20090326PAC to Staff 1-8.pdf

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~ROCKY MOUNTAIN
POWER
A DISION OF PAFlCORP l\!r ,~'
201 Sout Main, Suite 2300
Salt Lake Cit, Uth 84111
ionq MAR 2.6 PM 2i \ 1
March 25, 2009
Scott Woodbur
Deputy Attorney General
Idao Public Utilties Commission
472 W Washigton
Boise,ID 83702-5983
RE: PAC-E-08-08
IPUC _Production Data Request (1-8)
Please fid enclosed Rocky Mounta Power's Responses to IPUC_Production Data Request
Numbers 1-8. Provided on the enclosed CD are Attchments IPUC_Production 1 and 2.
Provided on the enclosed Confdential CD are Confdential Attchments IPUC _Production 4 -
(1-2). The Confdential Atthments are being provided to paries who have signed a
confdentiality agreement pursuat to the protective order in this case.
If you have any questions, please feel free to call me at [phone].
Sincerely,
100 ~Ov '(
Ted Weston, Manager
Reguation
Enclosures
Cc: Jean JewellfIUC
Eric OlsenllPA
Tony Y anellIIP A
Radall C. Budge
Katie Iverson
P AC-E-08-08/Rocky Mountain Power
March 25,2009
¡PUC Production Data Request 1
IPUC Production Data Request 1
Please provide a backcast of the methodology that the Company is proposing for
the period January 2006 to present. Show how the accounts included in the
ECAM mechanism would have changed over the period and why the calculation
of the Energy Cost Adjustment Mechanism (ECAM) rate for each anual period
and how the monthly deferral balance would have changed during the period
when ECAM rates were in effect.
Response to IPUC Production Data Request 1
Please refer to Attachment ¡PUC Production 1.
p. Ted Weston prepared this response and is the recordholder. Gregory N. Duvall
is expected to sponsor this response at hearing. Please contact J. Ted Weston at
801-220-2963 to discuss this response.)
IDAHO
PAC-E-08-08
ROCKY MOUNTAIN POWER
IPUC PRODUCTION DATA REQUEST (1-8)
ATTACHMENT ¡PUC PRODUCTION 1
ON THE ENCLOSED CD
P AC-E-08-08/Rocky Mountain Power
March 25, 2009
IPUC Production Data Request 2
IPUC Production Data Request 2
Please provide the same backcast information provided for Request No. 1 with
ECAM methodology modified to include:
a) 90/10 customer/company sharing of deferred power supply costs
b) An adjustment of$30/MWH for load above or below monthly normalized
loads approved by the Commission
c) An annual interest rate of 2% applied to the deferral balance
Response to IPUC Production Data Request 2
Please refer to Attachment IPUC Production 2.
In this analysis, the Company has reflected the assumptions stated above.
However, concerning subpar b, RMP believes $17.48/MWh is a more correct
value to use to avoid removing net power costs twice from the Company's
ECAM. Please refer to the Company's response to IPUC Production Data
Request 5 for the derivation of $17 .48/MWh. The $30/MWh in subpar b
includes both variable net power costs and fixed generation costs and, in RMP's
view, would remove net power costs twice since the net power costs included in
base rates are already excluded from the Company's ECAM by netting the base
NPC $/MWh against the actual $/MWh.
(J. Ted Weston prepared this response and is the recordholder. Gregory N. Duvall
is expected to sponsor this response at hearing. Please contact J. Ted Weston at
801-220-2963 to discuss this response.)
IDAHO
P AC-E-08-08
ROCKY MOUNTAIN POWER
IPUC_PRODUCTION DATA REQUEST (1-8)
ATTACHMENT IPUC PRODUCTION 2-
ON THE ENCLOSED CD
PAC-E-08-08/Rocky Mountain Power
March 25,2009
IPUC Production Data Request 3
IPUC Production Data Request 3
Please provide a description of power supply tracking mechanisms either existing
or proposed in other PacifiCorp state jurisdictions. Include in the description the
power supply accounts tracked and the history of rate adjustments since inception.
Response to IPUC Production Data Request 3
PacifiCorp curently has power cost tracking mechanisms in place in California,
Oregon and Wyoming with an application pending in Idaho and Utah. Utah
required legislative changes before a mechanism could be implemented. That
legislation was approved in March 2009 and the Company fied its Energy Cost
Adjustment Mechanism (ECAM) application in Utah in March 2009. Utah's
ECAM application is consistent with the application pending in Idaho.
California:
The California Energy Cost Adjustment Clause (ECAC) was approved by the
California Commission in December 2006 with a January 1, 2007 effective date.
The ECAC tracks all net power cost accounts as modeled in GRID, the same
accounts included in the Idaho application. California utilzes a forecast to set the
base for net power costs. The California ECAC tracks actual net power costs
compared to the NPC forecast and resets base net power costs anually. The
California ECAC allows for full recovery of the difference between actual net
power costs and those collected through rates. There are two components to the
ECAC, the offset rate and the balancing rate. The offset rate allows the Company
to update forecasted net power costs that are currently in rates annually. The
balancing rate is used to true-up actual power costs to what was collected in rates
for the prior period. Monthly entries are made to a balancing account and the
balance is recovered from or retured to customers through the balancing rate.
Rates are updated only if the new rates vary +/- 5% or more from current rates.
PacifiCorp updates the rates with a filing each August 1 with rates effective the
following January 1. No changes have been made to the mechanism since it was
approved.
The California ECAC deferral account balance for 2007 was $599,000 under
recovery and for 2008 the ECAC balance was $183,000 over collection.
Oregon:
The Oregon Public Utilties Commission approved PacifiCorp's Transition
Adjustment Mechanism (TAM) in September 2004 in Order 05-1050 (UE 170).
Net power costs (NPC) in Oregon are recovered through the annual Transition
Adjustment Mechanism (TAM). The TAM updates NPC for supply service
customers and sets the transition adjustment for customers electing to take direct
access in the following year. The TAM includes all NPC accounts, as modeled in
GRID, and is based on a forecast fied annually in April (outside of a general rate
PAC-E-08-08/Rocky Mountain Power
March 25,2009
IPUC Production Data Request 3
case). This fiing is limited to include only the following updates to PacifiCorp's
NPC: (1) forward price cure; (2) forecast loads; (3) normalized hydro
generation; (4) forecast fuel prices; (5) contract updates; (6) thermal heat rates,
planed outages and de-rates; (7) wheeling expenses; (8) new resource
acquisitions; and (9) state allocation factors. At the time the Company makes its
rebuttal filing, which is generally at the end of July, PacifiCorp updates the filing
to reflect: (1) the current forward price curve; and (2) new contracts and/or
updates for wholesale sales, purchases, fuel and wheeling expenses. After the
Commission's order is issued in the TAM in late October, PacifiCorp incorporates
any Commission-ordered changes and updates costs for a new forward price
cure and for contracts entered into by November 1 for the calculation
of indicative transition adjustments, which are fied by November 8, 2007. There
is one final update for net power costs with the latest forward price cure and
final transition adjustment rates, which is filed by November 15 with rates
effective January 1. No changes to the TAM have been made since it was
established in 2004.
There is no true-up to actual NPC with the TAM.
Wyoming:
The Wyoming Public Service Commission approved PacifiCorp's Power Cost
Adjustment Mechanism (PCAM) in February 2006. The PCAM includes the same
NPC accounts included in the Company's Idaho application, as modeled inGRID.
NPC have been unbundled in Wyoming and are collected through the PCAM with
anual fiings. The Wyoming PCAM has a $40 milion (total company) dead band
above or below the base NPC with sharing ratios outside the dead band. From $40
to $100 milion the sharing ratio is 70/30, from $100 - $200 milion it is 85/15
sharing and over $200 milion it has a 90/1 0 sharing band. The Wyoming PCAM
was implemented as part of a lawsuit and the base NPC were set artificially low.
No changes to the PCAM have been made since it was established in 2006.
Wyoming's PCAM deferral for the 2006 period was $2.4 milion, for the 2007
period it was $31.3 milion and for 2008 the deferral was $26.8 milion.
p. Ted Weston prepared this response and is the recordholder. Gregory N. Duvall
is expected to sponsor this response at hearing. Please contact J. Ted Weston at
801-220-2963 to discuss this response.)
PAC-E-08-08/Rocky Mountain Power
March 25, 2009
IPUC Production Data Request 4
IPUC Production Data Request 4
Please describe the risk management strategy employed by the Company for
market energy/capacity purchases and how that strategy could/wil impact the
power supply costs that flow through the proposed ECAM mechanism.
Response to IPUC Production Data Request 4
PacifiCorp employs several approaches to manage risk and control costs that
impact net power costs.
One way risk is managed is through portfolio scenario analysis and stochastic
production cost modeling conducted as par of the IRP process. With the use of a
capacity expansion optimization model, resource portfolios are developed
according to a range of input scenaros focusing on wholesale electricity prices,
gas prices, and carbon dioxide regulatory compliance costs. Monte Carlo
production cost simulation is used to assess stochastic risk for each portfolio.
A second approach employed to control power costs as par of the IRP process is
pursuit of demand side management as a priority resource. The Idaho irrigation
load control program is an example of this effort. With cooperation from
agricultural customers, the irrigation load management program grew from 80
MW to 215 MW in 2008. Work continues to expand energy efficiency activity
and increase acquired savings with the promotion of current offerings in addition
to the issuance of a DSM RFP for new programs, which was issued in November
2008.
In addition to the IRP process and DSM activities the Company adheres to
PacifiCorp Energy's risk management policy which describes position limits, a
value at risk limit, stop loss limits and credit risk management. Please refer to
Confidential Attachment IPUC Production 4 -1.
The Company also has a formal hedge strategy which describes volume hedge
tagets and price targets. Please refer to Confidential Attachment
IPUC Production 4 -2.
These documents describe procedures used to manage and report the commodity
price risks that could impact net power costs. This approach is intended to
reduce fluctuations in net power costs that would otherwise be seen absent
hedging, to limit exposure to market price volatilty for the forward rollng 48-
month period and to limit credit exposure resulting from hedge transactions. The
hedge program is expected to reduce the amount of any ECAM dollars compared
to a scenario under which the company did not hedge or hedged less.
PAC-E-08-08/Rocky Mountain Power
March 25,2009
IPUC Production Data Request 4
Confidential information is provided subject to the terms and conditions of the
protective order in this proceeding.
(Pete Warnen and Gregory N. Duvall prepared this response and are the
recordholders. Gregory N. Duvall is expected to sponsor this response at hearing.
Please contact J. Ted Weston at 801-220-2963 to discuss this response.)
IDAHO
PAC-E-08-08
ROCKY MOUNTAIN POWER
IPUC_PRODUCTION DATA REQUEST (1-8)
CONFIDENTIAL (LEVEL YELLOW)
ATTACHMENT IPUC_PRODUCTION 4 -(1-2)
ON THE ENCLOSED CONFIDENTIAL CD
P AC-E-08-08/Rocky Mountain Power
March 25, 2009
IPUC Production Data Request 5
IPUC Production Data Request 5
Please provide the unbundled production revenue requirement per kWh on a
system basis that is curently embedded in rates.
Response to IPUC Production Data Request 5
The total Company production revenue requirement on a dollar per MWh basis is
$34.39 as shown below, calculated as prescribed in IPUC Order No. 30715. This
calculation was used to determine the Load Growth Adjustment Rate (LGAR).
The inputs for this calculation, (as referenced in this Table), are from the
Settlement models in Docket No. PAC-E-08-07.
Unbundled Production Revenue requirement (Per IPUC Order No.3071S)
Description I Amount I Source
1 Production. Return On Investment 615,420,689 JAM Tab ECD
2 Production - Expense 3,624,067,686 JAM Tab ECD
3 Production - Revenues (2,242,830,255)RAM Tab 5, Adj No 1
Production Revenue Requirement 1,996,658,120 (Line 1 + Line 2 - Line 3)
System Load 58,052,638 RAM Tab 5, Adj No 1
Production $ per MWh $34.39
IPUC Order No. 30715 relates to Idaho Power's petition for approval of changes
to its power cost adjustment (PCA) mechanism. Rocky Mountain Power's Energy
Cost Adjustment Mechanism (ECAM) is unique from Idaho Power's PCA. Rocky
Mountain Power's ECAM is calculated on a $/MWh differential between base net
power costs and actual net power costs. The calculation subtracts the base $/MWh
rate established in a general rate case from the actual $/MWh net power costs
(NPC) expense incured to serve customers. This method removes the base net
power costs included in rates from load growth leaving only the incremental
increase or decrease in NPC. Including NPC expense the LGAR for Rocky
Mountain Power would remove these cost twice, once through the $/MWh
differential and again through the LGAR. The Company has utilzed the same
methodology from Order No. 30715 but excluded NPC from the calculation to
avoid this double count. The second table is a calculation of the LGAR that would
be appropriately applied to the Company's ECAM to avoid this double count.
P AC-E-08-08/Rocky Mountain Power
March 25,2009
IPUC Production Data Request 5
Unbundled Production Revenue reQuirement (Excludimi: Net Power Costs)
Description Amount Source
1 Production - Return On Investment 615,420,689 JAM TabECD
2 Production - Expense 3,624,067,686 JAM Tab ECD
3 Production. NPC Expenses (3,224,837,687)RAM Tab 5, Adi No 1
Production Revenue Requirement
(Line 1 + Line 2 - Line 3)(Excluding NPC)1,014,650,688
System Load 58,052,638 RAM Tab 5, Adi No 1
Production $ per MWh $17.48
(J. Ted Weston prepared this response and is the recordholder. Gregory N. Duvall
is expected to sponsor this response at hearing. Please contact J. Ted Weston at
801-220-2963 to discuss this response.)
PAC-E-08..08/Rocky Mountain Power
March 25,2009
IPUC Production Data Request 6
IPUC Production Data Request 6
To evaluate the impact of an Idaho ECAM on corporate financial statements,
please quantify and provide the workpapers showing the anual impact on total
Company earnings. Please include at least the impact in dollars, cash flow
impact, change in percent or basis points of return on equity, etc. Please provide
workpapers in Excel with formulas activated and operationaL.
Response to IPUC Production Data Request 6
Net power costs currently in rates in Idaho from Case No. PAC-E-07-05 on a total
Company basis are $827.9 milion. Actual net power costs for the twelve months
ended December 2008 were $1,120 milion. Approximately $18 milion ofthis
$292 milion net power cost differential would be allocated to Idaho. In Idaho 100
basis points is approximately $4.5 milion, so the $18 milion under recovery
represents a 400 basis point impact to Idaho's ROE. The $292 millon differential
is approximately 440 basis point impact on total company earings. Net Power
Costs have a significant financial impact on the Company and its abilty to
recover its prudently incured expenses to serve customers.
As Mr. Duvall noted in his testimony:
The Company's net power costs can fluctuate between
twenty-five to thirty-three percent of the Company's total
revenue requirement. They are subject to a high degree of
volatilty largely outside of the Company's control. Some of
the factors causing this volatilty include changes in retail
load, hydro conditions, wind generation, market prices,
third party wheeling expenses, natural gas and coal fuel
expenses. Because the Company depends on both the
electricity and natural gas markets to balance its system
and meet the load requirement, fluctuations in the markets
invariably impact the Company's net power costs. Coal
expenses, which were previously relatively stable, are
affected by changes in commodity costs due to contract re-
openers, and even the captive mine costs may change
signifcantly in today's environment due to the rapid
escalation of the costs of mining equipment and supplies.
An ECAM would give the Company an opportunity to
recover the net power costs that are prudently incurred to
serve customers.
PAC-E-08-08/Rocky Mountain Power
March 25, 2009
IPUC Production Data Request 6
Not only would an ECAM strengthen the Company's credit rating, which benefits
customers through reduced debt costs, it would also send a better price signal to
customers. Annual power costs updates would provide a more accurately notice to
customers of the cost of electricity which could encourage more efficient use of
energy.
p. Ted Weston prepared this response and is the recordholder. Gregory N. Duvall
is expected to sponsor this response at hearing. Please contact J. Ted Weston at
801-220-2963 to discuss this response.)
P AC-E-08-08/Rocky Mountain Power
March 25, 2009
IPUC Production Data Request 7
IPUC Production Data Request 7
Gregory Duvall on page 2 of testimony discusses volatilty largely outside the
Company's control. For each factor please provide a list of each process and
description of that process utilzed by the Company to control the volatilty. In
the answer also identify the areas where the process is completed, for instance a
process for planing, modeling, operations, etc.
Response to IPUC Production Data Request 7
(a) Changes in Retail Load:
Net power costs in Idaho are based on historical loads. Most fluctuations
in load are driven by weather, customer growth, or usage patterns. The
Company has no control over the impact weather has on Company loads.
The Company's demand side management (DSM) programs are designed
to influence customer growth by educating and promoting more efficient
use of energy. These DSM efforts dampen upward pressure created
through additional load growth.
(b) Hydro Conditions
To mitigate impact of hydro production variabilty and uncertainty in daily
operations, hydro generation is scheduled on a day-ahead basis taking into
account current weather and inflow forecasts.
(c) Wind Generation
Wind generation is scheduled hourly on a day-ahead basis by project.
Hourly forecasts are also created for up and down regulating margin on a
day-ahead basis.
(d) Market Prices
Please refer to the Company's response to IPUC Production Data Request
4.
(e) Third Party Wheeling Expenses:
PacifiCorp serves load on firm transmission and uses non-firm
transmission, when available,.for economic optimization. This strategy
minimizes exposure to use of third pary non-firm transmission. During
abnormal system conditions PacifiCorp wil use third pary non-firm
transmission to avoid load curtailment.
(I) Natural Gas Expenses:
Please refer to the Company's response to IPUC Production Data Request
4.
P AC-E-08-08/Rocky Mountain Power
March 25,2009
IPUC Production Data Request 7
(g) Coal Expenses:
The Company through its fuel procurement strategies attempts to
minimize coal price volatilty while providing optimum quality coal for
the thermal plants. The Company has been able to minimize fuel cost by
employing the following measures:
. Entering a mix of spot, short-term and long-term contract agreements
in order to diversify its exposure to changing market conditions.
. Contract Supply flexibilty - Negotiates the option to switch a portion
of the contract tonnage to a secondary source. This flexibility
mitigates the Company's supply risk and allows improved plant
performance through enhanced coal blending and minimizes costs.
. Contract pricing - Employ price collars to mitigate price volatility.
. Distressed coal purchases - The Company purchases discounted, albeit
non-compliant coal, when available provided the Company is able to
blend the coal and maintain acceptable quality levels.
. Competitive Bidding and Negotiations - The Company procures fuel
and transportation through competitive bidding.
(Gregory N. Duvall and Brian T. During prepared this response and are the
recordholders. Gregory N. Duvall is expected to sponsor this response at hearing.
Please contact J. Ted Weston at 801-220-2963 to discuss this response.)
~
P AC-E-08-08/Rocky Mountain Power
March 25, 2009
IPUC Production Data Request 8
IPUC Production Data Request 8
Please provide analyses showing why a 90/10 customer/Company sharing of
deferred power supply costs is inadequate or not appropriate.
Response to IPUC Production Data Request 8
As noted in the responses to IPUC Production Data Requests 4 and 7, the
Company has developed and implemented several risk mitigation programs.
These programs include PacifiCorp's Energy risk management policy which
defines position limits, a value at risk limit, stop loss limits and credit risk
management. The Company also has a formal hedge strategy which defines
volume hedge targets and price targets. PacifiCorp also has an extensive
integrated resource planing process which includes representatives from five of
the six states we serve. These include commission staff, state agencies, low
income agencies, commercial, industrial and special interest groups. The
Company continues to enhance its demand-side management programs. These
programs under go regular review and cost benefit demonstration. Idaho recently
acknowledge that the Company's DSM programs were prudent, cost effective and
in the public interest.
All of these programs help determine and control how power costs impact Rocky
Mountain Power's customers. The Company has a strong incentive to make
prudent resource decisions. Every decision made by the Company is scrutinized
by parties from six different jurisdictions. The Company curently has several
system controls in place to reduce risk these controls would continue to be
utilized with the approval of an ECAM. Rocky Mountain Power is committed to
being a low cost energy provider. The Company does not believe it needs
additional incentive to make prudent decisions. As noted in response to IPUC
Production Data Request 6 fluctuations in power costs can represent over 400
basis point impact to Company earings. With or without power costs
mechanisms the Company is focused on controllng costs and minimizing risk for
our customers.
Rocky Mountain Power's ECAM application requested dollar for dollar recovery
of net power costs. The Company believes that it should be allowed an
opportunity to recover all prudently incurred net power costs. Rocky Mountain
Power recognizes that Idaho currently has sharing ratios with Idaho Power and
A vista, and in consideration of this fact, the Company is wiling to accept 95% /
5% sharing bands which provide a strong incentive for the Company to make
prudent resource acquisition decisions without unduly putting the Company at
risk for non-recovery of prudently incurred power costs.
'" '..
PAC-E-08-08/Rocky Mountain Power
March 25,2009
IPUC Production Data Request 8
(J. Ted Weston prepared this response and is the recordholder. Gregory N. Duvall
is expected to sponsor this response at hearing. Please contact J. Ted Weston at
801-220-2963 to discuss this response.)