20080919Duvall Direct.pdf

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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE )
APPLICATION OF ROCKY )
MOUNTAIN POWER FOR )
APPROVAL OF CHANGES TO ITS )
ELECTRIC SERVICE SCHEDULES )
AND A PRICE INCREASE OF $5.9 )
MILLION, OR 4.0 PERCENT )
CASE NO. PAC-E-08-07
Direct Testimony of Gregory N. Duvall
ROCKY MOUNTAIN POWER
CASE NO. PAC-E-08-07
September 2008
1 Q.Please state your name, business address and present position with Rocky
2 Mountain Power (the Company), a division of PacifCorp.
3 A.My name is Gregory N. Duvall, my business address is 825 NE Multnomah St.,
4 Suite 600, Portland, Oregon 97232, and my present title is Director, Long Range
5 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 Master of Business Administration degree from University of Portland in 1979. I
10 was first employed by Pacific Power in 1976 and have held various positions in
11 resource and transmission planning, regulation, resource acquisitions and trading.
12 From 1997 through 2000 I lived in Australia where I managed the Energy Trading
13 Deparent for Powercor, a PacifiCorp subsidiary at that time. After returning to
14 Portland, I was involved in direct access issues in Oregon, was responsible for
15 directing the analytical effort for the Multi-State Process ("MSP"), and currently
16 direct the work of the integrated resource planing group, the load forecasting
17 group, the forward pricing group, and the net power cost group in the Company.
18 Purpose of Testimony
19 Q.What is the purpose of your testimony in this proceeding?
20 A.I present the Company's proposed net power costs for the 12-month period ending
21 December 2008. Specifically, my testimony:
22 · Describes the primary drivers ofthe increase in the Company's net power
23 costs,
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· Sponsors the GRID model Net Power Cost report that supports this filing, and
· Supports Rocky Mountain Power's decision to acquire the Chehalis Power
3 Generating Plant ("Plant") located in Chehalis, Washington.
4 Net Power Cost Results
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What are the proposed normalied net power costs?
The normalized net power costs for the twelve months ending December 2008 are
approximately $66.1 milion on an Idaho allocated basis, or $982 milion system-
wide. The Company's net power cost study is provided as Exhibit No. 14. The
allocation of total Company net power costs to Idaho is presented in Exhibit No.
12 in Mr. Brian S. Dickman's testimony.
How do these compare with the net power costs the Company presented in
Case No. PAC-E-07-05, the Company's last general rate case?
The Company's last rate filing, Case No. PAC-E-07-05, was settled with no
specific finding on net power costs. Idaho's allocated portion of net power costs
in the current filing is approximately $8.3 milion higher than the net power costs
filed in Case No. PAC-E-07-05. On a total Company basis, net power costs have
increased from $861 milion in Case No. PAC-E-07-05 to $982 milion, an
increase of approximately $ 1 2 i milion.
If the Company were able to use a forecast that actually matched the
period when rates from this case wil be in effect, the increase in power costs
would be even higher. For example, the recent 2008 Utah general rate case relies
on a forecast of costs at June 2009 with a resulting net power cost on a total
Company basis of $1. 1 09 bilion.
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1 As I explain in the testimony that follows, the Company is experiencing
2 sharply rising power and generation costs. Setting rates under such conditions
3 based upon the costs in an historic test period wil result in the rates not reflecting
4 the amount of power costs the company actually expects to incur during the
5 period the rates from the case are in effect. As a result, the Company wil
6 experience pressure to file another case soon after this one is completed. The
7 Commission may want to consider allowing the use of forecast test periods or
8 power cost adjustment mechanisms to mitigate the need for frequent rate cases in
9 the current environment.
10 Primary Drivers of Increase in Net Variable Power Costs
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Please describe the environment for net power costs now facing the
Company.
The Company's system net power costs are increasing sharply at a rate of$40 to
$50 milion every six months. Excluding the month when Mid Columbia prices
were extremely low due to concentrated snowmelt, the Company's forward price
curve for the 12-month test period in the current proceeding is more than 35
percent higher than the one for the 12-month period in Case No. PAC-E-07-05.
The Company has not experienced rising net power costs ofthis magnitude since
the Western energy crisis.
Are these cost increases reflected in the Company's most recent actual net
power costs?
Yes. The Company's actual system power costs for the twelve-month period
ending May 31, 2008, were approximately $1.058 billon. The Company's actual
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system power costs for calendar year 2007 were $975 milion. Thus, in just five
months, the Company's actual system net power costs increased by approximately
$83 milion. The Company's historical actual system net power costs, $975
milion, in 2007 exceeded the forecast net power costs the Company requested in
Case No. PAC-E-07-05, $861 milion, by $114 milion.
Is the Company's experience regarding increased net power costs unique or
transitory?
No. At its meeting on June 19, 2008, the FERC discussed the causes and
potential duration of rising electricity costs. The presentation by the analysts
from FERC's Office of Enforcement stated "that forward market prices for
electric power are much higher than the prices we actually experienced last year.
This trend is universal around the country." It also showed that the forward prices
for July and August of 2008 were significantly higher than last years, and
indicated that "(t)here is little reason to believe that this summer is unusuaL.
Rather, it may be the beginning of significantly higher power prices that willast
for years."
What are the primary drivers of the increase in net power costs?
In general, besides higher electrc prices, the largest factors causing the cost
increase are higher retail loads, higher coal prices and higher natural gas costs.
These increases are mitigated by the addition of new resources and the operation
of Company hedges.
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How does increased retail load impact the Company's proposed net power
costs?
This filing reflects a system-wide increase in load of 1.9 milion megawatt hours
(over three percent) when compared to total company loads included in Case No.
PAC-E-07-05. All things being equal, additional retail load wil require the
Company to re-dispatch the system utilizing additional higher cost thermal
resources and by making additional market purchases and reduced market sales.
Please explain the Company's coal fuel price increases.
The coal price increases at our generation facilties are being driven by a varety
offactors, including increases in commodity costs (oil, steel and gas), the impact
of contract re-openers, and higher mine operating costs.
Can you give examples of these cost increases?
Yes. The cost increase of fuel supplied by the Arch coal purchase is mainly due
to a price re-opener as well as contract escalation. The cost increase at the Jim
Bridger mine is mainly due to increased depreciation and depletion associated
with the underground mining operations, increased royalty costs, as well as
increased labor, benefits and overall operating costs. The cost increase at the
Deer Creek mine is caused by a combination of increased costs in materials and
supplies coupled with increased labor, benefits, insurance and royalties.
Please explain the sources of the increase in the Company's gas costs.
Gas prices have generally trended upward over the last several years and the
Company expects this trend to continue through end of 2008. Many gas utilities
have recently proposed double-digit increases to rates caused by increasing gas
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pass-through costs. The Company's gas costs reflect market prices, plus cost
increases or decreases to reflect Company's hedged position. In this case, the
Company forecast gas costs are increasing at less than market rates, due to the
Company's gas hedges.
Why have hydro costs increased in this case?
The Company has experienced varous cost increases associated with its hydro
generation, including purchase contract cost increases, and refined hydro
modeling to better reflect historical hydro availability and to verify the
assumptions and outputs of the VISTA modeL. The decrease in the Company's
owned hydro generation is somewhat offset by an additional short term purchase
from the Douglas County Public Utility District for generation from the Mid
Columbia projects.
Are the cost increases partially offset by the inclusion of the near zero
variable costs from renewable energy facilties expected to be in service
during the test period?
Yes. The net power costs include expected generation from the 94-megawatt
Goodnoe wind project located in Oregon that came online in July 2008, and the
70-megawatt expansion of the Marengo wind project located in Washington and
came online in June 2008. The proposed net power costs also include a full year
operation of the 140-megawatt Marengo wind project. Because the Company
owns these wind facilities, the variable cost of these resources is close to zero,
except a projected $ 1.14 per megawatt hour charge for intra-hour integration of
wind generation into the Company's resource portfolio. In this current
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proceeding, the Goodnoe Hils and Marengo expansion facilities are assumed to
be online beginning January 1,2008.
Do the proposed net power costs include the impact of the Chehalis plant?
Yes. The proposed net power costs include generation from the Chehalis plant
that is located in Washington, which is currently under a tollng agreement. The
Company has also entered into a contract to acquire the plant and the transaction
is expected to close in September 2008. Further details on the Chehalis plant are
provided in the testimony of Mr. A. Robert Lasich and Mr. Stefan A. Bird. In the
current proceeding, the Chehalis plant is assumed to be online beginning January
1, 2008. The Company's variable net power costs are lower because ofthe
generation from the Chehalis plant.
Please explain how the Company models the wind integration charges for
Leaning Juniper and Goodnoe Hils.
The Bonnevile Power Administration ("BP A") has proposed to charge for wind
integration beginning October, 2008. Because the Company's Leaning Juniper
and Goodnoe Hils wind facilities are interconnected to BP A's transmission
system, the Company is expected to incur such expenses for these two projects.
Has the Company modeled reserve requirements for the Leaning Juniper
and Goodnoe Hils wind facilties?
BP A provides the reserves for both wind facilities. The charges for Leaning
Juniper's reserves are included in the wheeling expenses. As a result, the reserve
requirements for Leaning Juniper are not modeled in GRID, while the resere
requirements for Goodnoe Hils are modeled in GRID because the facility has
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1 only come on-line recently and there is not enough historical data to approximate
2 the payment for the reserves.
3 Q.Did the Company adjust for startup costs related to the gas-fired units?
4 A.Yes. Because the GRID model does not capture the startp costs of the gas-fired
5 units that are not included in any other Federal Energy Regulatory Commission
6 ("FERC") accounts, a line item is added to the net power cost report to capture the
7 startp fuel costs of the gas-fired units. In addition, the adjustments made in
8 GRID to remove uneconomical dispatch of the gas-fired units result in additional
9 startups of the units, the additional operations and maintenance costs are included
1 0 in the net power costs report.
11 Determination of Net Power Costs
12 Q.Please explain net power costs.
13 A.Net power costs are defined as the sum of fuel expenses, wholesale purchase
14 power expenses and wheeling expenses, less wholesale sales revenue.
15 Q.Please explain how the Company calculates net power costs.
16 A.Net power costs are calculated using the GRID modeL. For each hour in the test
17 period, the model simulates the operation of the power supply portion of the
18 Company under three stream flow conditions. The results obtained from the
19 stream flow conditions are averaged and the appropriate cost data is applied to
20 determine an expected net power cost under normal stream flow and weather
21 conditions for the test period.
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Are these proposed net power costs developed with the same production
dispatch model used in Case No. PAC-E-07-05?
Yes. The Company has used the GRID model in its last several rate case filings
in Idaho. In this filing, the Company implemented GRID version 6.2.
Please generally describe the improvements in the GRID model reflected in
version 6.2.
The first change enhances the system balancing logic to better recognize
economic displacement by de-committing eligible thermal units. The study that
the Company did during the user acceptance testing showed a decrease in net
power costs by $5.1 milion on a total Company basis.
The second change improves the dispatch of resources with zero minimum
up and down time settings. The net power cost impact is either a small decrease
or a small increase depending upon parameters of the entire portfolio of resources.
The study that the Company did during the user acceptance testing showed an
increase in net power costs by $149,975 on a total Company basis.
The third change provides the capabilty to include a loss payment for
transmission losses as par of the total hourly transmission link cost. Because
there are no contracts modeled as such in this filing, there is no net power cost
impact from this change.
The fourth change provides the capabilty to include a capacity payment
and other costs in the total monthly transmission link cost. Because there are no
contracts modeled as such in this fiing, there is no net power cost impact from
this change.
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The fifth change improves the effciency of the system balancing
algorithm. The sixth change provides enhanced functionality for greater analyst
effciency. There is no net power cost impact associated with either of these
changes.
Does the Company propose to update its filing in its rebuttal testimony for
material changes in net power costs, such as new contracts, fuel costs and the
Official Forward Price Curve, irrespective of whether these changes increase
or decrease net power costs?
Yes. This ensures that the Commission has the most accurate and current
10 information available to it in setting rates for the test period.
1 1 GRID Model Inputs and Outputs
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Please explain the inputs that go into the model.
Inputs used in GRID include retail loads, thermal plant data, hydroelectric
generation data, wind plant generation data, firm wholesale sales, firm wholesale
purchases, firm wheeling expenses, system balancing wholesale sales and
purchase market data, and transmission constraints.
Please describe the retail load that is used in the modeL.
The retail load represents the hourly firm retail load that the Company served
within all of its jurisdictions for the twelve-month period ending December 31,
2007.
Please describe the thermal plant inputs.
To determine the amount of energy available, the Company averages for each unit
four years of historical outage rates and maintenance. The heat rate for each unit
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is determined by using a four-year average of historical burn rate data. By using
four-year averages to calculate outages, maintenance and heat rate data, annual
fluctuations in unit operation and performance are smoothed. For this filing, the
48-month period ending December 2007 is used. Other thermal plant data
includes unit capacity, minimum generation level, minimum up/down time, fuel
cost, and starup cost.
Are there any exceptions to the four-year average calculation?
Yes. Some plants have not been in service for the entire four-year period. For
those plants, the Company uses the manufacturer's expected value for the missing
months to produce a weighted average value of the known and theoretical rates.
Please describe the hydroelectric generation input data.
The Company uses the output from the VISTA hydro regulation model for
GRID's hydroelectric generation input data. The Company uses three sets of
expected generation from VISTA, which is the same as in Case No. PAC-E-07-
05.
Does the Company use other hydro generation inputs?
Yes. Other parameters for the hydro generation logic include maximum
capability, minimum run requirements, ramping restrctions, shaping capability,
and reserve carrying capability of the projects.
Please describe the wind generation input data.
The Company uses wind site information from the project developers to estimate
generation, or use historical patterns when they become available.
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Please describe the input data for firm wholesale sales and purchases.
The data for firm wholesale sales and purchases are based on contracts to which
the Company is a party. Each contract specifies the basis for quantity and price.
The long-term firm contracts are modeled individually, and the short-term firm
contracts are grouped based on general delivery points. The short-term firm
contracts with flexibility are modeled individually so that they are optimized from
the point of view of the holder of the call/put.
Please describe the input data for wheeling expenses and transmission
capabilty.
Firm wheeling expense is based on the wheeling expense for the twelve-month
historic period ending December 2007, adjusted for known contract changes in
the forecast period through twelve-months ending December 31, 2008. Firm
transmission rights between transmission areas in the GRID topology are based
on the Company's Merchant Function contracts with the Company's
Transmission Function and contracts with other paries. The limited additional
transmission to which the Company may have access is based on the experience
of the Company's commercial and trading department. An example would be the
day ahead firm transmission that the Company historically purchases on Path "C."
Please describe the system balancing wholesale sales and purchase input
assumptions.
The GRID model uses five market points to balance and optimize the system.
The four established wholesale markets are at Mid-C, COB, Four Corners, and
PV. The Mona market has also been incorporated to reflect the level of
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transactions the Company enters at this limited market. Subject to the constraints
of the system and the economics of potential transactions, the model makes both
system balancing sales and purchases at these markets. The input data regarding
wholesale markets include market price and market size.
What market prices are used in the net power cost calculation?
As noted above, the market prices for the system balancing wholesale sales and
purchases at four liquid markets are from the Company's June 30, 2008 Official
Forward Price, shaped into hourly prices. While the Mona market prices were
developed consistent with the Company's June 30, 2008 price curve, they are not
part of the official curve due to the limited nature of the market and are highly
confidentiaL. The market price hourly scalars are developed by the Company's
commercial and trading departent based on rollng five-year historical hourly
data. The hourly prices for the test period are then calculated as the product ofthe
scalar for the hour and the corresponding monthly price.
What prices are included in the Company's official forward price curve?
The offcial forward price curve contains monthly prices for both wholesale
electricity and natural gas. The electricity price curves are produced for both on-
peak and off-peak delivery patterns and for various delivery points, including
Mid-Columbia, California-Oregon-Border, Palo Verde, northern California
(NP 15), and southern California (SP 15). The natural gas price curves include
burner-tip prices for gas delivered to the Company's gas-fired plants along with
prices at various delivery points throughout the west, including Opal, Sumas,
Stanfield, and southern California.
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How is the offcial forward price curve developed?
The offcial forward price curve is typically updated each quarter and is
comprised of three primary components. (1) The first 72 months of the curve
reflect electricity and natural gas market forward prices as of a given quote date.
For example, the June 30, 2008 official forward price curve used for the current
proceeding reflects market forwards as of June 30, 2008. The market forwards
used in the official forward price curve are validated against broker quotes for that
trading day. (2) Months 73 through 84 of the official forward price curve are a
blend ofthe previous year month-on-month market forwards and the following
year month-on-month fundamentals forecast. (3) Beyond month 84, the forward
price curve is developed from a fundamentals-driven price projection. The
fundamentals portion of the curve is based upon an external natural gas price
forecast. The Company uses the exteral natural gas price projection and other
fundamental inputs to develop a consistent electrcity price forecast.
Which component of the forward price curve is used in this case?
Only the first component, market quotes, is used in this filing given the timing of
the test period.
Does the Commission use the Company's forward price curves for other
purposes?
Yes. The Commission has employed the Company's forward price curves in rate
case proceedings, integrated resource planing, resource acquisition analysis, and
avoided cost determination.
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What reports does the study produce using the GRID model?
The major output from the GRID model is the net power cost report. Additional
data with more detailed analyses are also available in hourly, daily, monthly and
annual formats by heavy load hours and light load hours.
Do you believe that the GRID model appropriately reflects the Company's
system operations in its operating environment?
Yes. The use of the GRID model as described in my testimony, coupled with
8 refinements, appropriately simulates the operation ofthe Company's system over
9 a variety of streamflow conditions consistent with the Company's operation of the
10 system including operating constraints and requirements.
11 Chehalis
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Please identify the information, data, models and analyses used by the
Company in evaluating whether to acquire the Plant.
The Company has used data and models from its 2007 integrated resource pIan
("IRP"), 2008 business plan and information regarding the Plant obtained from
the current owner in analyzing whether to acquire the Plant. The Company has
conducted due diligence with regard to the data provided by the current owner
and is satisfied that the data is reasonably reliable and consistent with
expectations relative to other similar facilities. We have analyzed this data using
the system optimizer and planing and risk models, which are the same models
used in performing analysis for the IRP.
Please describe how the Company evaluated the Plant acquisition.
The Company compared the cost of acquiring the Plant in 2008 to the cost of
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acquiring resources in accordance with the business plan. To do this, the
Company first ran the system optimizer model assuming the Plant was in service
beginning on October 1, 2008. Upon reoptimization, the Plant displaces front
office transactions prior to 2012 and displaces a combined cycle combustion
turbine on the east-side ofthe system beginning in 2012. This new portfolio was
then analyzed using the planning and risk model through 2027. The present value
revenue requirement of this new portfolio was then compared to the present value
revenue requirement of the business plan using two estimates for the cost of the
displaced combined cycle combustion turbine.
Please describe the assumptions used in the studies.
The Company assumed the Plant wil be included in the resource portfolio
beginning October 1, 2008, with availability after forced outages and maintenance
of92 percent. The maximum capacity is determined monthly, based on average
daily temperatures and ranges from 481 MW average in the summer to 511 MW
average in the winter. Wholesale electricity and natural gas prices are based on
the Company's December 31,2007 official forward price curve. The analyses
include capital cost recovery, fixed and variable operation and maintenance
expense, start-up and shut-down costs, pipeline costs, sales tax and property tax.
What costs are assumed for the combined cycle combustion turbine that is
displaced in 2012?
The Company assumed the cost of a new combined cycle combustion turbine to
be $1,000 to $1,150 per kilowatt in 2008 dollars. This assumption is based on a
variety of factors. The primary one is the results ofthe 2012 RFP, as described in
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the Confidential Testimony of Mr. Bird. It is supported by the costs incurred by
the Company in constructing its own resource in recent years, costs from the
results ofthe 2012 RFP, and costs in the studies pedormed by Standard & Poor's
and The Brattle Group, all of which are described in Mr. Birds testimony.
What are the results of the analysis?
The results ofthe analysis we performed are shown in Confidential Exhibit No.
15. Confidential Exhibit No. 15 shows the present value revenue requirement of
the business plan compared to that of the business plan as modified to include the
Plant commencing on October 1, 2008. Adding the Plant to the business plan
reduces total variable costs by $52.1 milion over the study horizon. This
reduction is driven by lower overall purchased power costs offset by increased
fuel and wheeling expenses and a reduction in revenue from wholesale sales.
Confidential Exhibit No. 15 also shows the overall benefit under two
views of the cost of the new facility that is displaced in 2012 by the addition of
the Plant in 2008. If the cost ofa new facility is assumed to be $1,000 per kW,
then the total benefit of adding the Plant to the Company's portfolio in 2008 is
about $142 milion. Assuming the cost of a new facility is $1,150 per kW, the
total benefit rises to $197 milion. Idaho's approximate share ofthese benefits
based on current allocation factors would be about 6 percent.
This analysis demonstrates that acquisition of the Plant on the terms and
conditions in the PSA reduces present value revenue requirement by about $142
milion to $197 milion and, therefore, wil be beneficial to the Company and its
customers and is in the public interest. This analysis does not include the benefits
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of avoiding the risks associated with slippages in permitting, capital cost
escalation and overrns, unkown terms and conditions and slippage of
construction schedules.
Does the purchase of the Plant in 2008 versus waiting to acquire another
resource in 2012 benefit the Company's customers?
Yes. Our analysis shows that the Company's customers are better offthrough
acquisition of the Plant now than acquisition of a similar resource in 2012 based
on market pricing and responses to the 2012 RFP.
How sensitive is the foregoing analysis to changes in the price of natural gas?
Given the significant correlation between prices for natural gas and market prices
for electricity, changes in the price of natural gas wil have the same effect on the
costs and benefits of any new resource with the characteristics of the Plant. The
Company wil have less exposure to the wholesale markets with the Plant than
without the Plant. Without the Plant the Company would be exposed to the price
volatility of electricity prices. With the Plant the Company is not exposed to
either natural gas prices or electricity prices alone, but rather the Company is
exposed to the ratio of electricity prices to natural gas prices, which is the implied
spark spread, to the extent the Plant is economical to run. The volatilty in the
implied spark spread is far less than the volatility of either electrcity or natural
gas market prices due to the significant correlation of those two commodities.
This correlation is due to natural gas-fired generation being the generation on the
economic margin in the region. The Plant is anticipated to be economical to run a
significant amount of time due to its low heat rate.
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1 Q.If the Company does not acquire the Plant, what alternatives are needed to
2 meet the Company's needs.
3 A.As demonstrated by the 2007 IRP and the 2008 business plan, the Company needs
4 to acquire substantial additional resources by 2012. The alternative to acquisition
5 of the Plant is addition of similar plants at higher costs or increased purchases of
6 power on the market. The impact of these alternatives on the Company's revenue
7 requirement would certainly be less favorable than acquisition of the Plant.This
8 is demonstrated by the analysis in Confidential Exhibit No. 15.
9 Q.What do you conclude from the foregoing?
10 A.The Company's analysis demonstrates that acquisition of the Plant is a great
11 opportnity and that it wil benefit the Company and its customers. I further
12 recommend that the Commission approve the Plant for inclusion in the revenue
13 requirement as ilustrated in the exhibit of Mr. Dickman.
14 Q.Does this conclude your direct testimony?
15 A.Yes.
Duvall, Di - 19
Rocky Mountain Power
28SEP l 9 A" 10= 53 Case No. P AC-E-08-07
Exhibit No. 14
Witness: Gregory N. DuvallIDAHO PUBLIC
UTILITIES COMMISSION
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Gregory N. Duvall
Net Power Cost Analysis
September 2008
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100ISEP '9 td1lO: 53
\OAHO PUBLIC
UT\UTIES COMMISSION
Confidential
Case No. PAC-E-08-07
Exhibit No. 15
Witness: Gregory N. Duvall
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Confidential
Exhibit Accompanying Direct Testimony of Gregory N. Duvall
NPV Comparson
September 2008
RECEIVED
ZU8l:SEP l9 AM JOS3
IDAHO PUBLIC
UTILITIES COMMISSION
THIS EXHIBIT IS CONFIDENTIAL
AND IS PROVIDED UNDER
SEPARATE COVER