20150424Redacted Comments.pdf

il RACI N E
OLSON
NYE
BUDGE
BAILEY
2O1 E. Center St.
P.O. Box 1391
Pocatello, lD 83204
o 208.232.6101
F 20A.232.6109
racinelaw.net
. , : il RANDALL C. BUDGEI .i ri [e-mail]
ilii iPl? 2tr fli.i I0: 09
i i", . ,,-: ,ii,lil.:i:r""::rr I t!-.. I :. .,-, .'..
April 23, 2015
Jean D. Jewell, Secretary
ldaho Public Utilities Commission
PO Box 83720
Boise, ldaho 83720-007 4
Re: IPUC Case No. PAC-E-14-10
Dear Ms. Jewell:
Enclosed you will find the original and seven (7) copies of both redacted
and confidential Joint Comments of the Monsanto Company and the PacifiCorp
ldaho lndustial Customers. The confidential Joint Comments are subject to the
Protective Agreement and should be filed under sealwith those copies
distributed only to those who have signed the Protective Agreement.
Thank you for your assistance. lf you have any questions, please don't
hesitate to call.
RCB:ts
Enclosurecc: Service List
Sincerely,
Randall C. Budge, ISB No. 1949
Thomas J. Budge, ISB No. 7465
RACINE, OLSON, NYE, BUDGE &
BAILEY, CHARTERED
P.O. Box 1391;2018. Center
Pocatello, Idaho 83204-1391
Telephone: [phone]
Fax: [phone]
[e-mail]
Afforneys for Monsanto Company
Ronald L. Williams,ISB No. 3034
Williams Bradbury, P.C.
1015 W. Hays St.
Boise LD,83702
Telephone: [phone]
Fax: [phone]
ron@williamsbradbury. com
Attorneys for PacifiCorp Idaho Industrial Customers
IN THE MATTER OF THE APPLICATION
OF ROCKY MOUNTAIN POWER FOR
APPROVAL OF A TRANSACTION TO
CLOSE DEER CREEK MINE AND FOR A
NOTICE OF APPLICATION DEFERRED
ACCOUNTING ORDER
i3l5 ,:Ifr 2lr Alf l0: 09
BEFORE THE IDAIIO PUBLIC UTILITIES COMMISSION
CASE NO. PAC-E.14.10
JOINT COMMENTS OF THE
MONSANTO COMPAI\IY AND
THE PACIFICORP IDAIIO
INDUSTRIAL CUSTOMERS
I. INTRODUCTION
COMES NOW intervenors, the Monsanto Company and the PacifiCorp Idaho Industrial
Customers ("PIIC") (collectively, the "Joint Parties"), by and through the above counsel, and
hereby, jointly submits these comments in response to the Application for Approval of
Transaction and for a Deferred Accounting Order (the "Application") filed by Rocky Mountain
Power ("RMP" or the "Company'') on December 15, 2014. The Monsanto Company's Petition to
Intervene was granted March 19,2015 by Order No. 33254. PIIC's Petition to lntervene was
granted March 19,2015 by Order No. 33255.
The Application contained an array of accounting and ratemaking requests related to the
Company's disposition of its investment in the Deer Creek Mine, including agreements to sell
certain mining assets to Bowie Energy Resource Partners, LLC ("Bowie"), a long-term coal
supply agreement for the Huntington facility ("Huntington CSA"), costs related to the expected
withdrawal from the United Mine Workers of America ("UMWA") 1974 Pension Trust, and a
loss on the settlement of the UMWA Retiree Medical liability (collectively, the "Transaction").
In total, the Company expects that these components of the Transaction will result in costs or
losses approximatirg $I on a total-Companybasis-with the majority, including the
write-off of the undepreciated investment in mining assets, being recognized in calendar years
2014 throu ghz}rc.t On an Idaho-allocated basis, these costs or losses will amount to
approximately $17.4 million, all of which the Company requests be passed on to customers
through several deferred accounts accruing a carrying charge based on RMP's authorized rate of
retum.
These comments are in response to the Commission Order 33221, giving notice of the
Application, and that this matter will proceed under Modified Procedure, authorizing interested
persons to file written comments in support or opposition, and providing rights of participation
by filing a Petition to Intervene.
' SeeApplication at 13.
Comments of Joint Parties - 2
II. COMMENTS
a. Summary
The Joint Parties have reviewed the Application and have developed a number of
recommendations and adjustments to the Company's accounting and ratemaking proposals.
Specifically, the Joint Parties' main recommendations and conclusions with respect to the
Transaction are as follows:
o Transaction Prudence. It is prernature for the Commission to make a prudence finding
now in this proceeding, outside a general rate case and prior to all of the Transaction
costs being known.
Depreciation Reserve Methodology. The Commission has historically required the use
of the depreciation reserve methodology to allocate gains from the disposition of Electric
Plant used to provide public service to Idaho ratepayers. Based on this method, Idaho
ratepayers should be responsible for 62.2% of losses associated with the Deer Creek
Mine disposition, with the Company responsible for the remaining 37.8%.
Amortization Period. The Company justified its deferral request based on benefits
expected to accrue well after the original useful life of the Deer Creek Mine.
Accordingly, the Commission should amortize the deferred account balance over a period
commensurate with the benefits received by ratepayers, or approximately seven years.
Carrying Charge. There should be no carrying charge approved, as the Company
should not be allowed to earn a retum on assets that are no longer in ratebase. If a
carrying charge is approved, it should be, at a maximum, no greater than the carrying
charge approved for the Energy Cost Adjustment Mechanism ("ECAM"), which accrues
interest at the customer interest on deposit rate.
Pension Withdrawal Deferral. It is not necessary in this proceeding for the
Commission to approve any deferred accounting related to the withdrawal from the 1974
Pension Trust. Notwithstanding, the Company should not be allowed to recover a lump-
sum settlement amount that exceeds the current perpetuity value to ratepayers of the
annual withdrawal payments at the current authorized rate of retum, or $37.6 million.
Return on Mine Assets. The Company did not propose to deduct the return on the
mining assets already reflected in rates from the amounts that it proposes to amortize in
the ECAM. Removing these costs will reduce the amounts amortized in the ECAM by
$0.7 million on an Idaho allocated basis, until the Company's next general rate
proceeding.
Comments of Joint Parties - 3
Construction Work in Progress / Preliminary Survey & Investigation Expenditures.
The Company is seeking to defer $3.5 million in Construction Work in Progress
("CWIP") expenditures (Total Company) associated with the Deer Creek Mine, $0.5
million in CWIP (Total Company) associated with the Preparation Plant, and $1.6 million
in Preliminary Survey and lnvestigation ("PS&I") expenditures. None of these
expenditures are recovered in current rates. As the CWIP expenditures have never been-
and never will be-used and useful, these costs should not be included in any deferral
mechanism approved for the Company. Similarly, with the closure of the Deer Creek
Mine, the PS&I expenditures do not now and will never provide customer benefits and
also should be excluded from the regulatory asset.
Facilities Used for the Benefit of Non-RMP Owners of llunter Generating Units.
The Hunter generating facilities served by the Deer Creek Mine and Mining Assets are
not owned exclusively by the Company. The portion of any regulatory assets established
due to the Transaction should be adjusted to remove the share attributable to non-
Company ownership.
Royalty Costs. Company is seeking deferral of royalty costs associated with mine
closure. Given the highly uncertain nature of the Company's estimates of these costs, the
Joint Parties reconrmend that the Commission require that any ultimate recovery of these
costs should be based on the royalties actually charged to the closure costs, rather than on
the Company's estimate.
Waiver of Sharing Bands in the Energy Cost Adjustment Mechanism. The Joint
Parties are supportive of a one-time, non-precedential exception that would grant RMP's
request to flow the change in coal supply costs associated with the Transaction through
the ECAM without the 90/10 sharing mechanism, as wellas the amortization expense
associated with the Deer Creek Mine and the Mining Assets, but only for the portion of
the Mining Assets that represents the loss on the sale of those assets.
Union Supplemental Unemployment and Medical Costs, Non-Union Severance
Costs, and Miscellaneous Closing Costsr lncluding Labor. The Joint Parties object to
granting deferred accounting treatment to these expenses, estimated at lmiltion, which
are within the discretion of the Company, were not unforeseen, are not yet fully known
and measurable, and do not have a material impact on the Company's financial integrity.
Inventory Write-Offs / Fuel Inventory Benefits. RMP is proposing to defer and
recover certain inventory write-offs it will experience as a result of the Transaction. The
Joint Parties do not object to deferral treatment for the inventory write-offs so long as the
Commission also recognizes the reduction in fuel inventory that RMP is projected to
experience during 2015 as a result of the Transaction, the return on which is estimated to
be approximately $6 million (Total Company).
Retiree Medical Obligation, Regulatory Asset - Income Tax, and Unrecovered ARO
Costs. The Joint Parties do not object to RMP's proposed deferral of these items up to
the amounts specified in the Application.
Comments of Joint Parties - 4
b. TransactionPrudence.
Contrary to the Company's request, it is not necessary or desirable for the Commission to
make a prudence finding in this proceeding, outside a general rate case and prior to all of the
Transaction costs being known. While the booking of deferred costs generally caries with it a
reasonable expectation of later recovery, it does not presume that such recovery must occur, nor
does it require that a prudence determination be made at the time authorization of cost deferral
occurs. That said, the Joint Parties are not challenging in this proceeding the prudence of the
Company's actions with respect to moving forward with the Transaction.
c. Single-Issue Ratemakins
RMP's request for deferral in this proceeding is an exercise in single-issue ratemaking,
which occurs when utility rates are adjusted or deferred in response to a change in cost or
revenue items considered in isolation. Single-issue ratemaking ignores the multitude of other
factors that otherwise influence rates, some of which could, if properly considered, move rates in
the opposite direction from the single-issue change.
When utility regulatory commissions determine the appropriateness of a cost that a utility
seeks to recover from its customers, the standard practice is to review and consider all relevant
factors as part of a general rate case, rather than just certain factors in isolation. Considering
some costs or revenues in isolation might cause a commission to allow a utility to increase rates
or defer costs in the area singled out for attention without recognizing counterbalancing savings
in another area.
When faced with an application like this, it is important to bear in mind that utility
ratemaking is not an exercise in expense reimbursement. The opportunity for utility cost
recovery is established in the rates approved by the Commission. [n reality, costs and revenues
Comments of Joint Parties - 5
are almost certain to differ from what was projected at the time rates were set. The simple fact
that a utility incurs a cost that differs from what was anticipated when rates were set does not
create an obligation on the part of the regulator to establish a mechanism for reimbursement. By
law, the Commission is only authorized to change rates upon a determination that existing rates
are unjust, unreasonable, discriminatory, preferential or insufficient. Idaho Code $ 6l-502.
There are limited situations, such as a change in federal tax rates2 or significant changes in fuel
costs3, in which singling out certain items for immedi ate rate recovery, tracker-increases or
deferred recovery is appropriate. As a general matter however, such cases involve costs which
are beyond its conhol of the utility, not costs incurred as a result of actions initiated !y the
utility. As this Commission has recognized, financial situations that are under the control of and
initiated by a utility do not create a good case for deferred accounting treatment. See
Commission Order No. 32766 (Commission denial of an application by Idaho Power to
immediately recover energy efficiency incentive payments in rates wherein the Commission said
"The Company has established a regulatory asset account [] and the Commission will address
recovery of that account when issues affecting all customers and their rates are reviewed in a
general rate case."). a
In conclusion, because single-issue ratemaking focuses on specific costs in isolation, the
Commission should view single-issue deferral proposals with great caution.
2 IPUC Case No. U-l500-164, Order No. 2t640, (December, 1987) In the Matter of the Investigation of the
Effects of Revisions of the Federal Income Tctx Code Upon the Cost of Serttice of Regulated Utilities.3 Simplot v. Intermountain Gas Co.,l}2ldaho 341, 630 P.2d 133 (1981);n IPUC Case No. IPC-E-12,24, Order No .32766,p.9 (March 2013), In the Matter of the Application of ldaho
Power Companyfor Authority to Implement Rates to Include Capitalized Custom Efficiency Incentive
Payments.
Comments of Joint Parties - 6
d. Deer Creek Mine Background
The Company originally invested in the Deer Creek Mine land and facilities in 1977 in
connection with the construction of the second Huntington Generation Unit. The Company's
investment was intended to supply fuel to the entire Huntington Facility located adjacent to the
mine. The Deer Creek Mine assets were originally included in the Company's rate base in Idaho
following the appeal of the Company's 1976 general rate case, where the Idaho Supreme Court
set aside the Commission's decision to exclude the Huntington Generation Unit 2 and Deer
Creek Mine from rate base and required the inclusion of those investments as a known and
measurable adjustment to the historical 1976 test period.s
Since that time, the Company has earned substantial amounts of return on its investment.
While the cost of operating the mine is recovered as a cost of coal and included in net power
costs, Idaho rates presently provide the Company with a return on rate base of approximately
$744,321, per year, on an Idaho-allocated basis, in connection with its investment in the Deer
Creek Mine assets and other assets involved in the Transaction. Over the approximate 37 year
period that the assets have been included in rate base, the Company has earned returns on its
investment in the Deer Creek Mine that likely far exceed the losses that it proposes to pass onto
ratepayers in this proceeding.
The returns that shareholders have received in connection with the investment in the Deer
Creek Mine have compensated for investment risk. This investment risk reflected, among other
things, the probability that the Company would ultimately have to dispose of the mining assets
for a loss. In recognition of this investment risk, it is critical that Commission ernploy an
s See Utah Power & Light v. Idaho Publ. Util. Com'n,102 Idaho 282 (lg8l).
Comments of Joint Parties - 7
equitable methodology to allocate the losses associated with the Transaction between
shareholders and ratepayers.
e. The Depreciation Reserve Methodolow
For purposes of allocating gains and losses associated with the disposition of utility
property between shareholders and ratepayers, the Commission has historically relied on the
depreciation reserve methodology, a method that the Company, itself, originally proposed in
Case No. PAC-E-99-2.6 Inthat proceeding, the Company argued that shareholders should be
entitled to a portion of the gain associated with the sale of the Centralia Generating Facility
because, at the time of the sale, shareholders continued to bear the risk of recovering the
undepreciated portion of the generating facility.T As applied to the Deer Creek Mine
Transaction, the depreciation reserve methodology will result in the below split of losses
between shareholders and ratepayers.
Table 1
Transaction Sharing Percentages Using
Depreciation Reserve Methodoloev ($000)
See In re the Application of PacifiCorp for an Order Approving the Sale of ils Interest in (l) the Centralia
Steqm Electric Generating Plant, (2) the Rate Based Portion of its Centralia Coal Mine, and (3) Related
Facilities; for a Determination of the Amount of and the Proper Ratemaking Treatment of the Gain Associated
with the Sale; and, (4) an EWG Determination, Case No. PAC-E-99-2, Order 28296 at 6 (Mar 2000).
rd.
1
2
3
Gross Plant
(a)
Depr. Res.
(b)
Net Plant
(c)
Shareholder% Ratepayer%
{d) ={c)+{a} (e}=1-(d}
Deer Creek Mine*
Prep Plant**
218,888
N,975
(136,100)
(27,0721t
82,788
19,350
37.8%
47.3%
62.2%
52.7%
5
6
+Percentage to be applied to unrecovered investment, direct closure costs, UMWA medica I Settlement, and 1974 pension trusl
withdrawalpayments
** Percentage to be applied to loss on the sale ofprep plant
Comments of Joint Parties - 8
The depreciation reserve methodology relies on the relationship between net plant and
gross plant to allocate gains and losses between shareholders and ratepayers. It is calculated by
multiplying the gain or loss by the percentage of capital associated with an asset that has been
paid for in rates by ratepayers through depreciation allowance. This percentage of capital repaid
by ratepayers is representative of the public's ownership interest in the disposed asset and has
historically been used by the Commission to allocate gains and losses associated with the
disposition of utility property.
The principle behind the depreciation reserve methodology is that over time ratepayers
gradually repay shareholders for the capital used to acquire utility plant through a depreciation
allowance. This concept has been recognized by the Idaho Supreme Court, which has stated that
"[o]ne way of looking at a depreciation allowance on a utility's personal property is that the
public buys that property from the utility as it is used up."8 As ratepayers reimburse shareholder
capital in utility property, the property becomes vested in the public and provides ratepayers with
a degree of tenancy in the utility property. Once the utility property is fully depreciated, for
example, ratepayers have a right to the full benefit of utilityproperty without having to pay to
use it. Prior to the full repayment of the asset, however, ratepayers are only vested in a
percentage of the utility plant. The goal of the depreciation reserve methodology is to allocate
the gains and losses from the disposition of utility property between shareholders and ratepayers
in accordance with this percentage interest.
This Commission has applied the depreciation reserve methodology in several instances.
For example, in Case No. Case No. PAC-E-99-2, the Commission agreed with the Company's
proposal that the gain from sale of the Centralia plant should be shared between shareholders and
8 Boise Water Corporation v. Idaho Public Utilities Commission, gg Idaho 158, 16l, 578P.2d 1089, 1092 (1978).
Comments of Joint Parties - 9
ratepayers using the depreciation reserve methodology, finding that "the depreciation reserve
methodology proposed by the Company to be a reasonable method for distribution of gain
associated with the sale of the Centralia plant."e Similarly, the Commission rejected Avista's
arguments that Avista should be entitled to the entirety of the gain from the sale of its share of
Centralia, instead holding that, notwithstanding the present value revenue requirement benefits to
ratepayers associated with the sale, the depreciation reserve methodology was the most
appropriate method to allocate the gain from the disposition of the plant between shareholders
and ratepayers.lo
Now, in this proceeding, where the disposition of utility plant results in a loss, the
Company proposes to pass 100% of losses onto customers. As a matter of equity, the
Commission should reject the Company's one-sided approach of allocating Transaction losses to
ratepayers and uniformly apply the depreciation reserve methodology, allocating a portion of
losses to the Company, just as it has been used to allocate gains to the Company in the past.
Any other methodology, including the Company's proposal for ratepayers to bear 100%
of the loss, would be unfair to ratepayers, who have been foreclosed from recognizing prior gains
based on the application of the methodology. Accordingly, the Joint Parties request that the
losses associated with the Deer Creek Mine disposition be allocated37.8% to the Company and
62.2% to ratepayers, as detailed in Table 1 above.
f. Amortization
The Company proposes to amortizethe deferred account balances requested in this
proceeding in a manner consistent with the current rates of depreciation for the Deer Creek
e Id. atll.r0 In re Application of Avista Corporationfor Authority to Sell lts Interest in the Coql-Fired Centrqliq Power
Plant, Case No. AVU-E-99-6, Order 28297 at I I (Mar 2000).
Comments of Joint Parties - 10
Mine.ll This amounts to a five year amortization period conrmensurate with the original useful
life of the mine, which was scheduled to conclude at the end of 2019. Because, however, the
Company justified its request for deferral based on benefits expected to accrue to ratepayers after
the original useful life of the Deer Creek Mine, a five-year amortization period is too short and
will not properly match the costs of the Transaction amortized to ratepayers with the benefits
received in rates. In order to properly match the level of ratepayer costs with benefits received in
rates, an amortization period of seven years is appropriate based on the application of the
depreciation reserve methodology. If the depreciation roserve methodology is not used, a nine
year amortizationperiod, or longer, would be appropriate.
A seven year amortization period is appropriate because the majority benefits associated
with the mine closure will not accrue to ratepayers until well after the end of the Deer Creek
Mine's original useful life. Confidential Figure l, below, details the timing of the benefits used
by the Company in its calculation of the net present value revenue requirement benefits of the
Transaction, used to justiff its proposed deferral.12
rr Application at 15.
" See Crane, Di at32:3-12.
Comments of Joint Parties - 11
Confidential Figure 1
Timing of Ratepayer Benefits Associated with the Transaction
on a Total Company Basis ($m)
As can be seen from Confidential Figure 1, despite the fact that the Company is
requesting for ratepayers to pay the entire amount of the Transaction costs over a five-year
period, the majority of benefits will not begin to be recognizedby ratepayers until after the end
of the Deer Creek Mine's original useful life. The figure includes each of the major benefit
categories in the Company's financial analysis, with the exception of the UMWA retiree medical
settlement, which was a hard-coded value in the Company's analysis. If the UMWA retiree
medical settlement benefits were included, it would further demonstrate that the benefits of the
transaction will not be recognized fully by ratepayers until after the end of the Deer Creek
Mine's original useful life. The Prep Plant Costs category includes the impacts of property tax
savings and coal handling costs, which are too small to be detailed independently in the figure
and largely offsetting. Finally, the benefit category related to the 1974 Pension Trust savings
excludes the terminal value of the pension withdrawal annuity liability, which, if included, would
result in an additiond I ratepayer benefit in2029.
Comments of Joint Parties - 12
Included in Attachment A is a numerical representation of the above benefits that
compares the Transaction costs to the cumulative ratepayer benefits expected from the mine
disposition over the period 2015 throudn2029. As can be noted from the Attachment, had the
economics been measured solely over the five-year period ending in2019, the Transaction would
not have produced a net benefit to ratepayers. A net benefit will only begin to accrue to
ratepayers after calendar year 202I, supporting a seven year amortization period. This timing,
however, is based on the assumption that the depreciation reserve methodology would be applied
to reduce the amount of transaction costs allocable to ratepayers. If the depreciation reserve
methodology is not applied, a net benefit will only begin to accrue to ratepayers after calendar
year 2024, supporting a nine year amortizationperiod.
A number of problems are created by the Company's proposal to amortize the
Transaction costs over a period preceding the time when the majority of the benefits are to be
recognized by ratepayers. Foremost, if a five-year amortization period is approved, generational
inequity will occur. The ratepayers responsible for paylng the upfront amortization will not be
the same ratepayers that ultimately receive the benefits associated with the Transaction. Further,
increases in other jurisdictions' loads may create a situation where the benefits ultimately
received by ratepayers through the inter-jurisdictional allocation methodology become diluted
with time. This jurisdictional inequity to Idaho customers, whose loads are not expected to grow
as rapidly as other jurisdictions, must be resolved in any amortization approved by the
Commission.
To solve these problems, amortization, first, must occur over the same period that
benefits are received in order to ensure that the ratepayers responsible for the costs are the same
ratepayers receiving the benefits. Second, any amount amortized must be dynamic, such that the
Comments of Joint Parties - 13
amortization will be reduced in the circumstance where Idaho's jurisdictional allocation of the
Transaction benefits, by virtue of its allocation of the Huntington facility, declines. An
illustrative example of a dynamic arnortization methodology is detailed in Table 2 below.
Table 2
Illustrative Dynamic Amortization Methodolo g.v
2016 2017 201 8
Illustrative Total Comp any
Amortization ($m)
Huntington Fuel Allocator (SE)
Idaho Allocated Amortization
($m)lll * [2]
10.00
6.0%
0.60
10.00
5.5%
0.55
10.00
5.0%
0.s0
10.00
4.0%
0.40
In summary, the Commission should require the Company to amortize the deferred
account balance over a seven year period in order to properly match the costs borne, and benefits
received, by ratepayers, as detailed in Attachment A. If the depreciation reserve methodology is
not employed by the Commission, however, a nine year amortizationperiod, or longer, should be
used. Such an amortization period is critical to ensuring that generational inequity does not
occur. In addition, the amortization should be dynamic, responding to changes in Idaho's share
of benefits as illustrated in Table 2, above.
g. Carrving Charse
The Company has proposed a carrying charge for the unrecovered investment in the Deer
Creek Mine and the Mining Assets equal to its overall rate of return.l3 It is the Joint Parties'
position that there should be no carrying charge approved, as the Company should not be
allowed to earn a return on assets that are no longer in ratebase. First and foremost, the Joint
Parties question the legality of providing a carrying charge on what will effectively be assets no
13 Application at 16.
Comments of Joint Parties - 14
longer owned by the Company and included in ratebase. Idaho Code $ 6l-502 prohibits the
Commission (except upon an explicit finding that the public interest would be serued) from
"setting rates [] that grants a return on construction work in progress or property held for future
use and which is not currently used and useful in providing utility service." With this statutory
bar in place, the Company has a significant burden of proving that it is "in the public interest" for
the Commission to establish a carryng charge, as requested.
There is a strong Commission precedent for approving deferred accounts with no
carrying charge. For example, in Case No. IPC-E-06-06, Idaho Power Company sought deferral
of costs incurred in an effort to develop the Grid West Regional Transmission Organization
("RTO"), the development of which was unsuccessful.14 In that proceeding the Commission
authorized a deferral but did not authorize a carryng charge on the deferred account balance
because the Idaho Power Company's ef[orts were unsuccessful.ls Upon reconsideration, the
Commission emphasized that it retains "discretionary authority in determining whether to
approve a carrying charge on a deferral account."l6
As another example, in Case No. IPC-E-09-2l,Idaho Power Company sought deferral of
costs related to the under recovery of transmission revenues from legacy transmission
agteements not recoverable through formula transmission rates.lT The Commission held that no
carrying charge should be allowed on the deferred account balance requested in that proceeding
because "the deferral provides sufficient benefit to the Company."l8 Finally, in Case No. IPC-E-
14 See In re the Application of ldaho Power Company for an Accounting Order Addressing the Deferral of Costs
Related to the Development of Grid West, Case No.IPC-E-06-06, OrderNo. 30157 at l.ts Id.16 Case No. IPC-E-06-06, Order 30235 at2.t7 In re the Application of ldaho Power companyfor an Accounting Order Authorizing the Defenal of
Transmission Costs Associated with the Order on Initial Decision (FERC Docket No. ER06-787), Case No.
IPC-E-09-2 l, Order No. 30940 ar 6.
'8 Id.
Comments of Joint Parties - 15
92-9,the Commission adopted Staff s proposal - in which Idaho Power concurred - that losses
from the sale of utility assets would be placed in a regulatory asset account and amortized over
ten years, with the unamortized balance of the loss included in revenue requirement but excluded
from ratebase, so as "not [to] allow the shareholders to earn a retum on an asset no longer owned
by the Company." le The Joint Parties are in accord with the Commission's announced position
in the cases cited above, and in other determinations made by the Commission, that there should
be no carrying charge approved in this case, as the Company should not be allowed to earn a
return on assets that are no longer in ratebase.
Alternatively, should the Commission decide to compensate the Company for the time
value of money associated with the recovery of the deferral, the Company should only be entitled
to recover the time value of money based on a more relative risk free rate. The overall rate of
return received by the Company includes a risk premium, both through the cost of equity and the
cost of debt, which provides the Company with profit commensurate with the level of risk
assumed in its investment in utility assets. The level of risk assumed by the Company in utility
assets, however, is not the same level of risk assumed with respect to recovering the deferred
accounts sought in this proceeding. Once a deferred account has been determined and approved
by the Commission for amortization, the risk of recovery surrounding the account balance is
much lower than other aspects of the Company's operations. As a result, the Company's overall
rate of return is not an appropriate carrying charge for the deferred account balance sought in this
proceeding. The Joint Parties also disagree with the Company as to "what is" the Company's
current overall rate ofreturn. 2o
Case No. IPC-E-93-20, Order No. 25241 , Application of ldaho Power Company for Authority to Sell Certain
Distribution Facilities Located on Bald Mountain.
In discovery, RMP states that it's overall pre-tax rate of return in Case No. PAC-E-I1-12 was ll.616%.
However, that case was resolved through a stipulation that did not speciff an approved return on equity or an
l9
20
Comments of Joint Parties - 16
If the Commission decides to allow a carrying charge, the Commission should, at a
maximum, apply a carrying charge that is consistent with the carrying charge applied to the
ECAM balance, based on the customer interest on deposit rate. Consistent with the power cost
deferrals included in the ECAM, the deferred account balances sought in this proceeding should
accrue interest at a rate not to exceed the interest on deposit rate, currently 1.0% per annum.
h. Pension Withdrawal Liability
Energy West Mining Company currently contributes approximately $3 million per year
into the 1974 Pension Trust. These costs are currently classified as a cost of fuel and included in
net power costs. When the Company closes the Deer Creek Mine and withdraws fromthe 1974
Pension Trust, it will have the option to continue paying the $3.0 million annual liability, in
perpetuity, or settle its liability with an upfront,lump-sum settlement amount.2l The lump-sum
settlement amount would be determined in a bilateral negotiation between the Company and the
1974 Pension Trust. For the plan year ending June 30, 2014, the Company estimated that the
withdrawal liability for Energy West was $96.7 million, based on a risk-free discount rate.
The Company's proposed treatment is to continue the annual contribution of $3 million
until an acceptable lump-sum withdrawal payment can be determined. Accordingly, this expense
should remain in net power costs, where it is currently recorded, requiring no deferral or special
accounting order from the Commission. If and when the Company proposes to recover a lump-
sum withdrawal payment, it should then be subject to Commission review and approval at that
time.
approved overall rate of return. See Case No. PAC-E-l l-12, Order 32432, and Stipulation filed October 18,
201 L The most recent post-tax rate of return approved by the Commission was 7.98oh, established in
Case No. PAC-E-10-07, which translates into approximately ll.l5%o on a pre-tax basis. See Case No. PAC-E-
l0-07, Order 32196,at12and 41. The Pre-tax ROR of 11J5% was estimated by applying the approved
Conversion Factor of I .6 I 5 to the approved ROE of 9.9Yo.2t Stuver, Di at I l:4-20.
Comments of Joint Parties - l7
Notwithstanding, the financial exposure to ratepayers of withdrawing from the 1974
Pension Trust is currently limited to an annuity payment of approximately $3.0 million per
year.22 Thus, to the extent that the Company negotiates a lump-sum withdrawal payment, any
amount paid in excess of the perpetuity value of the $3.0 would be harmful to ratepayers. Based
on the 7.98% cost of capital approved in Case No. PAC-E-10-07 (See footnote 20), the
perpetuity value of the $3.0 million annuity payment to ratepayers is approximately $37.6
million on a total Company basis,23 or approximately $2.4million on an Idaho allocated basis.
The amount for which aparty may be willing to settle an annuity payment is largely
driven by the perpetuity value. The perpetuity value represents the present value of a fixed
stream of payments made for an indefinite period of time and is calculated, simply, by dividing
the payment by the periodic interest rate:
Figure 2
Perpetui8 Value
Perpetuity Value =
Payment
Discount Rate
Based on this formula, at a7.98o/o cost of capital, any lump-sum amounts paid in excess
of $37.6 million would increase costs to ratepayers relative to the perpetuity value of the $3.0
million annual withdrawal liability. From the ratepayer perspective, any amount of funds paid in
excess of that amount would be more efficiently deployed by the Company as a permanent offset
to rate base, rather than as a lump-sum payment. It follows that any amount collected in excess
of that amount would only serve to eliminate any risk to shareholders and would not be
appropriately included in rates.
22 Stuver, Di at 11:4-20.23 $37.6 m: $3.0 m - 7.gB%.
Comments of Joint Parties - 18
i. Return on Minins Assets
The Company has proposed to begin immediate amortization of the Transaction costs
through the ECAM. The Company, however, is currently recovering the capital costs associated
with the disposed mining assets and did not propose any adjustment to remove the retum on
mining assets already included in rates. The Company proposal, therefore, overstates the amount
of cost incremental to base rates that ought to be recovered through the ECAM. Eliminating this
return component would result ina$744,321 annual reduction to the Company's ECAM
deferrals.2a
Two categories of costs have traditionally been included in rates associated with the Deer
Creek Mine. First, mine operating costs, including depreciation, are included in the cost of fuel
for the Huntington facility. This fuel cost is reflected in rates as a net power cost, which is trued-
up annually through the ECAM. Second, the net plant investment in the mining assets is
included in rate base, separate from the net power cost calculation. The rate base amounts and
associated return on the mining assets are only updated in rates in general rate case filings.
While the 'return o?-i.e. depreciation of-the mining assets will be trued-up as a
component of net power costs in the ECAM, the 'retum on' the mining assets will not be
accounted for in the ECAM proceeding. Under the Company's proposal, it will continue to earn
a return on the mining assets until new rates are established in a general rate proceeding. In
order to properly reflect the rate impact of the Company's proposal, the Commission should
require the Company to reduce the amount of Transaction costs amortized in the ECAM by the
24 See Attachment B (the Company's Supplemental Response to Monsanto Data Request ("DR") 1.22).The
$744,321return component was calculated by RMP in this data response using the 11.616% pretax return
alleged by the Company. Although the Joint Parties disagree with RMP's representation of its authorized
return, the return component amount depicted by RMP is referenced here for purposes of this discussion. If the
Commission determines that RMP's representation of its return is incorrect, it would impact the amount of the
refurn component.
Comments of Joint Parties - 19
$744,321of Idaho-allocated return on the mining assets already reflected in rates until the return
component is removed from rates in the Company's next general rate proceeding.
i. Construction Work in Progress / Preliminary Survev and Investisation Exnenditures
RMP is seeking to defer $3.5 million in Construction Work in Progress ("CWIP")
expenditures (Total Company) associated with the Deer Creek Mine, $0.5 million in CWIP
(Total Company) associated with the Preparation Plant, and $1.6 million in Preliminary Survey
and Investigation ("PS&I") expenditures, which is for a surface exploration drilling progam
outside the boundaries of the leases currently controlled by PacifiCorp. None of these
expenditures are recovered in current rates. As the CWIP expenditures have never been - and
never will be - used and useful, these costs should not be included in any deferral mechanism
approved for the Company. Similarly, with the closure of the Deer Creek Mine, the PS&I
expenditures do not now and will never provide customer benefits and also should be excluded
from the regulatory asset. The Joint Parties do not believe that the circumstances of this
Transaction warrant deviation from the Commission's typical requirement that costs can be
collected from customers only for assets that are used and useful and that provide benefits to
customers.
j. Facilities Used for the Benefit of Non-RMP Owners of Hunter Generatins Units
The Hunter generating facilities served by the Deer Creek Mine and Mining Assets are
not owned exclusively by the Company. Other parties own shares in Hunter Units Nos. 1 and?
that together represent 14.88% of the aggregate operating capacity of the three Hunter units.
Any regulatory assets established due to the Transaction should be adjusted to remove the share
attributable to non-Company ownership of these units. Currently, the costs of the Deer Creek
Mine and Mining Assets allocated to the other owners are recovered from the share of the cost of
Comments of Joint Parties - 20
coal charged to the other owne.s.25 With Deer Creek coal production discontinued, this vehicle
for recovery of the Deer Creek Mine and Mining Assets costs from the non-RMP owners no
longer exists. Instead, the Company's filing appears to contemplate fully recovering all
Transaction costs from retail customers, without recognizing that a portion of these facilities also
served non-RMP ownership interests. The Joint Parties disagree with such an approach and
recommend that RMP be required to remove the portion of the assets that were required to serve
the non-RMP-owned Hunter plant.
In discovery, RMP prepared a table that identifies the portion of the Transaction costs the
Company believes is allocable to retail customers after the portion of the assets required to serve
non-RMP ownership interests is removed. This adjustment results in a reduction of l
applied to the proposed regulatory assets associated with the Deer Creek Mine, the loss on the
Mining Assets, closure costs, and Retiree Medical settlement loss, as well as an adjustment to the
1974 Pension Trust regulatory asset.26 The Joint Parties believe this adjustment is reasonable,
with the exception of the loss on the Mining Assets, for which the adjustment should be closer to
I, to reflect the fact that the Preparation Plant is primarily used in support of the Hunter units.
To the extent any ofthese regulatory assets are approved in this proceeding, the regulatory asset
values should reflect these removals.
The Joint Parties note that RMP agreed to address this issue in its
Deer Creek Mine closing Settlements, agreeing to the following Settlement
very similar language in the Wyoming Settlement):
The [Utah] Parties agree that the Commission should enter an order
accounts to be established for all joint owner elements related
including but not limited to the following:
Utah and Wyoming
terms in Utah (with
authorizing separate
to the Transaction,
25 See RMP Response to Monsanto Data Request 2.4 (a),(b) and (d).26 See WY PSC Docket No. 20000-464-EA-14, RMP Response to WIEC Data Request 5.3 and Confidential
Attachment WIEC 5.3.
Comments of Joint Parties - 21
a. the Utah-allocated portion of unrecovered investment in the Deer Creek Mine and
the loss on the Mining Assets;
b. the Utah-allocated portion of Deer Creek closure costs;
c. the Utah-allocated portion of loss on settlement of the Retiree Medical
Obligation;
d. the Utah-allocated portion of the withdrawal from the 1974 Pension Trust; and
e. the Utah-allocated portion of total Company amount of $3.8 million of the net
Deer Creek Mine related CWIP (including PS&I and salvage).
The Company will be responsible for obtaining reimbursement of these costs from joint
owners; the Company's utility customers' rates will not be impacted in the event the joint
owners do not fully reimburse the Company.
k. Royaltv Costs
The Company is seeking deferral of royalty costs associated with mine closure. The Joint
Parties are concerned with the estimation of these costs provided by RMP in this case. One
portion of the royalty cost estimate, abandonment royalties amounting toI, appears to
be purely speculative at this point.27 The other portion of the royalty cost estimate, recovery-
basedroyaltieso-,isderivedbygrossingupRMP,sp1annedexpenditures
associated with mine closure, including the 1974 Pension Trust withdrawal and Retiree Medical
settlement loss.28 Given the highly uncertain nature of these estimates, the Joint Parties
recommend that the Commission require that any ultimate recovery of these costs should be
based on the royalties actually charged to the closure costs, rather than on the Company's
estimate. In addition, in the Wyoming Settlement, RMP agreed to cap the recovery of
See Utah PSC Docket No. 14-035-147, RMP Response to OCS Data Request 2.23. /tbardonment royalty
estimate source: RMP Response to IPUC Data Request 4, Confidential Attachment IPUC 4, EW Fin Model 12-
l5-14, 'EW FRF Pro Forma Closure Sale', "Royalties" tab.
See WY PSC Docket No.20000-464-EA-14, RMP I't Supplemental Response to WPSC Data Request 2.16.
Recovery-based royalty estimate source: RMP Response to IPUC Data Request 4, Confidential Attachment
IPUC 4, EW Fin Model 12-15-14,'EW FRF Pro Forma Closure Sale', "Royalties" tab.
Comments of Joint Parties - 22
abandonment royalties at75o/o of the total costs estimated in the Company's filing. The Joint
Parties recofirmend that a similar cap be adopted for Idaho.
l. Waiver of Sharine Bands in the Enersv Cost Adiustment Mechanism
The depreciation and operating expenses of the Deer Creek Mine and Mining Assets are
currently included in net power costs, and RMP proposes that these costs, along with the costs or
benefits realized for replacement coal supply, be subject to the ECAM without application of the
90/10 sharing band. The Joint Parties are supportive of a one-time, non-precedential exception
that would grant RMP's request to flow the change in coal supply costs associated with the
Transaction through the ECAM without the 90/10 sharing mechanism, as well as the
amortization expense associated with the Deer Creek Mine and the Mining Assets.
The Joint Parties believe this treatment is reasonable because the depreciation expense
associated with the Deer Creek Mine and the Mining Assets is currently included in net power
cost, and thus is part ofbase net power cost in rates. However, at the time these assets are taken
out of service they cease to be included in net power cost. Thus, actual net power cost, for the
pu{pose of calculating the 2015 ECAM, will be reduced by the amount of the depreciation and
operating expenses of the Deer Creek Mine and the Mining Assets. Absent any special
raternaking consideration, the ECAM mechanism will remove90%o of these costs currently
included in base NPC from ultimate recovery from customers, as if they had gone away. In the
Joint Parties' view, in the case of depreciation expense, such a result would be an unintended
consequence of ratemaking mechanics that would produce an unreasonable result, thus justifuing
deferred accounting treatment.
The depreciation expense for these assets is currently included in rates and RMP is
proposing to convert the corresponding net plant in service into a regulatory asset that would
Comments of Joint Parties - 23
continue to be amortized on the same schedule that the plant is being depreciated. In general, it
is reasonable for RMP to continue to recover its initial investment in the Deer Creek Mine and
the Mining Assets at the current level until rates are reset pursuant to the next general rate case.
If this amortization expense is deferred through the ECAM as proposed by RMP, then it
may also be reasonable to exempt it from the 90/10 sharing mechanism in the calculation of the
2015 ECAM (and the 2016ECAM, to the extent that it is not included in the rate effective period
following the next general rate case), in order to maintain current recovery levels. At the same
time, it would also reasonable to exempt the incremental benefits of supplying the Hunter and
Huntington plants through the Bowie contract from the 90/10 sharing mechanism to place this
companion impact on net power cost on the same playng field as the treatment of
depreciation/artortization expense. That is, it would be unreasonable to exempt the
depreciation/amortization expense from the 90/10 sharing (which benefits RMP) without also
exempting the incrernental benefits of the Bowie contract (which, on a standalone basis, is
projected by RMP to benefit customers).
This issue has also been addressed in the Utah and Wyoming Settlernents, with the
former providing as follows:
The [Utah] Parties agree that the Commission should enter an order authorizing a one-
time, non-precedential exception to be made to the 70130 Energy Balance Account
("EBA") sharing band for the following items, to be recovered by flowing them through
the EBA at l00Yo without applyng the sharing band until the rate effective date of the
next general rate case:
a. unrecovered Deer Creek Mine investment amortization, at the current level
of depreciation expense in rates, and the amortization of the loss related to
the Mining Assets at the current rate of depreciation as described in the
Application; and
b. actual Utah fueling cost for the Hunter and Huntington plants, including:
i. lower replacement coal costs;
ii. Prep Plant operational savings;
Comments of Joint Parties - 24
iii. pension timing savings; and
iv. savings on Energy West retiree medical benefits as a result of the
settlement of the Retiree Medical Obligation.
The Parties agree that the sharing band waiver is non-precedential, and the Company
agrees to not request any change or elimination of the EBA sharing band to be effective
prior to the end of the EBA pilot.
The Wyoming Settlement provides similar language and the benefits identified in section
(b) are identical to that of the Utah Settlement. The Joint Parties recommend that the same
benefits identified in section (b) above be recognized in the Idaho jurisdiction.
m. Union Supplemental Unemplovment and Medical Costs. Non-Union Severance Costs.
and Miscellaneous Closins Costs. Including Labor
RMP is seeking deferral of an estimated ! million (Total Company) in mine closing
costs associated with these items, most of which will be incurred in 2015-16. The Joint Parties
object to granting deferred accounting treatment to these expenses, which are within the
discretion of the Company, were not unforeseen, are not known and measurable, and do not have
a material impact on the Company's financial integrity. To the extent these costs are prudently
incurred, they can properly be recovered through the filing of a general rate case, depending on
the timing of the filing and test period used in the case. But as utility ratemaking is not a matter
of simple cost reimbursement, it should not be presumed that these costs are or will be
recoverable on a single-issue basis, outside the framework of a general rate case. Consequently,
the Joint Parties recommend that deferred accounting treatment for these costs be denied.
n. Inventorv Write-Offs / Fuel Inventorv Benefits
RMP is proposing to defer and recover certain inventory write-offs it will experience as a
result of the Transaction, estimated to be ! million (Total Company). The Joint Parties do not
object to deferral treatment for the inventory write-offs so long as the Commission also
recognizes the reduction in fuel inventory that RMP is projected to experience during 2015 as a
Comments of Joint Parties - 25
result of the Transaction. Fuel inventory has an impact on rates because it is included in rate
base and RMP eams its authorized rate of return on its value. RMP's fuel inventory for facilities
impacted by the Transaction is projected to decline significantly in 2015 relative to what is
included in rates (See Table 2 below). The Joint Parties object to the Company's failure to
recommend that any reduction in fuel inventory be recognized as a benefit to customers as part
of its proposed deferral. If RMP is to receive the benefit of defened accounting for many of the
costs it is incurring as a result of the Transaction, including an inventory write-off, then the
savings to customers in fuel inventory carrying costs should also be reflected.
Table 2
Coal Fuel Stock Balances Related to Transaction
Fuel Stock Site
PAC-E-11-12
Dec. 2011
Year-End Balances 2e
Current Projection
13-mo. av.
Dec 14-Dec 15 30
Difference
(Current Projection
- GRC Balances)
Hunter
Huntington
Deer Creek Mine
Preparation Plant
Rock Garden
7r,376,781
28,267,756
568,214
32,836,497
22.401.094
50,645,174
28,594,235
5,298
5,091,901
17,633,01 l
(20,737,607)
326,479
(562,916)
(27,744,596)
(4.768.083)
Total 155,450,342 101,969.619 (53.480-723\
The earnings on the reduction in fuel inventory for Calendar Year 2015, which the Joint
Parties estimate to be $6 million (Total Company)3I, should be deferred and credited against the
inventory write-off, and the excess credited against the remaining regulatory assets associated
with the Transaction that are approved by the Commission in this case.
2e Data Source: RMP Response to Monsanto Data Request 2.1, Attachment Monsanto 2.1.30 Data Source: I-lT PSC Docket No. 14-035-147,RMP Response to OCS Data Request 4.6, Attachment OCS 4.6.3r The $6 million Total Company estimate was derived using the Utah Commission Integrated Allocation Model
12-2-14 from UT PSC Docket No. 13-035-184. The Utah revenue requirement impact determined in the model
(-$Z.S million) was divided by the Utah system energy (SE) factor (41.972%) to derive the estimated Total
Company impact of the change in coal fuel stock balances relative to what was included in Case No. PAC-E-
11-12, using the authorized rate of return in Case No. PAC-E-10-07. Although this calculation was made using
a Utah model, it represents a reasonable estimation of the Total Company impact of the change in coal fuel
stock balances in Idaho rates.
Comments of Joint Parties - 26
The Joint Parties note that a fuel inventory credit is recognized in the Utah Settlement. [n
that Settlernent, the fuel inventory credit is recognized starting June 1, 2015. However, the Joint
Parties believe that amore appropriate date for the credit to start being accrued is January 1,
2015, to reflect the benefit of the reduced fuel inventory associated with the cessation of Deer
Creek mining operations at the end of 2014, rather than five months later, which is associated
with the target date of the Transaction.
o. Retiree Medical Obligation. Regulatorv Asset - Income Tax. and Unrecovered ARO
Costs
RMP has requested deferral of approximately! million (Total Company) for Retiree
Medical Obligation, ! miilion (Total Company) for an income tax regulatory asset, and !
million (Total Company) for unrecovered asset retirement obligation (ARO) costs. As the
Retiree Medical Obligation costs would have been amortized to FAS 106 expense absent the
settlement, the Joint Parties do not object to RMP's proposal for deferral of these costs. With
respect to proposed income tax regulatory asset, the Joint parties are not objecting to RMP's
proposal for deferral of this item to the extent it offsets what would otherwise be a duplicate tax
benefit to customers, as RMP maintains in its Response to Monsanto Data Request 2.5. And
because the unrecovered ARO costs are part of a long-term calculation applied to the asset
retirement obligation for a long-lived asset, deferral and amortization of these costs may be
appropriate.
II. Conclusion
In light of the approximatelyl milion in costs associated with the Transaction,
which the Company proposes to pass onto Idaho customers, the Joint Parties respectfully request
that the Commission adopt the proposed recommendations outlined in these comments. The
Comments of Joint Parties - 27
Joint Parties appreciate the opportunity to submit these comments regarding the Transaction to
dispose of the Deer Creek Mine and look forward to working with the Commission and
interested parties to resolve these matters.
RESPECTFULLY SUBMITTED this 23d day of April, 2015.
Monsanto Company PacifiCorp Idaho Industrial Customers
fratu,,;
Ronald L. Williams
WILLIAMS BRADBURY, P.C.RACINE, OLSON, NYE, BUDGE &
BAILEY, CHARTERED
Comments of Joint Parties - 28
CERTIFICATE OF MAILING
I HEREBY CERTIFY that on this 23'd day of April, 2015, I served a true, correct and complete
copy of the foregoing document, to each of the following, via the method so indicated:
Jean D. Jewell, Secretary (original and 7)
Idaho Public Utilities Commission
P.O. Box 83720
Boise,ID 83720-0074
E-mail : i ean j ewell@puc. idaho. gov
Ted Weston
Rocky Mountain Power
201 South Main, Suite 2300
Salt Lake City, Utah 8411I
E-mail : ted.weston@pacifi corp.com
Daniel Solander
Rocky Mountain Power
201 South Main, Suite 2400
Salt Lake city, Utah 8411I
E-mail: [e-mail]
Brad Mullins
333 SW Taylor Street, Suite 400
Portland, OR97204
E-mail : [e-mail]
Kevin Higgins
Energy Strategies
215 S. State St., Suite 200
Salt Lake City, Utah 84111
E-mail : khi [e-mail]
Ronald L. Williams
Williams Bradbury, P.C.
1015 W. Hays Street
Boise,Idaho 83702
E-mail : ron@,williamsbradbury.com
U.S. Mail + Email
E-mail
E-mail
E-mail
E-mail
RANDALL C. BUDGE
Comments of Joint Parties - 29
E-mail
Jim R. Smittt
Monsanto Company
1853 Highway 34
Soda Springs, Idaho 83276
Jim.r. smith@monsanto. com
E-mail
Comments of Joint Parties - 30
ATTACHME,NTA
(coNFIDENTTAL)
ATTACHMENT B
PAC-E- I 4- I 0/Rocky Mountain Power
April 16,2015
Monsanto Data Reque st 1 .22- l't Supple,rneirtal
Monsanto Data Requ est 1.22
Please state the return on rate base included in Dock* No. PAC-E-11-12
associated with each and every asset that will be sold, diqposed, or retired as a
result of the Deer Creek Mine Closure and the associated transaction with Bowie.
ltt Supplemental Response to Monsalrto Date Requestl.22
Please refer to Attachment Monsanto 1.22 ft Suppleinental. It is important to
note that PAC-E-11-12 was a settled case and these amounts are approximations
onlY.
Responder: Steve McDougal
Witness: Doug Stuver
ATTACHMENT MONSANTO 1.22 1ST SUPPTEMENTAT
ASSETS SOLD, DISPOSED OR RETIRED AS A RESUIT OF DEER CREEK MINE CTOSURE
PAC-E-11-12 was a settled case and these amounts are approximations only
RATE BASE(I}
Pre-Tax
Return
ldaho
Revenue
Requirement
Electric Plant in Service
Coal Mine Assets
Sold
Retired/Disposed
lntangible Assets
Sold
Retired/Disposed
General Plant
Sold
Retired/Disposed
Distribution Plant
Sold
Retired/Disposed
Accumulated Deoreciation
Coal Mine Assets
Sold
Retired/Disposed
lntangible Assets
Sold
Retired/Disposed
General Plant
Sold
Retired/Disposed
Distribution Plant
Sold
Retired/Disposed
SE Factor from PAC-E-11-12.
Retired/Disposed
Sold
Accumulated Deferred Income Tax at 12l3U2014
Total
Companv
47,762,065
247,365,560
11,706
3,431,094
966,545
(19,9s8,3s9)
(13s,289,993)
(6,s47l.
(1,918,701)
(276,8421
6.34t%
(2L,739,947l,
(6,607,LO71
ldaho
Portion
2,648,142
15,305,047
742
217,566
{.7,265,5641
(8,578,770l,
(41s)
(121,665)
(1,378,s3s)
(418,9s8)
71.62%
11.62%
lt.62%
71.62%
77.62%
17.62%
11.62%
17.62%
77.620/"
11,62%
77.62%
307,614
7,777,877
86
25,273
(747,0!71
(996,s30)
(48)
(14,133)
(160,134)
(48,667l,
TOTAT IDAHO ''RETURN ON'' IN RATES
(1) PAC-E-11-12 reflected projected plant balances for the test year. ADIT for these assets from
thatfilingisnotreadilyavailable. Actual AD|Tbalancesarereflectedforpurposesofthisresponse.
744,321