20100915Duvall Direct.pdf

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2010 SEP 15 M1 9: 35
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
In the Matter of the Application of )
PacifiCorp dba Rocky Mountain )
Power for Approval of Amendments to )
Revised Protocol Allocation )Methodology )
CASE NO. PAC-E-I0-09
Direct Testimony of Gregory N. Duvall
ROCKY MOUNTAIN POWER
CASE NO. PAC-E-I0-09
September 2010
1 Q.Please state your name, business address and present position with
2 PacifiCorp (the Company).
3 A.My name is Gregory N. Duvall, my business address is 825 NE Mu1tnomah
4 Street, Suite 600, Portland, Oregon 97232. My present position is Director, Long-
5 Range Planning and Net Power Costs.
6 Qualifications
7 Q.Briefly describe your educational and professional background.
8 A.I received a degree in Mathematics from University of Washington in 1976 and a
9 Masters of Business Administration from University of Portland in 1979. I was
10 first employed by PacifiCorp in 1976 and have held various positions in resource
11 and transmission planning, regulation, resource acquisitions and trading. From
12 1997 through 2000 I lived in Australia where I managed the Energy Trading
13 Deparent for Powercor, a PacifiCorp subsidiary at that time. After retuing to
14 Portland, I was involved in direct access issues in Oregon and was responsible for
15 directing the analytical effort for the Multi-State Process (MSP). Curently, I
16 direct the work of the integrated resource planning group, the load forecasting
17 group, the net power cost group, and the renewable compliance area.
18 Purpose of Testimony
19 Q.What is the purpose of your testimony in this proceeding?
20 A.I present the net power cost (NPC) study used to support the 2010 Protocol
21 revenue requirement analyses that is presented in the testimony of Mr. Steven R.
22 McDougaL. In addition, I present the NPC studies that were conducted to test the
23 sensitivity of high and low market prices, the studies that were conducted to
Duvall, Di - 1
Rocky Mountain Power
1 estimate the increased NPC that the Company would incur if there were strctural
2 separation by balancing areas, and the study that was used to develop the NPC
3 and resource changes associated with the load growth study. I also present an
4 analysis estimating the increased generation-related costs the Company would
5 incur if each jursdiction were to go-it-alone. The strctual separation study and
6 the go-it-alone study were conducted to provide a rough estimate of cost savings
7 that may arise from continuing to plan and operate as a single integrated system.
8 Finally, I present the NPC results associated with the load growth study. All
9 studies except the go-it-alone study were conducted using the Company's
10 Generation and Regulation Initiative Decision Tool (GRID) modeL.
11 2010 Protocol NPC Study
12 Q.Why did the Company prepare the 2010 Protocol NPC study?
13 A.The Company prepared the 2010 Protocol NPC study (Base NPC Study) at the
14 request of the Standing Committee. The purpose of the study was to compute a
15 current projection of total company NPC to support revenue requirement analysis
16 as presented in the testimony of Mr. McDougaL. The Standing Committee
17 requested that the Company update its NPC study to reflect the most recent
18 information available at the time.
19 Q.What input data did the Company use to conduct the Base NPC Study?
20 A.The Company used the 2008 Integrated Resource Plan (IRP) preferred portfolio,
21 along with (i) the Company's Februar 2009 load forecast, (ii) June 2009 Offcial
22 Forward Price Cures, and (iii) updated information of new and existing contracts
23 as of August 2009. Input assumptions for the Klamath River operations and dam
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1 removal schedule were taken from the Klamath Hydroelectrc Settlement
2 Agreement (KHSA) dated February 18,2010.
3 Market Price Sensitivity Studies
4 Q.Why did the Company perform market price sensitivity studies?
5 A.Wholesale power and gas market prices are volatile and unpredictable and have
6 the potential to affect each jursdiction differently under the Revised Protocol. To
7 test this, the Company was requested by the Standing Committee to ru a high
8 and a low market price sensitivity study and report the results of those studies.
9 Q.What assumptions were used for the high and low market price studies?
10 A.For the NPC studies supporting the high and low market price sensitivity
11 analyses, the Company increased or decreased market prices by 20 percent,
12 respectively. An annual sumary of the base, high and low market prices at
13 California Oregon Border (COB) and Palo Verde (PV) for electrcity and at
14 Rocky Opal for natual gas are provided in Exhibit No. 10. Chart 1 below shows
15 the impact of the high and low market prices on net power cost, presented as
16 percentage changes in NPC from the Base NPC Study.
Duvall, Di - 3
Rocky Mountain Power
Chart i
High and Low Price Studies Compared to Base NPC Study
5.00%
..4.00%II0U~3.00%Ql
~0 2.00%Q"..Ql 1.00%zc
ëjj 0.00%ticII -1.000/.,2015 2016 2017 2018 2019~u
Ql -2.00%tiII..c -3.00%Qlu~Ql -4.00%Q"
-5.00%
wyø'Q'''High market price case ""Low market price case
1 Structural Separation Studies and Go-It-Alone Analysis
2 Q.Why did the Company perform the structural separation studies and the go-
3 it-alone analysis?
4 A.The Company was requested to perform strctual separation studies and the go-
5 it-alone analysis by the Standing Committee as a means of estimating the cost
6 savings that may arse from continuing to plan and operate as a single integrated
7 system. These studies are highly assumption drven and should not be relied upon
8 other than for the purose they are used for in the MSP. The strctual separation
9 studies assume that Pacific Power and Rocky Mountain Power would become
10 separate entities and operate on a balancing area basis, and the go-it-a10ne study
11 assumes that each state jursdiction would become a separate entity. In the case
12 of strctual separation, it was assumed that the curent system-wide planing is
13 suffcient to cover the resource needs of both balancing areas, rather than as a
Duvall, Di - 4
Rocky Mountain Power
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8 A.
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21 A.
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single, integrated power system as is curently done. However, the balancing
areas were assumed to operate on their own. In the case of the go-it-alone
analysis, the jurisdictional entities would need to plan and operate on their own
because the significant differences in the jurisdictional non-coincidental peaks as
compared with the coincidental peaks of the system that are used in the
Company's planning.
What assumptions were made to perform the structural separation studies?
The Company curently operates in two balancing areas, east and west. The
strctual separation studies disconnect the transfer between the two balancing
areas. Loads and resources were assigned to each balancing area based on their
physical location. The Company has a small number of exchanges under which
power is received by the Company in one balancing area and retued to the
Company in the other balancing area. For puroses of the strctual separation
studies, the Company assumed these cross-balancing area exchanges would be
terminated, and therefore they were not included in either balancing area. A list
of major assumptions to NPC studies for the strctual separation analysis is
provided in Exhibit No. 11. The studies were performed on calendar years 2012,
2015 and 2017 based on changes in the Company's transmission additions that
impact the modeling topologies.
What are the limitations of the structural separation NPC study results?
As previously mentioned, the strctual separation study results are a highly
assumption-driven assessment of a balancing area strctual separation modeL.
The assignment of resources and the modeling of a balancing area strctural
Duvall, Di - 5
Rocky Mountain Power
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12 A.
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separation are based on one set of assumptions. It is not advocated by any par
including the Company and is provided solely for informational puroses. The
balancing area split of generation and transmission resources does not reflect the
pre-1989 merger assignent of resources between Pacific Power and the former
Utah Power. This study does not analyze the potential costs of refinancing,
additional workforce and other costs associated with changing the operation of a
single integrated system that serves each of California, Idaho, Oregon, Utah,
Washington and Wyoming to a control area strctural separated system. Neither
does the analysis evaluate what resources changes might occur under a balancing
area strctually separated system.
What were the results of the structural separation studies?
The strctural separation studies for calendar years 2012, 2015 and 2017 indicate
that the total NPC for the combined east and west balancing areas would be
higher than the Base NPC Study by about 3 percent as shown in Table 1 below.
Assuming a level ofNPC at $1.5 bilion, the dollar increased ranged from $37
millon to $45 milion.
Table i
Combined East and West Studies Compared to Base NPC Study
2012 2.50%
2015 3.68%
2017 3.02%
Has the Company updated its structural separation studies to incorporate
theKHSA?
Yes. The Company updated the studies that were previously provided to the
Standing Committee. The results presented in Table 1 above arè from the updated
Duvall, Di - 6
Rocky Mountain Power
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4 A.
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13 A.
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22 A.
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studies, and are consistent with what the Company has previously provided,
which indicated significant savings operating the system as a whole.
Please describe the go-it-alone analysis.
The go-it-a10ne analysis quantifies the difference between the total amount of
peak load that would need to be met on a state-by-statebasis and the amount of
peak load that would need to be met with the continuation of integrated system
resource planning. The loss of diversity that would occur if each jursdiction were
to go-it-alone would directly translate into an increased need for generating
resources, and therefore increased costs. For this analysis, the increased resource
requirements were priced at the 2008 IRP costs of new combined cycle
combustion turbines.
What are the limitations of the go-it-alone NPC study results?
Like the strctual separation study, the go-it-alone study is a highly assumption
drven assessment of a state separation modeL. It is not advocated by any part
including the Company and is provided solely for informational puroses. This
study does not analyze the potential costs of refinancing, additional workforce and
other costs associated with changing the operation of a single integrated system
that serves each of California, Idaho, Oregon, Uta, Washington and Wyoming to
a six-state separated system. The study also does not evaluate the impact of the
resource dispatching under a six -state separated system.
What were the results of the go-it-alone analysis?
If each jursdiction were required to plan to meet their own peak loads, the
additional costs incurred to acquire the necessary additional resources could be
Duvall, Di - 7
Rocky Mountain Power
1 approximately $270 millon each year. The results of the analysis are provided in
2 Exhibit No. 12.
3 Q.Why was GRI not used to prepare the go-it-alone study?
4 A.Modeling each jursdiction in GRID would require assumptions on resource and
5 transmission assignment, as well as assumptions on each jurisdiction's access to
6 wholesale markets. In the Company's view, creating a set of assumptions on
7 these issues that would prove reasonably acceptable to all jursdictions would be
8 impractical at this time. The Company believes that the analysis performed
9 reasonably captues the increased cost that would be incured if each jursdiction
10 needed to plan for itself.
11 Load Growth Analysis
12 Q.Why did the Company perform the load growth analysis?
13 A.The Company was requested to perform load growth analysis by the Standing
14 Committee as a means of evaluating whether the slower-growing states unfairly
15 subsidize the faster-growing states.
16 Q.How is the NPC calculated for the load growth analysis?
17 A.The first step is to identify which states are growing relatively faster than the rest
18 of the states, which are Utah and Wyoming in the curent study. The growth rate
19 of these two states durng the study period from calendar year 2010 through
20 calendar year 2019 was adjusted down to match the average growth rate of load in
21 the rest of the states. Then the 2008 IR resource portfolio was modified to
22 remove resource additions that would no longer be needed due to the reduced
23 system load.
Duvall, Di - 8
Rocky Mountain Power
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14 A.
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How was the 2008 IRP resource portfolio modifed as a result of the changes
in load growth?
First, the load and resource balance was updated from the 2008 IRP to reflect the
reduction in system peak load assumed for Utah and Wyoming. Next, the
resource additions in the east balancing area were reduced to maintain a minimum
of a 12 percent planning reserve margin. Several planned east resources included
in the 2008 IRP were removed, including the East CCCT (CCCT F 2x1, Utah
North), the East thermal PP A, the East Aero and the East GeothermaL. Planned
east wind resources and demand side management assumptions were not changed.
Front offce transactions in the load growth resource portfolio were reduced.
Exhibit No. 13 ilustrates the changes to the 2008 IRP preferred portfolio as a
result of the reduction in Utah and Wyoming load.
What is the impact of the reduced load?
By the end of the study period, through calendar year 2019, the total Company
NPC decreases by approximately 21 percent as compared to the Base NPC Study.
The results of the analysis are provided in Chart 2 below. The overall revenue
requirement impact of the reduced load, including the change to NPC and the
corresponding change fixed costs related to resource additions that would no
longer be required, is reflected in the revenue requirement study that is addressed
by Mr. McDougaL.
Duvall, Di - 9
Rocky Mountain Powe.r
Chart 2
Load Growth Study Compared to Base NPC Study
0%..II 2017 2018 20190u~-5%Ql~0Q"..Ql -10%z
.!:
QltiCII -15%~u
QltiII..-20%c
Qlu~
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-25%
Q.
A.
1
..Load Growth Study % Change from Base Study
2
Does this conclude your direct testimony?
Yes.
Duvall, Di - 10
Rocky Mountain Power
2um SEP l 5 AM 9= 35 Case No. PAC-E-10-09
Exhibit No. 10
Witness: Gregory N. Duvall
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Gregory N. Duvall
Annual Summary of Base, High and Low Market Prices at
COB, Palo Verde, and Rocky Opal
September 2010
Rocky Mountain Power
Exhibit No. 10 Page 1 of 1
Case No. PAC-E-10-09
Witness: Gregory N. Duvall
Multi-State Process (MSP)
Annual Summary of Base, High and Low Market Prices at COB, Palo Verde, and Rocky Opal
90
80 _.-
~70:!..'l 60 yøP
50 ~
40 I F
30
2010 2011
COB Average Annual Flat Prices:
Base Case (0609 OFPC), High Price Case, Low Price Case
.~~~.
.~øø~~--
..
-
2012 2013 2014 2015 2016 2017 2018 2019
..Base 0609 OFPC COB Flat
wN,~High Case 0609 OFPC (+20%) COB Flat
..Low Case 0609 OFPC (-20%) COB Flat
Palo Verde Average Annual Flat Prices:
Base Case (0609 OF PC), High Price Case, low Price Case
90
80
70
~:::!..'l
60
50
40
30
2010 2011 2012 2013 2014
..Base 0609 OFPC Palo Verde Flat
wwggw, High Case 0609 OFPC (+20%) Palo Verde Flat
2015 2016 2017 2018 2019
..Low Case 0609 OFPC (-20%) Palo Verde Flat
Opal Average Annual Natural Gas Prices:
Base Case (0609 OFPC), High Price Case, Low Price Case9
8
::7..ii:!6:!..'I 5
4
3
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
..Base 0609 OFPC Opal Gas ..Low Case 0609 OFPC (-20%) Opal Gas =..High Case 0609 OFPC (+20%) Opal Gas
Case No. PAC-E-1O-09
Exhibit No. 11
Witness: Gregory N. Duvall
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Gregory N. Duvall
Net Power Cost Assumptions for Strctural Separation
September 2010
Rocky Mountain Power
Exhibit No. 11 Page 1 of 3
Case No. PAC-E-10-09
Witness: Gregory N. Duvall
Multi-State Process (MSP)
Net Power Cost Assumptions for Structural Separation
East Balancing Area (East)
The Rocky Mountain Power jurisdictions of Idaho, Utah and Wyoming wil be assigned
to the East balancing area.
West Balancing Area (West)
The Pacific Power jursdictions of California, Oregon and Washington wil be assigned to
the West balancing area.
Topology
The total system has 26 transmission areas, which include load centers, market hubs,
location of generation resources, and transmission rights that the Company holds. Below
is the transmission topology for the total system.
Not..:All path ,atings ,.pr_nl Merchnl Fnnc1.n ñghls
Not ap~ysic¡;lpath/area .; re:pre~ent$corir~ctt,err
**, Contracts roay deliver in anyofthêtrarislTissîonarea,s
Based on the transmission rights for the Company's share of the Colstrp and Jim Bridger
plants, below are the transmission topologies for the East and West.
Rocky Mountain Power
Exhibit No. 11 Page 2 of 3
Case No. PAC-E-10-09
Witness: Gregory N. Duvall
GRID Transmission Topology, ~lli; side
Wheeling expenses are included in either the East or West, based on the location of the
points of receipts and deliveries.
Rocky Mountain Power
Exhibit No. 11 Page 3 of 3
Case No. PAC-E-10-09
Witness: Gregory N. Duvall
Load
Load in the East includes the load in the states of Idaho, Utah and Wyoming. Load in the
West includes the load in the states of California, Oregon and Washington.
Generation and Transmission Resources
All generation resources wil be assigned either to the East or West depending on their
physical locations, except the Jim Bridger and Colstrp plants that are shared between
East and West based on transmission connections.
Jim Bridger and Colstrip Plants
In accordance with the wheeling contract with the Idaho Power Company, approximately
95.8% of the Company's share of the Jim Bridger plant capacity is included in the West,
and the remainder is assumed to be transmitted to the East.
In accordance with the wheeling contract with the Bonnevile Power Administration, the
Company's right to the transmission capacity from the Colstrp plant is 156 megawatts,
of which 70 megawatts is to the West. As a result, the Company's share of the capacity
of the Colstrp plant is pro-rated based on the 70:86 split between the East and West.
Wholesale Contracts with Third Parties
All contracts that are entirely delivered to either the west side or east side of the system
wil be included in either the East or West, including all qualifying facilities. For the
puroses of this study, cross balancing area contracts have been excluded.
Transfers Between Balancing Areas
This study wil assume that there is no abilty to transfer between the balancing areas.
Case No. PAC-E-1O-09
Exhibit No. 12
Witness: Gregory N. Duvall
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Gregory N. Duvall
Go-It-Alone Sumary
September 2010
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Case No. PAC-E-1O-09
Exhibit No. 13
Witness: Gregory N. Duvall
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Gregory N. Duvall
Load Growth Portfolio Summar
September 2010
Multi-State Process (MSP)
Load Growth Portfolio Summary
Rocky Mountain Power
Exhibit No. 13 Page 1 of 1
Case No. PAC-E.10-09
Witness: Gregory N. Duvall
2008 IRP Preferred Portfolio (2008 IRP, Executive Summary, page 6)
~I Capacity, MW
Resource I 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018
East
CCCT F 2xl, Uta Nort -----570 ----
¡CAcro SCCT -------261 --
East Power Purchase Agreement ---200 ------
Coal Plant Turbine Upgrdes 3 44 33 25 2 14 -8 --
Geothermal ----35 -----
Wind II 99 249 -100 100 100 150 100 100 50
Combined Heat & Power 2 2 2 3 3 3 4 4 4 4
Distributed Standby Generation 4 4 4 4 4 4 4 4 4 4
DSM, Class i Uta Cool Keeper Load Control 25 50 40 30 10 10 10 10 10 10
DSM, Class i, Other ..........
DSM, Class 2 42 51 49 52 55 55 56 56 58 59
Front Offce Transactiom 75 50 150 394 493 200 202 228 717 800
West
Coal Plant Turbine Upgrades -9 9 12 12 -----
Swift Hydro Upgrades 21 ---25 25 25 ----
Wind 45 20 200 -------
Combined Heat & Power i i i i 2 2 2 2 2 2
Distrbuted Stadby Generation i i i i i i i i i i
DSM,Class i ..........
DSM, Class 2 35 36 39 39 38 39 39 39 39 29
Front Offce Transactiom --59 839 839 739 739 689 289 582
Total Planned Resources 332 517 587 1725 1619 1762 1207 1402 1224 1541
Planing Margin -
East 13.7%12.3%12.3%12.3%12.3%12.2%12.3%12.3%12.3%12.3%
West 14.6%11.5%11.5%11.5%11.6%11.7%11.6%11.7%11.6%11.6%
System 14.0%12.1%12.1%12.1%12.1%12.1%12.1%12.1%12.1%12.1%
2008 IRP Preferred Portfolio - Adjusted to Maintain Planning Margin
Capacity, MW I
Resource 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 I
East .-CCCT F 2xl. Uta North ----I -
¡CAero SCCT ----I -I -I -
East Power Purchasc Agreement ---
Coal Plant Turbine Upgrades 3 44 33 25 2 141 -
Geotherml -----"
Wind 'i 99 249 -100 100 100 150 100 100 50
Combined Heat & Power 2 2 2 3 3 3 4 4 4 4
Distributed Standby Generation 4 4 4 4 4 4 4 4 4 4
DSM, Class i Uta Cool Keeper Load Control 25 50 40 30 10 10 10 10 10 10
DSM, Class I, Other ..........
DSM, Class 2 42 51 49 52 55 55 56 56 58 59
Front Offce Trasactiom 75 50 .r~
West
Coal Plant Turbine Upgrades -9 9 12 12 -----
Swift Hydro Upgrades 21 .--25 25 25 ----
Wind 45 20 200 -------
Combined Heat & Power i i i i 2 2 2 2 2 2
Distrbuted Stadby Genertion i i i i i i i i i i
DSM,Class i ..........
DSM, Class 2 35 36 39 39 38 39 39 39 39 29
Front Offce Trasactiom --59 839 839 739 739 689 289 582
Total Planned Resources 332 517 437 1306 1266 1217 1080 1088 1057 1266
Planing Margin -
East 13.7%12.8%12.0%12.0%12.1%12.2%12.2%12.0%12.1%12.1%
West 14.6%IU%11.5%11.5%11.6%11.7%11.6%IJ.%11.6%11.6%
System 14.0%12.4%11.8%11.9%11.9%12.0%12.0"10 11.9%12.0%12.0%
ii The 99 MW amount in 2009 is the High Plains projec; the 249 MW in 2010 includs the 99 MW The Butts wid PPA.2J The Swift 1 hydro updates are shown in the year they enter into commerial seice
* Up to 120 MW ofiiditiona cost.effective Class i DSM progrms (100 MW eas 30 MW west) to be identified thugh competitive Requests for Proposals
and phased in as apoprate frm 2009-2018. Firm maret purhases (3rd qua produts) would be reduced by roughly comparble amounts.