showing the computation of the outage rates (planned and
unplaned) used in the power cost modeL. Include. all backup data
. showig each outage (planed or unplaned, etc.) and duration (planed
or unplaed) considered in the time penod, including NERC cause code,
tye of event, duraiion, energy lost, etc. Reference: ICNU 1.61
b) The heat rate cures for each resource an the spreadsheets showig the
denvaton of the heat rate cures. Reference: ICND 1.26
c) Workpapers and documentaon supportg the inputs contained in the
"Other Cost" fie used in the power cost model, includi.ng all electronic .
spredsheets used to compute any of the .lirie items in the fie. This
includes test year wheeling expenses modeled in GRID. Refererce: ICND
.1.36
d) Workpapers and docuentation supportg the "Energy Cost" fie use.in
the power cost model, including all electonic spreadsheets used to
compute any of the line items in the file. Reference: ICN 1.57
e) Workpapers and documentaion support the "Demand" file used in the
power cost model, including all electronic spreadsheets used to compute
any of the line items. in the fie. Reference: ICNU 1.58
3. As soon as practical, but no later th 15 days afer the Initial Study has been
provided, the Company will deliver to ICND:
a) All documents, workpapers or other information relied upon by the
Company in deterinng the market caps used in the power cost model
for the forecas test period. Reference: ICND i.2
b) The curent topology maps in the power cost model along with. an
explanation for all the differences that have been made to the topology
since the last Washington cae in which the Company proposed to chage
Unless otherwise noted, all Refereces are from discovery in UE90205.
PacifiC~rp Idaho Industrial Customers
Exhibit No. 6~9 Page 3 ?f 4
Witness: Randall J'-Falkenberg
net power costs and an explanaton of why the changes were made.
Include supportng docuentation, such as cOntrs r.sutig in changes
to the trsfer capabilties used in GRI. Reference: ICN 1.3
c) The date and a copy of the forward pnce cure, showing monthy heavy
load hour and light load hour forward prces, used in creating the test year
power cost model studies. Reference: ICNU 1,8
.. d) Documents showig al short-te fi trsactions (includig short-term
finn indexed tranactions and swaps) modeled in the test year power cost
study. In addition, eah contract will have a designtion as to its.purose
(i.e., trading, arbitràge or balancing.) Reference: ICN 1.10
e) For all power, fuel and transmission related contrcts.modeled in GRID
that were not included in the last Washington case in which the Company
proposed to change net power costs:
1. A copy of the contrct (in pdf or electonic formt, if
avalable), Reference: ICN.1.1 1
2. Any workpapers or other documents used to develop the
power cost model input assumptions related to the contract. id
f) Reguatory Fuel Budget and any other workpapers usd in developing the
power cost model fuel cost inputs. Reference: ICNU 1.59
g) Workpapers and documentation supportng the "Demand Cost" file used
in the power cost model, includin al electronic spreadsheets used to
aompute any of the line items in the fie. Reference: ICN 1.60
h) Identification of each instace in which the Compay chaged any
maum capacities, minium up or down ties or untminimui
capacities for theral or hydro generators modeled in the . power cost
. model since the'last Washington case in which the Company proposed to
chage net power costs. Reference: ICNU 1.61
i) Workpaper explaining the development of each line of l~ad adjustments
presented on the Company's power cost model output report. Reference:.
ICN 1.62
j) Workpapers for any screens applied to prevent uneconomic conuitment
and dispatch ofresoUIes in the GRID modeL. Reference: ICND 1.64
k) Workpapers and all supportng documents underlying the star-up fuel
cost included in GRID in the line labeled Other Fixed Costs, òr the
equivalent.
PacifiCorp Idah9 Industrial Customers
Exhibit No. 609 Page 4 of 4
Witness: Randall J. Falkenberg
B. Rebuttal Filing (and sur-surrebuttal Filng, if applicable) by Company
The Company will provide workpapers and supportg documents to lCNU as
described below:
1, Concurnt with Còmpany rebut or sur-surbutt filings:
a) Workpapers that show the soure, calculations an detls supportng the
testiony and other exhbits. The workpapers will include the net power
cost report on an adjustment-by-adjustment basis. The workpapers will
include, at a mium electronic copies of the net power cost report and
the net power cost modeL.
b) For any update, adjustment or correction to the power cost model, the
Company will include a description of the chage and a calculation of the
adjustment amount.
. 2. . As soon as practical but no later th five business days afer filing rebutt .or
sur-surebut :
a) To the extent tht any of the items in Section A change, new versions of
the supportng documentaon and workpapers will be provided.
b) ACcss to the updated ru in power cost model via the designated
inteet access or power cost model input fies contang al inputs and
output report associated with the update fiings.
c. Filngs by ICNU .
Testmony filed by ICNU in response to the Company's net power costs calculations
will provide workpapers and supporting documents as described below:
.1. Concurent with the fiing of ICNU testmony:
a) Workpapersthat show thè source, calculatons and details supporting the
testimony and other exhbits. The workpapers will show on an adjustment-by-
adjustment basis, the power cost model input fie or files used the back-up to
the input fies, and the power cost model stdy report or documents showing
. the impact of the adjustment on NPC as compared to the comparson scenaro.
The associated power cost model input files will also be provided.