HomeMy WebLinkAbout20130201Dickman Direct.pdfBEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE )
APPLICATION OF ROCKY ) CASE NO. PAC-E-13-03
MOUNTAIN POWER FOR )
AUTHORITY TO INCREASE RATES ) Direct Testimony of Brian S. Dickman
BY $2.2 MILLION TO RECOVER )
DEFERRED NET POWER COSTS )
THROUGH THE ENERGY COST )
ADJUSTMENT MECHANISM )
ROCKY MOUNTAIN POWER
CASE NO. PAC-E-13-03
February 2013
I Q. Please state your name, business address and present position with
2 PacifiCorp, dba Rocky Mountain Power (the "Company").
3 A. My name is Brian S. Dickman. My business address is 825 NE Multnomah St.,
4 Suite 600, Portland, Oregon, 97232. My title is Manager, Net Power Costs.
5 Qualifications
6 Q. Briefly describe your education and business experience.
7 A. I received a Master of Business Administration from the University of Utah with
8 an emphasis in finance and a Bachelor of Science degree in accounting from Utah
9 State University. Prior to joining the Company, I was employed as an analyst for
10 Duke Energy Trading and Marketing. I have been employed by the Company
11 since 2003 including positions in revenue requirement and regulatory affairs, and
12 I assumed my current role managing the Company's net power cost group in
13 March 2012.
14 Q. Have you testified in previous regulatory proceedings?
15 A. Yes. I have filed testimony in proceedings before the Idaho Public Utilities
16 Commission, the Wyoming Public Service Commission, and the Utah Public
17 Service Commission.
18 Summary of Testimony
19 Q. What is the purpose of your testimony in this proceeding?
20 A. My testimony presents the Company's calculation of the Energy Cost Adjustment
21 Mechanism ("ECAM") balancing account for the 12-month period from
22 December 1, 2011 through November 30, 2012 ("Deferral Period"). More
23 specifically, my testimony provides the following:
Dickman, Di - 1
Rocky Mountain Power
1 • A summary of the ECAM calculation, including changes made to comply
2 with the Commission order in the Company's previous ECAM filing
3 (Case No. PAC-E-12-03).
4 • Details supporting the addition of $15.9 million to the deferral balance
5 ("2012 Deferral"), bringing the total balance of the account to $25.5
6 million as of November 30, 2012.
7 • Background on the Company's ECAM and a description of the
8 Company's net power costs ("NPC").
9 Q. Are additional witnesses presenting testimony in this case?
10 A. Yes. Ms. Joe ile R. Steward, Director, Pricing, Cost of Service & Regulatory
11 Operations, is sponsoring testimony supporting the Company's proposed ECAM
12 collection rates in Schedule 94. The Company anticipates that effective April 1,
13 2013, Schedule 94 will collect approximately $15.2 million on an annual basis as
14 compared to the current collection rate of approximately $13.0 million.
15 Summary of the ECAM Deferral Calculation
16 Q. Please briefly describe the Company's ECAM authorized by the
17 Commission.
18 A. In general, the ECAM tracks deviations between actual NPC and the NPC in base
19 rates and defers 90 percent of the difference for later recovery.' Other items, such
20 as sales of sulfur dioxide ("SO 2") emission allowances or renewable energy
21 credits ("RECs"), may also be accounted for in the ECAM as a mechanism to true
1 Order No. 30904 in Case No. PAC-E-08-08 approved the stipulation entered into by the Commission
Staff, the Idaho Irrigation Pumpers Association, Monsanto and the Company that set up the structure and
content of the ECAM mechanism.
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Rocky Mountain Power
I up to actual experience. The deferred balance that accumulates over a one-year
2 period is then passed on to customers as a rate surcharge or credit. The ECAM
3 Schedule 94 rate, which appears as a separate line item on customer bills, collects
4 or credits to customers the balance of deferred costs at the end of a deferral
5 period. Schedule 94 is adjusted as needed in the Company's annual ECAM
6 filings. The annual deferral period for the ECAM is December 1 to November 30.
7 The Company is required to file an application with the Commission by February
8 1 of each year to seek approval of the deferral amount and to adjust the ECAM
9 rate effective April 1.
10 Q. How are the 2012 ECAM deferral calculations presented in your testimony?
11 A. The 2012 ECAM deferral calculations are contained in Exhibit No. 1. A summary
12 of the major components is contained in Table 1 below. Later in my testimony I
13 discuss the details of the ECAM deferral calculations contained in Exhibit No. 1.
14 Q. What changes to the ECAM calculation have been implemented to comply
15 with Commission Order 32597 from Case No. PAC-E-12-03?
16 A. The Company has reflected the changes to the ECAM calculation approved by the
17 Commission in the Company's 2012 ECAM filing, including:
18 • Replacement energy consumed by special contract customers during periods
19 where they buy through curtailment events is removed from the jurisdictional
20 load and the cost of the replacement energy is removed from NPC.
21 Replacement energy during curtailment events is passed-through directly to
22 these customers at a market price and should not have an impact on the
23 ECAM deferral calculation.
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Rocky Mountain Power
I • To calculate the load change adjustment rate ("LCAR") Monsanto's actual
2 load is adjusted to be on the same basis as the load used to set NPC in base
3 rates, i.e. the full load is reflected as if no curtailment events occurred. This
4 treatment ensures Monsanto is not penalized in the LCAR for reduced energy
5 use during curtailment events initiated by the Company.
6 • Transmission line losses are applied to Monsanto and Agrium metered load
7 when grossing up the metered load to the load at input. The loss adjustment
8 recognizes the impact of moving power through Idaho for wholesale
9 transactions.
10 • The intra-hour component of the non-owned wind integration cost is excluded
11 from the deferral balance, at a rate of $2.98 per MWh.
12 Incremental 2012 Deferral
13 Q. Please describe the ECAM components that make up the 2012 Deferral.
14 A. The 2012 Deferral is the sum of customers' 90 percent share of the following
15 items: the difference between the actual and in-rates NPC, the LCAR, the SO2
16 allowance sales adjustment, and the Emerging Issues Task Force ("EITF") 04-6
17 adjustment. An additional true-up of 100 percent of the revenue difference from
18 the sale of RECs is included. Detailed calculations are provided in Exhibit No. 1
19 attached to my testimony, and Table 1 below summarizes the various components
20 making up the deferral.
Dickman, Di -4
Rocky Mountain Power
Agrium
557,414
(22,411)
(40)
(2,230)
532,734
90%
479,460
(15,980)
Total
18,358,774
(713,607)
(1,764)
(30,019)
17,613,384
90%
15,852,046
17,197
Table 1
Summary of ECAM Deferral Account Balance
Customers Monsanto
10,481,031 7,320,329
(601,098) (90,098)
(1,212) (512)
(11,520) (16,269)
9,867,201 7,213,450
90% 90%
8,880,481 6,492,105
176,961 (143,783)
16,352,216 6,812,973 471,163 23,636,352
(12,780,472) (1,407,870) (96,019) (14,284,361)
153,150 100,182 7,023 260,355
3,724,894 5,505,285 382,167 9,612,346
12,782,335 11,853,607 845,648 25,481,589
(2,886,335) (795,088) (63,425) (3,744,847)
9,896,000 11,058,519 782,223 21,736,742
NPC Differential for Deferral
LCAR
S02
'EIIF 04-6 Adjustment
Customer Reponsibility
REC Deferral
Total Company Recovery for NPC Deferral -
Balancing Account Activity
Prior Deferral
ECAM Revenue Collection
Interest
Activity Through November 30, 2012
November 30, 2012 Balance For Collection
Schedule 94 Collection -Dec 2012 - March 2013 -
Expected Balance as of April 1, 2013
Schedule 94 Col lection-April 2013-March 2014 -
Expected Balance as of April 1, 2014 (Excluding
Incremental 2013 Deferral)
Monsanto/Agrium Amortization
2012 ECAM Balance (2011 Deferral) -3 YrAmortization
2013 ECAM Balance (2012 Deferral) -3 YrAmortization
2014 ECAM Balance (2013 Deferral) -2 YrAmor -tization
(554,734) 6,587,313 468,358 6,500,937 I
2,355,099 159,371 2,514,470
2,116,107 154,493 2,270,601
1 Q. Please explain the calculation of the ECAM balance for the Deferral Period.
2 A. Table 1 above summarizes the components of the ECAM balance, broken into
3 three customer groups. The $15.9 million is almost entirely made up of the
4 customers' share of the NPC differential, offset by adjustments for the LCAR,
5 SO2 allowance sales, and EITF 04-6. A reduction in actual REC revenue
6 compared to the base caused an increase to the deferral of $17,197.
7 The first section of Table 1 summarizes the Idaho-allocated share of those
8 items for which Idaho customers and the Company share responsibility: NPC
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Rocky Mountain Power
I differential, LCAR, SO 2 sales, and EITF 04-6 adjustment. The next section
2 calculates the 90 percent customer share of the above items and adds in the Idaho-
3 allocated REC revenue true-up, for which customers are refunded or surcharged
4 100 percent of the difference. The total of these items constitutes the 2012
5 Deferral.
6 The next section, Balancing Account Activity, starts with the $23.6
7 million balance approved in Order 32597 in the ECAM deferral account. That
8 balance is adjusted for collections and interest accrued during the Deferral Period.
9 When the 2012 Deferral is added the total outstanding balance as of November
10 30, 2012, is $25.5 million. The final rows in Table 1 illustrate the expected
11 Schedule 94 collections between December 1, 2012, and March 31, 2013, and
12 then over the next collection period from April 1, 2013, to March 31, 2014.
13 Finally, the table shows the annual amount that would need to be collected from
14 Monsanto and Agrium according to the multi-year amortization schedules agreed
15 to in the settlement agreement approved by the Commission in Case No. PAC-E-
16 11-12 ("2011 Rate Case").
17 Q. Based on your calculations, what is the balance expected to be in the ECAM
18 deferral account as of April 1,2013?
19 A. As of April 1, 2013, there will be an estimated balance of $21.7 million due for
20 collection. Monsanto is responsible for $11.1 million, Agrium is responsible for
21 $0.8 million, and the remaining $9.9 million will be due from other retail
22 customers.
Dickman, Di - 6
Rocky Mountain Power
I Q. What is the proposed collection amount due from customers under Schedule
2 94 beginning April 1, 2013?
3 A. As discussed by Company witness Ms. Steward, the Company proposes to collect
4 $10.5 million from retail tariff customers beginning April 1, 2013. This will
5 require no change to the ECAM surcharge rate for these customers. The surcharge
6 rate for Monsanto and Agrium will be set at approximately $4.8 million,
7 combined, to reflect the three year amortization outlined in the stipulation
8 between the parties and approved by the Commission in the 2011 Rate Case.
9 Q. The stipulation in the 2011 Rate Case stated the Company would track in the
10 ECAM Idaho's share of the customer load control service credit for the
11 irrigation load control program. Have you included an adjustment to true up
12 these expenses?
13 A. No. The tracking was intended as a mechanism to deal with uncertainty
14 surrounding the jurisdictional treatment of the dispatchable irrigation load control
15 program that was under review by the Multi-State Process Standing Committee
16 during the 2011 Rate Case. While the other states served by the Company have
17 not accepted a system allocation of these costs, the Company has not made a
18 determination that a true up of these expenses in Idaho is warranted at this time.
19 Q. Has the Company worked with parties to the stipulation in the 2011 Rate
20 Case as it related to hedging limits?
21 A. Yes. The Company met with parties on June 4, 2012 to discuss the Company's
22 hedging policies and procedures. As a result, the Company committed to provide
23 a semi-annual report on the Company's hedging activity.
Dickman, Di - 7
Rocky Mountain Power
I Summary of the NPC Differences
2 Q. Please explain the difference between adjusted actual NPC ("Actual NPC")
3 and the NPC in base rates ("Base NPC").
4 A. On a total Company basis, Actual NPC for the Deferral Period were
5 approximately $1.501 billion. During the Deferral Period, the Base NPC in rates
6 originated from two rate cases: Case No. PAC-E-10-07 ("2010 Rate Case") for
7 December 1, 2011 through January 9, 2012 and the 2011 Rate Case for January
8 10, 2012 through November 30, 2012. In the 2010 Rate Case and the 2011 Rate
9 Case the Base NPC were set at $1.025 billion and $1.205 billion, respectively.
10 The combined Base NPC for the Deferral Period are $1.176 billion.
11 Q. Did the Company anticipate that the actual NPC would be higher than the
12 NPC included in rates during the Deferral Period?
13 A. Yes. Company witness Mr. J. Ted Weston's testimony, filed on November 2,
14 2011, in support of the stipulation in the 2011 Rate Case, indicated that the
15 Company expected actual NPC for 2012 in excess of $1.5 billion. This projection
16 is very similar to the Actual NPC for the Deferral Period at $1.501 billion.
17 Mr. Weston's testimony also explained that the Company's original filing
18 in the 2011 Rate Case included NPC of $1.311 billion. At that time the Company
19 expected 2011 actual NPC to be closer to $1.35 billion.2 Base NPC of $1.205
20 billion from the 2011 Rate Case went into effect January 10, 2012 and were in
21 effect during 2012 even though the Company anticipated NPC to be in excess of
22 $1.5 billion that year.
2 Ultimately, the Company's 2011 actual NPC were $1.39 billion
Dickman, Di - 8
Rocky Mountain Power
I Q. What are the major drivers that result in a difference between Actual NPC
2 and Base NPC?
3 A. The approximate $325 million difference between the combined Base NPC and
4 Actual NPC in the Deferral Period is summarized in Table 2 by major category in
5 the NPC report.
Table 2
lJeierrai Period INI'C Reconciliation ( millions
Base NPC $ 1,176
Increase/(Decrease) to NPC:
Wholesale Sales Revenue 392
Purchased Power Expense (187)
Coal Fuel Expense 23
Natural Gas Expense 6
Wheeling, Hydro and Other Expenses (3)
Total Increase/(Decrease) $ 231
Settlement Adjustment 95
AdjustedActual NPC $ 1,501
6 The comparison of Base NPC to Actual NPC is hampered by the disparity in
7 timing between the test periods used to determine Base NPC in general rate cases
8 and the period over which those rates are in effect As described earlier, Base
9 NPC relies partially on rates set in the 2010 Rate Case as well as the 2011 Rate
10 Case. The historical nature of the test periods used in those cases causes the Base
11 NPC to be out of date during the Deferral Period For example, for the month of
12 December the actual NPC in December 2011 are compared to Base NPC for
13 December 2010. Test period timing causes large changes in NPC categories such
14 as wholesale sales revenue and purchase power expense because the underlying
Dickman, Di - 9
Rocky Mountain Power
I assumptions in Base NPC do not accurately reflect conditions during the Deferral
2 Period.
3 An apples-to-apples comparison is also difficult due to the "black box"
4 settlement adjustment used to reduce Base NPC in the 2011 Rate Case.
5 Removing the "black box" settlement adjustment from Base NPC accounts for 29
6 percent of the difference between Actual NPC and Base NPC during the Deferral
7 Period. Mr. Weston's stipulation testimony described that increasing NPC was a
8 significant driver of the overall rate increase sought in the 2011 Rate Case. He
9 explained that the stipulation in that case spread the known increase in NPC over
10 a period of two years in order to mitigate the rate impact of the rate case.' He
11 stated, "Ultimately, 90 percent of the difference between actual net power costs
12 and in-rates net power costs will be deferred and collected in the ECAM,
13 customers get the benefit of the delay in paying the higher level until the costs
14 become "actual" and also benefit from 10 percent of the incremental difference
15 not being included in the ECAM deferral."
16 Q. Did parties to the stipulation understand the impact the settlement would
17 have on the ECAM?
18 A. Yes. As noted by Mr. Weston the parties supported this approach knowing they
19 would benefit from the delay in paying the higher level of net power costs.
20 Q. Not withstanding the issues you describe above, can you explain some of the
21 differences in NPC categories?
22 A. Yes. Much of the variance in NPC is due to lower actual wholesale market prices
Case No. PAC-E-1 1-12, Testimony of J. Ted Weston at 7-8.
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Rocky Mountain Power
I for electricity and natural gas compared to the price forecasts used in Base NPC.
2 On average, wholesale electricity prices were approximately 23 percent lower,
3 and natural gas prices were lower by approximately 38 percent.
4 Q. How does the change in market prices impact NPC?
5 A. The lower market prices for electricity result in lower wholesale sales revenue,
6 which increases NPC as shown in Table 2. Actual wholesale sales revenue was
7 $392 million lower than the level included in Base NPC, and wholesale sales
8 volumes were 4,308 GWh (29 percent) lower. The impact of reduced wholesale
9 sales revenue was partially offset by lower purchased power expenses. In
10 addition, several large contracts that were included in Base NPC expired prior to
11 the Deferral Period, including: the BPA peaking contract, contracts for output of
12 Mid-Columbia hydro facilities, and several qualifying facility purchases from
13 large industrial customers.
14 Q. Did changes in load also impact NPC?
15 A. Yes. Actual system load during the deferral period was 1,574 GWh (2.7 percent)
16 higher than the load in Base NPC. Higher load, combined with the reduced
17 purchased power volume, also contributed to the reduction in wholesale sales
18 volume.
19 Q. Please explain the change in natural gas and coal fuel expense.
20 A. Actual natural gas fuel expense was $6 million higher than the level included in
21 Base NPC due to increased generation volume. The drop in market prices for
22 natural gas led to an increase in gas generation of 1,341 GWh (22 percent).
23 However, the effect of lower prices was offset by increased generation volume,
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Rocky Mountain Power
I resulting in higher overall natural gas fuel expenses. Coal fuel expense increased
2 approximately $23 million, or 3.1 percent, compared to the level in Base NPC,
3 and actual coal generation was approximately 120 GWh (0.3 percent) higher.
4 Description of the ECAM Calculations
5 Q. Please describe the ECAM calculations in Exhibit No. 1.
6 A. The ECAM deferral is calculated by comparing the Actual NPC to the Base NPC
7 on a monthly basis and deferring the differences into an ECAM balancing
8 account. The deferral amount is the difference in the system dollar per megawatt-
9 hour rate multiplied by the Idaho retail load. Exhibit No. 1 details the ECAM
10 calculation and contains supporting information, portions of which are
11 confidential.
12 Q. How are the Base NPC and Actual NIPC dollar per megawatt-hour rates
13 calculated?
14 A. The monthly NPC dollar amounts for Base NPC in the Deferral Period are
15 divided by the corresponding monthly normalized load to express the costs on a
16 dollar per megawatt-hour basis (Exhibit No. 1, line 1). The Actual NPC rate on a
17 dollar per megawatt-hour basis is calculated by dividing the monthly Actual NPC
18 dollar amount by the actual monthly system load (Exhibit No. 1, line 8). On a
19 dollar per megawatt-hour basis, the Base NPC average is $20.31 per megawatt-
20 hour, and the Actual NPC averages to $25.24 per megawatt-hour, $4.93 per
21 megawatt-hour higher.
22 Q. Please describe how the NPC deferral is calculated.
23 A. The deferral is calculated on a monthly basis by subtracting the Base NPC rate
Dickman, Di - 12
Rocky Mountain Power
I from the Actual NPC rate. The resulting monthly NPC rate differential (Exhibit
2 No. 1, line 9) is then multiplied by three groups of actual Idaho retail load at
3 input: tariff customers, Monsanto, and Agrium (Exhibit No. 1, lines 10 through
4 12) to calculate the NPC differential for deferral for each customer group,
5 (Exhibit No. 1, lines 14 through 16). For the 12-month period ended November
6 2012 the NPC differential was approximately $18.4 million before application of
7 the 90 / 10 sharing.
8 Q. What costs are included in the NPC differential for deferral?
9 A. The NPC differential for deferral captures all components of NPC as defined in
10 the Company's general rate case proceedings and modeled by the Company's
11 production dispatch model ("GRID"). Specifically, Base NPC and Actual NPC
12 include amounts booked to the following Federal Energy Regulatory Commission
13 ("FERC") accounts:
14 Account 447
15
16 Account 501
17
18
19 Account 503
20 Account 547
21 Account 555
22
23
Sales for resale, excluding on-system wholesale sales and
other revenues that are not modeled in GRID,
Fuel, steam generation; excluding fuel handling, start-up
fuel (gas and diesel fuel, residual disposal) and other costs
that are not modeled in GRID,
Steam from other sources,
Fuel, other generation,
Purchased power, excluding the Bonneville Power
Administration ("BPA") residential exchange credit pass-
through if applicable, and
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Rocky Mountain Power
I Account 565 - Transmission of electricity by others.
2 Q. Are adjustments made to the Actual NPC prior to comparing to Base NPC?
3 A. Yes. The Actual NPC recorded on the Company's books are adjusted to remove
4 entries that are not included in the determination of the Company's Base NPC for
5 regulatory purposes, such as out of period accounting entries. In addition, Actual
6 NPC adjustments are applied to reflect prior Commission approved adjustments,
7 such as the revenue imputation of the sales contract with the Sacramento
8 Municipal Utility District and removal of the effect of special contract customers
9 buying through curtailment.
10 Q. What constitutes an out of period accounting entry?
11 A. Out of period accounting entries are items booked during the Deferral Period but
12 that pertain to an operating period prior to the inception of the ECAM on July 1,
13 2009.
14 Q. Why is the cutoff of July 1, 2009, used to demarcate out of period entries?
15 A. Since the ECAM took effect, customers' rates have been adjusted to recover
16 essentially all of the Company's actual net power costs, excluding any differences
17 lost due to the 90 I 10 sharing. As a result, any accounting entries made during the
18 current Deferral Period that relate to any operating period since the ECAM took
19 effect should also be reflected in customer rates, whether they increase or
20 decrease Actual NPC. Accounting entries related to operating periods prior to the
21 inception of the ECAM should not impact the ECAM deferral. In this case, out of
22 period entries reduce the total Company Actual NPC by approximately $1.1
23 million.
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Rocky Mountain Power
I Q. In addition to the comparison of Actual NPC to Base NPC, what other
2 components are included in the ECAM?
3 A. There are four additional components included in the ECAM calculations: (i)
4 LCAR adjustment, (ii) credit for any SO 2 allowance sales variances, (iii)
5 adjustment for deferred costs associated with coal mine stripping activities
6 recorded under the Financial Accounting Standards Board ("FASB") EITF 04-6,
7 (iv) true-up of REC revenues as authorized by the Commission in Order No.
8 32196.
9 Q. Please describe the LCAR adjustment.
10 A. The calculation of the LCAR adjustment is a symmetrical adjustment for over- or
11 under-collection of the energy-related portion of the Company's embedded
12 revenue requirement for production facilities as specified in Case No. GNR-E- 10-
13 03, Order No. 32206. The LCAR accounts for variances in Idaho load that cause
14 the Company to collect more or less of these production-related costs. The LCAR
15 rate was last set in Order No. 32432 at $5.47 per megawatt-hour. This rate has
16 been in effect since April 1, 2011.
17 Q. How is the LCAR adjustment calculated and what is the impact on the 2012
18 Deferral?
19 A. The LCAR adjustment is calculated by subtracting the Idaho load at input
20 established in rates ("Base Load" shown in Exhibit No. 1, lines 18 through 20),
21 from actual Idaho load at input ("Actual Load" shown in Exhibit No. 1, lines 22
22 through 24). The difference (Exhibit No. 1, lines 26 through 28) is then multiplied
23 by the LCAR of $5.47 per megawatt-hour in all months of the Deferral Period
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Rocky Mountain Power
I (Exhibit No. 1, line 30) to arrive at the LCAR adjustment (Exhibit No. 1, lines 31
2 through 33) of $713,607 before the 90 /10 sharing.
3 Q. How are SO2 sales revenues included in the ECAM?
4 A. Line 35 of Exhibit No. 1 contains the total Company SO2 sales revenue during the
5 Deferral Period on a total Company basis. Line 37 of Exhibit No. 1 is Idaho's
6 allocated share of the SO 2 sales revenue which is calculated using Idaho's System
7 Energy ("SE") allocation factor authorized by the Commission from the 2011
8 Rate Case. For the Deferral Period, the total SO 2 sales revenue credit is a $1,764
9 reduction to the NPC deferral balance before the 90 / 10 sharing.
10 Q. How is the adjustment for accounting pronouncement EITF 04-6 included in
11 the ECAM?
12 A. Line 38 of Exhibit No. 1 reflects Idaho's allocated differences between the coal
13 stripping costs incurred by the Company and recorded on the Company's books
14 pursuant to the guidance of the accounting pronouncement EITF 04-6, and the
15 amortization of the coal striping costs when the coal was excavated. For the
16 Deferral Period, the total EITF 04-6 coal stripping deferral adjustment is a
17 $30,019 reduction to the NPC deferral balance before the 90 / 10 sharing.
18 Q. Please explain the sharing ratio between the Company and customers in the
19 ECAM.
20 A. The ECAM includes a symmetrical sharing ratio in which customers either pay or
21 receive 90 percent of the ECAM deferral balance and the Company is responsible
22 for the remaining 10 percent. Lines 52 through 54 of Exhibit No. 1 represent the
23 customers' 90 percent share of the monthly deferral shown on lines 47 through 49
Dickman, Di - 16
Rocky Mountain Power
I of Exhibit No. 1. For the Deferral Period, the customers' share of the deferred
2 balance is approximately $15.9 million. The remaining balance of approximately
3 $1.8 million is not included in the deferral calculation and is not recoverable from
4 customers.
5 Q. What is the amount of REC revenue true-up in the current filing?
6 A. As authorized by the Commission in Case No. PAC-E-10-07, Order No. 32196,
7 the Company included the difference between actual REC revenues during the
8 Deferral Period and the amount of REC revenues included in base rates. The REC
9 revenue true-up included in the ECAM is symmetrical but no sharing band is
10 applied - the entire difference between base and actual REC revenues is either
11 refunded or surcharged to customers. Base rates during the Deferral Period
12 included $6.58 million' in Idaho-allocated REC revenue. Idaho's actual REC
13 revenues for that same time period were approximately $6.56 million, a difference
14 of $17,197 (Exhibit No. 1, line 58). While the actual REC revenue was nearly
15 equal to the amount in rates for the deferral period in this case, the Company
16 expects actual REC revenue will be lower in the future.
17 Q. What is the total ECAM deferred balance as calculated in Exhibit No. 1?
18 A. The total ECAM deferred balance as of November 30, 2012 is $25.5 million,
19 shown on line 85 of Exhibit No. 1.
20 Q. How is this balance divided among customers?
21 A. The ECAM deferral is divided into three customer groups based on each group's
22 actual load during the deferral period. Of the $25.5 million, $12.8 million is
$6.58 million is the product of 1 month 9 days of $7.0 million from PAC-E-10-07 and 10 months 22 days
of $6.5 million from PAC-E-1 1-12.
Dickman, Di - 17
Rocky Mountain Power
I allocated to the tariff customers (Exhibit No. 1, Line 70), $11.9 million to
2 Monsanto (Exhibit No. 1, Line 77) and $0.8 million to Agrium (Exhibit No. 1,
3 Line 84). The Company will amortize and collect Monsanto's and Agrium's share
4 of the Commission approved 2012 ECAM balance over three years pursuant to
5 the stipulation approved by the Commission in Order No. 32432.
6 Q. Does the calculation of the deferred NPC adjustment in this application
7 comply with the parameters of the Idaho ECAM as approved by the
8 Commission?
9 A. Yes.
10 Q. Does this conclude your direct testimony?
11 A. Yes.
Dickman, Di - 18
Rocky Mountain Power
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