20090123Johnson Direct.pdf

DAVID J. MEYER
VICE PRESIDENT AN CHIEF COUNSEL OF
REGULATORY & GOVERNNTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENE
SPOKAE, WASHINGTON 99220-3727TELEPHONE: [phone]FACSIMILE: [phone]
REeF: ED
2009 JpJi¡ 23 P~ii \2: Li2
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF AVISTA CORPORATION FOR THE
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC AN
NATURAL GAS SERVICE TO ELECTRIC
AND NATURA GAS CUSTOMERS IN THE
STATE OF IDAHO
FOR AVISTA CORPORATION
(ELECTRIC ONLY)
CASE NO. AVU-E-09-01
DIRECT TESTIMONY
OF
WILLIAM G. JOHNSON
1
2
I.INTRODUCTION
Q.Please state your name, business address, and
3 present position with Avista Corporation.
4 A.My name is William G. Johnson.My business
5 address is 1411 East Mission Avenue, Spokane, Washington,
6 and I am employed by the Company as a Wholesale Marketing
7 Manager in the Energy Resources Department.
8
9
Q.What is your educational background?
A.I graduated from the University of Montana in
10 1981 with a Bachelor of Arts Degree in Political
11 Science/Economics.I obtained a Master of Arts Degree in
12 Economics from the University of Montana in 1985.
13 Q.How long have you been employed by the Company
14 and what are your duties as a Wholesale Marketing Manager?
15
16
A.I started working for Avista in April 1990 as a
Demand Side Resource Analyst.I joined the Energy
17 Resources Department as a Power Contracts Analyst in June
18 1996.My primary responsibilities involve power contract
19 origination and management and power supply regulatory
20 issues.
21 Q.What is the scope of your testimony in this
22 proceeding?
23 A.My testimony will 1) identify ànd explain the
24 proposed normalizing and pro forma adjustments to the
25 October 2007 through September 2008 test period power
Johnson, Di 1
Avista Corporation
1 supply revenues and expenses, and 2) describe the proposed
2 changes to the Power Cost Adjustment (PCA) calculation
3 methodology and the new authorized level of power supply
4 expense for PCA calculation purposes and 3) describe how
5 the Company proposes to track the expense and revenue
6 associated with the Lancaster plant, which will become an
7 Avista utilities resource beginning January 1, 2010.
8 Q.Are you sponsoring any exhibits to be introduced
9 in this proceeding?
10 A.Yes.I am sponsoring Exhibit No.6, Schedules 1
11 through 4, which were prepared under my supervision and
12 direction.
13 Q.Are other company witnesses providing testimony
14 regarding issues you are addressing?
15 A.Yes.Company wi tness Mr.Kalich provides
16 detailed testimony on the AURORA model used by the Company
17 to develop short-term power purchase expense, fuel expense
18 and short-term power sales revenue included in my exhibits.
19
20
21
II. Pro Form Exense Adjustment
Q.Please provide an overview of your pro forma
22 adjustment to power supply expense.
23 A. The pro forma adjustment to power supply expense
24 involves the determination of revenues and expenses based
25 on the generation and dispatch of Company resources and
Johnson, Di 2
Avista Corporation
1 expected wholesale market power prices as determined by the
2 AURORA model simulation for the pro forma period under
3 normal weather and hydro generation conditions.In
4 addition, adjustments are made to reflect contract changes
5 between test period and the pro forma period.The table
6 below shows total net power supply expense during the test
7 period and the pro forma period.For information purposes
8 only, the power supply expense currently in rates, which is
9 based on a calendar 2009 pro forma period, is also shown.
Power Supply Expense
. (Not Including Directly Assigned Potlatch Purchase)
Power Supply Expense in Current Base Rates (Calendar 2009 pro forma)
System
$17 4,849,000
Idaho
Allocation
Adjustment to Test Period
$180,395,000
$27,64,000 $9,789,095
Actual Oct 07-Sep 08 Power Supply Expense
July 2009 - June 2010 Pro forma Power Supply Expense $208,040,000
10
11
Increase from Expense in Current Rates $33,191,000 $11,752,933
The net effect of my adjustments to the test year
12 power supply expense is an increase of $27,645,000
13 ($208,040,000 - $180,395,000) on a system basis. The Idaho
14 allocation of this adjustment of $9,789,095 is incorporated
15 into the revenue requirement calculation for the Idaho
16 jurisdiction by Company witness Ms. Andrews.
17 The increase in power supply expense compared to the
18 pro forma level in current base rates is $33,191,000
19 (system) and $11,752,933 (Idaho allocation).The power
Johnson, Di 3
Avista Corporation
1 supply expense in current base rates is based on a calendar
2 year 2009 pro forma.
3 Q.What are the major factors driving the increased
4 power supply exense in the pro form year over the level
5 of power supply expense currently in base rates?
6
7
8
A.The level of power supply expense currently in
base rates is $174,849,000 (system numer).This expense
level is based on a calendar 2009 pro forma period.This
9 compares to the proposed pro forma power supply expense of
10 $208,040,000, an increase of approximately $33.2 million on
11 a system basis and an Idaho allocation of approximately
12 $11.8 million.
13 This increase in pro forma power supply expense over
14 the expense currently in base rates is based on numerous
15 factors, primarily reduced hydro generation due to the
16 elimination of the rate mitigation adjustment included in
17 the last case and higher retail loads.
18 Pro forma retail loads are 22.7 aM higher than loads
19 that current rates are based on.The increased loads are
20 due to two factors. One is the natural increase in retail
21 loads of approximately 14.3 aMW. The other 8.4 aMW of load
22 increase is due to the reduction in potlatch generation.
23 Because Potlatch generation expense is directly assigned to
24 Idaho, the Potlatch load equivalent to their generation is
25 removed from system loads.The reduction in Potlatch
Johnson, Di 4
Avista Corporation
1 generation has the effect of increasing system loads for
2 rate making purposes, while at the same time reducing the
3 Potlatch power purchase expense directly assigned to Idaho.
4
5
Hydro generation is also lower than the level in
current base rates.Pro forma hydro generation is 533.3
6 aM compared to 563.1 aM in current base rates, a
7 reduction of 29.8 aM.This pro forma removes the
8 additional 26.5 aMW of hydro generation incorporated in
9 last year's general rate case as the "rate mitigation
10 adjustment." The remaining reduction in hydro generation is
11 due to the reduction in Mid Columia purchased hydro
12 generation resulting from the expiration of the Wanapum
13 contract in November 2009.
14 The table below shows the primary factors driving the
15 increase in power supply expense compared to the level in
16 current base rates.
Johnson, Di 5
Avista Corporation
Power Supply Expense Change
July 2009. June 2010 Pro forma vs. 2009 Pro forma
(idaho)
$milions
System Load $11.0 $3.90
Rate Mitigation Removed $12.8 $4.53
Settlement Adjustments Removed $3.1 $1.10
Actual Transactions Mark-to-Model $4.3 $1.52
Coyote Operating Margin -$0.5 -$0.18
Other $2.5 $0.89
Total Pro forma Increase $33.2 $11.8
1
2
3 III. PRO FORM POWER SUPPLY EXPENSE
4 Overview
5 Q.Please identify the specific power supply cost
6 items that are covered by your testimony and the total
7 adjustment being proposed.
8 A.Exhibit No.6, Schedule 1 identifies the power
9 supply expense and revenue items that fall within the scope
10 of my testimony.These revenue and expense items are
11 related to power purchases and sales, fuel expenses,
12 transmission expense, and other miscellaneous power supply
13 expenses and revenues.
14 Q.What is the basis for the adjustments to the test
15 period power supply revenues and expenses?
Johnson, Di 6
Avista Corporation
1 A.The purpose of the adjustments to the test period
2 is to normalize power supply expenses for normal weather
3 and hydroelectric generation and to reflect known and
4 measurable changes for the pro forma period that rates will
5 be in effect.Adjustments are also made to reflect
6 contract changes from the test period to the pro forma
7 period.
8 The AURORA Model dispatches Company resources on an
9 hourly basis and calculates the level of generation from
10 the Company's thermal resources, fuel costs for thermal
11 resources, and the short-term purchases and sales necessary
12 to serve system requirements.
13 Q.Have any changes been made in the calculation of
14 pro form power supply costs from the last general rate
15 case?
16 A.Yes.The primary change made in this general
17 rate case is to include the actual term power and natural
18 gas transactions already entered into for delivery in the
19
20
pro forma period.Term transactions are monthly and
quarterly transactions.This is done to more accurately
21 reflect the actual power supply expense the Company will
22 incur during the pro forma period.
23 As of Novemer 30, 2008 Avista had entered into 33
24 forward electric contracts and 8 forward natural gas
25 contracts for delivery in the pro forma period.The
Johnson, Di 7
Avista Corporation
1 electric contracts include 15 physical purchases and 4
2 physical sales and 14 financial (fixed-for-floating swaps)
3 purchases.The natural gas transactions include 4
4 purchases and 4 sales.
5 The mechanics of including actual transactions in the
6 pro forma is to add the physical electric transactions as
7 resources and obligations in the AURORA model and include a
8 mark-to-model adjustment in the pro forma for the financial
9 electric and natural gas transactions. If the actual
10 transactions lower power supply expense (lower purchase
11 costs or higher sales revenue) as compared to the cost
12 produced by the AURORA model, then the lower cost is
13 included in the pro forma expense.If the actual
14 transactions increase power supply expense (higher purchase
15 costs or lower sales revenue) as compared to the cost
16 produced by the AURORA model, then the higher cost is
17 included in the pro forma expense.
18 The Company's hedging program layers in purchase and
19 sales transactions prior to the delivery period, and some
20 of the actual transactions were entered into during the
21 period of high forward prices during the middle of 2008.
22 Because prices have declined since July 2008, the overall
23 impact of the actual transactions is an increase in the pro
24 forma expense.The table below shows the impact of the
25 actual transactions in the pro forma. Overall, the actual
Johnson, Di 8
Avista Corporation
1 transactions increase pro forma expense by $4,314,400 on a
2 system basis, $1,527,729 Idaho allocation, compared to what
3 expenses would be based solely on the AURORA model output.
4 Avista' s hedging strategy and risk management program are
5 explained in Mr. Storro' s testimony.
Actual Electric and Natural Gas Transactions
Impact on Proforma Power Supply Expense
Term Transactions through 11-30-08
System
Numbers
Idaho
A1loætion
Physical Electric Transactions Mark to Market $43,304 $15,334
Financial Electric Transactions Mark to Market $2,923,297 $1,035,139
Natural Gas Transactions Mark to Market $1,347,800 $477,256
$4,314,400 $1,527,7296Total Proforma Impact of Actual Transactions
7 Detailed workpapers are provided for all the actual
8 transactions included in the pro forma.
9 Q. Are there any other changes in how the pro form in
10 this case was developed?
11 A.No. Other than including actual transactions and
12 the removal of the hydro rate mitigation adjustment, the
13 process to develop the pro forma net power supply expense
14 in this case is the same as in the 2008 general rate case.
15 A brief description of each adjustment is provided in
16 Exhibi t No.6, Schedule 2.Detailed workpapers have been
17 provided to the Commission coincident to this filing to
18 support each of the pro forma revenues and expenses.The
19 detailed workpapers for each adjustment show the actual
Johnson, Di 9
Avista Corporation
1 revenue or expense in the test period, and the pro forma
2 revenue or expense.
3 Long-Term Contracts
4 Q.How are long-term power contracts included in
5 the pro form?
6 A.Long-term power contracts are included in the pro
7 forma by including the energy receipt or obligation
8 associated with the contract in the AURORA model and
9 including the cost or revenue in the pro forma net power
10 supply expense.
11 Q.Are there any new power purchases or sales in the
12 pro forma?
13
14
A.Yes.The Company entered into a two-year
agreement to purchase generation from the Wells
15 hydroelectric plant that is assigned to the Colville Indian
16 Tribe, which I describe in more detail below.Also, the
17 purchase from Thompson River Cogen, a cogeneration plant in
18 Thompson Falls, Montana, that was included in the 2008 rate
19 case, was removed from this case because of the delays in
20 the start-up of the plant.
21 Q.Please describe the purchase of the Col ville
22 Indian Tribe's Well's generation output?
23 A.Avista entered into a two-year agreement
24 beginning October 2008 and ending September 2010 to
25 purchase the Colville Indian Tribe's 4.5% share of the
Johnson, Di 10
Avista Corporation
1 output of the Wells hydroelectric generation. Prior to this
2 agreement, Avista purchased 3.34% of the Well's output at
3 actual production cost from the owner of Wells, Douglas
4 PUD.The additional 4.5% of Wells output assigned to the
5 Colville Indian Tribe was purchased through a competitive
6 auction at the market prices at the time. The purchase of
7 the Colville Indian Tribe's share of Wells output at market
8 prices is the reason for the increase in Well's cost in the
9 pro forma.
10
11
Q. Why is this purchase important to the Company?
A.This purchase was important because of the
12 capacity and ancillary products that come with a Mid
13 Columia generation product.In addition to the energy,
14 Mid Columia generation has dYnamic capacity that the
15 Company uses for frequency regulation and load following.
16 The generation also comes with a "paper pond" that allows
17 the Company to shift generation from low load to high load
18 hours.
19 The amount of generation the Company has at the Mid
20 Columia is being reduced as the existing contracts with
21 Grant PUD expire and the amount of generation at Priest
22 Rapids (November 2005) and Wanapum (Novemer 2009) are
23 reduced by roughly half. The Wells purchase makes up for a
24 good portion of the loss of capacity at Priest Rapids and
Johnson, Di 11
Avista Corporation
1 Wanapum, and allows the Company to maintain regulation
2 functions at the Mid Columia.
3 Short-Term Power Purchases and Sales
4 Q.How are short-term transactions included in the
5 pro form?
6 A.After including the actual short-term
7 transactions explained earlier as resources and obligations
8 in the AURORA model, the balance of the short-term electric
9 power purchases and sales are an output of the AURORA
10 model. The model calculates both the volumes and price of
11 short-term purchases and sales that balance the system's
12 generation and long-term purchases with retail load and
13 long-term obligations.The price of the short-term
14 transactions represents the price of spot market power as
15 determined by the AURORA model.
16 Therml Fuel Expense
17 Q.How are therml fuel expenses determined in the
18 pro form?
19 A.Thermal fuel expenses include Colstrip coal
20 costs, Kettle Falls wood waste costs and natural gas
21 expense for the Company's gas-fired resources including
22 Coyote Springs 2, Rathdrum, Northeast, Boulder Park, and
23 the Kettle Falls combustion turbine.Uni t coal cos ts at
24 Colstrip are based on the long-term coal supply and
25 transportation agreements. Unit wood fuel costs at Kettle
Johnson, Di 12
Avista Corporation
1 Falls are based on multiple shorter-term contracts with
2 fuel suppliers and inventory.Total fuel costs for each
3 plant are based on the unit fuel cost and the plant's level
4 of generation as determined by the AURORA model.Exhibit
5 No.6, Schedule 3 shows the pro forma fuel costs by month
6 for each plant. Mr. Kalich provides details and supporting
7 workpapers regarding the fuel costs for the Company's
8 thermal plants.
9 Transmission Expense
10 Q. What changes in transmission expense are in the
11 pro form compared to the test year or the 2008 rate case?
12
13
A.There is almost no change in transmission
expense.Transmission expense in the pro forma is $4,000
14 (system) higher than the test year actual expense and
15 $169,000 lower than the pro forma in the 2008 rate case.
16 Q.will there be additional transmission expense in
17 the pro form period that has not been included in this
18 case?
19 A.Yes, beginning January 1, 2010 the Company will
20 purchase 250 MW of BPA point-to-point transmission for the
21 Lancaster plant.The cost of this transmission will be
22 approximately $375,250 per month. The Company proposes to
23 track this expense in the PCA at 100 percent until such
24 time that this expense is included in base retail rates.
25
Johnson, Di 13
Avista Corporation
1 iv. PCA CALCULTIONS
2 Proposed Changes to the PCA
3 Q.Is the Company proposing any changes to the PCA
4 methodology?
5
6
A.Yes.The Company is proposing four changes to
the PCA calculations.The first is to change the sharing
7 percentages between Customers and the Company from 90%/10%
8
9
to 95%/5%.The second change is to include third-party
transmission expense (Accounts 565710 & 565000)and
10 transmission revenue (Accounts 456100, 456016 & 456700) in
11 the PCA.The third change is to use the average cost of
12 production/transmission included in base rates as the
13 retail revenue credit instead of the marginal cost of power
14 currently used in the PCA. The fourth change is to include
15 the Production Tax Credit in the PCA.
16 The Company is also proposing to include the expenses
17 and revenues related to the Lancaster plant in the PCA
18 beginning January 1, 2010, until the expense and revenue
19 related to the Lancaster plant are included in base rates.
20 Customer ¡Company Sharing
21 Q. Why is the Company proposing a change in the
22 sharing between customers and the Company in the PCA?
23 A.The primary reason to change the sharing
24 methodology is the increased volatility of power supply
25 costs. The increased volatility is driven primarily by two
Johnson, Di 14
Avista Corporation
1 factors.One is the overall level of prices.Higher
2 prices mean greater absolute variability due to hydro
3
4
generation and load variations.Also important is the
recent price volatility in the energy markets.For
5 example, actual prices varied from $88/MW in April 2008
6 when the Company was purchas ing energy due to low hydro
7 generation from the delayed run-off to $25/MW in June when
8 the hydro run-off materialized and the Company was selling
9 surplus power. This kind of price volatility coupled with
10 hydro variation can cause very large changes in the
11 Company's power supply expense.In April 2008 alone, the
12 Company's power supply expense exceeded the authorized
13 level by over $4.0 million (Idaho Allocation, over $14
14 million on a system basis), leading to a PCA deferral of
15 over $3.5 million, with the Company absorbing over
16 $400,000.
17
18
An additional volatility the Company faces is the
price of natural gas.This is a significant source of
19 volatility with Coyote Springs 2 and will become even more
20 significant with the addition of Lancaster in 2010.A
21 rough rule of thum is that every $l/dth change in natural
22 gas prices changes Avista' s system power supply expense by
23 $10 million without the Lancaster plant.Natural gas
24 prices have varied by over $5/dth during 2008. This
25 variability caused by natural gas price will be even
Johnson, Di 15
Avista Corporation
1 greater when the Company begins receiving power from the
2 Lancaster plant in 2010.
3 Transmission Exense and Revenue
4 Q.Why is the Company proposing to include
5 transmission expense and revenues in the PCA?
6 A.Transmission expense is a significant component
7 of the Company's overall power supply expense. While much
8 of the transmission is purchased under long-term contracts,
9 some is purchased on a short-term basis and is subj ect to
10 variabili ty in the expense level.Including transmission
11 expense in the PCA tracks the variability in this power
12 supply related expense.
13 Including transmission revenue in the PCA is a
14 fairness issue.if customers are absorbing the majority
15 of any increases in transmission expense then it is fair
16 that they receive the majority of increases in transmission
17 revenue. The transmission revenue the Company is proposing
18 to include in the PCA is the sale of Avista transmission to
19 third parties.
20 Including transmission revenues and expenses in the
21 PCA is also consistent with the Company's Retail Revenue
22 Credit proposal.The proposed Retail Revenue Credit
23 includes both the Production and Transmission components of
24 the retail rate.
Johnson, Di 16
Avista Corporation
1 Finally, including transmission expense in the PCA is
2 necessary in order for the Company to include the expenses
3 associated with the Lancaster plant in the PCA. As stated
4 earlier in my testimony, beginning January 1, 2010, Avista
5 will be assigned 250 MW of BPA point-to-point transmission
6 from the Lancaster plant.This transmission is the only
7 means to move the power from the Lancaster plant to
8
9
Avista's system.The annual cost of this transmission is
approxima tely $4.5 million or $375,250 per month.
10 Transmission expense must be included in the PCA in order
11 for the Company to recover all the costs associated with
12 the Lancaster plant. If the PCA is not modified to reflect
13 transmission expense in the PCA, then the Company proposes
14 that only the transmission expense for the Lancaster plant
15 be included in the PCA (at 100% of expense) until the costs
16 are included in base retail rates.
17 Retail Revenue Credit
18 Q.What change is the Company proposing to the
19 Retail Revenue Credit rate?
20 A.The Company proposes that the average cost of
21 production and transmission be used as the retail revenue
22 credit rate in the PCA.Currently, the retail revenue
23 credit rate is the marginal cost of power.The average
24 production and transmission cost represents the power
25 commodity component of retail rates and is the revenue
Johnson, Di 17
Avista Corporation
1 collected from customers to recover power and transmission
2 costs.Using the average cost of production and
3 transmission as the retail revenue credit in the PCA
4 ensures that the actual revenue collected from customers
5 when retail sales increase is credited back against the
6 increased power supply expense and only the difference
7 between the actual cost of power and the amount of revenue
8 collected from customers is included in the PCA.
9 The average production cost also works equally well
10 when actual sales are lower than authorized sales. In that
11 case, actual power supply expense is lower because loads
12 are lower.The retail revenue credit adjusts for the
13 actual revenue the Company did not receive from customers.
14 The benefit of using the average cost of production
15 and transmission versus the marginal cost of power is that
16 the average cost of production works equitably for
17 customers and the Company when sales are both higher and
18 lower than the authorized level.As a note, the average
19 cost of production was used in the PCA for the months of
20 October 2008 through December 2008.Beginning January
21 2009, the retail revenue credit returned to being the
22 marginal cost of power.
23 Inclusion of Production Tax Credit in the PCA
24 Q.Please explain the Production Tax Credit and how
25 the Company proposes to include it in the PCA.
Johnson, Di 18
Avista Corporation
1 A.The Production Tax Credit (PTC) is a Federal
2 income tax credi t the Company receives based on energy
3 production at the Kettle Falls bio-fuel plant and for
4 increased generation from upgrades at Cabinet Gorge dam.
5 The amount of PTe included in this case is a system amount
6 of $2,766,722, which lowers customer's rates. The PTC for
7 ratemaking purposes is grossed up to a revenue level of
8 $4.26 million (system) using the conversion rate of 65%,
9 which is one minus the federal income tax rate. The PTC is
10 set to expire for Kettle Falls on December 31, 2009.
11 Q.Why is it appropriate to include the PTC in the
12 peA?
13 A.The PTC is a credit that is directly tied to the
14 level of generation at Kettle Falls and Cabinet Gorge. The
15 credit is accrued monthly based on the level of generation
16 at Kettle Falls and Cabinet Gorge.It is very similar to
17 other power supply expenses, such as fuel expense, which is
18 directly related to the level of production, and included
19 in the PCA.Because it is directly tied to the level of
20 generation at Kettle Falls and Cabinet Gorge it is an
21 appropriate revenue item to include in the PCA.
22 As noted earlier, the Kettle Falls portion of the PTC
23 is set to expire on December 31, 2009.When the PTC
24 expires at the end of 2009, the PCA will properly account
25 for this change.By including the PTC in the PCA,
Johnson, Di 19
Avista Corporation
1 customers will appropriately receive the full benefits from
2 the PTC through December 2009.If the PTC is not tracked
3 through the PCA, beginning January 2010 Avista would
4 inappropriately continue to flow a tax benefit to customers
5 that does not exist.
6 The Company proposes that Idaho's share of the system
7 PTC amount of $4.26 million be included in the authorized
8 level of power supply expense in the PCA, which would then
9 be compared with the actual PTC credit each month in the
10 actual power supply expense in the PCA.The differences
11 between the actual PTC and the authorized PTC will flow
12 through the PCA in the same manner as other power supply
13 expens es and revenues.
14 Inclusion of Lancaster Exense and Revenue in the PCA
15 Q.How does the eompany propose including the
16 expense and revenue related to the Lancaster plant in the
17 peA
18
19
A.Avista Utilities will begin purchasing the output
of the Lancaster plant January 1, 2010.The Company
20 proposes that the expense and revenues related to the
21 Lancaster plant be included in the PCA until they are
22 reflected in base retail rates.
23 The Lancaster plant has several cost components.
24 Three cost components are part of the Lancaster power
25 purchase agreement and include a fixed capital payment, a
Johnson, Di 20
Avista Corporation
1 fixed O&M payment and a variable O&M payment. All three of
2 these expenses will be recorded in Account 555, Purchased
3 Power Expense, which is an account tracked by the PCA. The
4 capital payment and the fixed O&M payment will be
5 relatively constant month to month, and the variable O&M
6 expense will be dependent on the amount of generation at
7 the plant.
8 Other Lancaster plant costs include natural gas fuel
9 expense and the natural gas pipeline transportation
10 expense, both of which are included in Account 547, Fuel
11 Expense, and the BPA transmission that is recorded in
12 Account 565, Transmission Expense.As explained earlier,
13 the Company is proposing in this filing that Transmission
14 Expense and Transmission Revenue be included in the PCA
15 calculation.
16 The Company is proposing that the fixed expenses
17 related to the Lancaster plant be isolated and tracked in
18 the PCA at 100% of the actual expense. The fixed expenses
19 include the capacity payment (capital payment and fixed O&M
20 payment), the natural gas pipeline transportation payment
21 and the BPA transmission payment. These fixed payments do
22 not vary and would otherwise be 100% included in base
23 rates.
24 The Company proposes that the variable expenses and
25 revenue from the Lancaster plant be included in the PCA in
Johnson, Di 21
Avista Corporation
1 a manner similar to other expenses and revenues that would
2
3
be subject to the Company's proposed 95%/5%
Customer /Company PCA sharing.The variable expenses
4 related to the Lancaster plant include the variable O&M
5 payment, natural gas fuel expense and the net impact of
either reduced electrici ty purchases or increased6
7 electrici ty sales.Tracking the variable expense and
8 revenue in the PCA at the proposed 95%/5% sharing
9 arrangement is similar to how these expenses are tracked
10 for other resources.
11 New Authorized Power Supply and Transmission Exense
12 Q.What is the authorized power supply expense and
13 revenue proposed by the Company for the PCA?
14
15
A.The proposed authorized level of annual system
power supply expense is $192,927,906.This is the sum of
16 Accounts 555 (Purchased Power), 501 (Thermal Fuel), 547
17 (Fuel), less Account 447 (Sale for Resale) . The proposed
18 level of Transmission Expense is $14,168,901. The proposed
19 level of Transmission Revenue is $9,478,694.
20 The level of retail sales MW and the retail revenue
21 credit will also be updated. The proposed authorized level
22 of retail sales to be used in the PCA is the July 2009
23 through June 2010 pro forma retail sales.The proposed
24 retail revenue credit is $47. 85/MW, which is the average
25 cost of production/transmission in this filing.
Johnson, Di 22
Avista Corporation
1 The proposed authorized PCA expense and revenue is
2 shown in Exhibit 6, Schedule 4.
3 Q.Does that conclude your pre-filed direct
4 testimony?
5 A. Yes.
Johnson, Di 23
Avista Corporation
DAVID J. MEYER
VICE PRESIDENT AN CHIEF COUNSEL OF 20nQ JAN 23 PM 12: 42
REGULATORY & GOVERNENTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENUE
SPOKAE, WASHINGTON 99220-3727
TELEPHONE: [phone]
FACSIMILE: [phone]
BEFORE THE IDAHO PUBLie UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION ) CASE NO. AVU-E-09-01
OF AVISTA CORPORATION FOR THE )
AUTHORITY TO INCREASE ITS RATES )
AND CHAGES FOR ELECTRIC AN )
NATURA GAS SERVICE TO ELECTRIC ) EXHIBIT NO. 6
AN NATURAL GAS CUSTOMERS IN THE )STATE OF IDAHO ) WILLIAM G. JOHNSON
)
FOR AVISTA CORPORATION
(ELECTRIC ONLY)
Avlsta Corp.
Power Supply Pro forma. Idaho Jurisdiction
System Numbers. Oct 2007 . Sep 2008 Actual and Jul 09 - Jun 10 Pro forma
Line Oct 07 - Sep 08 Jul 09 - Jun 10
No.Actals Adjustment Proforma
555 PURCHASED POWER
1 Moeled Short-Term Market Purchases $0 $51,202 $51,202
2 Actual ST Market Purchases - Physical 148,407 -117,609 30,798
3 Actual ST Purchases - Financial M-to-M $0 $2,923 2.923
4 Rocky Reach 2.068 89 2,157
5 Wanapum 5,406 -3,369 2,037
6 Wells, Avista and Colvile Share 1,311 11,302 12,613
7 Priest Rapids Project 4.858 2,361 7.219
8 Grant Displacement 5.552 -219 5.333
9 Douglas Settlement 497 122 619
10 WNP-3 12.553 2.248 14,801
11 Deer Lake-IP&l 7 0 7
12 Small Power 1.125 29 1.154
13 Stimson 1,964 138 2.102
14 Spokane-Upriver 1,790 300 2,090
15 Douglas Exchange Capacity 1.648 -1,648 0
16 Seatte Exchange Capacity 1,699 -1,699 0
17 Black Creek Index Purchase 144 11 155
18 Non-Monetary -242 242 0
19 Contrct A 6.808 -19 6,789
20 Contract B 6.764 -19 6,745
21 Contract C 6.675 -17 6,658
22 Contract D 7,576 -20 7.556
23 CS2 Exchange 387 -387 0
24 Northwestern Deviation Energy 1,867 -1.867 0
25 BPA NT Deviation Energy 3.236 -3,236 0
26 Potlatch Co-Gen Purchase 18,439 -18,439 0
27 Spinning Reserve Purchase 1.500 0 1.500
28 Ancilary Services 670 .670 0
29 Stateline Wind Purchase 3,424 -159 3.265
30 Total Accunt 555 246,133 .78,09 167.724
557 OTHER EXPENSES
31 Broker Commission Fees 104 0 104
32 REC Purchases 364 -14 350
33 Bad Debt Reserve 2,728 -2,728 0
34 Natural Gas Fuel Purchases 39.075 -39.075 0
35 Total Accunt 557 42,271 -41.817 454
501 THERMA FUEL EXPENSE
36 Kettle Falls - Wood Fuel 7.227 3.848 11.075
37 Kettle Falls - Start-up Gas 23 0 23
38 Colstrip - Coal 17.688 418 18,106
39 Colstip - Oil 91 111 202
40 Total Account 501 25.029 4,377 29,406
547 OTHER FUEL EXPENSE
41 Coyote Springs Gas 99,105 -30.692 68,413
42 Actual Gas Purchases Financial M-to-M 0 1,348 1,348
43 Gas Transportation Charge 5,961 911 6,872
44 Rathdrum Gas 616 -342 274
45 Northeast CT Gas 277 -216 61
46 Boulder Park Gas 2.127 -2.090 37
47 Kettle Falls CT Gas 312 -236 76
48 Total Account 547 108,398 -31,316 77,082
565 TRANSMISSION OF ELECTRICITY BY OTHERS
49 WNP-3 789 0 789
50 Sand Dunes-Warden 20 0 20
51 Black Creek Wheeling 18 2 20
52 Wheeling for System Sales & Purchases 845 0 845
53 PTP for Colstrip & Coyote 8,427 3 8,430
54 BPA Townsend-Garrson Wheeling 1.173 0 1,173
55 Avista on BPA - Borderline 1,483 -5 1,478
56 Kootenai for Worley 39 6 45
57 Sagle-Northern Lights 136 -2 134 Exhibit No.6
58 Garrison-Burke 592 0 592 Case No. AVU-E-09-01
W. Johnson, Avista
Schedule 1, p. 1 of 2
Avista Corp.
Power Supply Pro forma - Idaho Jurisdiction
System Numbers. Oct 2007 . Sep 2008 Actual and Jul 09 - Jun 10 Pro forma
Line Oct 07 - Sep 08 Jul 09 - Jun 10
No.Actuals Adjustment Proforma
59 PGE Firm Wheeling 643 0 643
60 Total Account 565 14.165 4 14,169
536 WATER FOR POWER
61 Headwater Benefits Payments 654 655
549 MISC OTHER GENERATION EXPENSE
62 Rathdrum Municipal Payment 175 -15 160
63 lTOTAL EXPENSE 436.825 -147.175 289.6501
447 SALES FOR RESALE
64 Modeled Short-Term Market Sales 0 53,641 53.641
65 Actual ST Market Sales - Physical 132.119 -119.617 12.502
66 Peaker (PGE) Capacity Sale 1,800 0 1,800
67 Nichols Pumping Sale 3,44 402 3,842
68 Sovereign/Kaiser DES 816 .755 61
69 Pend Oreile DES & Spinning 555 -165 390
70 Northwestern Load Following 5,225 -1.968 3,257
71 SMUDSale 49,173 -43,331 5,842
72 Ancilary Services 670 -670 0
73 Spokane Energy Service Fee - Peaker Sale -52 0 -52
74 BPA NT Deviation Energy 2.073 -2.073 0
75 Total Account 447 195,819 -114.536 81,283
456 OTHER ELECTRIC REVENUE
76 Renewable Energy Credit Sales 13 -13 0
77 Gas Not Consumed Sales Revenue 41,799 -41.799 0
78 Total Account 456 41,812 -41,812 0
453 SALES OF WATER AND WATER POWER
79 Upstram Storage Revenue 303 -1 302
454 MISC RENTS
80 Colstrip Rents 57 -33 24
81 \TOTAL REVENUE 237.991 -156,382 81,6091
82 ITOTAL NET EXPENSE 198.834 9.206 208.0401
83 Potlatch Purchase Assigned to Idaho 18,439
84 Total Adjustment Including Potlatch 27,645
Exhibit No.6
Case No. AVU-E-Q9-01
W. Johnson, Avista
Schedule 1, p. 2 of 2
1 A vista Corp.
2 Brief Description of Power Supply Adjustments
3
4 Line No.
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
1 Short-term Market Purchases - Short-ter purchases from the AURORA
Dispatch Simulation ModeL.
2 Actual ST Market Purchases Physical - Expense of the actual term
transactions entered into for the pro forma period as of 11-30-08.
3 Actual ST Purchases - Financial M-to-M - Mark to model price expense of
actual financial (fixed for floating swaps) electrcity purchases entered into for
the pro forma period as of 11-30-08.
4 Rocky Reach - The proforma cost for Rocky Reach is based on Chelan
PUD's budgeted expenses. Avista's costs are based on the Company's 2.9%
share of total cost.
5 Wanapum - Proforma costs are based on Grant County PUD's Power Cost
Forecast for Wanapum. Avista's costs are based on the Company's 8.2% share
of total Wanapum costs for July 2009 through October 2009. The Wanapum
contract expires October 31, 2009. Beginning November 2009 Wanapum
becomes par of the Priest Rapids Project and Wanapum costs are included in
the Priest Rapids Project costs for November 2009 though June 2010.
6 Wells - Wells' costs are based on the Company's 3.34% share of total cost at
project costs plus 4.5% of Well's output purchased from the Colvile Indian
Tribe at a competitive auction rate.
7 Priest Rapids Project - Priest Rapids Project expense includes the expense
related to the purchased power from the Priest Rapids development for the
entire pro forma year and power from the Wanapum development for the
months of November 2009 through June 2010.
8 Grant Displacement - Grant Displacement is scheduled energy from Grant
PUD that is priced at Grant's cost.
9 Douglas Settlement - Douglas Settlement is for power A vista purchases from
Douglas PUD per the 1989 Settlement Agreement.
Exhibit NO.6
Case No. AVU-E-09-01
W. Johnson, Avista
Schedule 2, p. 1 of 8
1
2 10 WNP-3 - Pro forma costs are based on the amount of energy and the lesser of
3 the actual rate or the midpoint. The pro forma uses the actual rate for contract
4 year 2008 though 2009 escalated at the 5-year average escalation rate to the
5 pro forma period.
6
7 11 Deer Lake-IP&L - Proforma expense is for power purchased from Inland
8 Power to sere Avista customers.
9
10 12 Small Power - Proforma costs are based on an expected generation and
11 proforma perod contract rates. (Contract details are provided in a
12 CONFIDENTIA workpaper).
13
14 13 Stimson - Ths purchase is from the cogeneration pi ant at Plumer, Idaho.
15 Pro forma costs are based on expected generation and proforma period16 contract rates.
17
18 14 Spokane-Upriver - Proforma expense is based on a purchase on the net of
19 pumping (at the plant) generation at a rate equal to the 8 year levelized avoided
20 cost included in the Company's 2003 Integrated Resource Plan.
21
22 15 Douglas Exchange Capacity - Proforma is $0 because A vista bids anually23 for ths capacity.
24
25 16 Seattle Exchange Capacity - Proforma is $0 because contract terinates
26 March 31, 2009.
27
28 17 Black Creek Index Purchase - Expense is for an October purchase at index
29 prices less transmission expense and a margin.
30
31 18 Non-Monetary - Expense is normalized to $0 in the proforma.
32
33 19 Contract A - Ths is a power purchase for the period Januar 2007 though
34 December 2010 (Contract details are provided in a CONFIDENTIA workpaper).
35
36 20 Contract B - This is a power purchase for the period Januar 2007 though
37 December 2010 (Contract details are provided in a CONFIDENTIA workpaper).
38
39 21 Contract C - This is a power purchase for the period Januar 2007 though
40 December 2010 (Contract details are provided in a CONFIDENTIA workpaper).
41
Exhibit NO.6
Case No. AVU-E-09-01
W. Johnson, Avista
Schedule 2, p. 2 of 8
1 22 Contract D - This is a power purchase for the period Januar 2007 though
2 December 2010 (Contract details are provided in a CONFIDENTIA workpaper).
3
4 23 CS2 Exchange - Proforma is $0 because contract terminated Dec. 31, 2007.
5
6 24 NorthWestern Load Following Deviation Energy - Proforma expense is $0
7 because deviation energy is priced at market and is not included In AURORA8 modeL.
9
10 25 BPA NT Deviation Energy - Proforma expense is $0 because deviation
11 energy is priced at market and is not included In AURORA modeL.
12
13 26 Potlatch Co-Gen Purchase - Pro forma expense is $0 because Potlatch
14 purchase expense is directly assigned to the Idaho jurisdiction and is not
15 included in system power supply expense.
16
17 27 Spining Reserve Purchase- Pro forma expense is for a purchase of spinning
18 reseres durng the months of May and June that. matches the test year
19 purchase expense.
20
21 28 Ancilary Services - Proforma expense is $0 because this is an intra-utilty
22 expense (matching revenue in Account 447).
23
24 29 Statelie Wind Purchase - Proforma expense is for a 10-year purchase from a
25 Nortwest wind project. Expense is based on expected energy amount times
26 the contract rate. (Contract details are provided in a CONFIDENTIA
27 workpaper).
28
29 30 Total Account 555
30
31 31 Broker Conission Fees - Proforma expense is associated with purchases
32 and sales of electrcity and natual gas fueL.
33
34 32 REC Purchases - Expense is for the purchase of Californa cerifiable
35 renewable Energy Credits to support the SMU Sale.
36
37 33 Bad Debt Reserve - Expense was for power the Company delivered but no
38 revenue was received (Lehman banptcy). Pro forma expene is $0.
39
Exhibit NO.6
Case No. AVU-E-09-01
W. Johnson, Avista
Schedule 2, p. 3 of 8
1 34 Natural Gas Fuel Purchases - This is the expense for natual gas purchased
2 for but not consumed for generation. Proforma expense is $0 because all gas
3 purchased is assumed to be used for generation, and included in Account 547.
4
5 35 Total Account 557
6
7 36 Kettle Falls Wood Fuel Cost - Proforma fuel expense is based on the
8 generation of the Kettle Falls plant in the AURORA Model and the projected
9 unit cost of fueL.
10
11 37 Kettle Falls-Start-up Gas - Pro forma expense is for star-up gas at Kettle
12 Falls and is based on the test-year expense.
13
14 38 Colstrip Coal Cost - Proforma fuel expense is based on the generation of the
15 Colstrp plant in the AURORA Model and the projected unit cost of fueL.
16
17 39 Colstrip Oil - Pro forma expense is for star-up oil expense. Pro forma is
18 based on a five year average.
19
20 40 Total Account 501
21
22 41 Coyote Springs Gas - Proforma expense is an output of the AURORA Model
23 based on the projected unt cost of fuel and the dispatch of the plant, which
24 determnes the volume of fuel consumed.
25
26 42 Actual Gas Purchases Financial M-to-M - Mark to model price expense of
27 actual natural ga purchases entered into for the pro forma period as of 11-30-28 08.
29
30 43 Gas Transportation Charge - This expense is for transportation of natual
31 gas from ABCO to the Coyote Springs 2 plant. Proforma expense is based on
32 transportation charges in Canada and from the Canadian Border (Kngs gate )
33 and for the Coyote Springs lateraL.
34
35 44 Rathdrum Gas - Proforma expense is an output of the AURORA Model
36 based on the projected unt cost of fuel and the dispatch of the plant, which
37 determines the volume of fuel consumed.
38
39 45 Northeast CT Gas - Proforma expense is an output of the AURORA Model
40 based on the projected unt cost of fuel and the dispatch of the plant (including
41 test firing), which determes the volume of fuel consumed.
Exhibit No.6
Case No. AVU-E-09-01
W. Johnson, Avista
Schedule 2, p. 4 of 8
1
2 46 Boulder Park Gas - Proforma expense is an output of the AURORA Model
3 based on the projected unit cost of fuel and the dispatch of the plant, which
4 determines the volume of fuel consumed.
5
6 47 Kettle Falls CT Gas - Proforma expense is an output of the AURORA Model
7 based on the projected unt cost of fuel and the dispatch of the plant, which
8 determines the volume of fuel consumed.
9
10 48 Total Account 547
11
12 49 WNP-3 Transmission - Proforma WN-3 wheeling is based on 32.22 MW at
13 a rate of$2.04/kW/mo.
14
15 50 Sand Dunes-Warden - Pro forma expense is for a transmission expense with
16 Grant PUD.
17
18 51 Black Creek Wheelig - Expense is for wheeling and shaping associated
19 with the Black Creek power purchase.
20
21 52 Wheeling for System Sales and Purchases - Proforma expense is short-ter
22 transmission purchases.
23
24 53 PTP for Colstrip and Coyotes Springs 2- This wheeling is for the
25 transmission of 196 MW from Colstrp at the Garson substation and 272
26 MW from the Coyote Springs 2 plant to Avista's system. Proforma expense is
27 based on 468 MW of capacity at a rate of $1.501/kW /mo.
28
29 54 BP A Townsend-Garrison Wheelig - Ths expense is for the transmission of
30 Colstrp power from the Townsend substation to the Garson substation.
31
32 55 Avista on BPA Borderline - Ths expense is to sere Avista load off ofBPA
33 transmission. Proforma expense is based on Avista's borderline loads priced
34 at BP A's NT transmission rates plus ancilar services cost and use of facilities35 charges.
36
37 56 Kootenai for Worley - Ths expense is for A vista load served using Kootenai38 PUD's facilities.
39
40 57 Sagle-Northern Lights - Expense is for transmission purchased from
41 Nortern Light Utility to sere A vista customers in northern Idaho.
Exhibit NO.6
Case No. AVU-E-09-01
W. Johnson, Avista
Schedule 2, p. 5 of 8
1
2 58 Garrison Burke - Garson Burke wheeling is an expense for the transmission
3 of Colstrp energy above 196 MW from the Garson substation over
4 . Nortwestern Energy's transmission system to the interconnection of
5 Nortwestern Energy and A vista.
6
7 59 PGE Firm Wheeling - PGE Firm wheeling reflects the cost of transmission
8 from the John Day substation to COB (Interte South) purchased from Portland
9 General Electrc. The Proforma expense is based on 100 MW at the curent
10 rate of$.53549/kW/mo.
11
12 60 Total Account 565
13
14 61 Headwater Benefits Expense - Proforma expense is based on the expense for
15 contract year September 2008 though August 2009
16
17 62 Rathdrum Municipal Payment - This includes a payment in Jan. 2010 of
18 $160,000 to the city of Rathdru for mitigation related to the Rathdr
19 generating facility.
20
21 63 Total Expenses - Sum of Accounts 555, 557, 501, 547, 565, 536, and 549.
22
23 64 Modeled Short-Term Market Sales - Short-term market sales from the
24 AURORA Model simulation.
25
26 65 Actual ST Market Sales-Physical - Revenue from the actual term
27 transactions entered into for the pro forma perod as of 11-30-08
28
29 66 Peaker (pGE) Capacity Sale - Ths proforma revenue is based on 150 MW
30 of capacity at a price of $1 /k W Imo.
31
32 67 Nichols Pumping Sale - Ths is a sale of energy to other Colstrp Units 3 and
33 4 owners at the Mid Columbia index price. Proforma revenue is based on
34 approximately 8 MW at the market price as determined by the AURORA35 modeL.
36
37 68 Sovereigniser DES - Ths contract provides load control serices to
38 Kaiser's Trentwood plant. (Contract details are provided in a
39 CONFIDENTIA workpaper).
40
Exhibit NO.6
Case No. AVU-E-09-01
W. Johnson, Avista
Schedule 2, p. 6 of 8
1 69 Pend Oreile DES & Spinning Reserves - Ths contract provides load
2 control and spinnng reseres for Pend Oreile PUD. (Contract details are
3 provided in a CONFIDENIA workpaper).
4
5 70 Northwestern Load Followig - Ths contract provides load following
6 capacity to Nortwester Energy. (Contract details are provided in a
7 CONFIDENTIA workpaper).
8
9 71 SMU Sale - Proforma revenue is the expected margi (margin only, not
10 including index priced energy) from the sale of energy and associated
11 renewable energy credits.
12
13 72 Ancilary Servces - Proforma revenue is $0 because it is intra-utility revenue
14 (matching expense in Account 555).
15
16 73 Spokane Energy Servce Fee - Peaker Sale - Expense is for the scheduling of
17 the Peaker (portland General) capacity sales.
18
19 74 BPA NT Deviation Energy - Proforma revenue is $0 because deviation
20 energy is priced at index and is not included in the AURORA modeL.
21
22 75 Total Account 447
23
24 76 Renewable energy Credit Sales - Proforma revenue is $0 because test year
25 revenue was for non-reoccmrng renewable energy credit sales.
26
27 77 Gas Not Consumed Sales Revenue - Ths is the revenue for natual gas
28 purchased for but not consumed for generation. Proforma expense is $0
29 because all gas purchased is assumed to be used for generation, and included30 in Account 547.
31
32 78 Total Account 456
33
34 79 Upstream Storage Revenue - Proforma revenue is based on the revenue for
35 contract year September 2008 though August 2009.
36
37 80 Colstrip Rents - Proforma revenue is based on expected revenue.
38
39 81 Total Revenue - Sum of Accounts 447, 456, 453 and 454.
40
41 82 Total Net Expense - Total expense minus total revenue.
42
Exhibit NO.6
Case No. AVU-E-09-01
W. Johnson, Avista
Schedule 2, p. 7 of 8
1 83 Potlatch Purchase Assigned to Idaho - This line shows the Potlatch
2 purchase adjustment. The Potlatch expense is directly assigned to Idaho and is
3 not included in the pro forma system power supply expense. The Potlatch
4 purchase expense is included in the adjustment in line 83 to show the total
5 adjustment from test year actual expense (includes Potlatch) to the proforma.
6
7 84 Total Adjustment Including Potlatch - This is the total adjustment in power
8 supply expense factoring in the Potlatch purchase expense directly assigned to9 Idaho.
10
Exhibit NO.6
Case No. AVU-E-09-01
W. Johnson, Avista
Schedule 2, p. 8 of 8
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