20170504Comments Redacted.pdf

BRANDON KARPEN
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
(208) 334-03s7
IDAHO BAR NO. 7956
IN THE MATTER OF THE APPLICATION
OF PACIFICORP DBA ROCKY
MOUNTAIN POWER FOR APPROVAL OF
A $7.5 MILLION DEFERRAL OF NET
POWER COSTS, AND AUHTORTTY TO
DECREASE RATES BY $6.9 MILLION.
CASE NO. PAC-E,.I7-02
COMMENTS OF THE
COMMISSION STAFF
ll;-^::!,,/i:nr.'_.-\r' ,l I l^.L/,
lnr,t!,, . -r.i i-j, ll: i_I
Street Address for Express Mail
472 W. WASHINGTON
BOISE, IDAHO 83702-5918
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
)
)
)
)
)
)
)
The Staff of the Idaho Public Utilities Commission, submits the following comments
regarding the above referenced case.
BACKGROUND
On March 31,2017 , PacifiCorp dba Rocky Mountain Power applied to the Commission
for an Order authorizing the Company to adjust its rates under the Energy Cost Adjustment
Mechanism (ECAM). The Company's present ECAM Application, if approved, would deuease
rates for all customer classes, with an average residential customer's bill decreasing by about
$ 1 .65 per month. The Company asks that, if approved, the new rates take effect on June 1,2017 .
The Commission first approved an annual ECAM in2009, and the mechanism has been
modified several times since then. See OrderNos. 30904,32432,32910,33008, 33440,and
33492. The ECAM allows the Company to adjust its rates each year to capture the difference
between the Company's actual net power costs (Actual NPC) and the power expenses recovered
1STAFF COMMENTS MAY 4,2017
through base rates (Base NPC). The adjustment is a separate line item on customer bills that
increases if power supply costs are higher than the amount already recovered in base rates, or
decreases if power supply costs are lower. These costs vary with changes in the Company's fuel
(gas and coal) costs, surplus power sales, and power purchases. Each month, the Company tracks
the difference between the Actual NPC it incurred to serve customers, and the Base NPC it
collected from customers through rates. The Company defers the difference between Actual NPC
and Base NPC into a balancing account for later disposition at the end of the yearly deferral
period. At that time, the ECAM allows the Company to credit or collect the difference between
Actual NPC and Base NPC through a decrease or increase in customer rates. The ECAM does
not affect the Company's earnings.
The Company is requesting approval for recovery of approximately $7.525 million
deferred costs plus interest, beginning June l, 2017 , through May 3 7,2078, for the deferral period
beginning December 7,2015, through December 31,2016. To recover this amount, the Company
has proposed a traditional rate plan that allows for the full recovery of the $7.525 million deferred
amount through Schedule 94 rates, and provided an alternative proposal designed to mitigate
future impacts on base rates. The deferred costs are broken down in the following table.
Balanci Account
The Company proposed an alternative rate proposal that would lower the ECAM recovery
amount by $3 million to $1 1.5 million, and use the remaining $4 million to reduce a depreciation
regulatory asset that was established in Case No. PAC-E-13-02.
STAFF COMMENTS MAY 4,20172
Balanci ng Accou nt Activity
Prior Deferral
ECAM Revenue Collection - Schedule 94
lnterest
Dec 15 - Dec 16 ECAM Deferral
December 31, 2016 Balance Fsr Collection
lnterest
Expected Balance as of June 1, 2017
s
$
I
I
$
t2,68.48/ffi
Through December 31, 2016
dule 94 Collection - Jan - May 2017
7,524,8t61
ldaho
Cugtomers
23,8L2,O74
{1&659,710}
3,658
5,155,021
7,526,945
{5,168,288)
10,283
STAFF REVIEW
Staff thoroughly reviewed the Company's Application focusing on four critical areas.
First, Staff analyzed whether the costs and revenues in the Company's NPC were reasonable
during the deferral period. Then, Staff audited contracts, invoices, and other documents to
authenticate the actual cost and revenue reflected in the Company's deferral balance. Then, Staff
reviewed whether the Company accurately calculated the deferral amount, account balances, and
resulting rates in compliance with past Commission orders. Finally, Staff reviewed the alternative
rate proposal for accuracy, and considered the appropriateness ofthat proposal.
Staff found that the costs and revenues were accurate, finding no exceptions in the audit,
and the Company's calculations were in compliance with Commission order. Based on its
analysis of the depreciation regulatory asset and the ECAM impact, Staff supports the Company's
alternative rate proposal.
In Case No. PAC-E-I5-09, the Commission approved shifting the Company's deferral
period from December through November used in previous ECAM's to a standard calendar year.
To make the transition, the Company was required to include thirteen months of deferrals which
totals about $7.527 million from December 2015 through December 2016. The table below
provides a summarized breakdown of the components which make up the total amount.
Su Table of 3O17 ECAM Deferral
J
Lake Side 2 Resource Adder
Production Tax Credits
Deer Creek Amortization Expense
REC Deferral
lnterest
Company Recoveryfor NPC Deferral
$
s
$
5
Deferral Before Sharing
haring Band
stomer Reponsibility
(
7,526,945
ldaho
Cuetomers
NPC Differential for Deferral
EITF 04-6 Adjustment
LCAR
DSM Costs
49,006
231,490
5,860,701
496,611
1,379,929
349,7W
198,103
STAFF COMMENTS MAY 4,2017
For the thirteen-month period, the NPC differential was an approximate $1.1 million
credit to customers before application of the 90% (customers) 110% (Company) sharing band.
The differential is the difference between Actual NPC and Base NPC. Other components subject
to the 90/10 sharing band in this year's ECAM include an adjustment for the treatment of coal
stripping costs under Emerging Issues Task Force (EITF) 04-6, a Load Change Adjustment
(LCA), and an adjustment for Demand Side Management (DSM) costs. Components not subject
to sharing include a true-up of the incremental Lake Side 2 generation resource adder, Production
Tax Credits, Deer Creek amortization expense, and Renewable Energy Credit revenues.
Analysis of Deferral
Staff believes: (l) the methodology used in the Company's filing complies with previous
Commission orders; (2) the Company utilized accurate actual loads and prudently incurred actual
cost/revenue amounts; and (3) the Company applied the proper loads, costs, and revenues
embedded in base rates. Accordingly, Staff believes the Company accurately adjusted for the
difference in prudently incurred actual costs/revenues verses base rate revenue recovery in its
Application.
Staff audited the Company's books and performed on-site audits at the Company's
Portland and Salt Lake City offices. Staff reviewed the Company's intemal audit work papers,
control processes, journal entries, invoices, and contracts. Staff also reviewed the Company's
adjustments to its actual costs. See Staff Audit Report Attachment A. Staff reconciled the
general ledger amounts to the net power costs provided in Company Exhibit No. 1. Staff also
reviewed the Company's hedge contracts and policies and believes they reasonably safeguard
price stability and fuel stability. In addition Staff reviewed the entries for the regulatory
depreciation of the Deer Creek mine closure, and believes they comply with Order No. 33304,
Case No. PAC-E-14-10. Staff believes the NPC in Company Exhibit No. 1 is accurate and
complies with ECAM policies.
Staff verified that base amounts used in the calculations were consistent with cost,
revenue, and loads that were embedded in base rates during the deferral period. The Company
properly used base figures from Case No. PAC-E-ll-t2 for December 2015. Staff then verified
that the base amounts reflected changes in base rates starting January 1,2016 due to an
adjustment to net power costs authorized in Order No. 33440, Case No. PAC-E-15-09. In
4STAFF COMMENTS MAY 4,2017
addition to an adjustment to net power costs, the Commission also authorized, starting January
2016, (1) the removal of the SO2 revenue adjustment, (2) the removal of the demand side
management cost adjustment, (3) the inclusion of a Production Tax Credit (PTC) adjustment, and
(4) changes to adjustment calculations using loads at customer meter rather than loads at
generation effectively eliminating the backcast adjustment for all months of the 2017 ECAM.
The ECAM includes a"90ll0 sharing band" in which customers paylreceive 90o/o of the
difference between actual costs/revenues and what the Company recovers through base rates. The
Company incurs/retains the remaining l0o/o. ln this year's ECAM, adjustments in the Company's
proposed deferral, subject to sharing, includes: (l) the difference between Actual NPC and Base
NPC; (2) the load change adjustment; (3) an adjustment for load control (DSM); and (4) an
adjustment for coal stripping costs. Adjustment in the deferral not subject to sharing includes: (1)
the Production Tax Credit Adjustment; (2) the Lake Side 2 adder; (3) the Renewable Energy
Credit Adjustment; (4) a credit for SO2 allowance sales; and (5) Deer Creek amortization
expenses. Each component is analyzed below.
NPC Difference
PmfiCorpEnrgy
llcl Powu Cod Compadlon
Adiuttcd Actud llPC I lD Brc ilPC PAC{-15{9
l0 ECAII Dchrnl Pcdod: Jmuary 2016 . hcamhr 21110
GIt{h $ll,!ul
uurt4_181 8is€ NPC i E!!!!!_Ac''!!hrcilPo I
175978927 4S,5&1,$12 (2S0,604,88r) 423% 6631 15M
!(lgjuiEActud hse t{PC I t
Specnl Sak For Resde
Purchasd Power& Nd lnterchange
Coal
Gm
Ohet
Base NPC PACtlS# Setlemenl Adu$rnenl
708,182 656 (211,13? 136) -30 3%
7S3.792{35 {r2.2$m1} .53%
317,W166 i60!1{$5i .1929i
160.,16{784 {2,r.ffi2.166i .150b
15207.946
rs3,745 520
ii]5S,431
2i7,047 811
!$.404616
11 1!5
$583
9887
7lW
16 113
11 119
7 290
ft5!
43.60
m.5{
m00
19.21
(9013) "575%
{488) -2e8%
{4536) -110I
(113.1) .1211
(lel) 26\
{3 87
1S.S
809
n.01
{3.2e) .11r,i
{0.27) {6'i;
l,u 6.1%
1109) '1.4ua
11801 .121%
tlPC (l{ct $ilem Lmd)r,{62,785,t63
',5fi,058,i7a
($,?t3,321) .43!a 58,264 80,2i0 lt,966l 33t 25.11 2539 0.21} -11S
The difference between actual Idaho jurisdictional NPC and NPC revenue collected
through base rates is a $1.1 million credit. Staff believes this amount is accurate and that actual
system NPC incurred by the Company is reasonable and prudent. Staff bases its assessment on
5STAFF COMMENTS MAY 4,2017
the overall validity of cost factors driving Actual NPC during the deferral period as compared to
NPC at the time base rates were set.
There is a $66 million difference on a total company basis between Actual NPC and NPC
recovered through base rates for the period of January 2016 through December 2016, which is
due to: a$214 million reduction in purchased power expense; a $42 million reduction in coal fuel
expense; a $61 million reduction in natural gas expense; a $24 million reduction in wheeling and
other expenses; and a $15 million settlement adjustment from PAC-E-15-09. This reduction in
cost is partially offset by $290 million decrease in wholesale sales revenue.
Revenue from market sales is $290 million lower than Base NPC due to a 57.60/o
reduction in sales volume and an ll.0% reduction in market prices driven by lower natural gas
prices. The unit cost for purchased power and net interchange is relatively stable, and the
reduction in purchased power expense is largely due to the decrease in the volume of market
purchases and long-term purchase power contracts. Coal fuel expense is $42 million lower than
Base NPC, driven by 6.4% increase in unit cost due to increasing costs per ton for delivered coal
and llYo reduction in generation due to lower natural gas prices and increased natural gas
generation.
Natural Gas
Although the unit cost of natural gas has droppedT.4% in20l6, the generation has
decreased as well due to lower load and lower volumes of wholesale sales. The "other" category
mostly includes wheeling, hydro generation, and wind generation. The Company indicates that
hydro and wind generation is very close to the Base NPC, but the wheeling expense has decreased
due to expired wheeling contracts.
Longwall
One of the reasons for the rising costs per MWh of coal was the unanticipated
abandonment of the Joy Longwall at Bridger Coal Company. Company Witness Wilding
explained that the abandonment of the Joy Longwall was due to unstable geologic conditions and
an unsafe working environment.
When the Company realized that it would be forced to abandon the longwall, the
Company wrote off the remaining asset amount (book value) of $12.5 million as well as the
6STAFF COMMENTS MAY 4,20t7
recovery costs of $7.6 million. Staff looked into the amounts included in this case for the
longwall abandonment and confirmed that the remaining asset value that was posted to the Jim
Bridger Plant coal cost was $12.5 million. Staff found that only some of the recovery costs were
posted during the months the work was performed and therefore expensed with the coal costs
from January 2016 to August 2016. The majority of the costs were then posted in September
2016 when it became evident that the longwall would need to be abandoned.
Under Generally Accepted Accounting Principles (GAAP) this is the correct method of
posting the loss for this event. The entire cost of abandonment, including the recovery costs,
increased Idaho allocated Net Power Costs by approximately $1.0 million, and the ECAM
deferral balance by approximately $900,000 due to sharing.
An alternative for regulatory purposes would be to place these expenses in a regulatory
asset. The Company has not requested an accounting order to do this. Staff agrees that the
Company's treatment of abandonment costs is appropriate for several reasons. The first is that by
leaving these expenses in the ECAM the Company shares in the expenses. Second, because the
change in net power costs in this case is already negative, these expenses can be absorbed in a
single year without increasing rates. Third, because this is an extraordinary expense, it will not be
included in the next year's ECAM and will therefore be a mitigating factor in future increases.
Fourth, Staff supports the Company's alternative rate proposal to decrease the depreciation
regulatory asset. Staff maintains that adding a regulatory asset as part of this case would be
inconsistent with that recommendation.
DSM
The DSM cost adjustment is calculated by subtracting the actual Idaho-allocated costs for
DSM load control programs from the DSM revenue collected through base rates. The adjustment
is a $71,884 reduction to the NPC defenal balance subject to the 90/10 sharing band. Staff
confirmed that the adjustment amount is accurate.
EITF 04-6
The EITF 04-6 is tracking the differences between coal stripping costs incurred by the
Company that is recorded as stated in the accounting pronouncement EITF 01-6, and the
7STAFF COMMENTS MAY 4,2017
amortization approved by the Commission in Case No. PAC-E-09-08 (subject to sharing). Staff
reviewed this adjustment and believes it is reasonable.
LCA
Staff reviewed the LCA and determined that it accurately adjusted for the under recovery
of fixed energy classified production costs due to actual loads that were lower than loads used to
set base rates. Staff examined the calculation and determined that it reflected the change to loads
at customer meter instead of loads at generation complying with Commission Order No. 33440.
As a result of the new calculation, the Company under-recovered $231,490 of fixed energy
classified production costs during the deferral period. This amount is subject to the 90110 sharing
band.
Production Tax Credit (PTC) Adiustment
In Case No. PAC-E-15-09, the Commission approved a settlement that moved PTC to the
ECAM at $ 1 .99 per MWh for a total $6.964 million for 2016. The Company eamed an Idaho-
allocated $6.467 million in PTC. Staff reviewed these calculations as well as the amount of PTC
earned in the 2016 year. Staff believes the Company complied with the Commission Order.
Lake Side 2 Resource Adder
In Case No. PAC-E-13-04,the Commission approved a Settlement Stipulation to allow
the Company to recover Lake Side 2 generation costs through the ECAM until the Company has
the opportunity to include them in base rates. See Order No. 32910. Staff believes the Company
has complied with this order by using the authorizedrate of $L99 per MWh of generation up to
the maximum of $5.43 million. In the year ending December 2016 the Company met the
maximum allowed by the Commission. The total deferral amount has exceeded the maximum,
but this was due to the 13-month deferral period. The excess amount of $0.43 million is due to
the amount accrued in December 2015.
Renewable Enersy Credit (REC) Adiustmcqt
REC prices remain low. In Case No. PAC-E-I5-09, the Commission approved a
settlement that moved $6.5 million in lower REC revenues from the ECAM to base rates effective
STAFF COMMENTS MAY 4,20t78
January 1,2016. See OrderNo. 33440. December 2015 represents $0.42 million of the
adjustment before the base rates were adjusted. The rest of the months in the deferral period
mitigated the adjustment amount to the $0.35 million balance.
SO2 Credits
SO2 sales revenues are no longer tracked in the ECAM, effective January 1,2016. There
were no SO2 sales in December 2015.
Analysis of Balancing Accounts
Staff reviewed the amounts and the methodology used in the balancing accounts and
believes the calculations are correct and that the ending balances are accurate. The balancing
account is used to keep a running total of monthly deferral amounts, collections through Schedule
94 ECAM rates, and monthly interest. In the PAC-E-I l-12 general rate case and as a result of
Order No. 32432, Monsanto and Agrium were authorized to amortize ECAM balances over a
3-year period requiring the Company to maintain separate balancing accounts for Monsanto,
Agrium, and tariff customers. At the end of that period, the Commission approved, in Order No.
33265, the Company's adoption of an equal monthly payment approach under which Monsanto
and Agrium would make equal monthly payments to retire their ECAM balances. After
reviewing the Company's ECAM balancing accounts, Staff believes the Company complied with
Commission Order No. 33265 by applying an equal payment approach starting April 2015 to
satisfy Agrium and Monsanto deferral amounts that accrued in the 2012 through2014 deferral
periods. Staff has confirmed the amounts were fully collected in March of 2016, and that separate
balancing accounts are no longer needed.
Analysis of Proposed Rates
The Company's existing ECAM tariff, Electric Service Schedule No. 94 is currently
designed to collect approximately $14.5 million annually or approximately $7 million more than
the current ECAM balance, resulting in an approximately 2.4 percent rate reduction for
customers. The $7 million reduction would typically flow through to all customer rates on an
equal line loss adjusted centslkWh basis beginning on June 1,2017 through reduced Schedule 94
rates.
9STAFF COMMENTS MAY 4,2017
Under the alternative Company proposal, rates would be reduced by $3 million from the
current level instead of the full $7 million, and approximately $4 million would be collected from
customers over the next year to offset the deferred regulatory asset created in Order No. 32910,
Case No. PAC-E-I3-02. This alternative rate proposal would still provide an immediate 1 percent
rate reduction for customers.
Staff reviewed the two rate plans proposed in this year's ECAM, and confirmed that the
Company's calculations were accurate, reasonable, and comply with prior Commission orders.
The traditional ECAM rate proposal decreases Schedule 94 rates by the full $7 million resulting
ina2.4 percent decrease effective on June 7,2077. The altemative rate plan helps to stabilize
rates in the ECAM for the next two years. The alternative proposal reduces Electric Service
Schedule No. 94 from a collection rate of approximately $14.5 million per year to approximately
$1 1.5 million per year, providing a $3 million or 1 percent customer rate reduction effective
June 1, 2017. The remaining $4 million reduction would be used to offset the depreciation
regulatory asset using incremental revenues collected through Schedule 94 rates.
In Case No. PAC-E-13-02 the Commission approved new depreciation rates that increased
Idaho's allocated depreciation expense by $1.7 million annually beginning January 1,2014.
Order No. 32910 authorized the Company to accrue those expenses into a depreciation regulatory
asset for recovery in the Company's next rate case. The Company has not filed a general rate
case since then and Staff has confirmed that as of December 31, 2016 the depreciation regulatory
asset balance is at $4.9 million. Staff agrees that retaining the $4 million of revenue from the
ECAM would reduce this regulatory asset significantly, and mitigates the need for recovery in a
future rate case. Staff supports this alternate rate proposal and recommends that the Schedule 94
rates and the depreciation regulatory asset be reduced accordingly.
Staff reviewed the Company's proposed ECAM rate based on the altemative rate plan and
found that it is appropriately applied to each customer class on a line-loss adjusted, equal cents
per kWh basis. A copy of the customer rate impacts for the ECAM with and without the rate
stability plan has been included as Attachment B and C, respectively, to these comments.
As noted above, the Company states that if the rate stability plan is approved, rates for
customer classes would decrease through the ECAM as follows:
. Residential Customers -.87oo Residential Schedule 35, Optional Time-of-Day Service - .9%o General Service Schedule 5 - 1.I%
STAFF COMMENTS 10 MAY 4,2077
. General Service schedule 9 - 1.2%
o Irrigation customers - .9Yoo Commercial or Industrial Heating Schedule 19 - 1.0%
o General Service Schedule 23 - .9%
o General Service Schedule 35 - 13%. Public Street Lighting - 0.4%
o Industrial Customer, Schedule 400 - 1.3%
o Industrial customer, Schedule 401 - 1.3%
Source: Application, Exhibit No. 5 to Direct Testimony of Ted Weston
CUSTOMER NOTICE AND PRESS RELEASE
The Company's press release and customer notice were included with its Application.
Staff reviewed the documents and determined that both meet the requirements of Rule 125 of the
Commission's Rules of Procedure (IDAPA 31.01.01).
The notice was included with customer bills. The last notice was mailed on AprrlZ7,
2017, which will allow most but not all customers a reasonable opportunity to file timely
comments with the Commission by the l|i4ay 4,2017, deadline. Staff does not believe customers
will object to the proposed rate decrease, but recommends that the Commission accept late-filed
comments to accommodate those customers whose bills are issued at the end of the billing cycle.
As of May 4,2017 , the Commission had received no comments from customers.
STAFF RECOMMENDATIONS
1 . Authori ze the ECAM deferral amount of gl ,526,845 for the period of Decemb er I , 2015
through December 31, 2016.
2. Adopt the Company's alternative rate plan to reduce Schedule 94 and reduce the
depreciation deferral.
3. Direct the Company to apply the $4.0 million in excess of the ECAM deferral amount to
reduce the depreciation regulatory asset authorized by Order No. 32910.
4. Direct the Company to submit tariffs that reflect Commission approved rates.
5. The Commission accept late-filled customer comments.
STAFF COMMENTS 11 MAY 4,2017
Respectfully submitted this qry day of May 2ol7.
General
Technical Staff: Joseph Terry
Yao Yin
Mike Louis
KevinKeyt
Daniel Klein
i:umisc : comments/pacel 7.2bkr$tyymlkkcomments
STAFF COMMENTS t2 MAY 4,2017
PacifiCorp dba Rocky Mountain Power Company
Enerry Cost Adjustment Mechanism
Audit Report (PAC-E-l 7-02)
by
Ioseph Terry
SCOPE
The scope of the audit was to examine the total power supply expenses of PacifiCorp dba
Rocky Mountain Power Company for the period of December 1,2015, through December 31,
2016, included for recovery in Case No. PAC-E-77-02, the Energy Cost Adjustment Mechanism
(ECAM). The audit consisted of an examination of the total fuel cost of all coal and natural gas
plants, purchased power, wheeling expenses, and sales for resale. Additionally, other costs
included in the ECAM have been reviewed. These costs include: Lake Side 2 resource adder,
Deer Creek Mine amortization, Renewable Energy Credits (REC) revenue, and Production Tax
Credits (PTC).
OVERALL AUDIT RISK
Audit risk is the risk that the financial statements are materially incorrect. Audit risk on
this audit is mitigated by several factors. The general financial risk occurs where a company
inflates net income by understating expenses and overstating revenues. In the ECAM the risk to
the customer would be that these expenses would be inflated, and therefore increase the recovery
amount or revenue earned through the ECAM. Company has a well-functioning internal audit
department with several audits performed in relation to the ECAM expenses and are thorough
and well documented. The 10% sharing of all power supply expenses above the base net power
costs increases the dollars required to be funded by shareholders, thus exposing shareholders to a
portion of the risk. This does not impact the Lake Side 2 resource adder, Deer Creek Mine
amortization, REC revenue, and PTC. Finally, this audit is performed annually and there have
been very few ifany exceptions noted in recent history.
INTERNAL AUDIT
Internal audit reports relating to the ECAM were available for review onsite in Portland.
Six internal audits in the 2015 and 2016 years were reviewed involving Cholla plant operation,
migratory bird compliance, two on Colstrip joint ventures, deferral mechanism controls, and
Hayden operations. The reports were detailed and complete with all exceptions noted and
correction steps identified and implemented.
SALES FOR RESALE
The audit sample was a non-random selection. Four counterparties were selected. All
entries for two different accounting months for each counterparty were reviewed. These entries
were traced back to the invoice, and then that invoice was checked with the applicable contract
to ensure all terms where correct. No exceptions were found.
Redacted Attachment A
Case No. PAC-E-I7-02
Staff Comments
05104117 Page I of 4
PURCHASED POWER
The audit sample was a non-random selection. Seven counterparties were selected. All
entries for at least two accounting months for each counterparty were reviewed except for one,
which was a small amount and therefore only one accounting month was selected. These entries
were traced back to the invoice, and that invoice was checked with the applicable contract to
ensure all terms were correct. No exceptions were found except for one entry that was for $0.01
for which the Company explained was a rounding error. I found that explanation adequate for
the amount.
WHEELING EXPENSE
The audit sample was a non-random selection. Two counterparties were selected. All
entries for four accounting months on one counterparty, and one accounting month for the other
was selected for review. These entries were traced back to the invoice, and that invoice was
checked with the applicable contract to ensure all terms were correct. No exceptions were found.
COAL FUEL EXPENSES
The coal fuel expense audit requires two steps. The first step is to audit the delivery costs
of coal, and the second step is to use those amounts to calculate the costs of the coal burned.
Average cost per ton delivered was lower in five of the plants and higher in the other five.
I expect that this may be an issue in the next ECAM audit.
The audit sample was a relatively random selection. Eight plants were selected for
different months, and another plant was selected for several months in a row. The Company uses
a weighted average cost of coal calculated on a monthly basis for the fuel cost. Therefore there
are two steps in the audit to verify monthly fuel costs. The first step is to audit all the deliveries
for that month. The second step was to audit the amount of coal bumed for that month, and then
double check all the formulas that determine the fuel costs for that month for that plant.
For the audit selection, the received amounts were traced to their respective invoices, and
then tracked back to the applicable contract to ensure that all terms were correct
exceptions were noted.
To audit the coal consumed I started with the hourly generation report. I then used that
report with the plant burn rates to calculate the amount of coal that was burned for that month.
This amount was compared with the monthly amounts reported by the Company. When
reconciling the hourly generation report to the monthly generation amount, I noted minor
discrepancies. However, the variances were not material. From that point there were no
exceptions noted.
No
Redacted Attachment A
Case No. PAC-E-17-02
Staff Comments
05104117 Page2 of 4
NATURAL GAS FUEL EXPENSE
The natural gas plants do not have individual storage capabilities. Therefore the natural
gas purchases for each month are reflective of the actual fuel expenses for that month. The only
storage facility is the Clay Basin storage facility.
Initial analysis showed that natural gas prices continued to decrease until the end of the
year when there was a price rebound.
The audit sample was a non-random selection. Two counterparties were
selected from two months and all entries were traced from the booked amounts to the trade
invoice. No exceptions were found.
Natural gas fuel expense is recorded at a system level and then allocated to the individual
plants. Expenses for some plants can be directly allocated, however, the Wasatch front uses an
indirect allocation process. The audit sample was a non-random selection. Ten different
selections were made, including one dealing with the Clay Basin storage facility. The Clay
Basin storage facility has a running weighted average cost of gas for every withdrawal. These
entries were traced to the invoice to ensure all terms were correct. No exceptions were found.
LAKE SIDE 2 RESOURCE ADDER
The Lake Side 2 resource adder was established in Order No. 32910 Case No. PAC-E-I3-
04. The adder amount is $1.99 per MWh up to a maximum of 2,729,00 MWh. The amount of
energy produced by Lake Side 2 was confirmed with the hourly generation logs. There were
some discrepancies between the hourly generation logs and the amounts used to calculate the
costs included in the ECAM. The difference does not create a material change in the ECAM
amounts as the Lake Side 2 power plant generated more power than the maximum allowed for
recovery so the dollars in the ECAM are capped.
DEER CRE,EK MINE AMORTIZATION
The Deer Creek Mine Amortrzation was calculated and set in Case No. PAC-E-14-10.
The amounts were audited in the previous ECAM, Case No. PAC-E-16-05, and found to be
accurate. The amortization expense has not changed from that case. In Case No. PAC-E-15-09,
the amount of net power costs in base rates was adjusted effective January 2016. Therefore the
amount in base rates was changed and the System Energy (SE) Allocation factor was also
adjusted slightly, causing the amount included in this line item to increase beginning in January
2016. This calculation was reviewed and confirmed.
RENEWABLE ENERY CREDITS (RE,C)
The REC audit sample was a non-random selection of three months of transactions.
These transactions were traced back to the invoice, and that invoice was checked with the
applicable contract to ensure all terms were correct. No exceptions were found.
Redacted Attachment A
CaseNo. PAC-E-17-02
Staff CommentsO5l\4ll7 Page 3 of 4
PRODUCTION TAX CREDITS (PTC)
The PTCs were included in the ECAM in Order No. 33440, Case No. PAC-E-15-09. The
monthly amounts were calculated based on Financial Accounting Standards (FAS) Interpretation
Number (FIN) 18. Under FIN 18 the PTC amounts allocated to each month will vary but, there is
no effect on the annual amounts, as the prescribed methodology automatically trues up the
amounts in the last month of the year. These calculations were reviewed and verified. The
MWh produced by the wind projects were reviewed and confirmed with the hourly generation
log. There was some trouble reconciling the hourly generation report to the monthly generation
amount. However, the variances were not material.
Redacted Attachment A
Case No. PAC-E-17'02
StaffComments
05104117 Page 4 of 4
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Case No. PAC-E-I7-02
Staff Comments
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Attachment U
Case No. PAC-E-L7-02
Staff Comments
05/04/17
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CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 4th DAY OF MAY 2017,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. PAC-E-17-02, BY MAILING A COPY THEREOF, POSTAGE PREPAID,
TO THE FOLLOWING:
TED WESTON
ROCKY MOUNTAIN POWER
1407 WEST NORTH TEMPLE STE 330
SALT LAKE CITY UT 841 16
E-MAIL: [e-mail]
Confi dential Information
DATA REQUEST RESPONSE CENTER
E.MAIL ONLY:
datarequest@paci fi corp. com
Non-Confi dential Information
BRUBAKER & ASSOCIATES
16690 SWINGLEY RIDGE RD #140
CHESTERFIELD MO 63017
E-MAIL: [e-mail]
Non-Confi dential Information
ANTHONY YANKEL
I27OO LAKE AVENUE
I.INIT 2505
LAKEWOOD OH 44107
E-MAIL: [e-mail]
Non- Confidential Information
WONNE R HOGLE
ASSITANT GENERAL COUNSEL
ROCKY MOI-iNTAIN POWER
1407 WN TEMPLE STE 320
SALT LAKE CITY UT 841 16
E-MAIL: [e-mail]
Confi dential Information
RANDALL C BUDGE
RACINE OLSON NYE & BUDGE
PO BOX 1391
POCATELLO ID 83204-1391
E-MAIL: [e-mail]
Non- Confi dential Information
ERIC L OLSEN
ECHO HAWK & OLSEN PLLC
505 PERSHING AVE STE lOO
PO BOX 6119
POCATELLO ID 83205
E-MAIL: [e-mail]
Non-Confi dential Information
ARYS
CERTIFICATE OF SERVICE