20040209Johnson Direct.pdf

DA VID J. MEYER
SENIOR VICE PRESIDENT AND GENERAL COUNSEL
A VISTA CORPORA nON
O. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: [phone]
FACSIMILE: [phone]
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF AVISTACORPORATIONFOR THE
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC AND
NATURAL GAS SERVICE TO ELECTRIC AND
NATURAL GAS CUSTOMERS IN THE ST ATE& IDmO
CASE NO. A VU-04-
DIRECT TESTIMONY
WILLIAM G. JOHNSON
FOR A VISTA CORPORA nON
(ELECTRIC ONLY)
I. INTRODUCTION
Please state your name, business address, and present position with
A vista Corporation.
My name is William G. Johnson. My business address is 1411 East Mission
Avenue, Spokane, Washington, and I am employed by the Company as a Senior Power
Supply Analyst in the Energy Resources Department.
What is your educational background?
I graduated from the University of Montana in 1981 with a Bachelor of Arts
Degree in Political Science/Economics. I obtained a Master of Arts Degree in Economics
from the University of Montana in 1985.
How long have you been employed by the Company and what are your
duties as a Senior Power Supply Analyst?
I started working for A vista in April 1990 as a Demand Side Resource
Analyst. I joined the Energy Resources Department as a Power Contracts Analyst in June
1996. My primary responsibilities involve long-term resource planning issues.
What is the scope of your testimony in this proceeding?
My testimony will 1) describe the adjustments to the 2002 test period power
supply revenues and expenses, and 2) describe the new base level of power supply costs for
Power Cost Adjustment (PCA) calculation purposes, using the proforma costs proposed by
the Company in this filing. A table of contents for my testimony is as follows:
Johnson, Di
A vista Corporation
Description
Introduction
Summary
Proforma Power Supply Costs
New Base Costs for PCA Calculations
Are you sponsoring any exhibits to be introduced in this proceeding?
Yes. I am sponsoring Exhibit No.1 0, Schedules 1 through 4, which were
prepared under my supervision and direction.
Are other company witnesses providing testimony regarding issues you
are addressing?
Yes. Company Witness Kalich provides detailed testimony on the AURORA
model used by the Company to develop a portion of the proforma power supply revenues and
expenses included in my exhibits.
II. SUMMARY
Please provide an overview of your direct testimony.
My testimony explains adjustments made to normalize power supply revenue
and expense items in the proforma period compared to the 2002 test period. This involves
estimating revenues and expenses based on normal stream flow and weather conditions, and
expected wholesale market power prices. In addition, adjustments are made to reflect known
and measurable power contract changes between the 2002 test period, and the time period
that retail rates are expected to be in effect (i., the proforma period beginning September 1
2004 and ending August 31 , 2005). The net effect of my adjustments to the 2002-test period
power supply net expense is a decrease of $30 522 000 on a system basis. The Idaho
Johnson, Di
Avista Corporation
allocation of this adjustment is incorporated into the revenue requirement calculation for the
Idaho jurisdiction by Witness Falkner.
III. PROFORMA POWER SUPPLY COSTS
Overview
Please identify the specific power supply cost items that are covered by
your testimony and the total adjustment being proposed.
Exhibit No.1 0, Schedule 1 identifies the power supply expense and revenue
items that fall within the scope of my testimony. These revenue and expense items are
related to power purchases and sales, wheeling expenses, thermal fuel expenses and other
miscellaneous power supply revenues and expenses identified in Exhibit No.1 0, Schedule 1.
What is the basis for the adjustments to the 2002 actual power supply
revenues and expenses?
Adjustments are made to set the power supply revenues and expenses based
on normal weather and normal stream flows. The AURORA model is used to normalize
power supply revenue and expenses that are dependent upon weather and stream flows. The
AURORA Model dispatches Company resources on an hourly basis and calculates the level
of generation from the Company s thermal resources along with the short-term purchases and
sales required to serve system requirements.
Adjustments are also made to reflect known and measurable contract changes
between the 2002 test period and the proforma period. The Company has included proforma
power supply adjustments to reflect power costs for the twelve-month period beginning
September 1 , 2004 and ending August 31 , 2005.
Johnson, Di
A vista Corporation
What changes has the Company made in the calculation of normal power
supply costs from the prior general rate case?
The primary change has been the adoption of an hourly system simulation
model as explained by Mr. Kalich. This model calculates the dispatch of Company resources
in each hour of the proforma year, rather than a monthly average dispatch as was done with
the dispatch model used in prior rate cases.
Power supply adjustments for known and measurable changes have been prepared
using the same methods that have been used in prior general rate cases. Detailed work papers
have been provided to the Commission coincident to this filing, that supports each of the
proforma adjustments. A brief description of each adjustment is also included in Exhibit No.
, Schedule 2.
What is the overall change in normalized power supply costs compared to
the prior general rate case?
Power supply expense has increased by approximately $11 million (Idaho)
from the prior general rate case. This increase is primarily driven by reduced wholesale net
revenues and an increase in fuel expense. Wholesale net revenue decreased by approximately
$6 million (Idaho) due primarily to the restructuring of the capacity sale to Portland General
Electric. The increase in fuel expense is driven by approximately $10.5 million (Idaho)
increase in natural gas fuel expense due to the addition of the Coyote Springs 2 plant, which
is offset by an approximately $6 million (Idaho) reduction in thermal fuel costs due mostly to
the sale of the Centralia plant.
Johnson, Di
A vista Corporation
Short-Term Purchases and Sales
How are the short-term market purchases (Account 555) and sales
(Account 447) determined in the proforma?
Short-term market purchases and sales are an output of the AURORA model.
They are the purchases and sales made to balance the system obligations and resources on an
hourly basis. Mr. Kalich explains the derivation of the short-term sales revenue, and short-
term purchase expense in detail in his testimony. Exhibit No. 10, Schedule 3 shows the
proforma monthly short-term purchases and sales amounts and average price. These figure
were taken from Mr. Kalich's Exhibit No. 11. As shown in Exhibit No. 10, Schedule 3
during the proforma period the Company is a net seller on an annual basis.
Lon2:- Term Contracts
What long-term contracts are included in the proforma?
There are five long-term or medium-term purchases and several small PURP A
purchases and one pending wind energy purchase. The long-term purchase is the WNP-
purchase from the Bonneville Power Administration (BP A). There are four medium-term
purchases with a term of January 2004 through December 2006. There are approximately 14
average megawatts of PURP A and other small power purchases. In addition, a new wind
power purchase that is expected to begin in early 2004 will provide approximately 10 average
megawatts of energy. A brief summary of these contracts is provided in Exhibit No.1 0
Schedule 2, and the detail of the costs for each is included in the workpapers that have been
provided with this filing.
Johnson, Di
A vista Corporation
The Company has very few remaining long-term sales. One that remains is the
Peaker capacity sale. This sale is the former Portland General Electric capacity sale that was
monetized in 1998. The other two long-term sales of more substantial dollar volume include
the Nichols pumping sale and the sale of reserves and control area services to Mirant for their
half of Coyote Springs 2. With the Nichols sale, A vista sells power to the other owners of
Colstrip units 3 and 4 to supply power to the pumps that supply water to the plant. The
contract rate is the Dow Jones Mid Columbia index price. For the proforma, the revenue
from the sale is based on the average market purchase and sales price developed by the
AURORA model. The net effect is little, if any, impact on overall net power supply expense
since the revenue from the sale offsets the cost created by the obligation. The advantage of
this sale is that it reduces the transmission losses associated with wheeling Colstrip energy to
Avista s system since some of Avista s Colstrip energy is "laid-off' at Colstrip to serve the
Nichols pumping load.
What is the impact on net power supply expense due to the expiration of
most of the long-term sales contracts since the last general rate case?
The net expense increase due to the expiration of long-term wholesale
contracts is approximately $15.7 million on a system basis. This is almost entirely due to the
restructuring of the Portland General Electric (PGE) capacity sale. In the 1998 rate case the
revenue from this sale was $18 288 000 ($10.16/kW/month) per year (system). With the
restructuring of the contract the current revenue is $1 800 000 per year ($l/kW/month)
(system), a revenue decrease of $16,488 000 per year on a system basis.Customers
however, have already received the full benefits of the original PGE capacity sale through the
Johnson, Di
A vista Corporation
accelerated amortization of the payment A vista received for restructuring the contract (PGE
Monetization). This accelerated amortization of the monetized contract payment was used to
offset a portion of the PCA deferral balance. The amortization of the monetized contract
payment ended December 2002.
The termination of other long-term energy sales had a relatively small impact on net
power supply expense. Long-term wholesale energy sales reduced net power supply expense
by approximately $750 000 (system) in the 1998 general rate case. The proforma in this
filing does not include any net revenue from wholesale energy sales. It does include revenue
from the sale of non-energy products, such as exchange capacity, generation reserves and
load following services.
Thermal Fuel Expense
How are thermal fuel expenses determined in the proforma?
Thermal fuel expenses include the Colstrip coal costs, Kettle Falls wood waste
costs and natural gas expense for the Company s gas-fired resources including Coyote
Springs 2, Rathdrum, Northeast, Boulder Park, and the Kettle Falls combustion turbine. Unit
coal costs at Colstrip are based on the long-term coal supply and transportation agreements.
Unit wood fuel costs at Kettle Falls are based on the multiple shorter-term contracts with fuel
suppliers. Unit fuel costs for natural gas are based on forward market prices. Total fuel costs
for each plant are based on the unit fuel cost and the plant's level of generation as determined
by the AURORA model. Exhibit No.1 0, Schedule 3 shows the proforma fuel costs by
month for each plant.
Johnson, Di
A vista Corporation
What is the change in Colstrip and Kettle Falls unit fuel costs?
The Colstrip per unit coal cost has increased from $10.27 per ton in the 2002
test year to $10.35 per ton in the proforma. The Kettle Falls per unit wood waste cost has
increased from $12.77 per green ton in the test year to $13.82 per green ton in the proforma.
The unit fuel costs increase at Kettle Falls is due in part to the increased demand for wood
fuels and the increased distance from the plant for new suppliers.
What is the change in natural gas fuel costs?
Natural gas fuel costs in 2002 did not include fuel consumption at Coyote
Springs 2, which accounts for over $30 million of the total $35.6 million natural gas fuel
expense in the proforma included in Account 547. Natural gas fuel expense will vary
significantly based on both the cost of natural gas and the generation level of the natural gas
fueled plants. In the proforma year, Coyote Springs 2 generates approximately 111 average
megawatts (aMW) and the Company s other gas fueled plants combined, which are primarily
peaking units, generate approximately 5 aMW.
Natural gas fuel unit costs are based on the forward market price of natural gas (as of
December 10, 2003) as explained by Mr. Kalich. The average price of natural gas at Malin
(gas price for Coyote Springs 2) during the proforma is $4.48 per dekatherm. Natural gas
expenses also include the expense for natural gas transportation agreements used to serve the
Coyote Springs 2 plant.
Johnson, Di
A vista Corporation
Do proforma natural gas fuel expenses include the cost of the fixed price
gas purchases made in 2001
No. The proforma natural gas fuel expenses are based on the current forward
market price of natural gas (as of December 10, 2003). The proforma net expense for natural
gas purchased for, but not consumed for generation is normalized to $0 since the proforma
assumes that all gas purchased will be consumed for generation and included in Account 547.
Mr. Lafferty s testimony addresses the fixed price gas purchases made in 2001.
Transmission Expense
What factors are driving the increase in transmission expense in the
proforma?
Transmission expense in Account 565 increases by approximately $1.
million (system) over the test year.The primary reason for the increased expense is
additional amounts of transmission purchased in the proforma period. The amount of BP A
transmission purchased to integrate generation is 343 MW, which includes 196 MW for
Colstrip and 147 MW for Coyote Springs 2.Prior to operating Coyote Springs 2 the
Company held 267 Megawatts of BP A transmission to integrate generation. Other changes
include a 15 MW increase in transmission capacity to the California Oregon Border (COB)
purchased from Portland General Electric, and an increase in short-term transmission expense
for short-term system purchases and sales.
Johnson, Di
A vista Corporation
IV. PCACALCULATIONS
Is the Company proposing any changes to how the PCA deferral is
calculated each month?
No. PCA entries will continue to be calculated in the same manner as the
current calculations. The final order in this case will determine the new authorized level of
power supply revenues and expenses used in the PCA calculation.There will be an
additional line to accommodate the new power purchase from the Potlatch Lewiston facility,
which I will discuss later in my testimony.
Will the PCA continue to include the revenues and expenses from
purchases and sales of transactions related to the acquisition of natural gas for thermal
generation?
Yes. The Company will likely continue to fix the price in advance on some
portion of natural gas necessary to run thermal generation. There will also be instances
where the Company later, because of a change in market electric and natural gas prices, sells
the gas and purchases electricity. These types of transactions may lead to a net gain or loss
on the sale of the natural gas that will be recorded as a separate line in the PCA. The
objective of these transactions is to provide some stability over time to the cost of natural gas
to fuel these generators, while also having the opportunity to make the most economic
decision when the time comes to either burn the gas or sell the gas and purchase electricity.
The revenue and expenses from these transactions will be recorded in Account 557 (Other
Power Supply Expenses) for the cost of the natural gas purchased and Account 456 (Other
Electric Revenues) for the revenue from the natural gas sales.
Johnson, Di
A vista Corporation
How will changes in the costs associated with Potlatch's Lewiston
generation be included in the PCA?
The Potlatch purchase expense will be a separate line item in the PCA
calculation. Changes in the Potlatch purchase expense will be included in the PCA at 100
percent of the change. change in Potlatch Lewiston corresponding to the change in
Potlatch generation will also be included at the 100 percent level in the retail revenue credit.
Additional Potlatch load changes, not corresponding to their generation, will be included at
the 90 percent level in the retail revenue credit within the PCA. The proposed base level for
the Potlatch power purchase expense and the Potlatch revenue corresponding to their
generation is shown in Exhibit 10, Schedule 4.
Will there be any change in how the retail revenue adjustment is
calculated in the PCA?
No. The only changes that will occur will be in the new authorized level of
retail sales and the incremental cost of power that will be approved in this case. The
Company has proposed that the authorized retail sales will be based on the weather-adjusted
2002 sales used in this case. The proposed base level of retail sales is shown in Exhibit 10
Schedule 4. The incremental cost of power is $36.38/MWh, which is the weighted average
price of Avista s short-term market sales and purchases as determined by the AURORA
model.
Johnson, Di
A vista Corporation
What is the new authorized level of power supply expense proposed by the
Company for the PCA?
The new authorized level of annual power supply expense is $71,456 998.
This is the sum of Accounts 555 (Purchased Power), 501 (Thermal Fuel), and 547 (Fuel) less
Account 447 (Sale for Resale). The current level of authorized power supply expense is
$57 866,430. The increase in expense is $13 590 568 on a system basis. The proforma-
authorized expense does not include the cost of power purchased from Potlatch. That
expense will be included as a separate non-system (100% allocated to Idaho) expense in the
PCA and changes to that expense will be included at the 100 percent level in the PCA
deferral calculation. The proposed base level of net power supply expense is shown in
Exhibit 10, Schedule 4.
Does that conclude your pre-filed direct testimony?
Yes.
Johnson, Di
A vista Corporation