20090707Vol III (Boise) Pgs 22-318.pdf

e BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF AVISTA CORPORATION FOR THE
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC AND
NATURAL GAS SERVICE TO ELECTRIC
AND NATURAL GAS CUSTOMERS IN THE
STATE OF IDAHO.
CASE NOS.
AVU-E-09-01
AVU-G-09-01
TECHNICAL HEARING
HEARING BEFORE
COMMISSIONER MACK A. REDFORD (Presiding)
COMMISSIONER MARSHA H. SMITH
COMMISSIONER JIM D. KEMPTON.,-'
PLACE:Commission Hearing Room
472 West Washington Street
Boise, Idaho
DATE:June 29, 2009
VOLUME III - Pages 22-318
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COURT REPORTING
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1 APPEARANCES
2
3 For the Staff:DONALD L. HOWELL, II, Esq.
-and-
KRISTINE A. SASSER, Esq.
Deputy Attorneys General
472 West Washington
Boise, Idaho 83702
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For Avista:DAVID J. MEYER, Esq.
Avista Corporation
Post Office Box 3727
Spokane, Washington 99220-3727
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9 For Idaho Forest Group:MCDEVITT & MILLER, LLP
by DEAN J. MILLER, Esq.
420 West Bannock Street
Boise, Idaho 83702
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For Clearwater Paper Corp.:GIVENS PURSLEY, LLP
by MICHAEL C. CREAMER, Esq.
601 West Bannock Street
Boise, Idaho 83702
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14 For Idaho Cons. League:BETSY BRIDGE
Idaho Conservation League
710 North Sixth Street
Boise, Idaho 83702
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For CAPAI:BRAD M. PURDY, Esq.
Attorney at Law
2019 North Seventeenth Street
Boise, Idaho 83702
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HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
APPEARANCES
1 I N D E Xe2
WITNESS EXAMINATION BY PAGE
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Scott L.Morris Prefiled Direct 26
4 (Avista)
5 Mark Thies Prefiled Direct 58
(Avista)
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William E.Avera Prefiled Direct 108
7 (Avista)
8 Richard L.Storro Prefiled Direct 167
(Avista)
9 Clint G.Kalich Prefiled Direct 200
10 (Avista)
11 William G.Johnson Prefiled Direct 214
(Avista)
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Don F.Kopczynski Prefiled Direct 237e13(Avista)
14 Scott J.Kinney Pre filed Direct 251
(Avista)
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Dave B.DeFelice Prefiled Direct 288
16 (Avista)
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20 E X H I B I T S
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NUMBER PAGE
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15.(Originally marked as Exhibit No.2,Marked 15
23 Norwood,in support of Stipulation. )Remarked 764
Stipulation and Settlement,23 pgs
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HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
INDEX
EXHIBITS
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1 BOISE, IDAHO, MONDAY, JUNE 29, 2009, 9: 33 A.M.
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4 COMMISSIONER REDFORD: Why don't we come to order
5 and begin. This will be -- this is the Idaho Public Utili ties
6 Commission.
7 My name is Mack Redford, and I i II be the Chair of
8 this proceeding today. Seated to my left is Marsha Smith, a
9 Commissioner. Seated to my right is Jim Kempton, who is the
10 President of the Commission and also a Commissioner.
11 The hearing today will be in the matter of the
12 Application of Avista Corporation for the authority to increase
13 its rates and charges for electric and natural gas service to
14 electric and natural gas customers in the state of Idaho. The
15 Case Nos. are AVU-E-09-01 and AVU-G-09-01. Particularly, the
16 hearing today is on the issue of the Stipulation and
17 Settlement, which has been -- I understand has been signed by
18 not only the Public Utili ties Staff, but also the Utility
19 Avista, and also the Intervenors -- all the Intervenors. If
20 that i s not correct, please let me know right now.
21 Okay, hearing nothing, again, this is a hearing
22 on the Stipulation and Settlement.
23 First of all, we i II take the appearances, and
24 we'll start with you, Mr. Meyer.
25 MR. MEYER: Thank you, Mr. Chairman. David Meyer
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HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
COLLOQUY
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1 for Avista.
2 COMMISSIONER REDFORD: Thank you.
3 MR. HOWELL: Mr. Cha i rman, my name is Don Howe 1 l,
4 Deputy Attorney General, and with me is Kristine Sasser, also a
5 Deputy Attorney General, on behalf of the Commission Staff.
6 COMMISSIONER REDFORD: Okay. Sir.
7 MR. CREAMER: Mr. Chairman, Michael Creamer on
8 behalf of Clearwater Paper Corporation.
9 COMMISSIONER REDFORD: Who is that again?
10 MR. CREAMER: Michael Creamer for Clearwater
11 Paper Corporation.
12 COMMISSIONER REDFORD: Oh, yes. Thank you.
13 MR. MILLER: Thank you, Mr. Chairman. Dean J.
14 Miller of the firm McDevitt and Miller for Idaho Forest Group.
15 COMMISSIONER REDFORD: Mr. Purdy.
16 MR. PURDY: Yes. Brad Purdy on behalf of the
17 Communi ty Action Partnership Association of Idaho.
18 COMMISSIONER REDFORD: Thank you.
19 MS. BRIDGE: Betsy Bridge on behalf of the Idaho
20 Conservation League.
21 COMMISSIONER REDFORD: Thank you. We need to
22 make sure once you i re speaking that you all push the button so
23 we can all hear.
24 Are there any other parties or persons that are
e 25 appearing today?
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HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
COLLOQUY
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1 Hearing none, we will start the proceeding, and,
2 Mr. Meyer, inasmuch as you are the Applicant in this case,
3 we i II go ahead and turn this matter over to you.
4 Oh, first of all, could the parties tell me --
5 we've got two witnesses: Mr. Lobb and Mr. Norwood. Are there
6 any other witnesses? We had previously believed that possibly
7 the only witnesses would be from the Staff and from the
8 Company. If there are any other witnesses, could you let me
9 know?
10 Hearing none, I'll presume that those are the two
11 witnesses.
12 Mr. Meyer.
13 MR. MEYER: Mr. Chairman, a procedural matter
14 before we begin, and I believe Mr. Howell was going to talk
15 about having or at least asking that all the testimonies and
16 exhibits that have been prefiled, not just in support of the
17 Settlement but initially, be spread into the record and
18 admi tted, and that was going to be by Stipulation.
19 MR. HOWELL: The Staff would certainly agree with
20 that. That was also the understanding of the parties.
21 COMMISSIONER REDFORD: Is there any obj ection to
22 that proceeding?
23 Hearing none, we will go ahead and spread all the
24 testimony on the record as if it was read into the record.
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HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
COLLOQUY
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1 (The following prefiled direct testimony
2 of Avista 'Wi tnesses Scott L. Morris, Mark Thies, William E.
3 Avera, Richard L. Storro, Clint G. Kalich, William G. Johnson,
4 Don F. Kopczynski, Scott J. Kinney, Dave B. Defelice,
5 Elizabeth'M. Andrews, Tara L. Knox, Brian J. Hirschkorn, and
6 Bruce W. Folsom; Staff Witnesses Randy Lobb, Lynn Anderson,
7 Keith Hessing, Rick Sterling, Joe Leckie, Donn English,
8 Cecily Vaughn, Terri Carlock, Matt Elam, Bryan Lanspery,
9 Marilyn Parker, and Curtis Thaden; Idaho Forest Group Witness
10 Larry A. Crowley; Clearwater Paper Corporation Witness
11 Dennis E. Peseau; and CAPAI Witness Teri Ottens; as well as
12 prefiled direct testimony in support of Settlement of Avista
13 Wi tness Kelly Norwood and Staff Witness Randy Lobb, was spread
14 upon the record.)
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HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
COLLOQUY
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I. INTRODUCTION
Q. . Please state your name, employer and business
3 address.
4 A.My name is Scott L. Morris and I am employed as
5 the Chairman of the Board, President, and Chief Executive
6 Officer of Avista Corporation (Company or Avista), at 1411
7 East Mission Avenue, Spokane, Washington.
8 Q.Would you briefly describe your educational
9 background and professional experience?
10 A.Yes. I am a graduate of Gonzaga Uni versi ty with a
11 Bachelors degree and a Masters degree in organizational
12 leadership.I have also attended the Kidder Peabody School
13 of Financial Management...14 I joined the Company in 1981 and have served in a
15 number of roles including customer service manager.In
16 1991, I was appointed general manager for Avista Utilities'
17 Oregon and California natural gas utility business.I was
18 appointed President and General Manager of Avista Utili ties,
19 an operating division of Avista Corporation, in August 2000.
20 In February 2003, I was appointed Senior Vice-President of
21 Avista Corporation, and in May 2006, I was appointed as
22 President and Chief Operating Officer. Effective January 1,
23 2008, i assumed the position of Chairman of the Board,
24 President, and Chief Executive Officer.
25 i am a member of the Western Energy Institute board of
26 directors, a member of the Gonzaga Uni vers i ty board of.
26 Morris, Di 1
Avista Corporation
""'.1 trustees, a member of Edison Electric Institute board of
2 directors, a member of the American Gas Association board of
3 directors, a member of ReliOn board of directors, and board
4 director of the washington Roundtable.I also serve on the
5 board of trustees of the Greater Spokane Incorporated, which
6 was formerly two separate organizations, the Spokane Area
7 Economic Development Council and the Spokane Regional
8 Chamber of Commerce.
9 Q.What is the scope of your testimony in this
10 proceeding?
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A.I will provide an overview of Avista Corporation
and Avista Utilities.I sumarize the Company's rate
13 requests in this filing, and the primary factors driving the.14 Company's need for general rate relief. I will provide an
15 overview of some of the initiatives that we have undertaken
16 in recent years to achieve operating efficiencies in an
17 effort to mitigate a portion of the increase in costs that
18 Avista, as well as other utilities in the industry are
19 experiencing.I will also briefly explain the Company 's
20 customer support programs that are in place to assist our
21 customers.Finally, I will introduce each of the other
22 witnesses providing testimony on the Company's behalf.
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A table of contents for my testimony is as follows:
Description
I. Introduction
II., Cost Drivers for Avista
III. Cost Management and Efficiencies
IV. Cus tomer Support Programs
V. Overview of Avista
VI. Rate RequestsElectric
Natural Gas
VII. Other Company Witnesses
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Q.Are you sponsoring any exhibits in this
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A.Yes.I am sponsoring Exhibit No. 1 Schedule 1,
pages 1 through 2 .Page 1 is a diagram of Avista' s
19 corporate structure; and page 2 includes a map showing
Avista's electric and natural gas service areas.These.20
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exhibi ts were prepared under my direction.
Q.Please sumarize the proposed changes in retail
23 rates in this filing.
24 A.In this filing Avista is proposing a net increase
25 in electric retail rates of 7.8%. The proposal consists of
26 an increase in electric base retail rates of $3l. 2 million
27 or l2 . 8%, and a reduction in the current Power Cost
28 Adjustment (PCA) surcharge of 5.0%. We are proposing that
29 the reduction in the PCA surcharge become effective
30 coincident with the effective date of new retail rates from
31 this general rate case filing.
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28 Morris, Di 3
Avista Corporation
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Company witness Mr. Hirschkorn' s testimony discusses this
change in the PCA surcharge. Therefore, the proposed
3 electric bill increase to customers from this filing is a
4 net increase of 7.8%. The proposed natural gas increase in
5 The followingthe filing is $ 2.74 million, or 3.0%.
6 illustra.tes how the estimated electric net increase was
7 derived.
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Illustration No.1:
$45,000,000
$40,000,000
$35,000,000
$30,000,000
$25,000,000
$20,000,000
$15,000,000
$10,000,000
$5,000,000
Bil Impact to Customers
12.8%*
$-
01-23-2009 07-01-2009
* The proposed increase is 12.8% as a percentage of present billed rates and14.2% as a percentage
22 of bas e tariff rates.
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29 Morris, Di 4
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II. COST DRIVERS FOR AVISTA
Q.Why is Avista proposing another electric revenue
3 increasè following the recent general rate request?
4 A.This case is about more than just year-over-year
5 changes in utility operating costs, such as power costs,
6 We are alsofuel, ~aterials and supplies, and labor.
7 investing large amounts of capital to preserve and upgrade
8 our existing utility infrastructure to meet growing
9 customer demand. We are also continuing to experience major
10 cost impacts related to meeting new reliability standards,
11 environmental compliance, and litigation related to the
12 preservation of what have historically been our low-cost
13 resources we have used for decades to serve our customers..14 Several examples of significant cost increases are as
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1.Comensation to the Coeur d' Alene Tribe (Tribe):
The recently announced Settlement Agreement among the
Tribe, Avista, and the U. S. Department of interior,
provides compensation to the Tribe related to their
ownership of the Southern one-third of Lake Coeur d'Alene (CDA). Although these costs were reviewed in
the prior general rate case, they were deferred for
future recovery in a subsequent rate case and are
included in the current filing. The annual cost to
Idaho customers from this Agreement is $1.5 million,
or a 0.7% increase in base retail rates.
2.Spokane River Relicensing: The resolution of issues
with the CDA Tribe helps clear the way for the Federal
Energy Regulatory Commission (FERC) to issue a newlicense for the Post Falls Hydroelectric Proj ect in
the State of Idaho. There is, however, one remaining
issue for the Projects in the State of Washington
related to water quality. We expect this issue to be
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resolved in the first half of 2009 and a new license
to be issued. The majority of the relicensing costs
were reviewed in the prior general rate case filing,
but were deferred for later recovery in this filing.
Thè annual cost to Idaho customers from relicensing
the Spokane River Projects is $3.8 million, or a 1.7%
increase in base retail rates.
3.Mitigation of Mercury and Therml O&:M Cost Increases:
During 2009, the Colstrip owners, including Avista,
will begin to incur significant costs to comply with
new Mercury emissions laws in the State of Montana.
Avista is also experiencing a significant increase in
O&M at its thermal plants, due in part to the rapid
increase in the cost of materials and the age of the
plants. The increase in annual costs is $1.6 million,
or a 0.7% increase in base retail rates.
4.Increase in Power Supply Costs: In our last rate case
we included a "rate mitigation adjustment" such that
the full increase in power supply costs was not
included in retail rates resulting from that case.
This case reflects the total power supply costs to
serve customers' loads. The increase in costs is also
driven by, among other things, the expiration of low-
cost Mid-Columia contracts, and an increase in retail
loads. Although the economy has slowed, the growth of
energy demands by customers continues to climb, we
believe due in part to a continuing increase in
televisions, computers, cell phone chargers, and other
consumer electronics in customers' homes. The
increase in annual power supply costs is $8.6 million,
or a 3.9% increase in base retail rates.
5.Investment in Facilities to Serve Customrs: As other
witnesses will explain in more detail, we are
continuing to invest significant dollars in utility
infrastructure. The investment is necessary to serve
new customers, upgrade aging facilities - some of
which are over 70 years old - and meet recently-
enacted reliability requirements for our energy
delivery facilities. Although in recent months the
rapid increase in the cost of materials (concrete,
copper, steel, etc.) has abated, such costs are still
orders of magnitude higher than what they were even a
few years ago. New investment reflected in this
filing results in an increase in annual costs to
customers of $3.1 million, or a 1.4% increase in base
retail rates.
31 Morris, Di 6
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2 These items alone total $18.6 million, representing an
3 increased revenue requirement of 8.4% for the Idaho
4 jurisdiction, prior to even addressing other utility
5 ownership and operating costs.
6 In a Novemer 2008 report prepared by the Brattle
7 Group for The Edison Foundation, "Transforming America 's
8 Power Industry: The Investment Challenge 2010-2030."It
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The u. s. electric utility industry is facing the
greatest challenge in its history. The demand for
electric service is increasing, reserve margins are
shrinking and input costs to build infrastructure for
all types of electricity production are soaring.
Global climate change and other environmental issues
are directing the industry toward greater development
and use of energy efficiency products and services and
low-emissions supply sources, all of which come withcosts.
We are a low-cost utility in the midst of a high-cost
environment:high cost of materials for utility
23 infrastructure, high fuel and purchased power costs, high
24 cost of compliance with environmental and reliability
25 requirements, and, recently, high costs to settle long-
26 standing litigation (CDA Tribe/Relicensing and Montana
27 Riverbed litigation). This is all in the face of increased
28 demands for service by our customers - and we need to meet
29 those needs by providing safe, reliable and efficient
30 service.
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III. COST MAGEM AN EFFXCIBNIES
Q.Wht is Avista doing to mitigate the impact of
3 increased costs On its customrs?
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4 A.We recognized that_ these increases in costs will
5 result in electric bills that will be more difficult for
6 some of' our customers to pay. I can assure you that we are
7 not just sitting on the sidelines as our costs go up.
8 i will explain a numer of cost-cutting and efficiency
9 measures that we have undertaken recently in an effort to
10 mitigate the overall cost impacts to our customers.In
11 addition, we have a history of making it a priority within
12 our Company to maintain meaningful programs to assist our
13 customers that are least able to pay their energy bills,.14 including working cooperatively with our local community
15 action agencies.
16 We will continue to aggressively manage costs to
17 achieve the appropriate balance in providing safe and
18 reliable service at cost-effective rates, and a high level
19 of customer satisfaction, while preserving the financial
20 health of the utility.
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Q.What measures has the Comany taken?
A.The measures below are among some of the actions
23 we have taken to mitigate the impact of increased costs on
24 our customers:
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1.Delayed the Reardan wind project. We have recently
delayed the construction of the $125+ million Reardan.
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Wind Project to 2013, due, in part, to the current high
cost of wind turbines and other materials.
Cancelled Ross Court Office Space. Avista' s main
office building was constructed in 1958, and expanded
in' 1978. Even though Avista' s ratio of the numer of
cus tomers served per employee continues to increase, we
have needed additional office space for some time. In
2008, in order to reduce costs, we cancelled pians to
build additional office space adjacent to the main
office, and instead chose to remodel existing space
formerly used by Horizon Credit Union nine miles fromthe main office.
3.OUt sourced Billing and Disaster Recovery. Avista
recently outsourced its bill printing and mailing
services, and at the same time complying with
requirements related to disaster-recovery for billingdata. The objectives were to move bill printing,
inserting and mailing offsi te and leverage core
competencies of the provider, to obtain disaster
recovery and avoid the cost of duplicate data storage,
ensure daily print volume flexibility, and reduce costs
for bill printing, inserting and mailing.
4.Additional On-line Service Offerings. In January 2008the Company completed the redesign of
ww.avistautilities.com. The primary objectives of
this project were to lower costs and enhance customer
satisfaction through the deployment of additional self-
service options, such as open/close/move, reporting and
making payment arrangements, enrolling in Comfort Level
Billing, and/or Automatic Payment Service (APS) .
Customers also have access to tools to help analyze
their bills and are provided with meaningful
information to make informed energy management choices.
The cost-saving objective is to achieve a 10% reduction
in the Company's Contact Center total call volume,
which results in lower staffing and lower costs to
customers.
Q. Are these the only measures the Coman has taken
44 recently to mitigate increased costs?
45 constantly looking forA.Avista isNo.
46 improvements in the way it provides services to its.47 customers, as well as ways to reduce the costs of those
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services. Ideas are generated through periodic evaluation
of its operating practices, and communications with other
3 utilities, and other industry participants, across the
4 country' on best practices.While a later witness, Don
5 KopcZYnski, will explore cost-saving initiatives in more
6 detail, I would like to highlight a few:
1.Mobile Dispatch. The Mobile Dispatch Project achieveda numer of financial and customer service benefits,
including increased productivity, enhanced customerservice, reduced costs, and improved field safety.
This proj ect uses wireless communications between the
home office and laptop computer in service trucks to
dispatch field crews. These capabilities allow for
efficient order dispatch, enhanced customer service
with efficient order booking, improved safety, and
reduced costs to perform the work.
2.outage Mangement. The Outage Management tool is
linked to the Company's Geographic Information System
(GIS mapping system). It allows the Company's
distribution facilities to be linked to individual
customer service points in a computer based model.The connecti vi ty provides tools to determine outage
areas and affected protective devices. Accurate outage
data can be collected for all incidents providing
feedback to improve reliability and outage statistics
which can be monitored in real time to indicate the
severity of major events and assist in resource
planning. These capabilities allow for quicker
restoration of electrical service for our customers,
thereby reducing labor expenses and enhancing customerservice.
3.Regional Infrastructure Efficiency. Prior to the
construction season each year, Avista, in partnership
with the City of Spokane, hosts Spokane's JointUtili ties Coordination Council to bring together
regional municipali ties, utili ty companies,
telecommunications providers, sewer, water and the
railroad to coordinate construction activities.
Municipalities and utilities share their project plans
and schedules so as to increase the coordination and
mitigate the risk of unknown projects. The efforts of
the Joint Utilities Coordination Council have resulted
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ih greater coordination and efficiencies across the
Spokane region.
Q. Has Avista considered additional measures to
6 mitigate increased costs?
7 A.Yes. In fact we are currently in the process of
8 revisiting our capital budget for 2009 for potential cuts.
9 With regard to operating expenses, in recent years Avista
10 has run its operations with attention to minimizing
11 expenses while providing reliable service and a high level
12 of customer satisfaction.Following the energy crisis of
13 2000/2001, we cut our operating expenses as we worked
14 toward regaining an investment grade credit rating. Since
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limiting the growth in these costs, while meeting
important rel iabi 1 i ty and environmental compliance
18 requirements, and preserving a high level of customer
19 satisfaction.
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iV. CUSTOMER SUPPORT PROGRAS
Q.What is Avista doing to assist customers with
23 their energy bills?
24 A.As I mentioned earlier, we have a history of
25 making it a priority within our Company to maintain
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able to pay their energy bills.We also have programs to.assist our entire customer base, i. e., not just our low..
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income cus tomers .Some of the key programs that we offer
or support are as follows:
1.Increased DSM Programs and Funding. In March 2008
Avista proposed, and the IPUC approved, modifications
to the Company's energy efficiency program offerings.The modifications further broadened the techni.cal and
financial support Avista provides to its customers, and
provides cus tomers wi th increased opportuni ty to manage
their energy bills. In 2008 Avista also launched the
award-winning "Every Little Bit" energy efficiency
promotional campaign which integrates all of the
Company's energy efficiency programs into one location.
2.Project Share. Project Share is a voluntary program
allowing customers to donate funds that are
distributed through community action agencies to
customers in need. In addition to the customer and
employee contributions of $67,468 (through Novemer,
2008) in Idaho, Avista shareholders contributed
$74,781, Idaho's share, to the program in 2008.
3.Comfort Level Billing. The Company offers the option
for all customers to pay the same bill amount each
month of the year by averaging their annual usage.
Under this program, customers can avoid unpredictable
winter heating bills.
4.Payment Arrangements. The Company's Contact Center
Representatives work with customers to set up payment
arrangements to pay energy bills.
5.CARS Program. Customer Assistance Referral andEvaluation Services provides assistance to special-
needs customers through access to specially trained
(CARES) representatives who provide referrals to area
agencies and churches for help with housing,
utilities, medical assistance, etc.
6.Customer Service Automtion. Customers are able to
access Avista' s Interactive Voice Response system
(IVR) for automated transactions to enter their own
payment arrangements, listen to outage messages and
conduct other business such as obtaining account
balances and requesting a duplicate bill.
7.Power to Conserve. In partnership wi th KREM
television, a half-hour television program is annually
developed that covers low-cost and no-cost ways to
37 Morris, Di 12
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save energy at home. The goal of the program is to
help limited income seniors and other vulnerable
populations with their energy bills by providing home
energy conservation education. The program provides
helpful energy conservation tips, information on
community resources and ways for customers to manage
their energy bills. A DVD of the program has also
been produced which is included as part of energy
conservation kits provided in senior conservationworkshops.
8. Senior Energy Workshops. Energy efficiency workshops
that focus on comfort and safety as well as the wise
use of energy have been specially designed for the
senior population. Kits are provided that contain
energy-saving items such as compact fluorescent light
bulbs, draft stoppers, rope caulking, etc. The Power
to Conserve program DVD along with energy efficiency
tip sheets are also included in the kit. Workshops
are held at senior meal sites, senior centers andother senior support locations.
9. RHQ.com - Caregivers Resource. Avista sponsors the
Caregivers Resource page on KHQ's Senior Life website
in order to reach seniors and caregivers wi th a wide
variety of resource information including energy
efficiency, energy assistance information, Avista
CARES, bill paying assistance, etc. Several video
clips offer low-cost, no-cost energy saving ideas.
10. Senior Pulications. Avista created a one page
advertisement that is placed in several senior
directories and publications as part of an effort to
reach seniors with information about energy
efficiency, Comfort Level Billing, Avista CARES, and
energy assistance information.
Again, Mr. Kopczynski provides additional detail in
39 his testimony concerning these and other programs designed
40 to assist customers.
41 As discussed in Mr. Folsom's tes timony , the Company
42 proposes to increase its low-income weatherization funding
43 for electric and natural gas service by a percentage.44 amount equal to the percentage rate increase granted in
38 Morris, Di 13
Avista Corporation
.1 this case for residential customers (net of the PCA
2 surcharqe reduction for electric service). The additional
3 funding would be provided through the DSM tariff rider,
4 Schedules 91 and 191.
5 In, addition, Avista actively participated in the
6 energy affordabili ty workshops in Case No. GNR-U-08-01. In
7 that Case, workshop participants are exploring ways to
8 address energy affordability and the difficulty some
9 customers experience in paying their energy bill. Avista
10 supports Staff's recommendation in that Case in favor of
11 legislation to allow the Commission to adopt a Low Income
12 Rate Assistance Program (LlRAP) for its Idaho customers,.13
14
at the request of the utility.
The LlRAP program would allow Avista, with ¡PUC
15 approval, to collect through a small monthly charge to all
16 customers, additional dollars that would be directed to
17 customers least able to pay their energy bills. The local
18 community actions agencies that are already in place would
19 administer these dollars.
20 Q.Are there other programs in the State of Idaho
21 that are available to provide assistance to customrs that
22 need help with their energy bill?
23 A.Yes.On September 30, 2008, President Bush
24 signed legislation that provides $5.1 billion for the Low
25 Income Home Energy Assistance Program (LIHEAP) for the.26 2008/2009 heating season. This increased funding will
39 Morris, Di 14
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serve an additional two million households and raise the
average grant from $355 to $550, and also allows states to
3 carryovér any funds remaining to next year's heating
4 season. Idaho's share of the LIHEAP funding was increased
5 from $12,376,000 to $26,969,000. This bill also provides
6 increased funding for weatherization assistance programs.
7 Q.Is Avista comunicating with its customers to
8 explain what is driving the increase in costs?
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10
A.Yes. The Company proactively communicates with
its customers in a numer of ways:electronic customer
11 communications, one-on-one customer interactions through
12 field personnel and account representatives, proactive and
13 reacti ve media contacts, and through our employees'.invol vement in community,business and civic14
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organizations,to name a few.We believe our
communications are helping our customers,and the
17 communities that we serve, better understand the issues
18 faced by the Company, such as increased environmental
19 mi tigation,infrastructure investment,and generation
20 constraints, all of which have lead to higher costs for
21 our cus tomers .
22 We have made extensive efforts to communicate with
23 our customers concerning the cost challenges that we are
24 facing, and we believe these communications are helping
25 customers better understand the factors that are causing.
40 Morris, Di 15
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increased costs for Avista, and the utility industry in
general.
Q. , Would you please coment on the emloyees'
4 dedication to achieve customer satisfaction?
5 Yes, I am pleased with the dedication of AvistaA.
6 Utilities' employees and their commitment to provide
7 While we continue toquality service to our customers.
8 maintain tight controls on capital and O&M budgets, our
9 indicate that customerservicecustomersurveys
10 satisfaction remains high. Our recent fourth quarter 2008
11 customer results show overall customersurveyan
12 satisfaction rating of 93% in our Idaho, Washington and
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Oregon operating divisions.This rating reflects a
15 contacted Avista related to the customer service they
positive experience for the majority of customers who have
16 received. These results can be achieved only with very
17 committed and competent employees.
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20
V. OVERVIEW OF AviSTA
21 for the utility and subsidiary operations.
Q.Please describe Avista' s current business focus
22 A.Our strategy continues to focus on our energy and
23 utility-related businesses, with our primary emphasis on
24 the electric and natural gas utility business.There are
25 four distinct components to our business focus for the
26.utility, which we have referred to as the four legs of a
41 Morris, Di 16
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stool, with each leg representing customers, employees, the
communities we serve, and our financial investors. For the
3 stool to be level, each of these legs must be in balance by
4 having the proper emphasis. This means we must maintain a
5 strong utility business by delivering efficient, reliable
6 and hig,l quality service, at a reasonable price, to our
7 customers and the communities we serve, and provide the
8 opportuni ty for sustained employment for our employees,
9 while providing an attractive return to our investors.
10 The Company recently received upgrades its corporate
11 credit ratings to investment grade by Moody's Investors
12 Service in Decemer 2007 and Standard & Poor's in February
2008.Al though we are continuing to make progress in.13
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improving the Company's financial condition, we are still
not as strong financially as we need to be.The Company
16 continues to be below investment grade with Fitch Ratings.
17 Timely rate relief through this filing is an important
18 element in continuing to gain financial strength and
19 improving our credit rating.with higher levels of
20 capi tal spending required over the next several years (i . e. ,
21 approximately $420 million during 2009-2010), it is more
22 important than ever that the Company remain financially
23 healthy in order to attract capital investment and
24 financing at the lowest cost possible. Company witness Mr.
25 Thies will discuss further the actions taken by the Company.
42 Morris, Di 17
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to improve cash flow, reduce debt, and our continuing
efforts to improve our financial condition.
Q.Please briefly describe Avista' s subsidiary
4 businesses.
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subsidiary theisAvistaCorp. ' s primaryA.
information and technology business,Advantage IQ,
described below,which is headquartered in Spokane,
8 Washington. In 2007, Avista completed the sale of the
9 operations of Avista Energy to Coral Energy Holding, L. P. ,
10 and certain of its subsidiaries, a subsidiary of Shell.
11 Avista currently holds a 6.8% share in Avista Labs'
12 successor company, ReliOn, which is held under Avista
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Capital.A diagram of Avista i s corporate structure is
provided on page 1 of Exhibit No.1, Schedule 1.
Q.Please provide an overview of Advantage IQ.
A.Advantage IQ, formerly known as Avista Advantage,
17 commenced operations in 1998 and is a provider of utility
18 bill processing, paYment and information services to multi-
19 site customers.Advantage IQ analyzes and presents
20 consolidated bills on-line, and pays utility and other
21 facility-related for multi-site customersexenses
22 throughout North America. Customers include, CSK Auto, Jack
23 in the Box, Staples, and Big Lots, to name a few.
24 Information gathered from invoices, providers and other
25 customer-specific data allows Advantage IQ to provide its
26.customers with in-depth analytical support,real-time
4':3 Morris, Di 18
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reporting and consulting services with regard to facility-
related energy, waste, repair and maintenance, and telecom
expenses.In 2007, Advantage IQ was awarded the ENERGY
4 STAR~ Sustained Excellence Award in recognition of its
5 continued leadership in protecting our environment through
6 energy efficiency.
7 Wht is the status of the formtion of a holdingQ.
8 company?
9 In February 2006, Avista filed for regulatoryA.
10 approval of the proposed formation of a holding company
11 Energy Regulatory(reorganization)with Federalthe
12 Commission (FERC) and the public utility commissions in
13 Idaho, Washington, Oregon and Montana, conditioned on.14
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approval by shareholders.On April 18, 2006, FERC issued
its "Order Authorizing Disposition of Jurisdictional
16 Facilities" in Docket No. EC06-85-000, approving the
17 Company's reorganization.Shareholder approval of the
18 reorganization was granted at Avista Corp. ' s Anual
19
20 Idaho Public Utili ties Commission issued an order approving
Shareholder meeting May 11, 2006.On June 30, 2006, the
21 Avista' s reorganization application, based on a settlement
22 in that state. On February 28, 2007, the Washington
23 Utilities and Transportation Commission issued an order
24 approving Avista' s reorganization application, based on a
25
26.settlement in that state.The Montana Commission has yet
to act on Avista' s Reorganization application, and the
44 Morris, Di 19
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procedural schedule for consideration of the Company's
application in Oregon has been suspended by agreement of
3 the parties to allow addi tional time for discussion among
4 the parties.
5
6
Q.Please briefly describe Avista Utilities.
A.Avista Utilities provides electric and natural
7 gas service within a 26,000 square mile area of eastern
8 Washington and northern Idaho. Of the Company's 352,423
9 electric and 309,912 natural gas customers (as of
10 Septemer 30, 2008), 120,972 and 72,326, respectively,
11 were Idaho customers. The Company, headquartered in
12 Spokane, also provides natural gas distribution service in
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southwestern and northeastern Oregon.A map showing
Avista's total electric and natural gas service areas are
15 provided in page 2 of Exhibit No.1, Schedule 1.
16 As of September 30, 2008, Avista Utilities had total
17 assets (electric and natural gas) of approximately $3.3
18 billion (on a system basis), with electric retail revenues
19 of $620 million (system) and natural gas retail revenues of
20 $447 million (system). As of September 2008, the Utility
21 had i, 49l full-time employees.
22 Avista has a long history of innovation and
23 environmental stewardship. At the turn of the 2 O~ century,
24 the Company built its first renewable hydro generation
25 plant on the banks of the Spokane River.In the i 980 ' s ,
.
45 Morris, Di 20
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Avista developed an award-winning biomass plant (Kettle
Falls) that generates energy from wood-waste.
3 To the future, Avista as well as other utilities are
4 facing ~ew state and federal mandates for renewable energy
5 and carbon control standards. For example, washington's
6 Senate Bill 6001 and Initiative 937 require certain public
7 and private utilities to produce 15 percent of their power
8 from new renewable resources by 2020, not including legacy
9 hydro production, and to eliminate the option of coal-fired
10 generation because of carbon emission limitations.
11 Recognizing these changes, the Company dropped all new coal
12 generation in its 2007 electric IRP, instead relying on
.13
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natural gas, renewables, and energy efficiency.Today,
Avista has one of the smallest carbon footprints in the
15 u. S.
16 VI. RATE REQUESTS
17 Q.Please provide an overview of Avista' selectric
18 rate request in this filing.
19 A.As previously discussed, in this filing Avista is
20 proposing a net increase in electric retail rates of 7.8%.
21 The proposal consists of an increase in electric base retail
22 rates of $31.2 million or 12.8%, and a reduction in the
23 current Power Cost Adjustment (PCA) surcharge of 5.0%. The
24 Company's request is based on a proposed rate of return of
.
46 Morris, Di 21
Avista Corporation
.8.80% with a common equity ratio of SO. 00% and an 11. 0%1
2
3
4
return òn equity.
Mr. Hirschkorn will provide details related to rate
spread and rate design.The proposed rate spread for the
5 net increase to each electric customer class is shown in the
.
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6 illustration below.
Illustration No.2:
Proposed
Service Schedule
Residential Service Schedule 1
General Service Schedules 11 & 12
Large General Service Schedules 21 & 22
Extra Large General Service Schedule 25
Potlatch Service Schedule 25P
Pumping Service Schedules 31 & 32
Street & Area Lighting Schedules 41-49
Overall Increase
Increase
8.7%
7.8%
7.8%
7.8%
5.7%
7.8%
8.9%
7.8%
Q. What is Avista's natural gas rate request in this
22 filing?
23 A.Wi th regard to na tural gas, the Company is
24 requesting an increase of $2,740,000 or 3.0%. As with the
25 electric increase, the Company's request is based on a
26 proposed rate of return of 8.80% with a common equity ratio
27 of SO.OO% and an 11.0% return on equity. The proposed rate
28 spread for each natural gas customer class is shown in the
29 illustration below..
47 Morris, Di 22
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Illustration No.3:
Proposed
Service Schedule
General Service Schedule 101
Large General Service Schedule 111/112
Interruptible Sales Service Schedule 131/132
Transportation Service Schedule 146
(excluding natural gas costs)
Overall Increase
Increase
3. l%
2.5%
1.7%
10.9%
3.0%
14 request for an electric rate increase in this filing?
Q.Wht are the primry factors causing the Comany's
15 A.The Company's electric general rate case test
16 period is based on 12 months ending September 30, 2008, and
.17
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a July 1, 2009 through June 30, 2010 proforma period.As
shown in Illustration No.4, the Company's electric request
19 is driven primarily by hydro relicensing and compliance
20 costs, increased capital investment to preserve and upgrade
21 our utility infrastructure to meet growing customer demand,
22 and higher power supply costs.
.
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48 Morris, Di 23
Avista Corporation
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"
1 Illustration No.4:
2
3 . Priary Components of Elecric Revenue Requiement
4
Pructon &Traion
Exns
38%
Incred Load
Mid Columia Puha
Pructon O&M - Plant Exp.
& Merur Abatement Exp.
5 Incr Net Plt
Invèsntl
35%
Generation Upgres
-Hyd & Ther
Tranmission Upgres
Distrbution
Prpert Tax on CS2
6
7
8
9
10
11 Ditrbution & Oter
Expens
11%
Distrbution Opraon &
Maintenance Costs
Admistrtive & Gener Expenses
Hydro ReJceosing &
Coplice Isues
16%
Spokae River Relicensing
CDA Tribe Settement
12
13
14 1 Inlude retu on investmnt, deon and
taes, offset by th ta beneft of intet.
15
16 Later wi tnesses provide details explaining these
17 changes in costs.
18 Q.What are the primary factors driving the Comany's
19 request for a natural gas rate increase?
20 A.The Company's natural gas request is primarily
21 driven by changes in various operating cost components,
22 maintenance andmainlydistributionoperationand
23 administrative and general expenditures.This causes an
24 increase in the fixed costs of providing gas service to
25 customers.
49 Morris, Di 24
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Q. The proposed rate increase is related to changes
in the fixed costs of providing natural gas service to
3 customers. Is the Comany proposing any changes related to
4 the cost of natural gas in this case?
5 A.No. Avista is not proposing changes in this filing
6 related, to the cost of natural gas included in customers i
7 current rates.Changes in natural gas costs are addressed
8 in the annual purchased gas adjustment (PGA) filings.
9
10
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VII. OTHER COMPAN WITNSSES
Q.Would you please provide a brief sumry of the
12 testimony of the other witnesses representing Avista in this
13 proceeding?.14 A.Yes.The following additional witnesses are
15 presenting direct testimony on behalf of Avista:
16 Mr. Mark Thies, Senior Vice President and Chief
17 Financial Officer will describe, among other things, the
18 overall financial condition of the Company, its current
19 credit ratings, the Company's plan for improving its
20 financial health, its near term capital requirements, the
21 proposed capital structure, and the overall rate of return
22 proposed by the Company. Mr. Thies explains that:
.
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. Avista' s plans call for significant capital
expenditure requirements for the utility
over the next two years to assure
reliability in serving growth in the numer
of customers and customer demand. Capital
expenditures of approximately $420 million
are planned for 2009-2010 for customer
50 Morris, Di 25
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growth, investment in generation,
transmission and distribution facilities for
the electric utility business as well asnecessary maintenance and replacements of
our natural gas utility systems. Avista
needs adequate cash flow from operations tofund these requirements, together wi th
access to capital from external sourcesunder reasonable terms.
. Avista' s corporate rating from Standard &Poor's is currently BBB-. Avista Utilities
needs to operate at a level that will
support a strong investment grade corporate
credit rating, meaning "BBBN or "BBB+N, in
order to access debt capital markets at
reasonable rates, which will decrease long-term costs to customers. Maintaining solid
credit metrics and credit ratings will also
help support a stock price necessary to
issue equi ty to fund capi tal requirements.
.
. The Company has proposed an overall rate of
return of 8.80%, including a 50.00% equity
ratio and an 11. 0% return on equity. We
believe the 1l. 0% provides a reasonablebalance of the competing obj ecti ves of
continuing to improve our financial health,
and the impacts that increased rates have on
our customers.
Dr. William E. Avera, as a President of Financial
35 Concepts and Applications (FINCAP), Inc., has been retained
36 to present testimony with respect to the Company's cost of
37 common equity. He concludes that:
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. Application of quantitative methods to alternative
groups of proxy companies imply a cost of equity
range of 11.3 percent to 13.3 percent.
. Because Avista' s requested ROE of 11.0% percent
falls below the lower end of the recommended
range, it represents a conservative estimate of
investors' required rate of return..
51 Morris, Di 26
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. Considering investors' expectations for capitalmarkets and the need to support financial
integrity and fund crucial capital investment even
under adverse circumstances, 1l. 0% percent is a
reasonable, albeit conservative, ROE for Avista.
. Because of Avista' s reliance on hydroelectric
generation, the Company is exposed to relatively
greater risks of power cost volatility.
. Investors view the Power Cost Adjustment ("PCA")
as supportive of the Company's financial
integrity, but they understand that the PCA does
not insulate Avista from the need to finance
accrued power production and supply costs or
shield the Company from potential regulatorydisallowances.
. Avista' s requested capitalization is consistent
wi th the Company's need to strengthen its credi t
standing and financial flexibility as it seeks toraise additional capital to fund significantsystem investments and meet the requirements of
its service terri tory.
. The reasonableness of a minimum 11.0% percent ROE
for Avista is also supported by the greater risks
associated with the Company's relatively smallsize and the need to consider flotation costs..Mr. Richard Storro, Vice President of Energy Resources,
28 will provide an overview of Avista' s resource planning and
29 power operations. He will discuss the Company's resources,
30 current and future load and resource position, and future
31 resource plans.He will also discuss Company hydroelectric
32 upgrades, current hydro relicensing issues, and mercury
33 abatement at Colstrip. Mr. Storro explains:
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. Avista' s electric generation portfolio, including
power supply operations;
. The Company is in an annual balanced-to-surplus
energy position through 2017 with the addition of
the Lancaster Power Purchase Agreement (PPA) i
. The Company's involvement with the Chicago Climate
Exchange ¡and
. Avista' s risk management policy for energy
resources, including the electric hedging plan..
52 Morris, Di 27
Avista Corporation
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2 Mr. Clint Kalich, Manager of Resource Planning & Power
3 Supply Analyses, will describe the Company' s AURO~ model
4 (Dispatch Model) inputs, assumptions, and results related to
5 the economic dispatch of Avista' s resources to serve load
6 requirements, and market forecas t of electricity prices. He
7 explains:
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. The key assumptions driving the Dispatch Model's
market forecast of electricity prices. This
discussion includes the variables of natural gas,
Western Interconnect loads and resources, and
hydroelectric conditions.. The model dispatches Avista' s resources and
contracts in a manner that maximizes benefits tocustomers.
. The use of quantitative rate-period loads for July
2009 through June 2010, for modeling pro forma netpower supply expenses.
. The output results from the model, includingthermal generation and short-term wholesale sales
and purchases, were provided to Mr. Johnson to
incorporate into the power supply pro formaadjustments.
25 Mr. william Johnson, Wholesale Marketing Manager, will
26 identify and explain the proposed normalizing and pro forma
27 adjustments to the test period power supply revenues and
28 expenses. He will also explain the new base level of power
29 supply costs for Power Cost Adjustment (PCA) calculation
30 purposes using the pro forma costs proposed by the Company
31 in this filing. Mr. Johnson describes:
32
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. The adjustment of revenues and expenses based on
normal streamflow and weather conditions, and
expected wholesale market power prices..
53 Morris, Di 28
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it Adjustments made to reflect known and measurable
changes in power contracts, thermal generation
fuel expense, and transmission expense, between
the test period, and the pro forma period.
. The net effect of the adjustments to the test
period power supply expense is an increase of
$27,645,000 on a system basis, $9,789,095 Idahoallocation.
. This increase in pro forma power supply expense
over the expense currently in base rates is based
on numerous factors, primarily reduced hydro
generation due to the elimination of the ratemitigation adjustment included in last year i s
general rate case and higher retail loads.
. Certain proposed revisions to the PCA, including a
95%/5% sharing mechanism.
18 Mr. Don Kopczynski, Vice President of Transmission and
19 Distribution Operations, will describe Avista' s electric and
20 natural gas energy delivery facilities and operations, and.21
22
recent efforts to increase efficiency and improve customer
service. Mr. Kopczynski describes:
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35
36
37
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.Avista's customer service programs such as energy
efficiency, Project Share, CARES program, Senior
Outreach Program, and paYment plans. Some of
these programs will serve to mitigate the impact
on customers of the proposed rate increase.
The Company's multi-faceted effort to increase
customer service automation, including replacement
and upgrade of the new Interacti ve Voice Response
(IVR) system, Mobile Dispatch, Outage Management
System, transmission and distribution system
efficiencies, and Web Redesign.
The decision by the Company to outsource our bill
printing and mailing services. This decision wasbased on Company needs for disaster recovery
compliance, added scalability and flexibility, and
cos t savings.
.
.
41 will discuss the electric transmission and distribution
Mr. Scott Kinney, Director, Transmission Operations,
.
54 Morris, Di 29
Avista Corporation
investments included in this case, and presents the.1
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Company's pro forma period transmission revenues and
expenses.In addition, he describes the Company's Asset
4 Managemeht Program. Mr. Kinney explains:
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6
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13
. Avista is expecting to invest over $15.1 million
(system) in electric transmission projects with
completion dates in 2009.
. Several revisions have been made to transmission
expenses for the 2009/2010 pro forma period.
. Changes in replacement and maintenance costs
associated with the Company's asset management.
Mr. Dave DeFelice, Senior Business Analyst, will
14 describe the pro forma adjustment for non-revenue capital
15 expenditures. Mr. DeFelice explains:
.16
17
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19
20
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23
. The rising cost of essential materials specific to
the utility industry is causing significant
increases in capital proj ect funding requirements.. These costs must be pro formed into historical
test-year computations in order to allow necessary
recovery of our costs to serve customers.
Ms. Elizabeth Andrews, Manager of Revenue Requirements,
24 will discuss the Company's overall revenue requirement
25 proposals.In addition, her testimony generally provides
26 accounting and financial data in support of the Company's
27 need for the proposed increase in rates. She sponsors:
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. Electric and natural gas revenue requirementcalculations.
. Electric and natural gas results of operations.
. Pro forma operating results including expense and
rate base adjustments.
. System and jurisdictional allocations.
.
55 Morris, Di 30
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Ms. Tara Knox, Senior Regulatory Analyst, sponsors the
cost of service studies for electric and natural gas
3 service, the revenue normlization adjustments to results of
4 operations, and the proposed retail revenue credit rate for
5 the PCA: Ms. Knox studies indicate:
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. Electric residential service, extra large general
service and street and area lighting service
schedules are earning less than the overall rate
of return under present rates, while general
service, large general service and pumpingservice schedules are earning more than the
overall rate of return under present rates.However, all customer groups are currently
providing a rate of return lower than the rate of
return requested in this case.
. Natural Gas small firm service is earning lessthan the overall rate of. return at present rates,while residential, interruptible and
transportation service schedules are earning more
than the overall rate of return to varying
degrees. All of the schedules are relatively
close to the overall return indicating the
current rate spread is fair.
Mr. Brian Hirschkorn, Manager of Pricing, discusses the
26 spread of the proposed annual revenue changes among the
27 Company's general service schedules.He explains, among
28 other things, that:
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. The proposed net increase in electric retail rates
is 7.8%, which consists of an increase in electric
base retail rates of $31.2 million or 12.8%, and a
reduction in the current PCA Surcharge.
. The monthly bill for a residential customer using
an average of 982 kWhs per month would increasefrom $78.47 to $85.18 per month, an increase of
$6.71 or 8.6%. This includes the proposed
increase in the monthly basic or customer charge
from $4.60 to $5.00.
. To achieve this, the Company is requesting that
the reduction in the PCA Surcharge become.
56 Morris, Di 31
Avista Corporation
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effective coincident with the effective date of
new retail rates.
. The proposed natural gas annual revenue increase
is $2.7 million, or 3.0%.
. The monthly bill for a residential customer using
66 therms per month would increase from $79.38 to
$81.94 per month, an increase of $2.56 or 3.2%.
This includes the proposed increase in the monthly
basic or customer charge from $4.00 to $4.25.
Mr. Bruce Folsom, Senior Manager of Demand Side
13 Management, provides an overview of the Company's DSM
14 programs and documents Avista's expenditures for electric
15 and natural gas energy efficiency programs.Mr. Folsom
16 exlains that:
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. The Company exceeded its 2008 electric efficiency
targets by approximately 40% and 2008 natural gas
efficiency target by approximately 34%.
. Avista' s expenditures for electric and natural gas
energy efficiency programs from January 1, 2008through Novemer 30, 2008 have been prudentlyincurred.
Q.Does this conclude your pre-filed direct
26 testimouy?
27 A.Yes.
.
57 Morris, Di 32Avis ta Corporation
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I. INTRODUCTION
Q. Please state your nae, business address, and
3 present position with Avista Corp.
4
5
A.My name is Mark Thies.My business address is
1411 East Mission Avenue, Spokane, Washington.I am
6 employed by Avista Corporation as Senior Vice President and
7 Chief Financial Officer.
8 Q.Would you please describe your education an
9 business exerience?
10 A.I received Bachelor of Arts degrees in Accounting
11 and Business Administration from Saint Amrose College in
12 Davenport, Iowa, and became a Certified Public Accountant
.13
14
in 1987.I have extensive experience in finance, risk
management,accounting and administration within the
15 utility sector, primarily in the Midwest.
16 I joined Avista in Septemer of 2008 as Senior Vice
17 President and Chief Financial Officer (CFO).Prior to
18 joining Avista, I was Executive vice President and CFO for
19 Black Hills Corporation, a diversified energy company,
20 providing regulated electric and natural gas service to
21 areas of South Dakota, Wyoming and Montana. I joined Black
22 Hills Corporation in 1997 upon leaving InterCoast Energy
23 Company in Des Moines, Iowa, where I was the manager of
24
25
accounting.Previous to that I was a senior auditor for
Arthur Anderson & Co. in Chicago, Illinois.
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Q. Wht is the scope of your testimony in this
proceeding?
A.i will provide a financial overview of the
4 Company and will explain the overall rate of return
5 proposed by the Company in this filing for its electric and
6 natural gas operations.The proposed rate of return is
7 derived from Avista's long-term cost of debt and common
8 equi ty, weighted in proportion to the proposed capital
9 structure.
10 i will address the proposed capital structure, as well
11 as the proposed cost of debt and equity in this filing.
12 Company witness Dr. Avera will provide additional testimony
13 related to the appropriate return on equity for Avista,.14
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34.
based on the specific circumstances of the Company,
together with the current state of the financial markets.
In brief, i will provide information that shows:
. Avista' s plans call for significant capital
expenditure requirements for the utility over the
next two years to assure reliability in serving
growth in the numer of customers and customer
demand. Capital expenditures of approximately
$420 million are planned for 2009-2010 forcustomer growth, investment in generation,
transmission and distribution facilities for the
electric utility business as well as necessary
maintenance and replacements of our natural gas
utility systems. Avista needs adequate cash flow
from operations to fund these requirements,
together wi th access to capital from externalsources under reasonable terms.
. Avista's corporate credit rating from Standard &
Poor's is currently BBB- and Baa3 from Moody's.
Avista Utilities needs to operate at a level that
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will support a strong investment grade corporate
credit rating, mèaning ~BBB" or ~BBB+", in order
to access capital markets at reasonable rates,
which will decrease long-term costs to customers.
Maintaining solid credit metrics and credit
ratings will also help support a stock pricenecessary to issue equi ty to fund capi talrequirements.
. The Company has proposed an overall rate of
return of 8.80%, including a 50.00% equity ratio
and an 11.0% return on equity. We believe the
11.0% provides a reasonable balance of the
competing objectives of continuing to improve our
financial health, and the impacts that increased
rates have on our customers.
The Company's initiatives to carefully manage its
19 operating costs and capital expenditures are an important
20 part of improving performance, but are not sufficient
21 without revenues from the general rate request for our.22
23
electric and natural gas businesses in these cases.
Certainty of cash flows from operations can only be
24 achieved with the continued support of regulators in
25 allowing the timely recovery of costs and the ability to
26 earn a fair return on investment.
27
28
29
30
.
Finally, I will provide testimony concerning the
Company's pension expense and its proposal for a balancing
account with respect to annual dollar differences between
cash payments and pension expense.
Thies, Direct 3
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A table of contents for my testimony is as follows:
Description
I.' Introduction
II. Financial Overview
III. Credit Ratings
IV. Cash FlowV. Capi tal Structure
VI. Cost of Debt
VII. Cost of Common Equity
VIII. Increase in Pension Expense
Page
1
4
13
27
36
37
37
40
Q.Are you sponsoring auy exibits with your direct
13 testimony?
14
15
A.Yes. I am sponsoring Exhibit No.2, Schedules 1
and 2, which were prepared under my direction.Avista's
16 credit ratings by the three principal rating agencies are
17 sumarized on Schedule 1, and Avista's actual capital.18
19
structure at Decemer 31, 2008 and pro forma capital
structure at June 30, 2009 are included on Schedule 2, page
20 1, with supporting information on pages 2 through 3.
21
22
23
:II. F:INAIAL OVEV:IEW
Q.Please provide an overview of Avista' s financial
24 si tuation.
25 A.The Company has made solid progress in improving
26 its financial health in recent years, as demonstrated by
27 improved financial ratios. Avista has reduced investments
28 in unregulated subsidiaries and redeployed the majority of
29 the proceeds from the sales of the unregulated subsidiaries
30 to the Utility. The Company has been able to improve its.Thies, Direct 4
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debt ratio and balance the overall debt / equity ratio by
paying down debt, issuing additional common stock, and
through . addi tional retained earnings.Al though we have
4 made progress in improving the Company's financial
5 condition, we are still not as strong as we need to be
6 given the current unrest in capital markets, which may
7 continue for some time.
8 Avista's goal is to operate at a level that will
9 support a strong corporate credit rating of BBB / BBB+, and
10 move away from the Ucliff" of the investment grade rating
11 scale. Operating at a higher rating will help reduce long-
12 term costs to customers. It will also reduce collateral
13 requirements and allow us to maintain access to more
14
15
16
for acquisition of natural andcounterpartiesgas
electrici ty .We expect that a continued focus on the
regulated utility,conservati ve financing strategies
17 (including the issuance of common equity) and a continued
18 supportive regulatory environment will contribute to an
19 overall improved financial situation, that will allow us to
20 move up from the current BBB- rating.
21 Wht additional steps is the Comany taking' toQ.
22 improve its finacial health?
23 We are working to assure we have adequate fundsA.
24 for operations, capital expenditures and debt maturities.
25 We recently acquired a new $200 million 364-day line of
26 credi t from our banks at reasonable rates that has allowedThies, Direct 5
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us to avoid the debt capital markets at a volatile time
when rates are very high. In Decemer 2008, we also
3 obtained a $30 million private placement of five-year debt
4 at favorable rates as compared to the public markets.
5 We are maintaining our original $320 million line of
6 credit, which will expire in April 2011, as well as our
7 Accounts Receivable Sales program.The Company plans to
8 obtain a portion of our capital requirements through equity
9 issuance.We also maintain an ongoing dialogue with the
10 rating agencies regarding the measures taken by the Company
11 to improve our credit rating.
12 Addi tionally,the Company is working through
13 regulatory processes to recover our costs in a timely.14 maner so that earned returns are closer to those allowed
15 by regulators in each of the states we serve. This is one
16 of the key determinants from the rating agencies'
17 standpoint when they are reviewing our overall credit
18 standing.
19 Q.In addition to having credit ratings that will
20 allow Avista to attract debt capital uner reasonale
21 ter.s, is it also necessary to attract capital from equity
22 investors?
23 A.It is absolutely essential.Avista has two
24 primary sources of external capital - debt lenders and
25 equity investors. Avista currently has approximately $2.0
26 billion of net investment in place to serve its customers.
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Avista Corporation.
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Approximately half of that investment is funded by debt
holders,and half is funded by equi ty inves tors.
3 Therefore, even though there tends to be a lot of emphasis
4 on maintaining credit metrics and credit ratings that will
5 provide access to debt capi tal under reasonable terms,
6 access to equity capital is equally important.
7 Addi tional equity capital generally comes in two forms
8 retained earnings and new equi ty issuances. Retained
9 earnings represent the annual earnings (return on equity)
10 of the Company that is not paid out to investors in
11 dividends.The retained earnings are reinvested by the
12 Company in utility plant, and other capital requirements,
13 to serve customers, which avoids the need to issue new.14 debt.Occasionally it is necessary to issue new common
15 stock to maintain the proper balance of debt and equity in
16 the capital structure, which allows Avista access to both
17 debt and equi ty markets under reasonable terms, on a
18 sustainable basis.Because of the large capi tal
19 requirements at Avista in the near-term, it is imperative
20 that Avista have ready-access to both the debt and equity
21 markets at reasonable costs.
22 Q.Are the debt an equity capital markets a
23 cometi ti ve market?
24 A.Yes.Our ability to attract new capital,
25 especially equity capital, under reasonable terms is
26 dependent on our ability to offer a risk/reward opportunityThies, Direct 7
Avista Corporation.
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that is better than the equity investors'other
alternatives. We are competing wi th not only other
3 utili ties, but businesses in other sectors of the economy.
4 As an example,if an equity investor believes, or
5 perceives, that the risk/reward opportunity is better with
6 WalMart than with Avista, or the utility industry in
7 general, the investor will put the equity dollars in
8 WalMart stock.Demand for the stock supports the stock
9 price, which provides the opportunity to issue additional
10 stock under reasonable terms to fund capital investment
11 requirements.
12 To the extent that the equity investor holds a
13 diversified portfolio of companies that includes utilities.14 and other energy companies, we would be competing with
15 those companies to attract those equity dollars.
16 In the debt markets, utilities are the third largest
17 issuers; right behind governments and financial services.
18 Therefore, it is a very competitive market and the Company
19 must be able to attract debt investors as well as equity
20 inves tors.
21 Q.Wht is Avista doing to attract equity
22 investment?
23 A.Avista is carrying a capital structure that
24 provides the opportunity to have financial metrics that
25
26
offer a risk/reward proposition that is competitive and/or
attractive for equity holders..Thies, Direct 8
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We have increased our dividend for common
shareholders,and have publicly stated that we intend to
3 work toward a dividend payout ratio that is comparable to
4 other utilities in the industry.This is an essential
5 element in providing a competitive risk/reward opportunity
6 for equity investors.
7 We are operating the business efficiently to keep
8 costs as low as practicable for our customers, while at the
9 same time ensuring that our energy service is reliable, and
10 resul ts in a high level of customer satisfaction.An
11 efficient, well-run business is not only important to our
12 customers, but also to investors.
13 We are employing tracking mechanisms such as the PCA.14 and PGA, approved by the regulatory commissions, to balance
15 the risk of owning and operating the business in a maner
16 that places us in a position to offer a risk/reward
17 opportunity that is competitive with not only other
18 utilities, but with businesses in other sectors of the
19 economy.
20 We are seeking rate relief to provide timely recovery
21 of costs and earned returns closer to those allowed by
22 regulators.If we are not able to achieve a reasonable,
23 actual, earned return on our equity investment, we will not
24 be able to attract equity dollars that are absolutely
25 necessary to support this business going forward.
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Dr., Avera provides additional testimony related to the
appropriate return on equity for Avista, that would allow
3 the Company access to equity capital under reasonable
4 terms, and on a sustainable basis.
5 Q.Do you believe there are misconceptions abut the
6 earning's of the Comany related to the equity investmt in
7 the Comany?
8 A.Yes I do.I believe some of our customers
9 believe that the earnings of the Company that we report
10 publicly each quarter are "profits" that are over and above
11 the dollars necessary to own and operate the utility, which
12 we know is simply not true. Just as we must pay interest
13 to debt holders in exchange for the use of their dollars,.14 we must also provide a return on investment for the equity
15 holder, or the equity holder will take his or her dollars
16 somewhere else.
17 i believe some do not understand that the quarterly
18 earnings or profits are the return or "interest" to the
19 shareholder, and without it we would not have the funds
20 necessary to run the business - i.e., it is, in fact, one
21 of the essential costs of owning and operating the
22 business.
23 Q.After Avista reported its earnings for the Second
24 Quarter (Q2) of 2008, it was reported in the Spokesm
25 Review newspaper that "Avista Quarterly Profits Soar." Did
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Avista's earnings for Q2 of 2008 exceed those authorized by
this Comssion?
A.No. While earnings from utility operations did
4 improve some for Q2 2008 versus the prior year, the primary
5 reason for the improvement was that Avista Corp completed
6 the sale of Avista Energy during Q2 2007, and recorded a
7 large loss in Q2 2007 related to the operations of that
8 business. The absence of the loss in 2008, resulted in a
9 substantial improvement in reported earnings in Q2 of 2008.
10 Q.What do the quarterly and annual earnings
11 reported by Avista tell us abut the earned return for
12 equity holders for 2008?
.13
14
A.Al though actual earnings for the calendar year
2008 have not yet been released, Avista has previously
15 provided "guidance" for the expected earnings for the year.
16 The current earnings guidance for Avista Utilities for 2008
17 is the range of $1.20 to $1.35 per common share. At
18 Septemer 30, 2008 Avista had approximately 54.0 million
19 common shares outstanding, and an equity investment in the
20 utility of $904 million, per our third-quarter 10-Q filed
21 with the Securities and Exchange Commission. If we were to
22 assume that Avista will see earnings in the middle of the
23 earnings guidance, at $1. 28/share, it would result in a
24 return on investment for equity holders of 7.6%.By
25 comparison, the currently authorized return on equity in
26 Idaho for Avista is 10.20%.Therefore, during 2008 we
Thies, Direct 11
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expect to earn substantially less than what we were
authorized to earn by the IPUC, i.e., we will not recover
3 our costs of providing service to customers, including a
4 competi ti ve return to equi ty holders.
5 If . we continue to fall short, it will threaten our
6 ability to obtain financing from debt and equity holders
7 under reasonable terms.
8
9
What is the Company expecting to earn in 2009?Q.
A.We received additional rate relief in all three
10 states where we do business during 2008 (January 1, 2009
11 While this provides additional costfor Washington).
12 recovery, we are also continuing to experience increases in
13
14
costs, and increased capital investment requirements.As
an example, our most recent rate case in Idaho included
15 recovery of new capital investment through Decemer 31,
16 What that means is, we are not2008, but none for 2009.
17 recovering the costs associated with the new capital
18 investment we have already made in 2009, and will continue
19 to make, until the conclusion of this rate case in mid-
20 2009.
21 Furthermore, if we do not reflect in retail rates the
22 cost of future capital that will be serving customers
23
24
25
during the period that retail rates are in place from this
case, we will continue to earn a lower return than what we
are authorized to earn.
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We have previously announced that we expect Avista' s
utility.earnings for 2009 to be in the range of $1.30 to
$1.45 per share.If we again use the middle of the range
4 ($1. 38/share) for illustrative purposes, 54.0 million
5 shares outstanding, and $1.0 billion of equity investment,
6 it would result in an earned return for 2009 of 7.5%, again
7 well below the authorized return of 10.2%.
8 As we process this rate filing, it is imperative that
9 we work toward recovery of the costs to provide service to
10 customers, and a meaningful opportunity to earn a return
11 closer to the allowed return, so that we can have access to
12 debt and equi ty capi tal under reasonable terms.
.13
14
15
16
III. CREDIT RATINGS
Q.How important are credit ratings for Avista?
A. Utilities need ready access to capital markets in
17 all types of economic environments. I believe few, if any,
18 would have predicted the kind of financial markets we have
19 experienced the past few months.The nature of our
20 business with long-term capital projects, our obligation to
21 serve, and the potential for high volatility in fuel and
22 purchased power markets, necessitates the ability to tap
23 the financial markets under reasonable terms on a regular
24 basis.
25 In these past few months we have seen ample evidence
26 of the benefit of having a higher credit rating. As an
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example, in Decemer, 2008, El Paso Electric, a BB credit,
issued ponds at an effective cost of 15%.
In the fall of 2008 we had planned to issue an
additional $100 million of long-term debt.In April 2008
we issued $250 million of 10-year debt at 5.95%.In the
6 fall of 2008, however, because of the unrest in the
7 financial markets, there were times when we could not issue
8 debt at any interest rate, and when it was available, the
9 all-in interest rates were 9.5% or higher. Fortunately, we
10 were able to negotiate the acquisition of an additional
11 credit line of $200 million for a period of 364 days, under
12 favorable terms, and avoid issuing new long-term debt at
13
14
these high rates - at least for now.We believe that
financial markets will be more stable as we move toward the
15 later part of 2009, and our financial circumstances will be
16 such that we will have access to new long-term debt at
17 reasonable rates.
18
19
Treasuries have decreasedYieldsonusQ.
significantly over the past several months.Why have
20 interest rates for utility bonds gone up?
21 Although it is true that the yield on USA.
22 Treasuries has declined, the interest rate spreads between
23 utility bonds and Treasuries that debt holders are
24 demanding have increased dramatically due to the unrest in
25 the financial system and the economy. The following graph
26 illustrates the dramatic rise in the gap during 2008
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between the yields on Treasuries and utility bonds rated
BBB+, BBB, and BBB- or below. The graph also illustrates
3 the significantly higher cost of debt for companies at or
4 below the lowest rung of the investment grade ladder (BBB-
5 or belo~), versus a credit rating of BBB, only one step
6 higher than Avista' s current rating of BBB-.
.
7
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10
11
12
13
14
15
16
17
18
19
20
21
+640 bps
+590 bps
+540 bps
+490 bps
+440 bps
+390 bps
+340bps
+290 bps
+240 bps
+190bps
+140 bps
Illustration No.1:
Average Utility Bond Spread to U.S. Treasury
-BBB+ -BBB -BBB-orWorse
BBB- or worse
+90 bps
Mar-07 Aug-oa No..OSAug-07 Oc"07 Jan-oa Mar-OS Jun-oaMay-07
22 debt securities.
Q.Please explain the credit ratings for Avista's
23
24
A.Rating agencies are independent agencies that
assess risks for investors.The three most widely
25 recognized rating agencies are Standard & Poor's (S&P),
.(Moody's) and FitchRatings
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(Fitch) . These rating agencies assign a credit rating to
companies and their securities so investors can more easily
3 understand the risks associated with investing in their
4 debt and preferred stock. Avista' s credit ratings by the
5 three principal rating agencies are sumarized on page 1 of
6 Exhibit No.2. Additionally, the. following rating actions
7 occurred during 2007 and 2008:
.
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25
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a. S&P upgraded Avista's corporate credit rating toBBB- from BB+ (February 2008) and Avista' s secured
debt rating to BBB+ from BBB- (Septemer 2007 and
affirmed in September 2008) .
b. Moody's upgraded Avista' s corporate credit rating
to Baa3 from Ba1 and Avista' s secured rating toBaa2 from Baa3 (December 2007) .
c. Fitch upgraded Avista' s long-term issuer default
rating to BB+ from BB and its secured debt ratingto BBB from BBB- (August 2007 and affirmed in
February 2008) .
As shown in Illustration No. 2 below, Avista is on the
lowest rung of the investment grade credit rating scale.
As I noted earlier, I believe it is important that we move
up the scale to at least a BBB or BBB+, so that we are not
on the edge of the investment grade cliff.
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3
4
5
6
7
8
Xllustration No.2:
S&P's Distrbution of Credit Ratigs of
U.S. Regulted Electrc Utities
(as of 115/09)
c 80
l 60..
~ 40!
! 20;z o
Avist
AA.A.BBB+BBB BBB-BB+ BB BB-A+A
Credit Rati
Q.Please explain the implications of the credit
9 ratings in ter.s of the Comany's ability to access
10 financial markets.
11 impact inves tor demand andA.Credit ratings
12 expected return. More specifically, when the company issues
13 debt, the credit rating helps determine the interest rate
14 at which the debt will be issued. The credit rating also
15 determines the type of investor who will be interested in
16 purchasing the debt. For each type of investment a
17 potential investor could make, the investor looks at the
18 quality of that investment in terms of the risk they are
19 taking and the priority they would have in the event that
20 the organization experiences severe financial stress.
21 Investment risks include the likelihood that a company will
22 not meet all of its debt obligations in terms of timeliness
23 and amounts owed for principal and interest. Secured debt
24 receives the highest ratings and priority for repayment
25
26
and, hence, has the lowest relative risk.In challenging
credit markets, where investors are less likely to buy
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3
corporate bonds, a higher credit rating will attract more
investors, and a lower credit rating could shrink or
eliminate the numer of potential investors.Thus, lower
4 credi t ratings may result in a company having more
5 difficulty accessing financial markets and/or incur
6 significantly higher financing costs.
7 What credit rating does Avista CorporationQ.
8 believe is appropriate?
9 The move to investment grade for Avista Corp lastA.
10 year was a significant step in improving the ability to
11 However, a creditaccess capital at a reasonable cost.
12 rating at the bottom of investment grade is not appropriate
13
14
15
In adverse conditions - whether unique tofor Avista.
Avista or by all market participants - a downgrade from
( inves tmen t to BB+(high-yield)isgrade)BBB-
16 significantly harder to overcome than a downgrade from BBB
17 to BBB-. As Avista experienced, it took approximately six
18 years for the Company to regain its investment grade rating
19 from S&P after it was downgraded during the energy crisis.
20 The difference between investment grade and non-investment
21 grade is not only a matter of debt pricing, it can be a
22 matter of any access at all. During the period from mid-
23
24
the credi t markets wereSeptemer to mid-Decemer,
essentially closed to non-investment grade issuers.In
25 order to be able to weather a potential downgrade, Avista
26 Utilities should operate at a level that will support a
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4
strong corporate investment grade credit rating, meaning a
~BBB" or an ~BBB+," using S&P' s rating scale.
A solid investment grade credit rating would also
allow to post less collateral withtheCompany
5 counterparties than would otherwise be required with a
6 lower credit rating. This results in lower costs. It also
7 increases financial flexibility since the credit line
8 capacity would not be reduced for outstanding letters of
9 credit.
10
11
Financially healthy utilities have lower financing
costs which, in turn, benefit customers.In addition,
12 financially healthy utilities are better able to invest in
13 the needed infrastructure over time to serve their
14 customers, and to withstand the challenges and risks facing
15 the industry.
16 What financial metrics are used by the ratingQ.
17 agencies to establish credit ratings?
18 S&P modified its electric and natural gas utilityA.
19 rankings in Novemer 2007 to conform to the ~business
20 risk/financial risk" matrix used by their corporate ratings
21 The change by S&P was designed to present theirgroup.
22 rating conclusions in a clear and standardized manner
23 across all corporate sectors.
24
25
26
S&P's financial ratio benchmarks used to rate
companies such as Avista are set forth in Illustration No.
3 below.
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6.7
8
9
10
11
12
13
14
15
16
17
18
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1 Xllustration No.3:
Standard & Poor's Financial Risk Indicative Ratios. US Utilties
FFO/Debt (%)FFOllnterest (x)Debt Ratio (%)
Modest 40 - 60 4.0 - 6.0 25 - 40
Intermediate 25 - 45 3.0 - 4.5 35 - 50
Aggressive 10 - 30 2.0 - 3.5 45 - 60
Highly leveraged Below 15 2.5 or less Over 50
12 Month End 9/30/08 Ratios:
Avista Adjusted*17.6 3.4 53.7
* Calculated as of 9/30/08 based on last known sap methodology
The ratios above are utilized to determine the
financial risk profile.Currently, Avista is in the
"Aggressive" category.The financial risk category along
with the business risk profile (Avista is in the Strong
category) is then utilized in Illustration No. 4 below to
determine a company's rating.S&P currently has Avista' s
corporate credit rating as a BBB-, as indicated in the
following illustration.
Illustration No.4:
Standard & Poor's Business Risk 1 Financial Risk Matnx
Financial Risk Profile
Highly
Business Risk Profile Minimal Modest Intermediate Aggressive leveraged
Excellent AM AA A BBB BB
Strong AA A A-BBB-BB-
Satisfactory A BBB+BBB BB+B+
Weak BBB BBB-BB+BB-B
Vulnerable BB B+B+B B-
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The other rating agencies (Moody's and Fitch) use a
similar methodology to analyze and determine utility credit
3 ratings.,
4 Q.Please describe how these ratios are calculated
5 and what they mean?
6 A.The first ratio, "Funds from operations/total
7 debt (%)", calculates the amount of cash from operations as
8 a percent of total debt. The ratio indicates the company's
9 ability to fund debt obligations. The second ratio, "Funds
10 from operations/interest coverage (x) " , calculates the
11 amount of cash from operations that is available to cover
12 interest requirements.This ratio indicates how well a
13 company's earnings can cover interest payments on its debt..14
15
The third ratio, "Total debt/total capital (%)", is the
amount of debt in our total capital structure.The ratio
16 is an indication of the extent to which the company is
17 using debt to finance its operations.S&P looks at many
18 other financial ratios; however, these are the three most
19 important ratios they use when analyzing our financial
20 profile.
21 Q.Do rating agencies make adjustmnts to the
22 financial ratios that are calculated directly from the
23 finacial statements of the Comany?
24 A.Yes. Rating agencies make adjustments to debt to
25 factor in off-balance sheet commitments (for example, the
26 accounts receivable program, purchased power agreements and
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1
2
the unfunded status of pension and other post-retirement
benefits) that negatively impact the ratios.S&P has
3 historically made adjustments to Avista' s debt totaling
4 approximately $226 million related to the accounts
5 receivable program, purchased power and post-retirement
6 The adjusted financial ratios for Avista arebenefits.
7 included in Illustration No. 3 abovè.
8 Where does Avista fall within those coverageQ.
9 ratios?
10 Avista's cash flow ratios have improved as aA.
11 result of the refinancing of the high cost debt that
12 S&P and Moody's took this intomatured in June 2008.
13 account when they upgraded Avista in Decemer 2007 and
14 February 2008. Progress in increasing the cash flow ratios
15 in recent years has been slower than anticipated due to
16 below normal stream flows affecting hydro generation,
17 higher thermal fuel costs than the amount included in rates
18 and the resulting inability to eliminate electric deferral
19 balances, and higher capital expenditures that require cash
20 up front before we can recover the costs from customers.
21 Each has an impact on the Company by reducing the amount of
22 available cash flow from operations, requiring external
23 financing and ultimately resulting in higher debt and lower
24
25
26
In fact, S&P stated the following in acash flow ratios.
January 2008 research report on Pacific Northwest
Hydrology:
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4
5
6
We find that Avista and Idaho Power, which are
comparably sized companies, face the most
substantial risk (related to hydro power) despite
their PCAs and cost update mechanisms. 1
Additionally, S&P stated the following in its February 2008
7 research update of Avista Corporation:
8 The Company's financial performance will continue
9 to be significantly affected by hydro conditions10 and gas prices. And the Company's key utility11 risk going forward is its exposure to high-cost12 replacement power, particularly in low water13 years. 2
1415 In order to improve the cash flow ratios, Avista must
16 reduce its total debt balances and increase its available
17 funds from operations. Although the Company has continued
18 to work towards paying down its total debt, the negative
19 impacts to cash flow caused by below-normal hydroelectric.20 generation and volatility of wholesale electric market
21 prices and natural gas prices in recent years, has
22 adversely affected Avista' s progress in improving the cash
23 flow ratios.
24 Q.Do the rating agencies look at any other factors
25 when evaluating a comany's credit quality?
26 A.Yes. In addition to financial ratios and metrics,
27 rating agencies also look at a numer of qualitative
28 factors which directly or indirectly may affect a company's
29 cash flow. These factors include:
1 Standard and Poor's, Pacific Northwest Hydrology and Its impact on
Investor-Owed Utilities' Credit Quality, January 2008
2 Standard and Poor's, Avista Corp's Corporate Credit Rating Raised One
Notch to BBB-, February 2008.Thies, Direct 23
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.1 · Regulation
2 · Markets
3 · Operations
4 · Competitiveness, and
5 · Management
6 In evaluating these factors, the rating agencies look
7 for regulatory actions that are supportive of cost recovery
8 and that eliminate or minimize volatility of cash flows.
9 They also consider the strength and growth of the economy
10 in our service territory, operations' ability to control
11 costs, whether our service is competitive, and the
12 effectiveness of management.
.13
14
Therefore, while the ratios are utilized in their
quantitative evaluation of a company, they are not the only
15 factors that are taken into account.
16 Q.What risks are Avista an the utility sector
17 facing that may impact credit ratings?
18 A.Avista's credit ratings are impacted by risks
19 that could negatively affect the company's cash flows.
20 These risks include, but are not limited to, the level and
21 volatility of wholesale electric market prices and natural
22 gas prices for fuel costs, liquidity in the wholesale
23 market (fewer counterparties and tighter credit
24 restrictions), recoverability of natural gas and power
25 costs, stream flow and weather conditions, changes in.Thies, Direct 24
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legislative and governmental regulations, relicensing hydro
projects, rising construction and raw material costs,
3 customers' ability to timely pay their bills, and access to
4 capital markets at a reasonable cost.
5 Credit ratings for the utility sector are also
6 adversely impacted by large capital expenditures for
7 environmental compliance, and the need for new generation
8 and transmission and distribution facilities. The utility
9 sector is in a cycle of significant capital spending, which
10 will likely be funded by large issuances of debt and
11 equity.This increases the competition for financial
12 capital at a time when the average utility credit rating is
13 just above investment grade..14 Gi ven the downturn in the economy and the tightened
15 credit markets, the rating agencies are keeping closer tabs
16 on all companies in order to make sure there is sufficient
17 liquidi ty in case the credit markets are inaccessible. Not
18 having sufficient sources of cash for potential cash
19 requirements could prompt a credit rating downgrade.
20 The increased capi tal spending needs and resul ting
21 increased debt issuances make regulation supporting the
22 full and timely recovery of prudently incurred costs even
23 more critical to the utility sector than in previous years.
24
25
Q.How important is the regulatory environmnt in
which a Comany operates?
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A. The regulatory environment in which a company
operates is a major qualitative factor in determining a
company's credi tworthiness .Moody's stated the following
4 regarding Avista' s regulatory environment in a Decemer
5 2008 credit ratings report:
6 "Avista benefits from credit supportive7 ratemaking practices in all three of its
8 jurisdictions, which include periodic mechanisms
9 to account for variations in the power and10 natural gas costs incurred as compared to the11 levels included in rates." However, Moody's also12 pointed out that "Failure to obtain adequate and13 timely support for recovery of and return on core
14 utility investments through pending and expected15 future regulatory proceedings, or any unexpected16 material deviation from the back-to-basics17 strategy, are among the more important factors
18 that could have negative rating implications.
"3
1920 Additionally, in a January 2008 article published by.21 S&P entitled "Top Ten US Electric Utility Credit Issues for
22 2008 and Beyond", S&P stated that "Recovering in a timely
23 manner federally and/or state mandated compliance costs is
24 paramount to preserving credit quality for regulated
25 electric utilities.
"4
26 Due to the maj or capi tal expendi tures planed by
27 Avista, the continued supportive regulatory environment
28 will be critical to Avista's financial health.
29 Additionally, although Avista has electric and natural gas
30 tracking mechanisms (PCA and PGA) to provide recovery of
3 Moody's Investor Service, Moody's Upgrades Avista Corp (Decemer 3,
2008)
4 Standard and Poor's, Top Ten US Electric Utility Credit Issues for
2008 and Beyond, January 2008.Thies, Direct 26
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the majority of the variability in commodity costs, these
changes - in costs must be financed until the costs are
recovered from customers.Investors and rating agencies
4 are concerned about regulatory lag and cost-recovery
5 related -to these items.
6 How do you exect the rating agencies will viewQ.
7 the Comany's proposed change in the PCA mechanism from a
8 "90%/10%" to a "95%/5%" sharing?
9 I believe the rating agencies will view theA.
10 Company's proposal favorably. In a report issued by S&P on
11 January 14, 2009 relating to the approval by the IPUC on a
12 similar change in Idaho Power's PCA, they stated US&P said
13 today that improvements to Idaho Power Company's annual PCA
14
15
mechanism supports credit quali ty but will have no
immediate impact on credit ratings."The changes are
16 expected to reduce the under-collection of power costs and
17 reduce cashflow volatility.
18
19
20
iV. CASH FLOW
Q.What are the Comany's sources to fun capital
21 requiremnts?
22 The Company utilizes cash flow from operations,A.
23 long-term debt and common stock issuances to fund its
24
25
Addi tionally, on an interim basis,capital expenditures.
the Company utilizes its credit facilities to fund working
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capital needs and capital expenditures until longer-term
financing can be obtained.
Q.Wht are the Coman's near-term capi tal
4 requiremts?
5 A.. As a combination electric and natural gas
6 utility, over the next few years, capital will be required
7 for customer growth, investment in generation, transmission
8 and distribution facilities for the electric utility
9 business, as well as necessary maintenance and replacements
10 of our natural gas systems.
11 The amount of capital expenditures planned for 2009-
12 2010 is approximately $420 million. For 2009 alone, these
13 costs equate to a total of $210 million. Total ratebase at.14
15
November 30, 2008 was $1.9 billion for the total Company;
therefore,these planned capital additions represent
16 substantial new investments given the relative size of the
17 Company. A few of the major capital exenditure items on a
18 system basis for 2009 include $60 million for electric
19 transmission and distribution upgrades, $20 million for
20 natural gas system upgrades, $10 million for environmental
21 (associated with the Spokane River relicensing and the 2001
22 Clark Fork River license implementation issues), and $30
23 million for generation upgrades.
24
25
Q.Wht are the Comany's long-term capital
requirements?
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A. Avista' s Integrated Resource Plan has identified
the potential need for the Company to finance significant
expendi tures for electric facilities.The preferred
4 strategy outlined in our 2007 integrated Resource Plan
5 includea total expenditures of $1.25 billion by 2018,
6 including investment in wind resources and upgrades at
7 hydroelectric stations.
8
9
Maj or capital expenditures are a normal part of
utility operations.Customers are added to the service
10 area, roads are relocated and require existing facilities
11 to be moved, and facilities continue to wear out and need
12 replacement. These and other requirements create the need
.13
14
for significant capital expenditures each year.We saw
significant increases in the costs of raw materials over
15 the past year, which our suppliers are continuing to pass
16 through to us in the pricing of their finished products.
17 Access to capital at reasonable rates is dependent upon the
18 Company maintaining a strong capital structure, sufficient
19 interest coverage, and investment grade credit ratings.
20 Q.What are the Comany' s near-te~ plans related to
21 its debt?
22 A.During 2008 the Company issued $250 million of
23 secured debt in April but, as explained earlier, chose not
24 to go forward !Ni th a planned issuance of $100 million in
25 long-term debt in Septemer due to unfavorable conditions
26 in the debt capi tal markets.The Company instead sought
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out and was able to establish a second bank line of credit
in the, amount of $200 million for 364 days to ensure
3 continued adequate liquidity. The Company was also offered
4 and accepted a private placement of $30 million of First
5 Mortgage Bond secured 5-year debt.
6
7
The Company currently plans to issue up to $150
million of secured, fixed rate bonds during 2009.The
8 proceeds from the issuance of the securities will be
9 utilized to fund capital expenditures and repay funds
10 borrowed under our credit facilities. The Company has no
11 long- term debt scheduled to mature in 2009; however, it has
12 an option to redeem $61.9 million of Trust Preferred
13 Securities in March 2009..14
15
Illustration No. 5 below shows the amount of debt
maturities for Avista each year:
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5
6
7
8
9
10
11
1
2
Xllustration No.5:
Debt Maturities by Year
proforma December 31,20093 $3
23%
21%
17%~
13%
8%
5%8%
i :.i i i
$250
$200
$150
$100
$50
$0
12 09 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38
.13
14
.~ _oiø IIpio 2O___
Q.Has the Comany taken any steps to address the
15 uncertainty related to interest rate expsure for the
16 planed debt issuance in 2009?
17 The Company recently entered into fourA.Yes.
18 forward-starting interest rate swaps for a total of $100
19 million as a hedge on a portion of the interest payments on
20 the long-term debt we are planning to issue in 2009. The
21 Company is continuing to analyze the possibility of
.
22
23
24
entering into additional transactions in order to lock in
the interest rate on a greater portion of the debt at a
time when Treasury rates are at all-time historical lows.
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Q. What is the status of the Comany's lines of
credit secured by first mortgage bonds an its accounts
3 receivable program?
4 A.The Company has a $320 million line of credit
5 that expires in April 2011, and a $200 million line of
6 credit that expires Novemer 24, 2009. The Company has the
7 option of increasing the $320 million line by $100 million
8 (up to $420 million) at any time during the term of the
9 agreement, subj ect to additional fees and obtaining bank
10 commitments. The agreement includes the option to release
11 the first mortgage bond security when the Company has an
12 investment grade credit rating. The Company also has the
13 option of renewing or upsizing the $200 million deal to.14 $250 million under certain circumstances.Additionally,
15 the Company has an $85 million accounts receivable funding
16 program that expires in March 2009. This agreement has
17 been renewed on a year-to-year basis, and we expect to
18 extend the agreement for another year.
19 The facilities have been sized to allow the Company to
20 maintain a liquidity cushion of at least $125 million at
21 all times to cover required working capital, counterparty
22 collateral requirements,and avoid issuing debt in
23 unfavorable market conditions if they persist through 2009.
24 Our liquidity is strong and we are confident that our
25 current agreements give us flexibility while facing both
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.the volatile financial markets and volatile energy1
2
3
commodi ty prices.
Many purchases of natural gas, or contracts for
4 pipeline capacity to provide natural gas transportation,
5 require collateral, and/or prepayments, based upon the
6 Company's credit rating.upgrades to Avista' s credit
7 ratings during 2007 and 2008 have reduced the amount of
8 collateral required to be posted with counterparties. If
9 Avista is upgraded above its current credit ratings, the
10 Company should see an increase in the numer of
11 counterparties willing to do business with us and the
12 collateral requirements are expected to decrease even
.13
14
further, resulting in reduced borrowing costs.The lines
of credit and accounts receivable program are our primary
15 sources of immediate cash for borrowing to meet these needs
16 and for supporting the use of letters of credit. A line of
17 credit is required to manage daily cash flow since the
18 timing of cash receipts versus cash disbursements is never
19 totally balanced.
20 Q.What are Avista's plans regarding comn equity
21 and why is this important?
22 A.Avista will continue to monitor the common equity
23 ratio of its capital structure, and assess the need to
24 issue additional common equity.Avista entered into a
.
25 sales agency agreement in Decemer 2006 to issue up to two
26 million shares of our common stock from time to time.
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During the third quarter of 2008, we issued 750,000 shares
of common stock under this agreement. Our plan for 2009 is
3 to continue with the periodic offering of common stock as
4 needed to support the Company's common stock ratio. To the
5 extent that we are not able to access the equity market,
6 there will be increased pressure on our lines of credit,
7 and an increased need to issue long term debt, which is
8 likely to unfavorably impact our cost of debt and debt to
9 equi ty ratio.It is important to the rating agencies for
10 Avista to maintain a balanced debt/equity ratio in order to
11 minimize the risk of default on required debt interest
12 paYments.
.13
14
As Dr. Avera explains in his testimony, the 50.0
percent common equity ratio requested by Avista in this
15 case is consistent with the range of equity ratios
16 maintained by the firms in the Utility Proxy Group.
17 Dr. Avera notes that electric utilities are facing,
18 among other things, rising cost structures, the need to
19 finance significant capital investment plans,and
20 uncertainties over accommodating future environmental
21 mandates. A more conservative financial profile, in the
22 form of a higher common equity ratio, is consistent with
23 increasing uncertainties and the need to maintain the
24 continuous access to capital that is required to fund
25 operations and necessary system investment, even during
26 times of adverse capital market conditions.
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He also discusses Moody's warning to investors of the
risks associated with debt leverage and fixed obligations
3 and their advice to utilities to not squander the
4 opportunity to strengthen the balance sheet as a buffer
5 against future uncertainties. Moody's noted that, absent a
6 thicker, equi ty layer, utili ties would be faced with lower
7 credi t ratings in the face of rising business and operating
8 risks:
.
9
10
11
12
13
14
15
16
17
18
19
There are significant negative trends developing
over the longer-term horizon. This developing
negative concern primarily relates to our view
that the sector's overall business and operating
risks are rising - at an increasingly fast pace -
but that the overall financial profile remainsrelatively steady. A rising risk profile
accompanied by a relatively stable balance sheet
profile would ultimately result in credit quality
deterioration.
5
This is especially the case for Avista, which faces
20 the dual challenge of financing significant capital
21 expansion plans in a turbulent market while at the same
22 time endeavoring to improve its credit standing. Avista is
23 committed to maintaining an appropriate level of equity to
24 support a strong credit rating.
25 Q.What are Avista' s plans regarding preferred
26 equity and other financing structures (for exle, hybrid
27 instruents) ?
28 A.Avista does not have any preferred equity or
29 other financing structures outstanding at Decemer 31,
5 Moody's Investors Service, 'U. S. Electric Utility Sector,. Industry
Outlook (Jan. 2008)..Thies, Direct 35
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2008. Currently, Avista does not plan to issue preferred
equity or other financing structures, but will continue to
3 evaluate the appropriateness of these financing vehicles.
4
5
6
V. CAPITAL STRUCTU
Q.Please explain the capital structure proposed by
7 Avista in this case.
8 A. Avista' s current capital structure consists of a
9 blend of long-term debt and common equity necessary to
10 support the assets and operating capital of the Company.
11 The proportionate shares of Avista Corp.' s actual capital
12 structure on September 30, 2008, are shown on page 1 of
13 Exhibi t No.2, Schedule 2. A pro forma capital structure.14 is also shown on page :L in the Schedule, which reflects
15 expected changes for the period ending June 30, 2009.
16 Supporting workpapers provide additional details related to
17 these adjustments on pages 3 through 4.
18 The rate of return to be applied to rate base in this
19 proceeding is equal to the weighted average cost of
20 capital, taking into account the pro forma adjusting items.
21 As shown on page 1 of Exhibit No.2, Schedule 2, Avista
22 Utili ties is proposing an overall rate of return of 8.80%.
23
24
25
26.Thies, Direct 36
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.
1
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3
VI. COST OF DEBT
Q.How have you determined the cost of debt?
Cost of debt in the Company's proposed capitalA.
4 structure includes long-term debt. As shown on page 1 of
5 Schedule 2 of Exhibit No.2, the actual weighted average
6 cost of long-term debt outstanding on Septemer 30, 2008
7
8
The size and mix of debt changes over timewas 6.91%.
based upon the actual financing completed.We have made
9 certain pro forma adjustments to update the debt cost
10 through June 30, 2009 to 6.60%. Pro forma adjustments to
11 long-term debt reflect expected maturities of outstanding
12 debt and the issuance of new debt to fund those maturities.
13 The pro forma weighted cost of long-term debt was reduced
14
15
16
17
from 3.45% to 3.30%.
VII. COST OF COMMON EOUITY
Q.Wht rate of return on comn equity is the
18 Comany proposing in this proceeding?
19 As further explained by Dr. Avera, the cost ofA.
20 equity has increased since the conclusion of Avista' s last
21 Difficult economic conditions andgeneral rate case.
22 increased volatility in the financial markets have caused a
23 flight to quality among investors, meaning that they have a
24 preference for investments with very low risk, such as U.S.
25 Treasury bonds, and they are demanding a higher premium
26 (return) for taking additional risk. As explained earlierThies, Direct 37
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in my ,testimony, the interest rate spreads between US
Treasuries and utility bonds increased dramatically in the
3 later part of 2008. Equity investments inherently contain
4 more risk, and our cost of equity has also increased since
5 our last rate case.
6 The Company is proposing an 1l. 0% return on common
7 equity (ROE), which falls below the lower end of Dr.
8 Avera's recommended range of required return on equity.
9 Dr. Avera testifies to analyses related to the cost of
10 common equity with an ROE range of 11.3% to 13.3%. In his
11 testimony Dr. Avera states that:
.
12
13
14
15
16
17
18
19
20
Considering investors' expectations forcapi tal markets and the need to support
financial integrity and fund crucial
capital investment even under adversecircumstances, I concluded that Avista' s
requested ROE of 11.0% percent isreasonable. (P. 5, L. 40 - P. 6, L. 1)
Q. Dr. Avera suggests an ROB range of 11.3% to
21 13.3%. Why is Avista requesting an ROB below the lower end
22 of the range?
23 A.As I have testified, Avista has made solid
24 progress towards improving its financial health. If Avista
25 can earn an 11.0% ROE, I believe our financial condition
26 would continue to improve and would further strengthen the
27 credi t ratings ratios.
28 Furthermore,as the Company has worked toward
.
29 improving its financial condition over the last several
30 years, it has done so with the customer in mind. Avista is
Thies, Direct 38
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3
4
5
6
7
8
9
10
11
12
.
.
attempting to balance the ability to continue to improve
our financial health and access capital markets under
reasonable terms with the impacts that increased retail
rates have on its customers.In this case, al though we
believe an ROE greater than 11.0% is supported and is
warranted, we also believe the 11.0% provides a reasonable
balance of the competing obj ecti ves .
Q. Please sumrize the proposed capital structure
and the cost components for debt and comn equity.
A. As also shown on page 1 of Exhibit No.2, Schedule
2, the following illustration shows the capital structure
and cost components proposed by the Company.
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3
4
5
6
7
8
9
10
11
12
13.14
15
16
17
18
19
20
21
22
23
24
.
Illustration No.6:
.\ ns r \ CORPOR \ 110'\
(cipital Stiiiclurc cind O\cicill RelIC of Rctiiin
* Pro form Common Equity of 50% is less th calculated Common Equity based on Pro Form
Capita Strtue at June 30, 2009 calculated above
VIIX. INCRESE XN PENSION EXENSE
Q. Has the Comany included an adjustmnt in this
filing for increased pension expense?
A.The pension hasCompany's expenseYes.
2009. Company witness Ms. Andrews discusses the accounting
adjustment to results of operations to reflect this.
Q. What is the reason for the increase in pension
exense in 2009?
A. The increase in pension expense is due primarily
to the negative overall market performance in 2008.
6 Most recent anysis, just prior to dis filig, indicates that the penion cost for 2009 may be higher at
$22.2 millon.
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.
.
.
1
2
3
Although the pension plan assets are diversified among
investment classes, negative returns were associated with
virtually all assets except cash.The stock market had a
4 negative 38% return on the S&P 500 Index, and bond markets
5 and commodities also performed negatively in 2008.
6 The Company's 2008 pension plan return on assets is
7 The negative returns andestimated to be negative 21%.
8 resulting declining value of our pension plan assets
9 increased the pension expense for 2009.
10 The overall market decline impacted the pension plan
11 assets of other companies as well.Most companies with
12 defined benefit pension plans have experienced similar
13 asset value declines and increased funding levels as a
14 resul t of general market conditions and the Pension
15 Protection Act of 2006 (PPA).
16 Results from an EEl survey conducted in early Decemer
17 indicated that all 24 electric utili ties who2008,
18 participated in the survey were estimating negative returns
19 for their pension plan assets in 2008.The 2008 average
20 expected pension returns of the 24 companies surveyed was a
21 negative 26.7%. The Company's pension returns, as described
22 above, were somewhat better than these reported returns.
23 will you describe the process utilized by theQ.
24 Comany for administering investments in its defined
25 benefit plan (pension plan)?
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A. Yes. The Company has a very disciplined approach
to the oversight and monitoring of the pension plan. The
3 Board of Directors of the Company, acting through the
4 Finance Committee of the Board, is responsible for setting,
5 monitoring and adjusting the Investment Policy Statement
6 (IPS) with respect to the investment of funds for the
7 pension plan.The IPS sumarizes the Finance Committee's
8 investment policies for the management and oversight of the
9 pension plan.It sets forth' the objectives of the plan,
10 the strategies designed to achieve these objectives,
11 procedures for monitoring and control of plan assets and
12 the delegation of responsibilities for the oversight and
13 management of plan assets. Given the long-term time horizon.14 of the pension plan, the IPS is designed to endure multiple
15 market environments and to not be reactive to what might be
16 considered normal short-term events.The IPS includes a
17 policy portfolio that envisions a reasonably stable
18 allocation of assets among major asset classes.
19 Q.Wht are the investment policies for managemt
20 and oversight of the pension plan?
21 A.As stated in the IPS, the objectives of the
22 pension plan are designed to provide a total return that,
23 over the long term, provides sufficient assets to fund its
24 liabili ties subj ect to an acceptable level of risk,
25 contributions and pension eXpense deemed appropriate by the
26 Board Finance Committee and to diversify investments within
Thies, Direct 42
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asset classes to reduce the impact of losses in single
investments.
3 Q., Wht resources does the Comany utilize to perform
4 its duties uner the Investment policy Statemnt related to
5 investment of Pension Assets?
6 A.The Company retains an external investment
7 management consultant to develop and recommend asset
8 allocation of the pension plan assets, evaluate and
9 recommend investment managers and monitor the performance
10 and business of the investment managers of the plan assets.
11 This consultant provides a quarterly performance and
12 compliance report of the plan assets. The performance
13 report is reviewed by the Company's internal Benefits Plan.14 Administration Committee quarterly. The performance report
15 is also reviewed by the Board Finance Committee on a
16 quarterly basis.In addition,a . report detailing
17 compliance with the specific requirements of the IPS is
18 provided quarterly to the Board Finance Committee.
19 Q.What are ,the impacts of the Pension Protection
20 Act (PPA) on the Comany's Pension plan?
21 A.The PPA was passed in 2006 and requires annual
22 increases to the pension funding level in order to
23 eventually achieve a fully funded plan.The PPA
24 established that in 2008 the funding level would be 92% of
25
26
the pension plan obligations.For 2009 this level
.increases to 94%. In 2008, Avista' s funding level was 92%
Thies, Direct 43
Avista Corporation
100
.
.
.
1
2
and is projected to be 94% in 2009, based on increased
Company contributions to the plan. If the plan funding
3 level does not meet these established percentages, the
4 entire funding deficit must be added to the contribution
5 over the next seven years in order to be fully funded after
6 If the percentage falls below 80%, planseven years.
7 restrictions would be imposed and the plan would be
8 considered "at-risk." Should this occur, benefit accruals
9 would be frozen and plan participants would not be able to
10 accrue additional pensibn benefits. Additionally, lump sum
11 distributions to participants would not be allowed.
12 To avoid these restrictions the Company is committed
13 to fully meeting these funding levels and complying with
14
15
the requirements of the PPA.
Q.Do the anual cash contributions to the pension
16 fund equal the annual pension expense recognized ~ the
17 Comany?
18 In fact the cash contribution that AvistaA.No.
19 will make to the pension fund in 2009 will be substantially
20 higher than the proforma expense of $18.4 million
21 identified earlier. The annual cash contribution is driven
22 by the need to comply wi th the funding requirements of the
23
24
25
PPA (e.g., 94% funded by the end of 2009).It will be
necessary to make a cash contribution to the pension fund
in 2009 of at least $42 million, and more recent analysis
Thies, Direct 44
Avista Corporation
101
.indicates that we may need to contribute $67 million of1
2
3
cash in 2009.
The pension expense recognized by the Company is
4 determined using a formula as prescribed by Financial
5 Accounting Standard No. 87 (FAS 87). The objective of FAS
6 87 is to recognize the compensation cost of an employee i s
7 pension benefits (including prior service cost) over that
8 employee i s approximate service period. While the pension
9 cash contribution amount does affect the pension expense,
10 the FAS 87 assumptions and calculations are different from
11 those used to determine the funded status.
12 As can be seen by the differences in the 2009 cash.13
14
contribution of $67 million and the pension expense of
$18.4 million, the differing requirements of the PPA and
15 FAS 87 can result in a substantial difference between cash
16 contributions and recognition of expense.The current
17 level of pension expense reflected for ratemaking purposes
18 is $11.85 million. Therefore, until the conclusion of this
19 case, the current annualized difference between the cash
20 contribution and pension expense is over $55 million ($67
21 million - $11.85 million) .
22
23
Q.What impact does that timing difference have on
the Company?
.Thies, Direct 45
Avista Corporation
102
, '
.1
2
A. The result for Avista in 2009 is that the Company
would make a cash paYment of $67 million, while recovering
3 $11.85 million of expense through its retail rates. Absent
4 some form of accounting treat~ent or, other relief from the
5 Commission, Avista would not recover the time value of
6 money on the difference between the cash paYment and the
7 level of expense.Because of the magnitude of this
8 difference, the absence of a carrying cost would have a
9 significant impact on the earnings of the Company.The
10 difference of $55 million times the requested rate of
11 return of 8.80% is $4.8 million for 2009 alone.
12 Q.Have you seen these kinds of cash versus exense
13 differences in the past?.14 A.Nothing even close to this magni tude.A
15 comparison of cash paYments versus pension expense for each
16 year from 1992 through 2008 is shown in Illustration No. 7
17 below. Not only are the anual differences much smaller,
18 but on a cumulative basis through 2007, the difference is
only $1.4 million.However, in 2008 the cash paYment is19
20
21
$l6.0 million higher than the expense, and the difference
for 2009 will be even greater.
.Thies, Direct 46
Avista Corporation
103
.1 J:llustration No.7:
Year
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008.2
3
Cash
Contribution
$0.0
$0.0
$0.0
$0.0
$0.0
$3.3
$0.0
$0.0
$3.3
$0.0
$12.0
$12.0
$15.0
$15.0
$15.0
$15.0
$28.0
Annual
Expense
-$1.1
-$0.5
$1.0
$2.0
$2.4
$2.2
$1.5
$2.4
$0.8
$3.8
$9.3
$14.9
$13.6
$11.9
$12.8
$12.3
$12.0
Difference
$1.1
$0.5
-$1.0
-$2.0
-$2.4
$1.1
-$1.5
-$2.4
$2.5
-$3.8
$2.7
-$2.9
$1.4
$3.1
$2.2
$2.7
$16.0
Cumulative
Difference
$1.1
$1.6
$0.6
-$1.4
-$3.8
-$2.7
-$4.2
-$6.6
-$4.1
-$7.9
-$5.2
-$8.1
-$6.7
-$3.5
-$1.3
$1.4
$17.3
Q.Do you expect these maj or cash versus expense
4 differences to continue for the indefinite future?
5 A.No. Al though they may continue for some period
6 of time, as the financial markets recover, which we
7 anticipate they will at some point, the cash contribution
8 requirement for the pension plan will come down and
9 potentially go to zero at some point. At that point, there
10 would be opportunity for the cumulative difference between
11 cash and expense to again move toward zero.
12 In the meantime, however, we have a significant
13 difference between the cash contribution and pension
14 expense that needs to be addressed in some way..
104
Thies, Direct 47
Avista Corporation
.1
2
Q. What is the Coman proposing with regard to this
difference between the cash contribution to fun the
3 pension- plan an the annual level of pension exense?
4 A.Due to the substantial difference between the
5 2009 pension payment and the amount of authorized utility
6 pension. cost, the Company is requesting approval to
7 establish a regulatory asset for the carrying costs on the
8 cumulative difference between payments and authorized
9 pension cost. It is important to emphasize that we are not
10 requesting accounting treatment to defer the actual dollar
11 differences between the cash payment and expense, but only
12 the carrying cost on those dollar differences.
.13
14
In future periods if the pension cash payments are
less than the authorized cost, the cumulative difference
15 will decrease and the resulting carrying cost accrual will
16 decrease.
17 Q.When does the Comany propose to start the
18 accrual of the carrying cost, and at what rate?
19 A.The Company is proposing to begin accruing the
20 carrying charge effective February 1, 2009, at its
21 authorized rate of return during the month. the accrual
22 occurs, compounded annually. The current authorized rate of
23 return is 8.45%.
24
25
26
Q.How would the accrual calculations be made?
A.A reduction to the cash payments would first be
.made to remove the portion related to non-utility. The
Thies, Direct 48
Avista Corporation
105
.1
2
remaining utility portion would be allocated to utility
jurisdictions and services based on the labor dollars
3 included in this filing.
4 Assuming the Company will be making contributions to
5 the pension plan in 2009 of $67 million, after removing the
6 portion of pension costs related to non-utility companies
7 of 0.42%, or $0.28 million, the remaining portion of the
8 $67 million related to utility operations amounts to $66.72
9 million.In contrast, the amount of pension expense
10 related to utility operations on a system basis is $11.85
11 million from the last general rate case.
12 A carrying charge would be accrued each month,
13 beginning February 1, 2009, based on the cumulative.14 difference between the actual cash paYments and the
15 authorized pension expense.
16 Q.Wht accounts would be used to account for the
17 accrual of the carrying cost?
18
19
20
A.The accrual of the carrying cost would be
recorded by debiting Account 182.3 Other Regula tory
Assets and crediting Account 419 - Interest Income.The
21 carrying cost calculation and a. breakdown of the regulatory
22 asset would be maintained by utility jurisdiction
23 (Washington and Idaho) and utility service (electric and
24 gas) .Should the accrual become negative, Account 431 -
25 Other Interest Expense would be debited and Account 182.3
26 would be credited until the balance in Account 182.3
Thies, Direct 49
Avista Corporation.
106
.
.
.
1
2
reaches zero, and then, Account 254 - Other Regulatory
Liabilities would be credited. Deferred federal income
3 taxes would be recorded by debiting Account 410.2
4 Provision for Deferred Income Taxes, Other Income and
5 Deductions and crediting Account 283 - Accumulated Deferred
6 Income Taxes-Other.
7 How would the deferred carrying costs beQ.
8 recovered in rates?
9 The Company would continue to review the balanceA.
10 of deferred carrying costs to determine if a rate
11
12
13
14
Theadjustment to recover the costs was necessary.
liability accounts willregulatoryasset/regulatory
function like a balancing account.While a regulatory
asset will be created in 2009, a rebound in the investment
15 market could cause the regulatory asset to be offset by
16 regulatory liability entries over a period of time, and no
17 If a rate adjustmentrate adjustment would be necessary.
18 were to become necessary, the Company would file a request
19 as part of a general rate case or other filing to recover
20 the deferral balance.
21 conclude your pre-filed directQ.Does that
22 testimony?
23 A.Yes.
Thies, Direct 50
Avista Corporation
107
.1 I.INTODUCTION
2
3
Q.
A.
Please state your name and business address.
william E. Avera, 3907 Red River, Austin, Texas,
4 78751.
5
6
Q.
A.
In what capacity are you emloyed?
I am the President of FINCAP, Inc. , a firm
7 providing financial,economic,and policy consulting
8 services to business and government.
9 Q. Please describe your educational backgroud and
10 professional experience.11 A. A description of my background and
12 qualifications, including a resume containing the details
13 of my experience, is attached as Exhibit 3, Schedule 1..14 A. Overview
15
16
17
Q.What is the purpose of your testimony in this
case?
A.The purpose of my testimony is to present to the
18 Idaho Public Utilities Commission (the "Commission" or
19 "IPUC") my independent evaluation of the fair rate of
20 return on equity ("ROE") for the jurisdictional electric
21 and gas utility operations of Avista Corp. ("Avista" or
22 " the Company").In addition,I also examined the
23 reasonableness of Avista's capital structure, considering
24 both the specific risks faced by the Company and other
25 industry guidelines.
.
108 Avera, Di 1
Avista Corporation
.
10
1
2
3
4
Q. Please sumrize the informtion and materials
you relied on to support the opinions and conclusions
contained in your testimony.
A. To prepare my testimony, I used information from
5 a variety of sources that would normally be relied upon by
6 a person in my capacity.I am familiar with the
7 organization, finances, and operations of Avista from my
8 participation in prior proceedings before the I PUC , the
9 washington Utilities and Transportation Commission, and the
Oregon Public Utility Commission.In connection with the
11 present filing, I considered and relied upon corporate
12 disclosures, publicly available financial reports and
13 filings, and other published information r&lating to.l4
15
16
17
Avista. I also reviewed information relating generally to
current capital market conditions and specifically to
current investor perceptions,requirements,and
expectations for Avista' s utility operations.These
18 sources, coupled with my experience in the fields of
19 finance and utility regulation, have given me a working
20 knowledge of the issues relevant to investors' required
21 return for Avista, and they form the basis of my analyses
22 and conclusions.
23 Q. What is the role of the rate of return on comn
24 equity in setting a utility's rates?
25 A. The ROE serves to compensate common equity
26 investors for the use of their capital to finance the plant.
109 Avera, Di 2
Avista Corporation
.1 and equipment necessary to provide utility service.
2 Investors commit capital only if they expect to earn a
3 return on their investment commensurate with returns
4 available from alternative investments with comparable
5 risks.To be consistent with sound regulatory economics
6 and the standards set forth by the U. S. Supreme Court in
7 the Bluefield1 and Hope2 cases, a utility's allowed ROE
8 should be sufficient to: 1) fairly compensate the utility's
9 investors, 2) enable the utility to offer a return adequate
10 to attract new capital on reasonable terms, and 3) maintain
l1 the utility's financial integrity.
.12
13
14
Q. How did you go about developing your conclusions
regarding a fair rate of return for Avista?
A. I first reviewed the general conditions in
l5 capital markets, as well as the operations and finances of
16 Avista and industry-specific risks perceived by investors.
17 With this as a background, I conducted various well-
18 accepted quantitative analyses to estimate the current cost
19 of equity, including alternative applications of the
20 discounted cash flow ("DCF") model and the Capital Asset
21 Pricing Model ("CAPM"), as well as reference to expected
22 earned rates of return.Based on the cost of equity
23 estimates indicated by my analyses, the Company's ROE was
1 Bluefield Water Works & Improvement Co. v. Pub. Servo Comm'n, 262
u.s. 679 (1923).2 Fed. Power Comm'n v. Hope Natural Gas Co., 320 u.s. 591 (1944)..
110 Avera, Di 3
Avista Corporation
.1
2
evaluated taking into account the specific risks and
potential challenges for Avista' s utility operations in
3 Idaho.
4 B. Sumry of Conclusions
5 Q. Wht are your findings regarding the fair rate of
6 return on equity for Avista?
7 A. Based on the results of my analyses and the
8 economic requirements necessary to support continuous
9 access to capital under reasonable terms, I determined that
10 a fair ROE for Avista falls in the range of 11.3 percent to
11 13 .3 percent.The bases for my conclusion are sumarized
12 below:
.13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
. The turmoil in financial markets has resulted in a
fundamental shift in investors' risk perceptions,
which has increased the cost of capital for
utilities such as Avista:
o The dramatic sell-off in common stocks and
sharp increase in utility bond yields
associated with the ongoing credit crisis are
indicative of a significant revision in
investors' willingness to assume risks, which
has led to higher costs for long-term capital;
o Yields on triple-B rated utility bonds have
increased approximately 110 basis points since
the all-party settlement in Avista / s last Idaho
rate proceeding was reached in August 2008,
which specified an ROE of 10.2 percent;
o Because of the "flight to quality", government
bond yields have fallen sharply at the same
time that the required returns for other asset
classes, such as common stocks and public
utility bonds, have moved sharply higher to
compensate for increased perceptions of risk.
As a result trends in Treasury bond yields have
virtually no relevance in evaluating long-term
capital costs for Avista in the current capitalmarket climate..
111 Avera, Di 4
Avista Corporation
.1
2
3
4
5
6
7
8
9
. Ìn order to reflect the risks and prospects
associated with Avista' s jurisdictional utility
operations, my analyses focused on a proxy group of
seventeen other utilities with comparable
investment risks. Consistent with the fact that
utilities must compete for capital with firms
óutside their own industry, I also referenced a
proxy group of comparable risk companies in the
non-utility sector of the economy;
.
10
11
12
13
14
15
l6
17l8
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
. Because investors' required return on equity is
unobservable and no single method should be viewed
in isolation, I applied both the discounted cash
flow ("DCF") and capital asset pricing model
("CAPM") methods, as well as the comparable
earnings approach, to estimate a fair ROE forAvista:
o My application of the constant growth DCF model
considered four alternative growth measures
based on projected earnings growth, as well as
the sustainable, "br+sv" growth rate for each
firm in the respective proxy groups;
o After eliminating low- and high-end outliers,
my DCF analyses implied a cost of equity range
of 11.5 percent to 13.4 percent for the proxy
group of utilities and 13.1 percent to 13.5
percent for the group of non-utility companies;
o Application of the CAPM approach using forward-
looking data that best reflects the underlying
assumptions of this approach implied a cost of
equity of 11.2 percent for the utility proxy
group and 11.5 percent for the firms in the
non~utility proxy group;o My evaluation of earned rates of return
expected for utili ties suggested a cost of
equity on the order of at least 11.4 percent;
o Based on these results, I concluded that the
cost of equity for the proxy groups of
utilities and non-utility companies is in the
11.3 percent to 13.3 percent range.
Considering investors'expectations for capital
41 markets and the need to support financial integrity and
42 fund crucial capital investment even under adverse
43 circumstances, I concluded that Avista' s requested ROE of.
112 Avera, Di 5
Avista Corporation
.1 11.0 percent is reasonable and, if anything, understated.
2 Based on my evaluation, I determined that:
3 . Because Avista' s requested ROE of 11.0 percent4 falls below the lower bound of my recommended
5 range, it represents a conservative estimate of6 investors' required rate of return;
.
7
8
9
10
11
12
13
14
15
16
l7
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
. The reasonableness of an 11. 0 percent minimum ROE
for Avista is also supported by the need to
consider the Company's credit standing, which
remains relatively weak:
o The pressure of funding significant capital
expenditures of $420 million in the next two
years, gi ven that the Company's ra tebase is
$1.9 billion, coupled with increased operating
risks; heighten the uncertainties associated
with Avista;
o Because of Avista' s reliance on hydroelectric
generation and increasing dependence on natural
gas fueled capacity, the Company is exposed to
relatively greater risks of power cost
volatili ty;
o Standard and Poor's Corporation ("S&P") ranks
Avista as 159 out of a total 175 utilities with
investment grade credit ratings, with only 16
companies in the industry having a credit
profile weaker than Avista' s;
o Given Avista's present credit ratings, an
inadequate rate of return imposed in this
proceeding would further pressure the Company's
financial flexibility and cre~it standing;
o My conclusion that an 11.0 percent ROE for
Avista is a conservative estimate of investors'
required return is also reinforced by the
Company's relatively greater risks as comparedwith the proxy groups, the greateruncertainties associated with Avista' s
relatively small size, and the fact that my
recommended ROE range does not consider
flotation costs.
.
113 Avera, Di 6
Avista Corporation
.1
2
3
Q. Wht is your conclusion as to the reasonableness
of the Company's capital structure?
A. Based on my evaluation, I concluded that a common
4 equity ratio of 50.0 percent represents a reasonable basis
5 from which to calculate Avista' s overall rate of return.
6 This conclusion was based on the following findings:
7 . Avista' s requested capitalization is consistent
8 wi th the Company's need to strengthen its credi t9 standing and financial flexibility as it seeks to10 raise additional capital to fund significant system11 investments and meet the requirements of itsl2 service territory;
13 . Avista' s proposed common equity ratio is entirely14 consistent with the range of common equity ratios
l5 maintained by the proxy group of utilities and is16 in-line with the 47.2 percent and 50.8 percent17 average equity ratios, based on year-end 2007 data18 and near-term expectations, respectively..19
20
21
22
23
24
25
26
27
. My conclusion is reinforced by the investment
community's focus on the need for a greater equity
layer to accommodate higher operating risks and thepressures of funding significant capital
investments. This is reinforced by the need to
consider the impact of unfavorable capital markets
condi tions, as well as off-balance sheet
commi tments such as purchased power agreements,
which carry wi th them some level of imputed debt.
28 Q. What other evidence did you consider in
29 evaluating your recommendation in this case?
30 A. My recommendation was reinforced by the following
31 findings:
32
33
34
35
36
.Sensitivity to regulatory uncertainties has
increased dramatically and investors recognize
that constructive regulation is a key ingredient
in supporting utility credit standing andfinancial integrity;
.
114 Avera, Di 7
Avista Corporation
.1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
l6l7
18
19
20
21
22
23
24
25
26
27
28
29
.
30
31
32
.Providing Avista with the opportunity to earn a
return that reflects these realities is an
essential ingredient to strengthen the Company's
financial position, which ultimately benefits
customers by ensuring reliable service at lowerlong-run costs;
My conclusion is reinforced by the economic
reality that Avista' s actual returns have fallen
systematically short of the allowed ROE; and the
financial impact of an ROE below the minimum level
requested by Avista would threaten the Company's
ability to maintain an investment grade creditrating;
Investors are aware of the near-term challenges
posed by upward pressure on costs and rising
capital expenditures. For Avista, these concerns
are magnified by the fact that its credit standing
remains on the precipice between investment gradeand speculative status;
Regulatory support, including a reasonable ROE,
will be a key driver in securing_ additional
progress towards continued improvement in the
Company's financial health. Further strengthening
Avista's financial integrity is imperative toensure that the Company has the capabi 1 i ty to
maintain an investment grade rating while
confronting potential challenges associated with
funding infrastructure development necessary to
meet the needs of its customers.
.
.
.
II. CAPITAL KAT CONDITIONS
Q.
A.
Wht is the purpose of this section?
This section evaluates the impact of recent
33 capi tal market trends on Avis ta ' s ROE.In addition, I
34 examine the implications of Avista's relatively weak credit
35 standing and discuss why it is critical to support
36 improvement in the Company's finances on an ongoing basis.
.
115 Avera, Di 8
Avista Corporation
.1 A. Long-term Capital Costs Have Increased
2
3
4
5
6
Q. Wht are the implications of recent capital
inrket conditions?
A. Recent volatility in the debt and equity markets
linked to the ongoing financial crisis and the economic
downturn evidences investors' trepidation to commit capital
7 and marks a significant upward revision in their
8 perceptions of risk and required returns since the last
9 agreed-upon ROE of 10.2%. The Chicago Board Options
10 Exchange Volatility Index, commonly known as the "VIXn, is
11 a key measure of expectations of near-term volatility and
12 market sentiment based on options prices for the S&P 500
13 Composite Stock Index ("S&P 500n). The unprecedented price.14
15
fluctuations and uncertainty that investors have endured
16 and sustained increase in the VIX, plotted in Figure WEA-1,
since the third-quarter of 2008 is mirrored in the sharp
17 below. The vertical line on the graph represents the date
18 that Avista' s settlement agreement was filed with the IPUC
19 in the last case. The graph illustrates the dramatic
20 increase in volatility since that rate case.
.
116 Avera, Di 9
Avista Corporation
.1
2
70
60
50
40
30
20
10
FIGUR WEA-l
CBOE VIX INDEX - ONE-MONTH MOVIG AVERAGE
Las Settleent Filed (1 0.2010 ROE)
./~'" ~~ 4r?t ~/'O J'~ '%i. ./~'" ~ ~ ~/. '\vi_ '%'-n.~~~~~~~~~~~~
3
4 Bloomberg reported in October 2008 that the VIX had surged
5 26 percent to almost triple its average during the past
6 year. 3.7 With respect to utilities specifically, as of year-end
8 2008, the Dow Jones Utility Average stock index had
9 declined over 28 percent since June 2008, while yields on
10 utility bonds have increased precipitously. Figure WEA-2
11 below plots the monthly average yields on triple-B utility
12 bonds reported by Moody's Investors Service ("Moody's")
13 from January to Decemer 2008:
3 Kearns, Jeff, ~VIX 'Exploding' as Stocks Plunge on Growing Recession
Concern," Bloomberg (Oct. 15, 2008)..
117 Avera, Di 10
Avista Corporation
.
3
4
5.6
7
8
9
10
11
12
13
l4
.
1
2
FIGUR WEA-2
MOODY'S TRPLE-B PUBLIC UTILIT BOND YILDS4
9.5%
9.0%
8.5%La Setlemet Filed (102% ROE)
8.0%
7.5%
7.0%
6.5%
6.0%
~
~'(¡p
.t&. ~ 1ó
0el ""'!ei "'0el
¿ ~ ~ ~ & Q ~ ~-~ Vl'( 'Q ~ ~'! "~Q 0t- lb'0el ¡p ¡p '0el ei ¡p '!ei '0el
As illustrated above, from January to August 2008 the
average yield on triple-B rated utility bonds increased
gradually to approximately 7 percent. Meanwhile ,Moody's
reported that for the months of October and November 2008
the average yield on triple-B utility bonds had climbed to
8.6 percent and 9.0 percent, respectively. The monthly
yield for December 2008 of 8.1 percent is approximately l10
basis points higher than the average in August 2008, when
the all-party settlement in Avista' s last Idaho rate
proceeding was reached, establishing a 10.2% ROE. Thus,
bondholders are demanding a higher return to hold utility
debt.
4 Based on seasoned bonds wi th maturities of at least 20 years.
118 Avera, Di 11
Avista Corporation
.1
2
3
Q. What does this evidence indicate with respect to
establishing a fair ROE for Avista?
A. The dramatic sell-off in common stocks and sharp
4 increase in utility bond yields are indicative of higher
5 costs for long-term capital, and the ongoing credit crisis
6 has spi~led over into the utility industry. For example,
7 utilities have been forced to draw on short-term credit
8 lines to meet debt retirement obligations because of
9 uncertainties regarding the availability of long-term
10 . 1 5capita .As the Edison Electric Institute ("EEl") noted
1l in a letter to congressional representatives, the financial
12 crisis has serious implications for utilities and their
13 customers:.14
15
16
17
18
19
20
21
22
In the wake of the continuing upheaval on Wall
Street, capital markets are all but immobilized,
and short-term borrowing costs to utilities have
already increased substantially. If the
financial crisis is not resolved quickly,
financial pressures on utilities will intensify
sharply, resulting in higher costs to our
customers and, ultimately, could compromise
service reliability. 6
23 Similarly, an October 1, 2008, Wall Street Journal
24 report confirmed that dislocations in credit markets were
25 also impacting the utility sector:
26 Disruptions in credit markets are j ol ting the27 capi tal-hungry utility sector, forcing companies
5 Riddell, Kelly, -Cash-Starved Companies Scrap Dividends, Tap Credit,"
Pittsburgh Post-Gazette (Oct. 2, 2008).6 Letter to House of Representatives, Thomas R. Kuhn, President, Edison
Electric Institute (Sep. 24, 2008)..
119 Avera, Di 12
Avista Corporation
.1
2
to delay new borrowing or come up with different-often more costly-ways of raising cash. 7
3 An October 2008 report on the implications of credit market
4 upheaval for utilities noted that, while high-quality
5 companies can still issue debt, "they now have to pay an
6 unusually high risk premium over Treasuries.
"8 Similarly,
7 S&P recently concluded:
8 Regulated electric issuers continued to access
9 debt markets during the fourth quarter of 2008 at10 rates in line with the 10-year average of about11 8% for five-year notes, not the abnormally low12 interest rate environment of the 2000' s which is13 a distant memory. 9
14 Meanwhile, a Managing Director with Fitch Ratings, Ltd.
l5 ("Fitch") observed that with debt costs at present levels,
16 "significantly higher regulated returns will be required to.l7 attract equity capital. "10 As Fitch concluded:
18 The collapse in secondary market debt pricing and
19 in equity valuations is worrisome. We see new20 debt now priced at around 9% or higher pushing up21 against average authorized ROEs for utilities of
22 around 10.25% to 10.50%. Thus, raising new23 equity, which is now priced close to book value,24 is likely to be dilutive.11
25 More recently, Fitch confirmed "sharp repricing of and
26 aversion to risk in the investment community," and noted
7 Wall Street Journal "Turmoil in Credit Markets Send Jolt to Utility
Sector" (Oct. 1, 2008), p. B4.8 Rudden's Energy Strategy Report (Oct. 1, 2008).
9 Standard & Poor's Corporation, "Industry Report Card: U. S. Electric
Utility Credit Quality Remains Strong Amid Continuing EconomicDownturn," RatingsDirect (Dec. 19, 2008).10 Fitch Ratings Ltd., "EEI 2008 Wrap-Up: Cost of Capital Rising,"
Global Power North America Special Report (Nov. 17, 2008).11 Fitch Ratings Ltd., "Investing In An Unpredictable World," Fitch
Ratings' 20th Anual Global Power Breakfast (Nov. 10, 2008)..
120 Avera, Di 13
Avista Corporation
.1 that the disruptions in financial markets and the
2 fundamental shift in investors' risk perceptions has
3 increaseà the cost of capital for utilities such as Avista:
4 The broad credit markets are in shamles and5 access to credit is restrictive, particularly at6 lower credit ratings. While credit is available7 to investment-grade issuers in the utilities,
8 power and gas sectors, it is more expensive,
9 particularly when viewed against the easy money10 environment which prevailed for most of this
i i decade. 12
12 Fitch concluded, "The sharp increase in the cost of
13 equity capital is a negative credit development.,,13
l4 Q. Do trends in the yields on Treasury notes and
15 bonds accurately reflect the expectations and requirements
16 of Avista's equity investors?
17 A. No. Figure WEA- 3, below, plots the yields on.l8 20-year Treasury bonds from 2006 through Decemer 2008:
12 Fitch Ratings Ltd. , "U. s. Utili ties, Power and Gas 2009 Outlook,"
Global Power North America Special Report (Dec. 22. 2008).13 Id..
121 Avera, Di 14
Avista Corporation
.
3
4.5
6
7
8
9
10
11
12
l3
14
.
1
2
FIGUR WEA-3
20-YEAR TREASURY BOND YILDS
5.5%
5.0%
4.5%
4.0%
3.5%
3.0%~ ~ ~ ~~ ~ ~ ~ ~ ~~ ~ ~ ~ è ~ ~ ~ ~ ~ ~~~~~~~~~~~~~~~~ 'O~~~~~vs- a" vs- " -(I lr -(I lr " ~ ~ ~ v ~ :; v~ ä' (p ä' Vá' ä' Vá'
As shown above, beginning in the third quarter of 2007, the
yields on 20-year Treasury bonds began a general decline.
In response to accelerating concerns over economic
uncertainties and the Federal Reserve's actions to increase
liquidity in the face of a profound crisis in credit
markets, the fall in Treasury bond yields has become
increasingly pronounced, with daily yields on 20-year bonds
falling below 3 percent in Decemer 2008. Meanwhile, the
price of 3-month Treasury bills rose high enough to push
rates into the negative for the first time in history. 14
While the yields on Treasury securities have fallen
significantly, the required returns for common stocks and
14 Kruger, Daniel and Cordell Eddings, 'Treasury Bills Trade at
Negative Rates as Haven Demand Surges," ww.bloomberg.com (Dec. 9,
2008) .
122 Avera, Di 15
Avista Corporation
.1 public utility bonds have moved sharply higher to
2 compensate for increased perceptions of risk. This" flight
3 to quality" has caused the spread between the observable
4 yields on triple-B rated utility bonds and 20-year Treasury
5 bonds to spike dramatically. Figure WEA-4, below, plots
6 the monthly spread between triple-B public utility bond
7 yields and 20-year Treasury bond yields since January 2006:
8 FIGUR WEA-4
9 YIELD SPREAD - BBB UTILITY VERSUS 20- YR TRASURY BONDS
6.0%
5.0%
4.0%
3.0%.20%
1.0%
0.0%
/I
/~-,/-.J--
~~ ~ ~~~ ~~ ~ ~,~ ~~~ ~".,-q-q"' .,-q~'O..'O..~ ~'O..fl Vif'Oif~ flVif
10 As illustrated above, the gap between the yields on
11 20-year government bonds and triple-B utility bonds has
12 widened as the extent of the challenges facing the
13 financial system and economy became increasingly clear to
14 investors. During 2007, this yield spread averaged 142
15 basis points, versus 293 basis point in 2008, and 556 basis
.
123 Avera, Di 16
Avista Corporation
.
2
3
4
5
6
7
8
9
10II
12
13
14
15
16
17
18.19
1 points in December 2008. As Standard & Poor's recently
observed:
The Standard & Poor's composite spreads widenedto new five-year highs yes terday , leaving the
investment-grade spread at 554 basis points (bps)
and the speculative grade spread at 1,598 bps,
both well more than triple their five-year movingaverages. ... With speculative-grade defaults on
the rise, a higher preponderance of credit
downgrades, and a general malaise about the
future of the economy, we expect spreads to
remain at their elevated levels for some time
until confidence is restored to the market. lS
Q. What does this imply with respect to the ROB for
a utility such as Avista?
A. Because of the dramatic increase in the spreads
between public utility and government bond yields, trends
in Treasury bond yields have virtually no relevance in
20 As a result of the turmoil and uncertainty spreading
evaluating long-term capital costs for Avista.
21 through financial markets, investors have sought a safe
22 haven in government-backed securities, such as Treasury
23 bonds. While the required returns for other asset classes,
24 such as common stocks and public utility bonds, have moved
25 sharply higher to compensate for increased perceptions of
26 risk, the yields on Treasury securities have fallen
27 significantly. As evidenced above, the spread between the
.
lS Standard & Poor i s Corporation, uCredi t Trends: u. S. Composite Credit
Spreads Daily (Dec. 2, 2008) i" RatingsDirect (Dec. 2, 2008).
124 Avera, Di 17
Avista Corporation
.1 observab~e yields on utility bonds and Treasury securities
2 has spiked dramatically as a result.
3 In other words, while focusing solely on the decrease
4 in Treas;ury bond yields experienced since 2007 would
5 suggest that investors' required returns might have fallen,
6 the exact opposite is true. Treasury bond yields have
7 declined because of a "flight to quality" as investors'
8 risk perceptions have mounted in the face of the ongoing
9 financial crisis. As the Wall Street Journal noted, "Real-
LO world borrowing costs are in a different universe from
11 Treasury yields and Fed rates. "16 (emphasis added) The fact
12 that the prices of Treasury bonds have been driven sharply
l3 higher is the mirror image of higher, not lower returns for.14 more risky asset classes, such as the common stock of
15 utili ties like Avista.
l6 Q. Would expectations of an economic recession lead
17 to lower capital costs?
18 A. No. Investors' required rates of return for
19 Avista and other financial assets are a function of risk,
20 with greater exposure to uncertainty requiring higher - not
21 lower - rates of return to induce long-term investment.
22 This has been vividly demonstrated in numerous segments of
23 the debt markets where heightened uncertainties regarding
16 Gangloff, Mark, "Ahead of the Tape: The Shocks Are Getting A
Workout, U The Wall Street Journal at ci (Sep. i 7, 2008) (emphasis
added) ..
125 Avera, Di 18
Avista Corporation
.1 risk exposure has resulted in the almost complete inability
2 of borrowers to access credit at reasonable rates.
3 It is important not to confuse investors' expectations
4 for fut~re growth and cash flows, which is one
5 consideration in estimating the cost of equity, with their
6 required rate of return. In fact, trends in growth rates
7 say nothing at all about investors' overall risk
8 perceptions. The fact that investors' required rates of
9 return for long-term capital can rise in tandem with
10 expectations of declining growth that would accompany an
11 economic slowdown is demonstrated in the bond markets,
12 where perceptions of greater risks have pushed yields on
13 long-term utility bonds sharply higher..l4 Similarly, the uncertainty over future trends in
15 corporate earnings and stock prices has led investors to
16 sharply reevaluate what they are willing to pay for common
l7 stocks. While the precipitous decline in utility stock
18 prices may in part be attributed to somewhat diminished
19 expectations of future cash flows, there is also every
20 indication that investors' discount rate, or cost of
21 equity, has moved significantly higher to accommodate the
22 greater risks they now associate with equity investments.
23 The idea that the current recession would lead the
24 rate of return demanded by equity investors to decline is
25 also contrary to economic logic. As documented above, the.
126 Avera, Di 19
Avista Corporation
.1 required, yield on long-term utility bonds has increased
substantially in response to investors' heightened risk2
3 perceptions.A drop in the cost of common equity would
4 imply that the risk premium between common stocks and bonds
5 has decl ined.The notion that equity risk premiums would
6 be declining at a time of unprecedented capital market
7 turmoil runs counter to common sense. Investors require a
8 higher rate of return to assume more risk and common stocks
9 have the lowest priority claim on a company's cash flows.
10 Given the significant increase in triple-B utility bond
11 yields documented earlier, the dramatic widening of the
l2 yield spreads between risk-free Treasury bonds and
13 corporate debt instruments,and investors heightened.14 sensitivity to risk, there is no evidence to suggest that
15 the return demanded by equity investors has declined.
16 Q. IS there any basis to ignore current capital
17 market conditions in establishing a fair ROE for Avista?
18 A. Absolutely not. As noted earlier, the standards
19 underlying a fair rate of return require that Avista' s
20 authorized ROE reflect a return competi ti ve with other
21 investments of comparable risk and preserve the Company's
22 ability to maintain access to capital on reasonable terms.
23 This standard can only be met by considering the
24 requirements of investors in today's capital markets.
25 The events of the last several months undoubtedly mark
26 a significant transition in investors' expectations and.
127 Avera, Di 20
Avista Corporation
.1 there is very little indication that the dire conditions
confronting the economy and financial markets will be2
3 resolved quickly. As Fitch recently concluded, uhigher
4 corporate interest rates are likely to prevail through 2009
5 and into the foreseeable future. "17 Moreover, the fact that
6 market volatility may complicate the evaluation of the cost
7 of equity provides no basis to ignore the upward shift in
8 investors' risk perceptions and required rates of return
9 for long-term capital.
10 B. Support For Avista's Credit Standing
11
12
Q.
A.
What credit ratings have been assigned to Avista?
On February 7, 2008, S&P raised the Company's
13 corporate credit rating from UBB+" to UBBB-", while Moody's.14 Investors Service (UMoody' s") upgraded Avista' s issuer
15 credi t rating from UBa1" to UBaa3" in Decemer 2007.18
16 Fitch Ratings, Ltd. (UFitch") upgraded its issuer default
17 rating for Avista one notch to UBB+" in 2007, and has since
18 assigned the Company a upositive Outlook", indicating the
19 potential for higher ratings going forward.
19 The ratings
20 assigned by S&P and Moody's represent the lowest rung on
21 the ladder of the investment grade scale, with Fitch
17 Grabelsky, Glen, "Surviving the Present, Preparing for the Future, R
Fitch Ratings' 20~ Annual Global Power Breakfast (Nov. 10, 2008).18 Moody's Investors Service, "Credit Opinion: Avista Corp., R Global
Credit Research (Dec. 21, 2007).19 Fitch Ratings, Ltd, "Fitch Upgrades Avista Corp. 's IDR to 'BB+' from
'BB'; Outlook Positive," Press Release (Aug. 9, 2007)..
128 Avera, Di 21
Avista Corporation
.1
2
3
4
5
6
7
8
9
10
11
12l3l4.
1Sl6
17
l8
19
.
continuing to maintain a speculative grade, or "junk"
credit r,ating.
Q. How have investors' risk perceptions for firms
involved in the utility industry evolved?
A. The past decade witnessed steady erosion in
credit quality throughout the utility industry, both as a
result of revised perceptions of the risks in the industry
and the weakened finances of the utilities themselves. As
illustrated in Figure WEA-S, below, S&P reports that the
majority of the companies in the utility sector now fall in
the "BBB" rating category:20
FIGUR WEA-5
S&P'S DISTRUTION OF CREDIT RATINGS OF
U.S. REGULATED ELECTRC UTllITS
70
: 60
! 50
=
~ 40
t 30
¡ 20
Z 10
o
AA.A A- BBB+ BBB BBB- BB+ BB
Credit Rating
BB-A+
Fitch recently concluded that the short- and long-term. . 21
outlook for investor-owned electric utilities is negative.
Similarly,Moody's observed,"Material negative bias
20 Standard & Poor's Corporation, ~ Issuer Ranking: U. S. Regulated
Electric Utilities, Strongest To Weakest," RatingsDirect (Jan. 8,
2009.21 Fitch Ratings, Ltd., ~U.S. Utilities, Power and Gas 2009 Outlook,"
Global Power North America Special Report (Dec. 22, 2008).
129 Avera, Di 22
Avista Corporation
.1 appears to be developing over the intermediate and longer
term due to rapidly rising business and operating risks. "222
3 Q. How does Avista's relative credit standing
4 compare with others in the utility industry?
5 A. Avista i s senior debt ratings from S&P and Moody's
6 remain at the very bottom of the investment grade scale,
7 with the "BB+" rating assigned by Fitch falling in the
8 speculative grade category. In a recent report by S&P
9 ranking U. S. regulated utilities from strongest to weakest,
lO Avista was ranked 159 out of the total l75 companies with
l1 investment grade credit ratings.23 In other words, only 16
12 companies in the utility industry with investment grade
13 ratings have a credit profile weaker than Avista' s..14
15
16
17
18
19
20
2l
22
.
Meanwhile, in a ranking of electric and gas utility parent
companies, Fitch placed Avista at 44th position out of 48
companies.24
Q. What are the implications of Avista's relative
credit staning, given the current climate in the capital
markets?
A. As documented earlier and in the testimony of Mr.
Mark Thies, the current environment poses significant
challenges with respect to a utility's ability to raise
22 Moody's Investors Service, "U. S. Electric Utility Sector," Industry
Outlook (Jan. 2008).23 Standard & Poor's Corporation, "Issuer Ranking: U. S. Regulated
Electric Utilities, Strongest To Weakest," RatingsDirect (Jan. 8,2009) .24 Fitch Ratings Ltd., "U. S. Utilities, Power and Gas 2009 Outlook,"
Global Power North America Special Report (Dec. 22, 2008).
130 Avera, Di 23
Avista Corporation
.1 capital on reasonable terms. For Avista, these concerns
2 are magnified by the fact that its credit standing remains
3 relatively weak. The Company's efforts to regain
4 investment grade credit ratings have been successful, but
5 Avista' s, finances remain pressured.
6 Fitch recently observed that in current credit
7 markets, "'flight to quality' is selective within the
8 (utili ty) sector, favoring companies at higher rating
9 levels. "25 Because Avista' s ratings are at the very bottom
10 of the investment grade barrel, there is no backstop in the
11 event of a prolonged and/or worsening crisis and reduced
12 flexibility to respond to other challenges, such as a
13 continuation of poor hydro condition or increased capital.14 outlays.
15 As Mr. Thies confirms in his testimony, regulatory
16 support will be a key driver in securing additional
17 progress in the Company's financial health. Further
l8 strengthening Avista' s financial integrity and continued
19 progress in raising the Company's credit standing is
20 imperative to ensure the capability to maintain an
21 investment grade rating while confronting potential
22 challenges.
25 Fitch Ratings Ltd., "U. s. Utilities, Power and Gas 2009 Outlook,"
Global Power North America Special Report (Dec. 22, 2008)..
131 Avera, Di 24
Avista Corporation
.1 Moreover, the negative impact of declining credit
2 quality on a utility's capital costs and financial
3 flexibility becomes more pronounced as debt ratings move
4 down the scale from investment to non-investment grade.
5 Fitch recently noted the penalty associated with
6 speculative grade ratings:
.
7
8
9
10
11
12
13
14
15
16
17l8
19
20
21
22
23
24
25
26
27
28
The incentives for companies to attain investment
grade ratings are significant. As of June 20,2008, the Bloomberg US 10-year 'BB' -rated
Corporate Bond Composite Index (BB Index) was
trading at a yield of 8.75%, representing a
spread of approximately 452 basis points over USTreasuries. The Bloomberg 10-year 'BBB' -rated
Corporate Bond Composite Index (BBB Index) was
trading at a yield of 6.56%, a spread of 233
basis points over US Treasuries. The yield and
spread differential of 219 basis points between
the BBB Index and the BB Index underscores the
considerably lower cost of capital incurred by
investment grade companies relative to
speculative grade companies in the public debt
markets at present. In addition to a lower cost
of capital, investment grade companies also
typically enjoy significantly fewer covenant
constraints in bond indentures and loan
agreements as well as less security in the form
of collateral than their speculative grade
counterparts.26
29 Since that time, speculative grade yields spreads have
30 increased dramatically. As noted earlier, S&P reported
31 that the premium on speculative debt issues was now more
32 than triple the five-year moving average and exceeded 1,500
33 basis points. This assessment of widening yield spreads
34 for utilities was recently confirmed by Fitch:
26 Fìtch Ratìngs Ltd., "Borderlìne Credìts - Part II, H Leveraged
Finance US Special Report (June 24, 2008)..
132 Avera, Di 25
Avista Corporation
.1
2
3
4
5
6
7
Several investment-grade issuers, mostly 'BBB' to'A i rated operating companies, have issued senior
unsecured debt with financing costs clustered in
a range approximating 250 to 450 basis points
above the 5% to 6% range of just 12 months ago,
and spreads have widened 700-1000 basis pointsf L. d . 27or specu ative-gra e companies.
8 With Avista i s credit ratings poised on the precipice
9 between investment grade and junk bond status, the stakes
10 associated with an inadequate rate of return are increased
11 dramatically. In. turn, the need for supportive regulation
12
13
14
15
16.17
18
and an adequate ROE may never have been greater.
Q. What are the implications of disregarding actual
capital market conditions in setting the allowed rate of
return on equity?
~-
A. If the increase in investors' required rate of
return on long-term capital is not incorporated in the
allowed rate of return on equity, the results will fail to
19 meet the comparable earnings standard that is fundamental
20 in determining the cost of capital. From a more practical
21 perspective, failing to provide investors with the
22 opportunity to earn a rate of return commensurate with
23 Avista' s risks will only serve to further weaken its
24 financial integrity, while hampering the Company's ability
25 to attract the capital needed under reasonable terms to
26 meet the economic and reliability needs of its service
27 area.
.
27 Fitch Ratings Ltd., "U.S. Utilities, Power and Gas 2009 Outlook,"
Global Power North America Special Report (Dec. 22, 2008).
133 Avera, Di 26
Avista Corporation
.1
2
3
III. RISKS OF AVISTA
Q.
-A.
What is the pUrPse of this section?
As a predicate to my capital market analyses,
4 this section examines the investment risks that investors
5 consider in evaluating their required rate of return for
6 Avista.
7 A. Operating Risks
8 Q. How does Avista's generating resource mix affect
9 investors' risk perceptions?
lO A. Because close to one-half of Avista's total
11 energy requirements are provided by hydroelectric
12 facilities,the Company is exposed to a level of
13 uncertainty not faced by most utilities. While hydropower.14
15
confers advantages in terms of fuel cost savings and
diversity, reduced hydroelectric generation due to below-
16 average water conditions forces Avista to rely more heavily
17 on wholesale power markets or more costly thermal
18 generating capacity to meet its resource needs. As S&P has
19 observed:
20 A reduction in hydro generation typically21 increases an electric utility's costs by22 requiring it to buy replacement power or run more23 expensive generation to serve customer loads.24 Low hydro generation can also reduce utilities'25 opportunity to make off-system sales. At the26 same time, low hydro years increase regional27 wholesale power prices, creating potentially a
28 double impact - companies have to buy more power
.
134 Avera, Di 27
Avista Corporation
.1
2
than under normal condi tions ,
prices.28
paying higher
3 Investors recognize that volatile energy markets,
4 unpredictable stream flows,and Avista's reliance on
5 wholesale purchases to meet a significant portion of its
6 resource needs can expose the Company to the risk of
7 reduced cash flows and unrecovered power supply costs. S&P
8 concluded that Avista' s "key utility risk going forward is
9 its exposure to high-cost replacement power, particularly
10 in low water years, ,,29 and concluded that Avista, along with
11 Idaho Power Company, "face the most substantial risks
12 despite their PCAs and cost-update mechanisms. ,,30
l3 Similarly, Fitch concluded, "The potential negative cash.14 flow impact from a prolonged period of below normal hydro
15 condi tions and high natural gas prices are primary sources
16 of concern" for Avista' s investors. 31
17 Addi tionally, Avista has become increasingly reliant
18 on natural gas fired generating capacity to meet base-load
19 needs.Given the significant price fluctuations
20 experienced in energy markets discussed subsequently,
28 Standard & Poor's Corporation, ~Pacific Northwest Hydrology And Its
Impact On Investor-Owed Utili ties' Credit Quality," RatingsDirect
(Jan. 28, 2008).29 Standard & Poor's Corporation, ~ Avista Corp.' s Corporate Credit
Rating Raised One Notch To 'BBB-'," RatingsDirect (Feb. 7, 2008).30 Standard & Poor's Corporation, ~Pacific Northwest Hydrology And Its
Impact On Investor-Owed Utilities' Credit Quality," RatingsDirect
~Jan. 28, 2008).3 Fitch Ratings, Ltd., ~Fitch Affirms Avista Corp. 's IDR at 'BB+';
Outlook positive," Press Release (Feb. 6, 2008)..
135 Avera, Di 28
Avista Corporation
.1 increasing reliance on natural gas heightens Avista' s
2 exposure to fuel cost volatility.
3 Q. Does Avista anticipate the need to access the
4 capital markets going forward?
5 A. '. Most definitely. Avista will require capital
6 investment to meet customer growth, provide for necessary
7 maintenance and replacements of its natural gas utility
8 systems, as well as fund new investment in electric
9 generation, transmission and distribution facilities.As
10 discussed by Company witness Mr. Thies, planned capital
1l expenditures for 2009-2010 total approximately $420 million
l2 for Avista' s electric utility operations alone.This
13 represents a substantial investment given Avista' s ratebase.14 was $1.9 billion as of November 30, 2008.
15 Continued support for Avista' s financial integrity and
16 flexibili ty will be instrumental in attracting the capital
i 7 necessary to fund these projects in an effective manner.
18 Avista' s reliance on purchased power to meet shortfalls in
19 hydroelectric generation magnifies the importance of
20 strengthening financial flexibility, which is essential to
21 guarantee access to the cash resources and interim
22 financing required to cover inadequate operating cash
23 flows, as well as fund required investments in the utility
24 system.
.
136 Avera, Di 29
Avista Corporation
.1
2
3
Q. Is the potential for energy market volatility an
ongoing ,concern for investors?
A. Yes. Investors recognize that the prospect of
4 further turmoil in energy markets is an ongoing concern.
5 S&P has reported continued spikes in wholesale energy
6 market prices,32 with Moody's warning investors of ongoing
7 exposure to Uextremely volatile" energy commodity costs,
8 including purchased power prices, which are heavily
9 influenced by fuel costs. 33 Similarly, the FERC Staff has
10 continued to recognize the ongoing potential for market
11 disruption, with a 2008 market assessment report noting
12 ongoing concerns regarding tight supply and congestion.
34
13 FERC continues to warn of load pockets vulnerable to.14 periods of high peak demand and unplanned outages of
15 generation or transmission capacity and ongoing reliability
16 concerns that led FERC to establish mandatory standards for
1 7 the bulk power sys tem . 35
18 In recent years utili ties and their customers have
19 also had to contend with dramatic fluctuations in gas costs
20 due to ongoing price volatility in the spot markets.S&P
32 Standard & Poor's Corporation, ~Fuel and Purchased Power Cost
Recovery in the Wake of Volatile Gas and Power Markets - U. S. Electric
Utilities to Watch" RatîngsDîrect (Mar. 22, 2006).33 Moody's Investors Service, ~Storm Clouds Gathering on the Horizon
for the North American Electric Utility Sector," Specîal Comment at 6
(Aug. 2007).34 FERC, Office of Market Oversight and Investigations, ~2008 Sumer
Market and Reliability Assessment," (May 15, 2008).35 See Open Commîssîon Meeting Statement of Chairman Joseph T.
Kelliher, Item E-13: Mandatory Reliability Standards for the Bulk-
Power System (Docket No. RM06-16-000) (Mar. 15, 2007)..
137 Avera, Di 30
Avista Corporation
.1 concluded that "natural gas prices have proven to be very
2 volatile" and warned of a "turbulent journey" due to the
3 uncertainty associated with future fluctuations in energy
4 costS.36 Fitch has also highlighted the challenges that
5 fluctuations in commodity prices can have for utilities and
6 recently noted that:
7 From their September 2007 low of $5.29, spot
8 natural gas prices as reported at Henry Hub rose
9 150% to $13.31 in early July 2008 and declined10 57% to $5.68 per million British thermal unit
11 (mmtu) on Dec. 10, 2008. The sharp run-up and12 subsequent collapse of natural gas prices in 200813 is emlematic of the extreme price volatility14 that characterizes the commodity and is likely to15 persist in the future.n
.16
17
l8
Q. Wht other finacial pressures impact investors'
risk assessment of Avista?
A.Investors are aware of the financial and
19 regulatory pressures faced by utilities associated with
20 rising costs and the need to undertake significant capital
21 investments. As Moody's observed:
22
23
24
25
26
27
28
(PJ ressures are building. Utilities are facingrising operating costs and infrastructure
investment needs that are prompting them to seek
more-frequent requests for rate relief.
Meanwhile, as energy (and other commodity) costs
rise, so does the risk of a consumer backlash
over electric rates that could prompt legislative
36 Standard & Poor's Corporation, ~Top Ten Credit Issues Facing U.S.
Utilities,n RatingsDirect (Jan. 29, 2007).37 Fitch Ratings, Ltd., ~U.S. Utilities, Power and Gas 2009 Outlook, n
Global Power North American Special Report (Dec. 22, 2008)..
138 Avera, Di 31
Avista Corporation
.1
2
intervention or a more contentious atmosphere
between utilities and their regulators. 38
3 Similarly, S&P noted that "heavy construction programs",
4 along with rising operating and maintenance costs and
5 volatile fuel costs, were a significant challenge to the
6 utility industry.
39 Fitch recently echoed this assessment,
7 concluding:
8 Continued access to capital at reasonable rates
9 in 2009 remains uncertain at a time when manylO utili ty holding groups have historically high11 capital investment programs and will require
l2 ongoing access to reasonably priced capital in13 order to fund new investment and refinance
l4 maturing debt. 40
15 While providing the infrastructure necessary to meet
16 the energy needs of customers is certainly desîrable, it.17
l8
imposes additional financial responsibilities on Avista.
As noted earlier, the Company's plans include electric
19 utility capital expenditures of approximately $420 million
20 just over the 2009-2010 period.S&P recently noted the
21 pressures associated with financing Avista's infrastructure
22 investment, concluding:
23 For a utility of its size, Avista has a large24 capital program and will need to rely on external
38 Moody's Investors Service, ~U. S. Investor-Owed Electric Utilities:
Six-Month Industry Update,. Industry Outlook (July 2008) .
39 Standard & Poor' s Corporation, ~Ratings Roundup: Utility Sector
Experienced Equal Numer Of upgrades And Downgrades During Second
9uarter Of 2008,. RatingsDirect (Jul. 22, 2008).Fitch Ratings Ltd., ~U.S. Utilities, Power and Gas 2009 Outlook,.
Global Power North America Special Report (Dec. 22, 2008)..
139 Avera, Di 32
Avista Corporation
.1
2
financing at a time when credit markets continue
to be in turmoil. 41
3 Investors are aware of the challenges posed by rising costs
4 and burdensome capital expenditure requirements, especially
5 in light of Avista' s relatively weak credit standing and
6 the ongoing capital market turmoil.
7
8
9
Q. Wht other
evaluation of Avista?
A. Avista and
considerations affect investors'
other utili ties are confronting
lO increased environmental pressures that could impose
11 significant uncertainties and costs.In 2007 S&P cited
12 environmental mandates, including emissions, conservation,
13 and renewable resources as one of the top ten credit issues
14 facing u.s. utilities.42 Similarly, Moody's noted that "the.15 prospect for new environmental emission legislation, via
16 federal or state carbon emission rules, represents the
17 single-biggest emerging issue on the horizon", 43 while Fitch
18 recently observed that:
19 Profound changes in energy policies and20 environmental regulations are likely to result
21 from the upcoming change of presidential22 administration, changes in Democratic leadership
23 in the House of Representatives, and a wide24 Democratic legislative majority. Accelerating25 support for carbon emissions reductions to combat
41 Standard & Poor's Corporation, UAvista Corp.' s $200 Million, 364-Day
Credit Facility Addresses Liquidity Constraints," RatingsDirect (Dec.
1, 2008).42 Standard & Poor's Corporation, uTop Ten Credit Issues Facing U. S.
Utilities," RatingsDirect (Jan. 29, 2007).43 Moody's Investors Service, UU. S. Investor-Owed Electric Utilities,"
Industry Outlook (July 2008) ..
140 Avera, Di 33
Avista Corporation
.1
2
3
4
5
global climate change is expected to result in
enactment of carbon legislation to dramatically
reduce emissions late next year or in 2010, but
the structure,- timing and implementation is still
uncertain.
44
6 Q. Would investors consider Avista' s relative size
7 in their- assessment of the Comany's risks an prospects?8 A. Yes. A firm's relative size has important
9 implications for investors in their evaluation of
10 alternative investments, and it is well established that
11 smaller firms are more risky than larger firms.With a
12 market capitalization of approximately $1.0 billion, Avista
l3 is one of the smallest publicly traded electric utilities
14 followed by Value Line,which have an average
15 capitalization of approximately $6.3 billion.45.16 The magnitude of the size disparity between Avista and
17 other firms in the utility industry has important practical
18 implications with respect to the risks faced by investors.
19 All else being equal, it is well accepted that smaller
20 firms are more risky than their larger counterparts, due in
21 part to their relative lack of diversification and lower
22 f. . 1 . l' 46inancia resi iency.These greater risks imply a higher
23 required rate of return, and there is ample empirical
44 Fitch Ratings, Ltd., "U.S. Utilities, Power and Gas 2009 Outlook, H
Global Power North America Special Report (Dec. 22, 2008).45 ww.valueline.com (Retrieved Dec. 29, 2008).
46 It is well established in the financial literature that smaller
firms are more risky than larger firms. See, e.g., Eugene F. Fama and
Kenneth R. French, "The Cross-Section of Expected Stock ReturnsH, The
Journal of Finance (June 1992) ¡George E. Pinches, J. Clay Singleton,
and Ali Jahankhani, "Fixed Coverage as a Determinant of Electric
Utility Bond RatingsH, Financial Management (Sumer 1978)..
141 Avera, Di 34
Avista Corporation
.
8
9
10
11
12
1 evidence that investors in smaller firms realize higher
2 rates of return than in larger firms. 47 Common sense and
3 accepted financial doctrine hold that investors require
4 higher returns from smaller companies, and unless that
5 compensation is provided in the rate of return allowed for
6 a utility, the legal tests emodied in the Hope and
7 Bluefield cases cannot be met.
B. Capital Structure
Q. Is an evaluation of the capital structure
maintained by a utility relevant in assessing its return on
equity?
A.Yes. Other things equal, a higher debt ratio, or
13 lower common equity ratio, translates into increased.14
15
financial risk for all investors. A greater amount of debt
means more investors have a senior claim on available cash
16 flow, thereby reducing the certainty that each will receive
l7
18 which lenders are exposed, and they require correspondingly
his contractual payments.This increases the risks to
19 higher rates of interest.From common shareholders'
20 standpoint, a higher debt ratio means that there are
21 proportionately more investors ahead of them, thereby
22 increasing the uncertainty as to the amount of cash flow,
23 if any, that will remain.
.
47 See for example Rolf W. Banz, uThe Relationship Between Return and
Market Value of Common Stocksn, Journal of Financial Economics
(Septemer 1981) at 16.
, 142 Avera, Di 35
Avista Corporation
.1
2
3
Wht comon equity ratio is implicit in Avista's
capi tal structure?
Avista's capital structure is presented in the
Q.
requested
A.
4 testimony of Mr. Thies.As sumarized in his testimony,
S the pro~forma common equity ratio used to compute Avista' s
6 overall rate of return was SO. 0 percent in this filing.
7 Q. Wht was the average capitalization maintained by
8 the utility proxy group?
9 A. As shown on Exhibit 3, Schedule 3, for the 17
10 firms in the utility proxy group, common equity ratios at
11 Decemer 31, 2007 ranged between 34.4 percent and 59.6
12 percent and averaged 47.2 percent.
.13
14
15
Q. What capitalization is representative for the
proxy group of utilities going forward?
A. As shown on Exhibit 3, Schedule 3, The Value Line
16 Investment Survey ("Value Line") expects an average common
17 equity ratio for the proxy group of utilities of SO. 8
18 percent for its three-to-five year forecast horizon, with
19 the individual common equity ratios ranging from 41. S
20 percent to 65.0 percent.
2l Q. How does Avista's comon equity ratio comare
22 with those maintained by the reference group of utilities?
23 A. The 50.0 percent common equity ratio requested by
24 Avista is entirely consistent with the range of equity
25 ratios maintained by the firms in the Utility proxy Group
26 and is in-line with the 47.2 percent and 50.8 percent
.
143 Avera, Di 36
Avista Corporation
.1 average equity ratios at year-end 2007 and based on Value
2 Line's near-term expectations, respectively.
3
4
5
6
Q. Wht implication does the increasing risk of the
utility industry have for the capital structures maintained
by utilities?
A. As discussed earlier, the average credit rating
7 associated with firms in the electric industry has fallen
8 to triple-B, with Avista's "BBB-" rating occupying the
9 lowest rung on the ladder of the investment grade scale.
10 At the same time, electric utilities are facing, among
l1 other things, rising cost structures, the need to finance
12 significant capital investment plans, and uncertainties
13 over accommodating future environmental mandates. A more.14
15
conservative financial profile, in the form of a higher
16 uncertainties and the need to maintain the continuous
common equity ratio,is consistent with increasing
17 access to capital that is required to fund operations and
18 necessary system investment, even during times of adverse
19 capital market conditions.
20 Moody's has warned investors of the risks associated
21 with debt leverage and fixed obligations and advised
22 utilities not to squander the opportunity to strengthen the
23 balance sheet as a buffer against future uncertainties. 48
.
48 Moody's Investors Service, ~Storm Clouds Gathering on the Horizon
for the North American Electric Utility Sector,. Special Comment (Aug.
2007) .
144 Avera, Di 37
Avista Corporation
.1
2
Moody's noted that, absent a thicker equity layer,
utili tias would be faced with lower credit ratings in the
3 face of rising business and operating risks:
4 There are significant negative trends developing
5 over the longer-term horizon. This developing
6 negative concern primarily relates to our view
7 that the sector's overall business and operating8 risks are rising - at an increasingly fast pace -9 but that the overall financial profile remains10 relatively steady. A rising risk profile11 accompanied by a relatively stable balance sheet12 profile would ultimately result in credit quality
13 deterioration.
49
14 This is especially the case for Avista, which faces the
15 dual challenge of financing significant capital expansion
16 plans in a turbulent market while at the same time
17 endeavoring to improve its credit standing..l8
19
20
Q. Wht other factors do investors consider in their
assessment of a comany's capital structure?
A. Depending on their specific attributes,
21 contractual agreements or other obligations that require
22 the utility to make specified paYments may be treated as
23 debt in eval ua ting Avis ta ' s financial risk. Because power
24 purchase agreements ("PPAs") and leases typically obligate
25 the utility to make specified minimum contractual paYments
26 akin to those associated with traditional debt financing,
27 investors consider a portion of these commitments as debt
28 in evaluating total financial risks.Because investors
49 Moody's Investors Service, "U. S. Electric Utility Sector," Industry
Outlook (Jan. 2008)..
145 Avera, Di 38
Avista Corporation
.1 consider the debt impact of such fixed obligations in
2 assessing a utility's financial position,they imply
3 greater risk and reduced financial flexibility.In order
4 to offset the debt equivalent associated with off-balance
5 sheet obligations, the utility must rebalance its capital
6 structure by increasing its common equity in order to
7 restore its effective capitalization ratios to previous
8 levels. 50
9 These commitments have been repeatedly cited by major bond
10 rating agencies in connection with assessments of utility
l1 financial risks. For example, in explaining its evaluation
12 of the credit implications of PPAs, S&P affirmed its
13 position that such agreements give rise to "debt.14 equivalents" and that the increased financial risk must be
15 considered in evaluating a utility's credit risks. 51 S&P
16 also noted that it has refined its methodology to include
17 imputed debt associated with shorter-term PPAs and
18 operating leases.Ð
19 As discussed earlier, a significant portion of the
20 Company's power requirements are currently obtained through
21 purchased power contracts.These contractual payment
50 The capital structure ratios presented earlier do not include
imputed debt associated with power purchase agreements or the impact
of other off-balance sheet obligations.51 Standard & Poor's Corporation, "Standard & Poor's Methodology For
Imputing Debt For U. S. Utilities' Power Purchase Agreements,"
RatingsDirect (May 7, 2007).52 Standard & Poor's Corporation, "Implications Of Operating Leases On
Analysis Of u.S. Electric Utilities," RatingsDirect (Jan. 15, 2008)..
146 Avera, Di 39
Avista Corporation
.1 obligations, along with operating leases and obligations
2 pos tretirement benefits,fixedassociatedwithare
3 commitments with debt-like characteristics and are properly
4 considered when evaluating the financial risks implied by
5 Avis ta ' scapi tal structure.S&P reported that it adjusts
6 Avista' scapi talization to include approximately $123
7 million leases,andfrominimputeddebtPPAs,
8 postretirement benefit obligations. 53 Unless the Company
9 takes action to offset this additional financial risk by
10 maintaining a higher equity ratio, the resulting leverage
11 wi 1 1 weaken Avis ta ' s credi tworthiness, implying a higher
12 required rate of return to compensate investors for the
13 greater risks. 54.14
15
16
Q. Wht did you conclude with respect to the
Coman's capital structure?
A. Based on my evaluation, I concluded that Avista' s
17 requested capital structure represents a reasonable mix of
18 capital sources from which to calculate the Company's
19 While industry averages provideoverall rate of return.
20 one benchmark for comparison, each firm must select its
21 capitalization based on the risks and prospects it faces,
.
53 Standard & Poor's Corporation, "Avista Corp., n RatingsDirect (Aug.
29, 2008).54 Apart from the immediate impact that the fixed obligation of
purchased power costs has on the utility's financial risk, higher
fixed charges also reduce ongoing financial flexibility, and the
utility may face other uncertainties, such as potential replacement
power costs in the event of supply disruption.
147 Avera, Di 40
Avista Corporation
.as well its specific needs to access the capital markets.
2 A public utility with an obligation to serve must maintain
1
3 ready access to capital under reasonable terms so that it
4 can meet the service requirements of its customers.
5 Moody's recently concluded that the electric utility sector
6 "is entering a major period of capital-raising needs, and
7 will need to attract a significant amount of new equity
8 capital in order to maintain existing ratings. ,,55 Moody's
9 also observed that its ratings for Avista anticipate
10 "conservative financing strategies. ,,56
l1 Avis ta ' scapi tal structure ref lects the chal lenges
12 posed by its resource mix, the burden of significant
13 capi tal spending requirements, and the Company's ongoing.14 efforts to strengthen its credit standing and support
15 access to capital on reasonable terms. The need for access
16 becomes even more important when the company has capital
17 requirements over a period of years, and financing must be
18 continuously available, even during unfavorable capital
19 market conditions.
55 Moody's Investors Service, "U. S. Investor-Owed Electric Utilities:
Siz-Month Industry Update," Industry Outlook (July 2008) ..56 Moody's Investors Service, "Credit Opinion: Avista Corp.," Global
Credit Research (Dec. 3, 2008)..
148 Avera, Di 41
Avista Corporation
.1
2
3
4
iv. CAPITAL MAT ESTIMATES
Q.
A.
What is the purpose of this section?
This section presents capital market estimates of
the cost of equity.The details of my quantitative
5 analyses are contained in Exhibit 3, Schedule 2, with the
6 results being sumarized below.
7 A. Overview
8 Q. What role does the rate of return on comn
9 equity play in a utility's rates?
10 A. The return on common equity is the cost of
11 inducing and retaining investment in the utility's physical
12 plant and assets. This investment is necessary to finance
l3 the asset base needed to provide utility service..14 Investors will commit money to a particular investment only
15 if they expect it to produce a return commensurate with
16 those from other investments with comparable risks.
17 Moreover, the return on common equity is integral in
18 achieving the sound regulatory objectives of rates that are
19 sufficient to: 1) fairly compensate capital investment in
20 the utility, 2) enable the utility to offer a return
21 adequa te to attract new capi talon reasonable terms, and 3)
22 maintain the utility's financial integrity. Meeting these
23 objectives allows the utility to fulfill its obligation to
24 provide reliable service while meeting the needs of
25 customers through necessary system expansion.
.
149 Avera, Di 42
Avista corporation
.1
2
3
Q. Did you rely on a single method to estimate the
cost of equity for Avista?
A. No. In my opinion, no single method or model
4 should be relied upon to determine a utility's cost of
5 equity because no single approach can be regarded as wholly
6 reliable. For example, a publication of the Society of
7 Utility and Financial Analysts (formerly the National
8 Society of Rate of Return Analysts), concluded that:
.
9
10l1
12
13
14
15
16
17
18
19
20
21
Each model requires the exercise of judgment as
to the reasonableness of the underlying
assumptions of the methodology and on the
reasonableness of the proxies used to validate
the theory. Each model has its own way of
examining inves tor behavior, its own premises,
and its own set of simplifications of reality.
Each method proceeds from different fundamental
premises, most of which cannot be validated
empirically. Investors clearly do not subscribe
to any singular method, nor does the stock price
reflect the agplication of anyone single method
by investors. 7
22 Therefore, I used both the DCF and CAPM methods to estimate
23 the cost of equity.In addition, I also evaluated a fair
24 ROE return using an earnings approach based on investors'
25 current expectations in the capital markets.In my
26 opinion, comparing estimates produced by one method with
27 those produced by other approaches ensures that the
28 estimates of the cost of equity pass fundamental tests of
29 reasonableness and economic logic.
57 Parcell, David C., ~The Cost of Capital - A Practitioner's Guide,"
Society of Utility and Regulato~ Financial Analysts (1997) at Part 2,
p. 4..
150 Avera, Di 43
Avista Corporation
.1
2
3
Q., Wht was your conclusion regarding a fair rate of
return on equity for the proxy comanies?
A. Based on the results of my quantitative analyses,
4 and my assessment of the relative strengths and weaknesses
5 inherent in each method, I concluded that the cost of
6 equi ty for the proxy companies is in the 11.3 percent to
7 l3 .3 percent range.
8 B. Results of OUantitative Anlyses
9 Q. How did you defiiie the comparable risk proxy
10 groups you used to implement the DCF model?
11 A. In estimating the cost of equity, the OCF model
12 is typically applied to publicly traded firms engaged in
13 similar business activities or with comparable -investment
14 risks. As described in detail in Exhibit 3, Schedule 2, I.15 applied the DCF model to a utility proxy group composed of
16 those dividend-paying companies included by Value Line in
17 its Electric Utilities Industry groups with: (1) S&P
18 corporate credit ratings of "BBB-" or "BBB," (2) a Value
19 Line Safety Rank of "2" or "3", and (3) a Value Line
20 Financial Strength Rating of "B+" to "B++".I excluded
21 three firms that otherwise would have been in the proxy
22 group, but are not appropriate for inclusion because they
2 3 ei ther do not pay common di vidends or were in the process
24 of being acquired.
25 Under the regulatory standards established by Hope and
26 Bluefield,the salient criteria in establishing a.
151 Avera, Di 44
Avista Corporation
.
9
10
11
l2
13.14
1 meaningful benchmark to evaluate a fair rate of return is
2 relative risk, not the particular business activity or
3 degree of regulation.Consistent with this accepted
4 regulatory standard, I also applied the DCF model to a
5 reference group of comparable risk companies in the non-
6 utility sector of the economy. My non-utility proxy group
7 was composed of those U. S. companies followed by Value Line
8 that 1) pay common dividends, 2) have a Safety Rank of "1",
3) have a Financial Strength Rating of "A" or above, and 4)
have investment grade bond ratings. 58
Q. How do the overall risks of your proxy groups
comare with Avista?
A. As shown below, Table 1 compares the non-utility
proxy group with the utility proxy group and Avista across
15 four key indicators of investment risk:16 TABLE 117 COMPARISON OF RISK J:NDICATORS
18
.
S&:P
CreditRating
Value Line
Safety Financial~ Strenhi A+
3 B++3 B+
Ma
0.84
0.82
0.85
Non-Utility Group
Utility Proxy Group
Avista Corp.
A+
BBB
BBB-
58 In addition, I also included only those firms with at least two
published growth estimates from Value Line, IBES, First Call, or
Zacks.
152 Avera, Di 45
Avista Corporation
.1 Considered together, a comparison of these objective
2 measures indicates that the risks investors associate with
3 Avista generally exceed those of the proxy groups.AS a
4 result, the cost of equity estimates indicated by my
5 analyses provide a conservative estimate of investors'
6 required rate of return for Avista.
7
8
9
10
Q.Wht cost of equity is implied by your DCF
results for the utility proxy group?
A.My application of the OCF model,which is
discussed in greater detail in Exhibit 3,Schedule 2,
11 considered four alternative measures of expected earnings
12 growth, as well as the sustainable growth rate based on the
13 relationship between expected retained earnings and earned.l4 rates of return ("br + sv").As shown on Exhibi t 3 ,
15 Schedule 4 and sumarized below in Table 2, after
16 eliminating illogical low- and high-end values, application
17 of the constant growth DCF model resulted in the following
18 cost of equity estimates:19 TABLE 2
20 DCF RESULTS - UTILITY PROXY GROUP
Growth Rate
Value Line
IBES
First Call
Zacksbr+sv
Average Cost of Equity
13.4%
12.3%
11. 5%
11.8%
11. 9%
.
153 Avera, Di 46
Avista Corporation
.1
2
3
4
5
6
7
8
9
LO
1l
.
l2
13
14
l5
16
17
18
19
.
Q. What were the results of your DCF analysis for
the non-utility reference group?
A. C As shown on Exhibit 3, Schedule 6, I applied the
DCF model to the non-utility companies in exactly the same
manner described earlier for the utility proxy group. As
sumarized below in Table 3, after eliminating illogical
low- and high-end values, application of the constant
growth DCF model resulted in the following cost of equity
estimates:
TABLE 3
DCF RESULTS - NON-UTILITY GROUP
Growth Rate
Value Line
IBES
First Call
Zacks
br+sv
Average Cost of EQUity
13.1%
13.4%
13.2%
13.5%
13.3%
Q. Do you believe the constant growth DCF moel
should be relied on exclusively to evaluate a reasonable
ROE for Avista?
A. No. As noted earlier, because the cost of equity is
unobservable, no single method should be viewed in
isolation.Moreover, evidence suggests that reliance on
the DCF model as a tool for estimating investors' required
rate of return has declined outside the regulatory sphere,
154 Avera, Di 47
Avista Corporation
.1
2
with the CAPM being Uthe dominant model for estimating the
cost of equity."s9
3 Q. How did you apply the CAPM to estimate the cost
4 of equity?
5 A. Like the DCF model, the CAPM is an ex-ante, or
6 forward~looking model based on expectations of the future.
7 As a result, in order to produce a meaningful estimate of
8 investors' required rate of return, the CAPM is best
9 applied using estimates that reflect the expectations of
10 actual investors in the market, not with backward-looking,
11 historical data.Accordingly, I applied the CAPM to the
12 utility proxy group based on a forward-looking estimate for
13 investors' required rate of return from common stocks..14 Because this forward-looking application of the CAPM looks
15 directly at investors' expectations in the capital markets,
16 it provides a more meaningful guide to the expected rate of
17 return required to implement the CAPM.
l8 Q. Wht cost of equity was indicated by the CAPM
19 approach?
20 A. As shown on Exhibit 3, Schedule 8, my forward-
21 looking application of the CAPM model indicated an ROE of
22 approximately 11.2 percent for the utility proxy group.
23 Applying the CAPM approach to the firms in the non-utility
S9See, e.g., Bruner, R.F., Eades, K.M., Harris, R.S., and Higgins,
R.C., ~Best Practices in Estimating Cost of Capital: Survey and
Synthesis," Financial Practice and Education (1998)..
155 Avera, Di 48
Avista Corporation
.1 proxy group (Exhibit 3, Schedule 9) implied a cost of
equity of 11.5 percent.2
3 Q. Wht other analyses did you conduct to estimate
4 the cost of equity?
5 A. As I noted earlier, I also evaluated the cost of
6 equity using the comparable earnings method. Reference to
7 rates of return available from alternative investments of
8 comparable risk can provide an important benchmark in
9 assessing the return necessary to assure confidence in the
lO financial integrity of a firm and its ability to attract
11 capital.This comparable earnings approach is consistent
12 with the economic underpinnings for a fair rate of return
l3 established by the U. S. Supreme Court. Moreover, it avoids.l4 the complexities and limitations of capital market methods
15 and instead focuses on the returns earned on book equity,
16 which are readily available to investors.
17 Q. What rates of return on equity are indicated for
18 utilities based on the comarable earnings approach?
19 A. Value Line reports that its analysts anticipate
20 an average rate of return on common equity for the electric
21 utility industry of 11.5 percent in 2009 and over its 2011-
22 2013 forecast h. 60orizon,with natural gas distribution
23 utilities expected to earn an average rate of return on
60 The Value Line Investment Survey at 148 (Dec. 26, 2008). The
capital structure corresponding with this expected return reflects an
equity ratio of 50 percent..
156 Avera, Di 49
Avista Corporation
.1
2
3
4
S
6
7
8
9
LO
11
12
13.
14
common equity of 1l. 5 percent to 12.0 percent. 61 As shown
on Exhibit 3, Schedule 10, Value Line's projections for the
utility proxy group suggested an average ROE of 11.4
percent after eliminating potential outliers. 62 Based on
the resul ts discussed above,I concluded that the
comparable earnings approach implies a fair rate of return
on equity of at least 11.4 percent.
Q. What did you conclude
equity implied by your analyses
A. The cost of equity
wi th respect to the cost
for the proxy groups?
estimates implied by
of
my
quantitative analyses are sumarized in Table 4, below:
TABLE 4.
SUMY OF QUANITATIVE RESULS
Method
DCF
CAPM
Comparable Earnings
Cost of EQUity Estimtes
utility Non-Utility
proxy Group Proxy Group
11.S% - 13.4% 13.1% - 13.S%
11.2% 1L.S%
11.4%
Based on the results of my quantitative analyses, and
15 my assessment of the relative strengths and weaknesses
l6 inherent in each method, I concluded that the cost of
17 equi ty is in the l1. 3 percent to 13.3 percent range.
.
61 The Value Line Investment Survey 446 (Dec. 12, 2008). The capital
structure corresponding with this expected return reflects an equity
ratio of 46 percent.62 As highlighted on Schedule WEA-12, I eliminated six extreme low- and
high-end outliers. While these Value Line projections may accurately
reflect expectations for actual earned rates of return on common
equity over the forecast horizon, they are unlikely to be
representative of investors' required rate of return.
157 Avera, Di SO
Avista Corporation
.1
2
3
4
C. Flotation Costs
Q. What other considerations are relevant in setting
the return on equity for a utility?
A. The common equity used to finance the investment
5 in utility assets is provided from either the sale of stock
6 in the capi tal markets or from retained earnings not paid
7 out as dividends. When equity is raised through the sale
8 of common stock, there are costs associated with "floatingH
9 the new equity securities.These flotation costs include
10 services such as legal, accounting, and printing, as well
11 as the fees and discounts paid to compensate brokers for
12 selling the stock to the public. AlSO, some argue that the
13 "market pressure" from the additional supply of common.14
15
stock and other market factors may further reduce the
amount of funds a utility nets when it issues common
16 equity.
17 Q. Is there an established mechanism for a utility
18 to recognize equity issuance costs?
19 A. No. While debt flotation costs are recorded on
20 the books of the utility, amortized over the life of the
21 issue, and thus increase the effective cost of debt
22 capital, there is no similar accounting treatment to ensure
23 that equity flotation costs are recorded and ultimately
24 No rate of return is authorized on flotationrecognized.
25 costs necessarily incurred to obtain a portion of the equity
26.In other words, equi tycapi tal used to finance plant.
158 Avera, Di 51
Avista Corporation
.1 flotatiqn costs are not included in a utility's rate base
2 because neither that portion of the gross proceeds from the
3 sale of common stock used to pay flotation costs - is
4 available to invest in plant and equipment, nor are
5 flotation costs capitalized as an intangible asset. Unless
6 some provision is made to recognize these issuance costs, a
7 utility's revenue requirements will not fully reflect all of
8 the costs incurred for the use of investors' funds. Because
9 there is no accounting convention to accumulate the
10 flotation costs associated with equity issues, they must be
11 accounted for indirectly, with an upward adjustment to the
12 cost of equity being the most logical mechanism.
.13
l4
15
Q. What is the magnitude of the adjustmnt to the
"bare bones" cost of equity to account for issuance costs?
A. There are any numer of ways in which a flotation
16 cost adjustment can be calculated, and the adjustment can
17 range from just a few basis points to more than a full
18 percent.One of the most common methods used to account
19 for flotation costs in regulatory proceedings is to apply
20 an average flotation-cost percentage to a utility's
21 dividend yield.Based on a review of the finance
22 literature, Regulatory Finance: Utilities' Cost of Capital
23 concluded:
24 The flotation cost allowance requires an25 estimated adjustment to the return on equity of
.
159 Avera, Di 52
Avista Corporation
.1
2
3
approximately 5% to LO%, depending on the size
and risk of the issue. 63
Alternatively,a study of data from Morgan Stanley
4 regarding issuance costs associated with utility common
5 stock issuances suggests an average flotation cost
6 percentage of 3.6%.64 Applying these expense percentages to
7 a representative dividend yield for a utility of S. 3
8 percent implies a flotation cost adjustment on the order of
9 19 to SO basis points.
10
11
12
Q. Has
flotation costs
A. Yes.
the i PUC Staff previously considered
in estimating a fair ROE?
For example, in Case No. IPC-E-07-8, IPUC
13 Staff witness Terri Carlock noted that she had adjusted her
14 DCF analysis to incorporate an allowance for flotation.15 costS.65 While issuance costs are a legi timate
16 consideration in setting the return on equity for a
17 utili ty, a specific adjustment for flotation costs was not
18 included in defining my recommended ROE range.
63 Roger A. Morin, Regulatory Finance: Utilities' Cost of Capital, 1994,
at 166.64 Application of Yankee Gas Services Company for a Rate Increase, DPUC
Docket No. 04-06-01, Direct Testimony of George J. Eckenroth (Jul. 2,
2004) at Exhibit GJE-11.1. Updating the results presented by Mr.
Eckenroth through April 2005 also resulted in an average flotation
cost percentage of 3.6%.65 Case No. IPC-E-07-8, Direct Testimony of Terri Carlock at 10 (Dec.
10, 2007)..
160 Avera, Di 53
Avista Corporation
.1 v. RETU ON EQUITY FOR AVISTA CORP.
2
3
Q..
A.
What is the purpose of this seetion?
In addition to presenting the conclusions of my
4 evaluation of a fair rate of return on equity range for
5 Avista, this section also discusses the relationship
6 between ROE and preservation of a utility's financial
7 integrity and the ability to attract capital under
8 reasonable terms on a sustainable basis.
9 A. implications for Financial Integrity
lO Q. Why is it important to allow Avista an adequate
11 return on equity?
12 A. Given the importance of the utility industry to
13 the economy and society, it is essential to maintain.14 reliable and economical service to all consumers. While
15 Avista remains committed to provide reliable utility
16 service, a utility's ability to fulfill its mandate can be
i 7 compromised if it lacks the necessary financial wherewithal
18 or is unable to earn a return sufficient to attract
19 capita1.Coupled with the ongoing potential for energy
20 market volatility, Avista's exposure to variations in
21 hydroelectric generation and natural gas price volatility,
22 along with plans for significant infrastructure investment,
23 pose a numer of potential challenges that might require
24 the relatively swift commitment of significant capital
25 resources in order to maintain the high level of service
26 that customers have come to expect.Investors' increased.
161 Avera, Di 54
Avista Corporation
.
7
8
9
10
11
1 reticence to supply additional capital during times of
2 crisis .. highlights necessity preserving thetheof
3 flexibility necessary to overcome periods of adverse
4 capi tal market conditions.These considerations heighten
5
6
the importance of allowing Avista an adequate return on the
fair value of its investment.
Q. What role does regulation play in ensuring that
Avista has access to capital under reasonable ter.s and on
a sustainable basis?
A. Investors recognize that constructive regulation
is a key ingredient in supporting utility credit ratings
12 and financial integrity, particularly during times of
13 adverse conditions. Fitch noted that:.l4l5
16
17
Regulatory risk remains a recurring theme for
this year's outlook, as the pressure of a weak
economic backdrop could result in political push-
back to rate increase requests. 66
18 The report went on to conclude, "Fitch is concerned that
19 the recent rapid escalation in the cost of capital will not
20 be reflected on a timely basis in utility rates. "67 Moody's
21 has emphasized the need for regulatory support "in an era
22 of broadly rising costs," noting that as cost pressures
23 have escalated for electric utilities, so too has the
24 importance of timely recovery through the regulatory
.
66 Fitch Ratings Ltd., "U.S. Utilities, Power and Gas 2009 Outlook,"
Global Power North America Special Report (Dec. 22, 2008).67 Id.
162 Avera, Di 55
Avista Corporation
.process and the risks associated with regulatory lag. 68 S&P
2 concluded "the quality of regulation is at the forefront of
1
3 our analysis of utility creditworthiness, "69 and recently
4 observed that its risk analysis focuses on the utility's
5 ability to consistently earn a reasonable return:
6 Notably, the analysis does not revolve
7 around "authorized" returns, but rather
8 on actual earned returns. We note the
9 many examples of utilities with healthy10 authorized returns that, we believe,
l1 have no meaningful expectation of12 actually earning that return because of13 rate case lag, expense disallowances,14 etc. 70
15 Similarly, with respect to Avista specifically, the
16 major bond rating agencies have explicitly cited the
17 potential that adverse regulatory rulings could compromise.18 the Company's credi t standing.Of particular concern to
19 investors is the impact of regulatory lag and cost-recovery
20 on Avista' s ability to earn its authorized ROE and maintain
21 its financial metrics, with Moody'S concluding that:
22 Failure to obtain adequate and timely support for23 recovery of and return on core utility
24 investments through pending and expected future25 regulatory proceedings could have negative26 ratings implications. 71
68 Moody's Investors Service, ~Regulatory Pressures Increase For u. S.
Electric Utilities, n Special Comment (March 2007) .69 Standard & Poor's Corporation, ~Assessing u.S. Utility Regulatory
Environments, n RatingsDirect (Nov. 7, 2008).70 Standard & Poor's Corporation, ~ Assessing U. S. Regulatory
Environments, n RatingsDirect (Nov. 7, 2008).71 Moody'S Investors Service, ~Credit Opinion: Avista Corp., n Global
Credit Research (Dec. 3, 2008)..
163 Avera, Di 56
Avista Corporation
.1 S&P observed that rate relief will remain critical to
2 Avista' s credit outlook,72 and concluded that "regulatory
3 lag will continue to be a drag on the company's ability to
4 earn its authorized ROE.,,73
5 For Avista, these concerns are magnified by the fact
6 that its credit standing is poised on the precipice between
7 investment and speculative grade ratings.While the
8 Company's efforts to regain an investment grade credit
9 rating have been successful, Avista' s financial metrics
i 0 remain pressured. As Mr. Thies conf irms in his tes timony ,
11 regulatory support will be a key driver in securing
12 additional improvement in the Company's financial health.
13 Further strengthening Avista's financial integrity is.14 imperative to ensure that the Company has the capability to
15 maintain an investment grade rating while confronting
16 potential challenges.
17
18
19
Q. Do customers benefit by enhancing the utility's
financial flexibility?
A. Yes. While providing an ROE that is sufficient
20 to maintain Avis ta ' s abi 1 i ty to at tract capital, even in
21 times of financial and market stress, is consistent with
22 the economic requirements emodied in the U. S. Supreme
72 Standard & Poor's Corporation, ~u. S. Electric Utility Credit Quality
Remins Strong Amid Continuing Economic Downturn," RatingsDirect (Dec.
19, 2008).73 Standard & Poor's Corporation, ~Avista Corp. 's Corporate Credit
Rating Raised One Notch To 'BBB-'," RatingsDirect (Feb. 7, 2008)..
164 Avera, Di 57
Avista Corporation
.1 Court' s . Hope and Bluefield decisions, it is also in
2 customers' best interests. Ultimately, it is customers and
3 the service area economy that enjoy the benefits that come
4 from ensuring that the utility has the financial
5 wherewithal to take whatever actions are required to ensure
6 reliable service. By the same token, customers also bear a
7 significant burden when the ability of the utility to
8 attract necessary capital is impaired and service quality
9 is compromised.
10 B. Return on Equity RecOJendation
11 Q. Wht then is your conclusion as to a fair rate of
12 return on equity range for Avista?
13 A. As explained above, based on the capital market.14 oriented analyses for the utility and non-utility proxy
15 groups described in my testimony, I concluded that the fair
16 rate of return on equity range was 11. 3 percent to 13.3
17 percent.Considering capital market expectations, the
18 potential exposures faced by Avista, and the economic
19 requirements necessary to maintain financial integrity and
20 support additional capital investment even under adverse
21 circumstances, it is my opinion that this represents a fair
22 and reasonable ROE range for Avista.
.
165 Avera, Di 58
Avista Corporation
.1
2
3
4
Q. Based on the results of your evaluation, what is
your opinion regarding the reasonableness of the ROB
requested by Avista in this case?
A. My evaluation indicates that Avista's requested
5 ROE of 11.0 percent represents a conservative estimate of
6 investors' required rate of return.Given the fact that
7 the Company's requested ROE falls below the lower bound of
8 my recommended range, it should be viewed as floor in
9 establishing rates for Avista.This conclusion is
LO reinforced by the need to buttress the Company's credit
11 standing, which remains relatively weak, as well as the
12 pressures of funding significant capital expenditures and
13
l4.15
16
meeting increased operating risks,including those
associated with Avista' s reliance hydroelectricon
generation and exposure to volatility in natural gas and
wholesale power markets.The reasonableness of a minimum
17 11.0 percent ROE for Avista is also supported by the
18 Company's relatively greater risks as compared with the
19 proxy groups, the higher uncertainties associated with
20 Avista' s relatively small size, and the fact that my
2l recommended ROE range does not consider flotation costs.
22
23
24
.
Q. Does
testimony?
A. Yes.
this conclude your pre-filed direct
166 Avera, Di 59
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.1
2
I. INTRODUCTION
Q.Please state your nae, emloyer and business
3 address.
4 A.My name is Richard L. Storro.I am employed as
5 the Vice President of Energy Resources by Avista
6 Corporation located at 1411 East Mission Avenue, Spokane,
7 Washington.
8 Q.Would you briefly describe your educational and
9 professional background?
10 A.I received a Bachelor of Science degree in
11 physics from the College of Idaho and a Bachelor of Science
12 degree in electrical engineering from the Uni versi ty of
13 Idaho, both in 1973. I began working for Avista in 1973 as.14
15
a distribution engineer and have held several other
engineering positions with the Company.I have held
16 management positions in line and gas operations, system
17 operations,hydro production and cons truction,and
18 transmission. I joined the Energy Resources Department as
19 a Power Marketer in 1997, became Director of Power Supply
20 in 2001, became President of Avista Ventures in 2007, and
21 became Vice President of Energy Resources in January 2009.
22 Q. Wht is the scope of your testimony in this
23 proceeding?
24
25
A. My testimony will provide an overview of Avista's
resource planning and power operations.This overview
.
167 Storro, Di
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i
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2
includes sumaries of the Company's resources, the current
and future load and resource position, future resource
3 plans, and an update on the Company's involvement with the
4 Chicago Climate Exchange. The third section discusses the
5 Lancaster Power Purchase Agreement. The fourth section of
6 my testimony discusses hydro and thermal project upgrades.
7 This is followed by a hydro relicensing update.My
8 testimony concludes with a discussion of generation plant
9 operation and maintenance issues.
10 A table of contents for my testimony is as follows:
.
11
12
13
14
15
16
17
18
19
20
21
i.II.III.iv.
V.
VI.
DescriptionIntroduction
Avista i s Resource Planning and power Operations
Lancaster Power Purchase Agreement
Hydro and Thermal Project upgrades
Hydro Relicensing
Generation Plant Operation & Maintenance
Pagei
3
11
22
25
31
Q.Are you sponsoring any exhibits?
A.Yes. I am sponsoring Exhibit No.4, Schedules 1
22 through 5. Schedule 1 is Avista' s 2007 Electric integrated
23 Resource Plan, Schedule 2 is a map and picture of the
24 Lancaster Generation Facility, Schedule 3 is the Lancaster
25 Generating Facility Power Purchase Agreement Evaluation
26 Overview, Schedule 4 is the Independent Valuation of the
27 Lancaster Facility Tolling Agreement, and Schedule 5 is the
28 Overview of the Lancaster Power Purchase Agreement.
.
168 Storro, Di
Avista Corporation
2
.1
2
II. AVISTA' S RESOURCE PLAING AN POWER OPERTIONS
Q. Would you please provide a brief overview of
3 Avista's power generating resources?
4 A.Yes.Avista's resource portfolio consists of a
5 mix of 'hydroelectric generation projects, base-load coal
6 and natural gas-fired thermal generation facilities, wood
7 waste-fired renewable generation, natural gas-fired peaking
8 generation proj ects, long-term contracts including wind and
9 Mid-Columia hydroelectric generation, and market power
10 purchases and exchanges.Avis ta -owned generation
11 facilities have a total capability of 1,787.6 MW, which
12 includes 55% hydroelectric and 45% thermal resources.
.13
14
Table No.i below sumarizes the present net
capability of Avista's owned generation resources:
.
169
Storro, Di
Avista Corporation
3
.
.2
3
4
5
6
7
8
9
10
11
12
13.
1 Table No.1: Avista Generation
MW
541
261
18
10.2
15
15
90.4
36
Northeast CT
Kette Falls CT
Boulder Park
Rathdrum CT
56
10
24
164
The Company also has long-term contractual rights for
166 MW of capability from Mid-Columia generation projects
in 2009, owned and operated by the Public Utility Districts
of Grant, Chelan and Douglas counties. The Company has a
ten-year contract for 35 MW of wind generation capability
from the Stateline Wind Project and also receives 100 MW of
energy from other contracts through 2010.
Q. Would you please provide an overview of Avista' s
resource planning an power supply operations?
A. Yes. The Company uses a combination of owned and
contracted-for resources to serve its requirements.
170 Storro, Di
Avista Corporation
4
.
.
.
1
2
3
4
Dispatch decisions related to these resources are made by
the Power Supply section of the Energy Resources
Department.The Department studies capacity and energy
resource needs on an ongoing basis.The Company utilizes
5 short and medium-term wholesale transactions to balance
6
7
resources with load requirements.Longer-term resource
to existingupgradesdecisionsfor new resources,
8 resources, demand-side management (DSM), and long-term
9 contract purchases are generally made in conjunction with
10 the Integrated Resource Plan (IRP) and Request for
11 Proposals (RFP) processes.
12 Please sumrize the current load an resourceQ.
13 position for the Coman.
14 The Company had forecasted annual energy andA.
15 capacity deficits starting in 2011 in the 2007 Electric
16 IRP, without the addition of the Lancaster Power Purchase
17 The Company is currently proj ecting aAgreement (PPA).
18 balanced-to-surplus energy position through 2017 on an
19 average anual basis with the inclusion of the Lancaster
20
21
However, as I will explain later, there are monthlyPPA.
and quarterly deficits and surpluses prior to 2017.The
22 Company's annual energy net resource position becomes
23 deficient in 2018 and the deficiencies will increase from
24 that time forward if additional resources beyond the
25 The average anual energyLancaster PPA are not added.
171 Storro, Di
Avista Corporation
5
.resource deficiency in 2018 is 8 aM which increases to 5151
2
3
aM in 2028.
The Company's capacity resource position is surplus
4 through 2018 with the inclusion of the Lancaster PPA.
5 Capacity deficiencies begin at 67 MW in 2019 and increase
6 to 843 MW in 2028. Additional details concerning the load
7 and resource positions are in Company witness Kalich's
8 Exhibi t No.5, Schedule 2.
9 Q.How does the Comany plan to meet future resource
10 needs beginning in 2018?
11 A.The Company has pursued the Preferred Resource
12 Strategy laid out in the 2007 Electric IRP, which is
.13
14
attached as Exhibi t No.4, Schedule 1.The IRP provides
details about resource needs, specific cost and operating
15 characteristics of the resources evaluated for the
16 Preferred Resource Strategy, and the scenarios used for
17 resource evaluations.
18 The Company's 2007 Electric IRP was submitted to the
19 Commission in August 2007.The Company will continue
20 evaluating a mix of resource options to meet future load
21 requirements,including medium-term market purchases,
22 generation ownership, hydroelectric upgrades, renewable
23 resources, customer load reduction (e.g., conservation),
24 long-term contracts, and generation lease or tolling
25 arrangements.As stated earlier, longer-term resource.
172 Storro, Di
Avista Corporation
6
.1
2
decisions are generally made in conjunction with the
Company i s IRP and RFP processes, al though the Company does
3 acquire - some resources outside of formal RFP processes.
4 The first decade of the Company's Preferred Resource
5 Strategy in the 2007 IRP included a mix of 87 MW of DSM,
6 upgrades to existing plants, 350 MW of gas-fired CCCT, 300
7 MW of wind, and 35 MW of other renewable generation (such
8 as small co-generation, biomass and geothermal) .
9 The Company continues to evaluate and acquire various
10 demand side management (DSM) measures. Avista has acquired
11 approximately 138 aM of DSM over the past 30 years. The
12 Company has over 110 aM of DSM still in place today, which
13 equates to 6.2% of the Company's owned generation. Avista.14 continues to acquire cost-effective DSM and anticipates
15 acquiring an additional 87 aM of DSM over the next decade
16 based on the 2007 IRP results.
17 The Company's Preferred Resource Strategy will be
18 updated in the 2009 Electric IRP, which we plan to submit
19 to the Commission in August 2009.Research and modeling
20 for this new plan are currently underway by the Company's
21 Resource Planning Department with the aid of the Technical
22 Advisory Committee.
23 Q.Please provide an update on renewable energy
24 acquisitions.
.
173 Storro, Di
Avista Corporation
7
.1
2
A. The Company has actively pursued renewable energy
projects that meet the resource acquisition goals set in
3 the Preferred Resource Strategy (PRS) of the 2007 Electric
4 IRP.The PRS is in the process of being updated for the
5 2009 IRP. The renewable component of the first decade of
6 the 2007 PRS included 300 MW of nameplate capacity wind and
7 35 MW of other renewable resources.Other renewable
8 resources include low or carbon neutral technologies such
9 as biomass, geothermal and solar generation.
10 The Company purchased the rights to develop a SO MW
11 wind site located at Reardan, washington from Energy
12 Northwest in May 2008. This site has already been proven
13 to be a viable wind site through several studies based on.14 collected and historical wind data.We are also
15 investigating the acquisition of additional leases to
16 expand the potential of the site to 65 MW.The Reardan
17 site is currently scheduled to be developed and on line by
18 2013.The Company has also placed met towers at other
19 locations within its service territory and will determine
20 whether or not to proceed wi th further development of any
21 of those sites after sufficient wind speed data is
22
23
collected.Other renewable energy options are also being
considered.The Company will consider a request for
24 proposals for wind and other renewables after the 2009 IRP
25 has been completed in August 2009..
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Avista Corporation
8
.1
2
3
Q. Can you provide an overview of Avista's risk
managemnt program for energy resources?
A.Yes,Avista Utilities uses a variety of
4 techniques to manage risks associated with serving load and
5 managing Company resources. The Company's risk management
6 approach uses price diversification through the use of. a
7 layering strategy for forward purchases and sales, and by
8 using stop-loss price controls to protect against market
9 price run-ups and run-downs by utilizing upper and lower
10 price control limits.The Energy Resources Risk Policy
11 provides general guidance to manage the Company's energy
12 risk exposure, as it relates to electric power and natural
13 gas resources over the long term (more than 18 months),.14
15
short term (monthly and quarterly periods out to 18
months), and immediate term (present month).The purpose
16 of the Risk Policy is not to develop a specific procurement
17 plan for buying or selling power or natural gas for
18
19
generation at any particular time.Several factors,
including the variabili ty associated with loads,
20 hydroelectric generation, and electric power and natural
21 gas prices, are considered in the decision-making process
22 regarding procurement of electric power and natural gas for
23 generation.
24 The use of a layering strategy reduces the Company's
25 and its customers' exposure to purchases of large amounts.
175
Storro, Di
Avista Corporation
9
.1
2
of energy during high-priced periods.An after-the-fact
view of the purchases over time will show that some of the
3 transactions will be advantageous, while other transactions
4 will not be as advantageous.However, this layering
5 strategy will provide for more stable pricing for customers
6 over the long-term.
7 Q.Can you please provide an update of the Comany's
8 involvement with the Chicago Climate Exchange?
9 A.Yes, the Company joined the Chicago Climate
10 Exchange (CCX) in 2007. The CCX commitment is divided into
11 Phases 1 and 2 which span 2003 to 2006 and 2007 to 2010
12 respectively.The Company liquidated its 400,000 metric
13 tons of surplus Phase 1 credits in 2008 for $2,577,100 for.14 an average price of $6.44 per metric ton.The Company
15 presently has approximately 147,000 tons of surplus credits
16 from the 2007 compliance year which the Company plans to
17 sell after the CCX prices rebound since they have been
18 below $2 per ton since September 2008.The Company
19 anticipates a surplus of credits for all of the remaining
20 years in Phase 2. We do not plan on continuing with the
21 CCX past Phase 2 when it ends in 2010, because of
22 Washington's invol vement with the Western Climate
23 Initiative. The CCX is a voluntary reduction program and
24 companies can no longer be a memer if they are bound by a
25 mandatory emissions reduction program..
176 Storro, Di 10
Avista Corporation
.1
2
3
4
III. Lancaster Power Purchase Agreemnt
Q.What is the Lancaster Power Purchase Agreemnt?
A.The Power Purchase Agreement for the Lancaster
Generating Facility (Lancaster PPA)is a tolling
5 arrangement for a merchant gas-fired plant. This merchant
6 plant is located in the Company's service territory just
7 outside of Rathdrum, Idaho.Exhibi t No.4, Schedule 2
8 includes a picture of the Lancaster Generating Facility and
9 a map of its location.
10 The Lancaster Generating Facility is a General
11 Electric Frame 7FA turbine that went into commercial
12 service as a merchant plant in Septemer 2001.The plant
13 is comprised of a 245 MW gas-fired combined-cycle.14 combustion turbine plus 30 MW of duct firing capability.
15 The plant employs 20 people, had an average net heat rate
16 in 2006 of 6,925 btu/kWh, and an average equivalent
17 availability of 92.9% in 2006.
18 Internal and independent reviews both indicated that
19 the Lancaster PPA is cost-effective compared to other
20 resource options under base case conditions as well as
21 under several scenarios that will be described in more
22 detail later in my testimony.
23 Although we are providing documentation regarding the
24 decision-making related to Lancaster in this filing, we are
25 not proposing that the revenues and expenses be reflected.
177
Storro, Di 11
Avista Corporation
in retail rates in this filing.Lancaster will become a.1
2
3
utility resource on January 1, 2010, and this case will be
concluded prior to that time.It is unlikely, however,
4 that Avista' s next general rate case will be concluded on
5 or before January 1, 2010. As Mr. Johnson explains in his
6 testimony, we are proposing that the Lancaster revenues and
7 expenses, beginning January 1, 2010, be included in the PCA
S until they can be reflected in base retail rates.
9 Q.Could you please provide som backgroun related
10 to the acquisition of the Lancaster PPA by Avista
11 Utilities?
12 A.Yes.The opportuni ty to acquire the power
13 purchase agreement (tolling) rights for Lancaster was a.14
15
result of negotiations related to the sale of Avista Energy
which held the rights to this tolling arrangement.In
16 April 2007, the utility completed an initial assessment of
17 the Lancaster PPA utilizing the 2007 IRP model.The
is assessment concluded that this type of resource fit the
19 Company's long-term capacity and energy needs. The PRS for
20 the 2007 IRP had indicated that a 350 MW natural gas
21 baseload resource was needed in the 2008 - 2017 timeframe.
22 As part of the April 17, 2007 announcement of the sale of
23 Avista Energy to Coral Energy, the Company also announced
24 that Avista Utilities would have rights to the Lancaster
25 PPA beginning on January 1, 2010..
178
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Avista Corporation
.
.
.
1
2
3
4
Q. Please provide an overview
included with the Lancaster PPA.
agreemntsofthe
three main components to thisA.There are
agreement,which include the actual Power Purchase
5 Agreement, natural gas transportation for the plant, and
6 transmission for the plant.
7 The PPA for Lancaster is available to the Company from
8 January 1, 2010 through October 31, 2026. In exchange for
9 paYments outlined in the PPA, the utility will have the
10 right to dispatch Lancaster. This requires the Company to
11 arrange and pay for natural gas fuel procurement and
12 as well astransportation to the Lancaster plant,
13 subsequent transmission to move the power from the plant.
14 In turn, the Company is entitled to the entire electric
15 capacity and energy output from the plant.
16 The Lancaster plant is interconnected with the Gas
17 Transmission Northwest (GTN) natural gas pipeline system.
18 On January 1 , 2010 , the Company wi 1 1 receive permanen t
19 assignent of firm natural gas transportation capacity on
20 the TransCanada Alberta and TransCanada BC systems and
21 temporary assignent of firm natural gas transportation
22 The GTN temporary assignentcapacity on the GTN system.
23 of firm transportation capacity on the GTN pipeline by
24 Shell Corporation terminates on October 31, 2017.These
25 firm transportation agreements will allow for deliveries of
179 Storro, Di 13
Avista Corporation
.1
2
approximately 26,000 Dth/d from the AECO trading hub on the
Alberta'system and approximately 26,000 Dth/d from either
3 the Stanfield or Malin trading hubs south of the plant off
4 of the GTN system.
5 The Lancaster plant is interconnected electrically
6 wi th the Bonneville Power Administration (BPA). There is a
7 transmission agreement, held by the Company in the name of
8 Avista Energy, with BPA for 250 MW of long-term
9 transmission capacity rights from the Lancaster point of
10 receipt to the John Day point of delivery that was assigned
11 to Coral on a short term basis through Decemer 31, 2009.
12 Effective January l, 2010, there will be a permanent
13 assignent of the long-term transmission rights to Avista.14 Utilities.These transmission rights will be used while
15 the Company evaluates interconnecting Lancaster directly
16 with our system.
17 Q.How did the Comany determine the need and
18 suitability of the Lancaster PPA?
19 A.The initial analysis was performed by the
20 Company's Resource Planning staff based on the 2007 IRP
21 models and methodology. It had already been determined as
22 part of the IRP process that there was a need for energy
23 and capacity in the timeframe for the availability of the
24 Lancaster PPA based on the load and resource tabulations.
25 An analysis of the first, third and fourth quarters.
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Avista Corporation
.1
2
(excluding the spring runoff months) showed deficits
beginning in 2010, with annual average energy deficiencies
3 in 2011. Capacity deficits started at 146 MW in 2011 and
4 grew into the future. These energy and capacity deficits,
5 combined with the IRP identified need of 350 MW of base
6 load natural gas-fired resources, indicated that the
7 Lancaster PPA was an alternative option for the Company and
8 its cus tomers .
9 Q.Please provide more details abt the internl
10 study on the Lancaster PPA.
11 A.The Lancaster Generating Facility Power Purchase
12 Agreement Evaluation Overview was completed on April 11,
.13
14
2007.A copy of this study is included as Exhibit 4,
Schedule 3. The study identified all of the natural gas-
15 fired combined cycle plants located in the Northwest to use
16 as a comparison to Lancaster. Of the 13 plants identified
17 with a combined capacity of 1,946 MW, only four of those
18 plants besides Lancaster were not owned by utili ties. None
19 of these plants were known to be for sale at the time the
20
21
study was completed.This essentially ruled out the
purchase of a brownfield site.However, the study was
22 conducted with the assumption that a brownfield site was
23 available.Brownfield site costs were chosen based on a
24 review of the most recent plant purchases in the Pacific
25 Northwes t ..
181 Storro, Di 15
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.1
2
3
Q. What were the results of the internl study
concerning the Lancaster PPA?
A.In all base cases, the Lancaster PPA provided a
4 significant benefit relative to the construction of a
5 greenfield plant.The 2010 start date showed a positive
6 benefit to the PPA unless a brownfield project of less than
7 $550/kW were located.The Company was not aware of any
8 such projects at the time of this study and has not found
9 any projects in this price range since the study was
10 completed.
11 Q.Were any third-party reviews of the Lancaster PPA
12 solicited?
.13
14
15
16
A.Yes, in August 2007 the Company contracted with
Thorndike Landing, LLC for an independent assessment of the
Lancaster PPA relative to other utility gas-fired
operations.The study used four different valuation
17 metrics and perspectives including discounted cash flow
18 analysis,valuation under a purchase scenario,
19 identification and valuation of similar assets, and a
20 review of similar market transactions in the region. They
21 'also reviewed the Company's analytical processes used for
22 the Lancaster evaluation and resource planning in general.
23 Thorndike Landing completed their study and assessment
24 late in October 2007 and it is included as Exhibit 4,
25 Schedule 4. The study concluded that the Lancaster PPA was.
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Avista Corporation
.1
2
cost-effective and financially favorable relative to other
natural gas-fired options generally available to utilities
3 in the Pacific Northwest.
4 Q.Can you describe the discouted cash flow aspect
5 of the Thorndike Laning study and the results of that
6 study?
7 A.Yes, Thorndike Landing performed a discounted
8 cash flow analysis to determine the intrinsic and extrinsic
9 value of the Lancaster PPA under base, high and low case
10 scenarios.The base case assumed that the output from
11 Lancaster can be interconnected to the Avista transmission
12 system and that the transmission will be remarketed or
13 otherwise optimized. The high case scenario included a.14 doubling of CO2 prices, which raised the overall cost of
15 running this plant by the price of the CO2 emissions
16 credits.The low case scenario assumed the addition of
17 S,OOO MW of combined cycle capacity throughout the WECC,
18 which negatively impacts margins by providing a large
19 amount of regional surplus power.The total value of the
20 Lancaster PPA, as dispatched against the market, was
21 positive in all three cases modeled for the Thorndike
22 Landing study showing that the PPA was cost-effective for
23
24
Avista.Table 2 shows the results of this independent
evaluation.The results ranged from a PPA value of
.
183 Storro, Di 17
Avista Corporation
.
4
5
6
7
8
9
10.11
12
13
14
15
16
17
18
19
20
21
22.
1
2
3
$SOO,OOO in the low case up to $20. S million in the high
case.
Table 2: Lancaster PPA Value vs. Market
Power Puchase Power Puchase
"Agreement value Agreemnt Value
Description ($000)($/kW)
Base Case $16,500 $64
Lo Case $500 $2
High Case $20, SOO $78
Q.Can you describe the valuation uner the purchase
scenario section of the Thorndike Landing study along with
the valuation of similarly-situated plants?
A. Yes, Thorndike Landing performed a valuation of
Lancaster under an ownership scenario which was then
compared to ownership values of other recent plant
transactions in the region.This aspect of the study
represented the present value of the difference between the
variable dispatch costs, fixed O&M, insurance, and taxes
for each plant compared to the proj ect market net revenue.
In this portion of the study, the variable dispatch cost
excluded the cost of the PPA in the case of Lancaster or
the recovery of capital or fixed costs in the case of other
plants.This comparison indicated that the Lancaster
project had a greater value per kilowatt than recently
constructed or transacted plants in the region.Even
though the Company will not own the Lancaster plant, this
section of the study is a strong indication that a similar
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7
8
9
10.11
12
13
14
15
16
17
18
19
20
21
.
1
2
PPA or toll opportunities at one of the other regional
plants would be somewhat less economically favorable to the
3 Company than Lancaster. Table 3 sumarizes the results of
4 this aspect of the study.
5
6 Table 3: Lancaster Plant Value vs. Regional CCCT Projects
Proj ect Name Plant Value ($/kW)Lancaster $677Coyote Springs 2 $652
Port Westward $528Goldendale$365
Q. Why did the Comany not purchase Lancaster
outright rather tha taking a poer purchase agreement?
A. The Thorndike Landing study, along with the
Company's own studies, indicated that the outright purchase
of Lancaster would be a beneficial and preferable option to
the Company.The Lancaster plant became available for
purchase in 2007 along with 13 other power plants, all
owned by Goldman Sachs through its Cogentrix subsidiary,
located across the U. S. in 2007. The Company submitted a
bid for the Lancaster plant, but that bid was rejected
because Goldman Sachs wanted to sell all of the plants to a
single purchaser . This left the power purchase agreement
as the only viable option for obtaining the generation
output from the Lancaster plant.
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Q., Please discus the aspect of the Thorndike Landing
study.that identified market activity for similar types of
3 plants.
4 A.The Thorndike Landing review of similarly-
5 situated plants found seven comparable transactions that
6 yielded an average value of $533/kW within the region.
7 Approximately 25 comparable transactions were found
8 throughout the rest of the U.S. with an average value of
9 $465/kW.Therefore, the Lancaster value of $677/kW
10 compares very favorably with these transactions.
11 Q.What was the final opinion of the Thornike
12 Landing study concerning the Lancaster PPA?
.13
14
A.Thorndike Landing stated that they "found that
the Toll provides positive value to Avista and its
15 customers. . . and the value of the Lancaster facility appears
16 consistent with - if not greater than - the value of other
17 resources in the market." (See Exhibit 4, Schedule 4 at p.
18 1) Thorndike Landing also reviewed Avista' s analytic
19 process and valuation methodology and found the following:
20 Thorndike Landing has reviewed Avista' s analytical21 methodology and has found that Avista' s analytical
22 process and methodology is a very contemporary23 approach to analyzing resources. In fact, the
24 utility industry in general has been slow, as25 compared to other industries, to adopt risk26 analysis into its process and it wasn't until the27 power and sector crises of 2001-02 that even some28 utilities began to incorporate risk into their29 processes. Today, we find that many utilities do30 factor risk analyses into their processes, but31 many still do not. Additionally, Avista's process.
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7
8
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12
13
14
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16
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20
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is .also grounded on sound resource planning using
mul tiple scenarios and a robust vs. static process
through which the company is able to assess
mul tiple scenarios and resource portfolios, not
just a single resource in isolation. For these
reasons, we have found that Avista' s analytical
process is sound and even surpasses processes used
by 'many of their peers across the industry.
Therefore, we have not identified any area or
aspect of its process generally for which we would
suggest modification at this time. (See Exhibit 4,
Schedule 4 at p. 15)
.
Thorndike Landing concluded as follows:
In conclusion, Thorndike Landing believes that the
transaction for the Toll is reasonable and that
the value Avista would remit for the Toll is
reasonable and would result in a net benefit to
Avista and its customers. Further, based on ourt
analysis and assumptions, the value of the
Lancaster Facility appears to be greater than that
of other recently constructed or transacted
facilities in the region. The greater value
appears to be primarily driven by one or more ofthe following:
25 . Lower electric transmission costs
26 . Lower gas transportation costs
27
28
. Lower gas taxes (the state of Idaho has no
fuel tax)
29
30 .
31
32
. Dual sourcing of fuel (Alberta/Malin vs.
Sumas). (See Exhibit 4, Schedule 4, at p.19)
Q.Is the Lancaster PPA a prudent acquisition?
A.Yes, the Lancaster acquisition is prudent.As
33 shown in the internal and external studies covered in the
34 preceding testimony, the Lancaster PPA is needed for
35 utility service, it is cost-effective compared to other
.
187 Storro, Di 21
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.alternatives, and fits within the resource needs identified1
2
3
in the 2007 IRP.
Q.Can you sU1rize the studies that lead the
4 Company to believe that the Lancaster PPA is a prudent
5 decision?
6 A.Yes.Both the internal and external studies
7 regarding the Lancaster PPA showed that the PPA was cost-
8 effective when compared to similar base load resources and
9 is needed for utility service based on the Company's load
10 and resource position, and fits within the resource
11 guidelines established in the 2007 IRP.The cost-
12 effectiveness of the PPA included an analysis of the
.13
14
associated natural gas transporta tion and electric
transmission agreements.Furthermore, the Lancas ter PPA
15 provides the Company with the ability to operate the plant
16 in a flexible manner consistent with an owned-plant and the
17 PPA stipulations provide protections against losses due to
18 mechanical failures at the facility. A white paper that
19 sumarizes the Lancaster studies can be found in Exhibit 4,
20 Schedule 5.
21
22
23
XV. HYRO AN THERM PROJECT UPGRAES
Q.Can you provide an overview of the capi tal
24 improvemnts. that were recently comleted on the Noxon
25 Rapids Proj ect?.
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A.Yes.Reliability work was completed on Noxon
Rapids Unit #5, the largest and most efficient unit at the
project, which was installed in 1977.This reliability
4 work began in September 2007 and was completed in 2008.
5 The work was not expected to increase the unit's 92.0%
6 efficiency rating or the 125 MW unit rating, but solved
7 several reliability concerns.The costs associated with
8 this work were approximately $9.2 million (system) and were
9 included and approved in Case No. AVU-E-08-01.
10 Q.Please describe the upgrade projects planned for
11 the Noxon Rapids generating UDits starting in 2009.
12 A.The Company plans to upgrade the Noxon Rapids
13 generating units #1 through #4 which are currently using.14 1950' s era technology.The upgrades on these four units
15 are expected to add an additional 30 MW of capacity and 6
16 aM of energy to the Noxon Rapids project and improve
17 reliability.One upgrade is planned for completion
18 annually, starting in April 2009 and ending in 2012. Table
19 No.4, Noxon Rapids Upgrades, sumarizes the timing and
20 additional capacity and efficiency of these upgrades.
.
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1 Table No.4: Noxon Rapids Uprades
Noxon Rapids Schedule of Aditionl Aditional
Unit #Carletion Capacity Efficiency
1 April 2009 7.5 MW 5.0%
3 April 2010 7.5 MW 7.8%
2 April 2011 7.5 MW 6.0%
4 April 2012 7.5 MW 4.7%
For Unit #1, we are replacing the stator core,
rewinding the stator, installing a new turbine and
performing a complete mechanical overhaul which is expected
to be completed in April 2009. This upgrade is expected to
increase the unit's efficiency 5.0% and increase the unit
rating 7.5 MW.The upgrade will also solve several
reliabili ty concerns for the unit including mechanical
vibration and the age of the stator.
The remaining upgrade work on units #2, #3 and #4 are
planned from 2009 to 2012. The Unit #3 upgrade is planned
to increase unit efficiency 7.8% and boost the unit rating
7.5 MW.Uni t #2 is scheduled to have a new turbine and
complete mechanical overhaul between August 2010 and April
2011.This upgrade is planned to increase uni t #2
efficiency 6.0% and boost the unit rating by 7.5 MW. The
upgrade work at Unit #4 involves the installation of a new
turbine and a complete mechanical overhaul from August 2011
through April 2012.The Unit #4 upgrade is planned to
190 Storro, Di 24
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.increase efficiency 4.7% and increase the unit rating by1
2
3
7.5 MW.
The costs associated with Unit #1 are planned for
4 completion in April 2009, totaling approximately $17.2
5 million (system), is further described in Company witness
6 Mr. DeFelice's testimony.Company wi tness Ms . Andrews
7 incorporates the Idaho share of these costs in her
8 adjustments.The costs for the remaining Noxon Rapids
9 upgrades for units #3, #2 and #4 have not been included in
10 this case, but will be included in future rate proceedings.
.
11
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14
v.HYRO RELICENSING
Q.Would you please provide an update on work being
done under the existing nRC operating license for the
15 Comany's Clark Fork River generation projects?
16 A.Yes.Avista received a new 45-year FERC
17 operating license for its Cabinet Gorge and Noxon Rapids
18 hydroelectric generating facilities on the Clark Fork River
19 on March 1, 2001.The Company has made significant
20 progress working in collaboration with 27 signatories to
21 the Clark Fork Settlement Agreement toward meeting the
22 goals, terms, and conditions of the Protection, Mitigation
23 and Enhancement (PM&E) measures under the license.The
24 implementation program has resulted in the protection of
25 approximately 2,SOO acres of bull trout, wetlands, uplands,.
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and riparian habitat.The fish passage program,using
electrofishing and trapping with over 150 adults radio
3 tagged and their movements studied, has reestablished bull
4 trout connectivity between Lake Pend Oreille and the Clark
5 Fork River tributaries above Cabinet Gorge Dam. Avista has
6 worked with the U. S. Fish and Wildlife Service to develop
7 two experimental fish passage facilities.The testing of
8 these facilities, however, has not produced a design that
9 will attract adult bull trout. Nevertheless, studies will
10 continue to seek solutions for developing a volitional fish
11 passage facility.
12 Recreation facility improvements have been made to 30
.13
14
sites along the reservoirs.Finally, tribal memers
continue to monitor known cultural and historic resources
15 located within the project boundary to ensure that these
16 sites are appropriately protected.The earlier costs
17 associated with the PM&E measures were reviewed and were
18 included in prior cases.Ms. Andrews has included a pro
19 forma adjustment to reflect the planned PM&E expenditures
20 for the 2009/2010 proforma period.
21 Q.Would you please provide an update on the current
22 status of the Cabinet Gorge Bypass Tuels Project?
23 A.Yes. Total dissolved gas levels occurring during
24 spill periods at Cabinet Gorge Dam was an unresolved issue
25 when the current Clark Fork license was received.The
.
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license provided time to study the actual biological
impacts of dissolved gas and subsequent development of a
dissolved gas mitigation plan.The studies documented no
4 biological impact from dissolved gas below the project;
5 the stakeholders ultimately concluded thathowever,
6 dissolved gas levels should be mitigated, in accordance
7 with federal and state law. A plan to reduce dissolved gas
8 levels was developed with all stakeholders, including the
9 Idaho Department of Environmental Quality.The original
10 plan called for the modification of two existing diversion
11 tunnels which could redirect streamflows exceeding turbine
12 capacity away from the spillway.
13 The 2006 Preliminary Design Development Report for the
14
15
Cabinet Gorge Bypass Tunels Project indicated that the
did not meet theconfigurationpreferredtunnel
16 performance, cost and schedule criteria established in the
17 approved Gas Supersaturation Control Plan (GSCP). This led
18 the Gas Supersaturation Subcommittee to determine that the
19 Cabinet Gorge Bypass Tunnels Proj ect was not a viable
20 The subcommittee isalternative to meet the GSCP.
21 developing an addendum to the original GSCP and it is
22 expected to be completed in the first quarter of 2009.
23 Even though the final addendum has not been completed, the
24 subcommittee has agreed that the tunel bypass project did
25 not meet expectations so an addendum to the GSCP with
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mitigation and other alternatives must be pursued. The
cost of the original study was completed in 2008 and
3 included in the last Idaho General Rate Case, No. AVU-E-08-
4 01.
5 Q.Wht is the status of expenditures related to
6 comliance with the Clark Fork PM&:E's?
7 A.Since implementation began,the Clark Fork
8 Management Committee! (CFMC) and FERC have reviewed and
9 approved all annual PM&E budgets.The CFMC has been very
10 deliberate in their review and approval of annual budgets
11 to assure that only quality proj ects directly tied to the
12 CFSA are approved. In addition, during the last several
13 years, unforeseen conditions such as severe rain and snow.14 events, extended spring run-off sometimes resulting in
15 flooding, and dramatic swings in fuel and materials costs
16 have resulted in a numer of previously approved projects
17 eventually being postponed or eliminated.Those proj ects
18 combined with the prudence review of the CFMC, have
19 resul ted in a larger then anticipated unexpended PM&E
20 obligation currently estimated at $4.3 million.In
21 anticipation of the need to reduce the unexpended
22 obligation and to assure that the unexpended obligation
23 does not continue to grow, Avista plans to expend, with
1 The Clark Fork Maagement Committee is comprised of representatives
from the 28 Agency, Tribal and Non-governental signatories to the
Clark Fork Settlement Agreement..
194 Storro, Di 28
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CFMC approval, an additional $500,000 per year in O&M
expenditures, starting in early 2010, for the 2010 - 2015
3 timeframe. Ms. Andrews has included a proforma adjustment
4 to reflect this increased spending level.
5 Q.Would you please give a brief upte on the
6 status of efforts to relicense the Spokane River
7 Hyroelectric Projects?
8 A.Yes. The Company filed applications with FERC in
9 July 2005 to relicense five of its six hydroelectric
10 generation projects located on the Spokane River.The
11 Spokane River Project, which is currently under a single
12 FERC license, includes Long Lake, Nine Mile, Upper Falls,
13 Monroe Street, and Post Falls. Little Falls, the Company's.14 sixth project on the Spokane River, is not under FERC
15 jurisdiction, but operates under separate Congressional
16
17
authority.Our current license for the Spokane River
Project expired in August 2007.The Company is currently
18 operating under an annual license, but expects to receive a
19 new SO-year license by July 2009.
20 The Spokane River Relicensing costs include actual
21 life-to-date expenditures from April 2001 through the end
22 of December 2008, and 2009 pro forma expenditures through
23 June 30, 2009.As explained by Company wi tness Ms .
24 Andrews, the majority of these charges were reviewed in the
.
195 Storro, Di 29
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Company's previous general electric rate case proceeding,
Case No. AVU-E-08-01.Through the Settlement agreement
3 approved by the Commission in that case, the Company was
4 allowed to defer the amortization of these charges,
5 including a carrying charge on the deferrals and
6 unamortized balance, and include recovery of these costs in
7 its next general rate case.
8 Q.Has there been a final resolution to the
9 relicensing issues associated with the Coeur d'Alene Tribe?
10 A.Yes.A comprehensive agreement was signed with
11 the Coeur d' Alene Tribe and the U. S . Department of the
12 Interior.This agreement supports the issuance of a 50-
13 year FERC license for the Post Falls hydroelectric project.14 and the Spokane River hydroelectric proj ects .The
15 comprehensive settlement provides for paYment over the life
16 of the license of over $150 million for environmental
17 measures in and around Coeur d' Alene Lake and for
18 compensation to the tribe, as well as rights-of-way for
19 transmission lines over tribal lands and future storage
20 paYments connected with a new FERC license for the Post
21 Falls dam.The settlement also includes provisions for
22 Avista to make paYments to the Tribe for past and future
23 use of submerged Tribal lands and to satisfy the Company's
24 obligation to mitigate the impacts of the Post Falls dam on
.
196 Storro, Di 30
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the Tribes natural and cultural resources on its
Reservation.
The proposed settlement between the Coeur d' Alene
4 Tribe, Avista, and the U. S. Department of the Interior was
5 explained in Avista' s prior general rate case (Case No.
6 AVU-E-08-01) .Ms. Andrews has reflected the costs
7 associated with the settlement in this case through a pro
8 forma adjustment.
9
10
11
VI.Generation Plant Operation &: Maintenance Exenses
Comany exeriencing increasedtheQ.Is
12 expenditures associated with the operation and maintenance
13 of its generation facilities?
14
15
Yes. The operation and maintenance expenses forA.
Avista's generating facilities continue to increase.Ms.
16 Andrews has included Idaho's share of the 2009-2010
17 proforma period incremental non-labor costs above the test
18 period of approximately $899,000 (Idaho share).These
19 increases are mainly due to major O&M expenditures planned
20 1986) , Kettle Fallsfor Colstrip (completed 1984
21 (completed in 1983), and Rathdrum CT (completed in 1995).
22 Increased costs at Colstrip include major overhauls of
23 units # 4 and #3 in 2009 and 2010 respectively.Kettle
24 Falls will be undergoing a turbine overhaul in 2009.
25 Rathdrum CT has a hot gas path maintenance scheduled for
197 Storro, Di 31
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unit #1 in 2010 and painting of both units in 2011. These
increases represent a new and higher level of O&M costs
3 that are expected to continue given where each of the
4 projects are in their respective life-cycles.
5 Q.In addition to the O&:M expenses described above,
6 are there other significant O&: expenses anticipated by the
7 Comany?
8 A.Yes.The Company and the owners of Colstrip
9 Units #3 and #4 are required to mitigate the mercury
10 emissions from these projects. Mercury emissions laws in
11 Montana are going into effect January 1, 2010 with a second
12 phase going into effect in 2018.Ini tial testing of
13 mercury control technologies at Colstrip did not meet the.14 targets set by the Montana Department of Environmental
15 Quality, but further optimization of the mercury control
16 systems is expected to meet the required emissions levels.
17 Full mercury control operations are expected to begin by
18 mid-2009 to provide enough time to fine tune the system
19 with Colstrip plant operations.
20 The largest expense involved with the mercury control
21 project will be a significant increase in O&M costs. The
22 Company's share of the new O&M costs is expected to be
23 approximately $3 million per year. The current capital
24 budget for Colstrip is estimated to be sufficient to meet
25 the capi tal expenditures for this proj ect .After some.
198 Storro, Di 32
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initial 'capital expenditures planned in 2009, the increase
in O&M costs is expected to start in December 2009. Ms.
3 Andrews has included the Idaho share of the pro forma
4 period èxpenses in her pro forma adjustments in this case.
5 Q.Does this conclude your pre-filed direct
6 testimony?
7 A. Yes it does.
.
.
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I. INTRODUCTION
Q.Please state your name, the name of your
3 employe~, and your business address.
4
5
A.My name is Clint Kalich. I am employed by Avista
Corporation at 1411 East Mission Avenue,Spokane,
6 Washington.
7
8
Q.In what capacity are you employed?
A.I am the Manager of Resource Planning & Power
9 Supply Analyses, in the Energy Resources Department of
10 Avista Utilities.
11 Q.Please state your educational background and
12 professional experience.
.13
14
A.I graduated from Central Washington University in
1991 with a Bachelor of Science Degree in Business
15 Economics. Shortly after graduation, I accepted an analyst
16 position with Economic and Engineering Services, Inc. (now
17 EES Consulting, Inc.), a Northwest management-consulting
18 firm located in Bellevue, Washington.While employed by
19 EES, I worked primarily for municipalities, public utility
20 districts, and cooperatives in the area of electric utility
21 management.My specific areas of focus were economic
22 analyses of new resource development, rate case proceedings
23 involving the Bonneville Power Administration, integrated
24 (least-cost) resource planning, and demand-side management
25 program development.
.
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.1 In late 1995,I left Economic and Engineering
2 Services, Inc.to join Tacoma Power in Tacoma, washington.
3 i provided key analytical and policy support in the areas
4 of resource development, procurement, and optimization,
5 hydroelectric operations and re-licensing, unbundled power
6
7
supply rate-making,contract negotiations, and system
operations.I helped develop, and ultimately managed,
8 Tacoma Power's industrial market access program serving
9 one-quarter of the company's retail load.
10 In mid-2000 I joined Avista Utilities and accepted my
11 current position assisting the Company in resource
12 analysis,dispatch modeling,resource procurement,
13 integrated resource planning, and rate case proceedings..14 Much of my career has involved resource dispatch modeling
15 of the nature described in this testimony.
16 Q.What is the scope of your testimony in this
17 proceeding?
18
19
A.My testimony will describe the Company's use of
the AURO~ dispatch model, or "Dispatch Model."i will
20 explain the key assumptions driving the Dispatch Model's
21 market forecast of electricity prices.The discussion
22 includes the variables of natural gas, Western Interconnect
23 loads and resources, and hydroelectric conditions.I will
24 describe how the model dispatches our resources and
25 contracts in a manner that maximizes benefits to customers
.
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1
2
and tracks their values for use in pro forma calculations.
Finally, i will present the modeling results provided to
3 Company Witness Mr. Johnson for his power supply pro forma
4 adjustment calculations.
5 sponsoring any exhibi ts in thisQ.Are you
6 proceeding?
7
8
9
10
I am sponsoring Exhibit No.5, Schedules 1A.Yes.
and 2.Schedule 1 provides a forecast of Company load and
resource positions from 2009 through 2019.Schedule 2
provides sumary output from the Dispatch Model.All
11 information contained in the exhibits was prepared under my
12 direction.
13
14
15
II. THE DISPATCH MODEL
Q.What model is the Company using to dispatch its
16 portfolio of resources and obligations?
17
18
The Company uses EPIS, Inc.' s Dispatch Model forA.
determining power supply cos ts .The model optimizes
19 dispatch of Company-owned resources and contracts in each
20
21
hour of the pro forma year.The pro forma period is July
1 , 2009 through June 30, 20 i 0 .It reflects true system
22 operations by evaluating future resource decisions on an
23 hourly basis.
24 What AURORA version and database is the CompanyQ.
25 using for this case?
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A.The Company is using AURO~ version 9.3.1004,
and the latest available database for it
3 (North_American_DB_2008-03) .
4
5
6
Q.Please briefly describe the Dispatch Model.
A.The Dispatch Model was developed by EPIS, Inc. of
Sandpoint,Idaho.It is a fundamentals-based tool
7 containing demand and resource data for the entire Western
Interconnect.It employs multi-area,transmission-8
9
10
constrained dispatch logic to simulate real market
conditions.Its true economic dispatch captures the
11 dYnamics and economics of electricity markets-both short-
12 term (hourly, daily, monthly) and long-term. On an hourly
13 basis the Dispatch Model develops an available resource.14 stack, sorting resources from lowest to highest cost.It
15 then compares this resource stack with load obligations in
16 the same hour to arrive at the least-cost market-clearing
17 price for the hour.Once resources are dispatched and
18 market prices are determined, the Dispatch Model singles
19 out Avista resources and loads and values them against the
20 marketplace.
21 Q.What experience does the Company have using
22 AUR0RA?
23
24
A.The Company purchased a license to use the
Dispatch Model in April 2002.AURO~ has been used for
25 numerous studies, including the Company's 2003, 200S, 2007,
.
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2009 integrated Resource Plans ("IRPs"), our 2005, 2007,
and 2008 rate filings in the State of Washington and our
3 2004 and 2008 general rate case filings before this
Commission.The tool is also used for various resource4
5 evaluations,market forecasting,and requests for
6 proposals.
7
8
Q.Who else uses AURO~?
A.AURO~ is used all across North America.In
9 the Northwest specifically, AURO~ is used by the
10 Bonneville Power Administration, the Northwest Power and
11 Conservation Council, Puget Sound Energy, Idaho Power,
12 Portland General Electric, Seattle City Light, Grant County
13 PUD, Snohomish County PUD, and Tacoma Power, among others..14 Q.What benefits does the Dispatch Model offer for
15 this type of analysis?
16 A.The Dispatch Model generates hourly electricity
17 prices across the Western Interconnect, accounting for its
18 specific mix of resources and loads.The Dispatch Model
19 reflects the impact of regions outside the Northwest on
20
21
Northwest market prices,limited by known transfer
(transmission) capabilities.Ul timately, the Dispatch
22 Model allows the Company to generate price forecasts in-
23 house instead of relying on exogenous forecasts.
24 The Company owns a numer of resources, including
25 hydroelectric plants and natural gas-fired peaking units,
.
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which serve customer loads during more valuable on-peak
hours. By optimizing resource operation on an hourly
3 basis, the Dispatch Model is able to appropriately value
4 the capabilities of these assets. For example, actual 2008
5 on-peak prices through mid-December were 23% higher than
6 off-peak prices.In 2007 the difference was 25%. Forward
7 prices for 2010 were 28% at the time this case was
8 prepared.For comparison, Dispatch Model on-peak prices
9 for the pro forma period average 28% higher than off-peak
10 prices.In sumary, the Dispatch Model appropriately
11 values the energy from Avista' s resources during on-peak
12 periods in a manner similar to that recently experienced in
13 the Northwest region..14 Q.On a broader scale, what calculations are being
15 perfor.ed by the Dispatch Model?
16 A.The Dispatch Model's goal is to minimize overall
17 system operating costs across the Western interconnect,
18 including Avista' s portfolio of loads and resources.The
19 dispatch model generates a wholesale electric market price
20 forecast by evaluating all Western Interconnect resources
21 simultaneously in a least-cost equation to meet regional
22 loads. As the Dispatch Model progresses from hour to hour,
23 it "operates" those least-cost resources necessary to meet
24 load.With respect to the Company's portfolio, the
25 Dispatch Model tracks the hourly output and fuel costs
.
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.1 associated with portfolio generation. It also calculates
2 hourly .energy quantities and values for the Company's
3 contractual rights and obligations.In every hour the
4 Company's loads and obligations are compared with available
5 resources to determine a net position.This net position
6 is balanced using the simulated wholesale electricity
7 market. The cost of energy purchased from or sold into the
8 market is determined based on the electric market-clearing
9 price for the specified hour and the amount of energy
10 necessary to balance loads and resources.
11 Q.How does the Dispatch Model determine electric
12 market prices, and how are prices used to calculate market
13 purchases and sales?.14 A.The Dispatch Model calculates electricity prices
15 for the entire Western Interconnect, separated into various
16 geographical areas such as the Northwest and Northern and
17 Southern California.The load in each area is compared to
18 available resources, including resources available from
19 other areas that are linked by transmission corridors, to
20 determine the electrici ty price in each hour.Ultimately,
21 the market price for an hour is set based on the last
22 resource in the stack to be dispatched.This resource is
23 referred to as the "marginal resource. "Given the
24 prominence of natural gas-fired resources on the margin,
.
206
Kalich, Di
Avista Corporation
7
.this fuel is a key variable in the determination of1
2
3
wholesale electricity prices.
Q.How does the Dispatch Model operate regional
4 hydroelectric projects?
5
6
A., The model begins by "peak shaving" loads using
sys tem hydro resources.When peak shaving, the Dispatch
7 Model determines which hours contain the highest loads and
8 allocates to them as much hydroelectric energy as possible.
9 Remaining loads are then met with other available
10 resources.
11 Q.Has the Company made any modifications to the
12 database for this case?
.13
14
A.Yes. Avista' s portfolio of resources is modified
to reflect actual operating characteristics, natural gas
15 prices are modified to match projected forward prices over
16 the pro-forma period, regional resources are modified where
17 better information is known, and Northwest hydro data is
18 replaced with Northwest Power Pool data.
19 Q.Please describe your update to pro form period
20 natural gas prices.
21 A.Natural gas prices for this filing are based on a
22 3-month average from September i, 2008 to November 30, 2008
23 of July 2009 through June 2010 monthly forward prices.
24 Natural gas prices used in the Dispatch Model are
25 presented below in Table No 1.
.
207
Kalich, Di
Avista Corporation
8
.
2
3
4
5
6
7
8
9
10.11
12
13
14
15
16
17
18
19
20
21
22.
1 Table No. 1 - Pro Form Natural Gas Prices
Price Price
Basin ($/dth)Basin ($/dth)
AECO 7.31 Stanfield 7.67
Malin 7.75 Sumas 7.83
Spokane 8.03 Henry Hub 8.08
Rockies 5.59 Topock 7.49
Q. What hydro record is the Company using in this
filing?
A. The Company bases this case on the 50-year
hydrological record beginning in 1929. Data are sourced
from the Northwest Power Pool's (NWPP) 2006-07 Headwater
Benefits Study. This study is the latest available.
Q. What is the Company's assumtion for rate period
loads?
A. Rate period loads (July 2009 through June 2010)
used in this case are taken from the Company's 2009 load
forecast completed in July 2008. As this load is generated
us ing ~ normal weather," it el imina tes the need for a
weather-normalization adjustment.The Company's latest
energy and capacity loads and resources tabulations (L&Rs)
are attached in Exhibi t No.5, Schedule 1.As the L&Rs
show, system loads are expected to equal i,134 aMW
including a large co-generator's entire load.For this
filing, system loads are reduced by 49 aM of co-generation
by the large industrial customer load located in Idaho.
This adjustment lowers the rate period loads to l, 085 aM.
208
Kalich, Di
Avista Corporation
9
.1
2
3
Q. How does the Dispatch Model Operate Company-
controlled hYdroelectric generation resources?
A.The Dispatch Model treats all hydroelectric
4 generation plants within a load area as a single large
5 plant.The Company's hydroelectric plants are on average,
6 however, more flexible than the average plant used in each
7 load area. To account for this additional flexibility, the
8 Company algebraically extracts its plants from the region
9 and develops individual hydro operations logic for them.
10 Company-controlled hydroelectric resources are separated
11 into three river systems:the Spokane River, the Clark
12 Fork River, and individually separate the Mid-Columia
.13
14
projects.This separation ensures that the flexibility
inherent in these resources is credited to customers in the
15 pro forma exercise.
16 Q.Please compare the operating statistics from the
17 Dispatch Model to recent historical hydroelectric plant
18 operations.
19 A.Over the pro forma period the Dispatch Model
20 generates 70% of Clark Fork hydro generation during on-peak
21 hours (based on average water).Since on-peak hours
22 represent only 57% of the year, this demonstrates a
23 substantial shift of hydro resources to the more expensive
24 on-peak hours. This is identical to the 5-year average of
25 on-peak hydroelectric generation at the Clark Fork through
.
209
Kalich, Di
Avista Corporation
10
.1 2008. Similar performance is achieved for the Spokane and
2
3
Mid-Columia proj ects.
Q.Please provide a sumry of the monthly and
4 average Northwest Forward natural gas and electrici ty
5 prices?
6 Table No. 2 presents modeled natural gas andA.
7 electricity prices.
8 Table No. 2 - Dispatch Model Prices Sumry
cs:i:i &:NE/BP/Flat CS:i:i &:NE/BP/Flat
Rathdr KFCT (7 x 24)Rathdr KFCT 7 x 24)
Gas Gas Mid-C Gas Gas Mid-C
Month ( $/dth)($/dth)($/MW)Month ($/dth)($/dth)($/MW)
Jul-09 7.18 7.51 57.01 Jan-10 8.38 8.76 67.51
Aug-09 7.29 7.63 63.09 Feb-10 8.36 8.74 62.47
Sep-09 7.29 7.64 60.64 Mar-10 8.12 8.50 57.69
Oct-09 7.34 7.68 55.47 Apr-10 7.41 7.76 49.74
Nov-09 7.75 8.11 59.58 May-10 7.36 7.70 39.36
Dec-09 8.13 8.50 71. 66 Jun-10 7.44 7.79 34.74
Average 7.67 8.03 56.59.
9
10
11
12
13
14
15
16
17
18
19.
Q.Are Mid-Columia electric prices from the
Dispatch model the same as the Forward Market?
A.No,Mid-Columia electric prices from the
Dispatch Model differ from the forward market for a variety
of reasons. The forward market prices are not only an
expectation of future prices,but they contain an
adjustment for risk or unknown future conditions, based on
the premise you can ~ lock in" prices.The Dispatch Model
is a spot market model that forecasts prices for a specific
time in the future given load, hydro, and fuel price
210
Kalich, Di II
Avista Corporation
.1 conditions. Average annual Mid-Columia prices in the
2 forward market are $63. Ol/MW on-peak and $49. 26/MW off-
3 peak (based on average forwards between 9/1/2008 and
4 11/30/2008). The average Mid-Columia price from the
5 Dispatch Model is $62. 52/MW on-peak and $48. 68/MWh off-
6 peak.
7 Q.You stated earlier in your testimony that you are
8 using the NWP hydro study as the basis for your hydro
9 dataset. Does the NWP study include the Cabinet unit 4 or
10 any of the recent Noxon Rapids upgrades?
11 A.No, the NWPP study does not include the Cabinet
12 Uni t 4 or the Noxon Rapids 1 and 3 upgrades. The data will
be included in our next data submittal to the NWPP.I.13
14
15
expect the upgrade to be reflected in the 2009 NWPP study.
Q.How have you accounted for the upgrades in the
16 pro form?
17 A.The Cabinet Uni t 4 upgrade is expected to
18 generate an additional 1.98 aMW in an average water year;
19 Noxon Rapids Units 1 and 2 are expected to generate 3.3
20 average megawatts of additional energy in an average water
21 year.To account for this energy in the pro forma, the
22 unit sizes are increased to reflect the corrected amount of
23 energy. The Dispatch Model then generates at the upgraded
24 energy and capacity levels when the units are dispatched.
.
211
Kalich, Di 12
Avista Corporation
.1
2
Q. Company witness Storro discusses a new generation
resource that will enter Avista's supply portfolio in 2010.
3 Is this resource included in the Dispatch Model and the
4 Proform?
5 A.The 270-MW gas-fired combined-cycle generation
6 resource you are referring to entered commercial service in
7 2001, though it was not owned or operated by the utility
8
9
arm of Avista Corporation.It has been in our Dispatch
Model since we began using the tool in 2002.However,. we
10 have never included the resource in our portfolio of
11 resources that are tracked for ratemaking purposes. Though
12 we assume operational control over the facility in January
13 2010, we have not elected to include it in this filing.14
15
because the resource doesn't become available to us until
the midpoint of the proforma period.As Company witness
16 Johnson explains in more detail in his testimony, the
17 Company is proposing to track the costs and benefits of
18 this resource through the PCA mechanism when it enters our
19 resource portfolio in January 2010.
20
21
22
iv. RESULTS
Q.Please sumarize the results from the Dispatch
23 Model that are used for ratemking.
24 A.The Dispatch Model tracks the Company's portfolio
25 during each hour of the pro forma study.Fuel costs and
.
212
Kalich, Di 13
Avista Corporation
.1
2
3
4
5
6
7
8
9
10
11
.
.
generation for each resource are sumarized by month.
Total market sales and purchases, and their revenues and
costs, are also determined and sumarized by month. These
values are contained in Exhibit No.5, Schedule 2 and were
provided to Mr. Johnson for use in his calculations. Mr.
Johnson adds resource and contract revenues and expenses
not accounted for in the Dispatch Model (e. g., fixed costs)
to determine net power supply expense.
Q.this conclude pre-filed directDoesyour
testimony?
A. Yes, it does.
213
Kalich, Di 14
Avista Corporation
.1
2
I. INTRODUCTION
Q.Please state your name, business address,an
3 present position with Avista Corporation.
4 A.My name is William G. Johnson.My business
5 address is 1411 East Mission Avenue, Spokane, washington,
6 and I am employed by the Company as a Wholesale Marketing
7 Manager in the Energy Resources Department.
8
9
Q.Wht is your educational background?
A.I graduated from the University of Montana in
10 1981 with a Bachelor of Arts Degree in Political
11 Science/Economics.I obtained a Master of Arts Degree in
12 Economics from the University of Montana in 1985.
.13
14
15
16
Q.Bow long have you been emloyed by the Comany
and what are your duties as a Wholesale Marketing Manager?
A.I started working for Avista in April 1990 as a
Demand Side Resource Analyst.I joined the Energy
17 Resources Department as a Power Contracts Analyst in June
18 1996.My primary responsibilities involve power contract
19 origination and management and power supply regulatory
20 issues.
21 Q.What is the scope of your testimony in this
22 proceeding?
23 A.My testimony will 1) identify and explain the
24 proposed normalizing and pro forma adjustments to the
25 October 2007 through September 2008 test period power.
214 Johnson, Di 1
Avista Corporation
.1
2
supply revenues and expenses, and 2) describe the proposed
changes to the Power Cost Adjustment (PCA) calculation
3 methodology and the new authorized level of power supply
4 expense for PCA calculation purposes and 3) describe how
5 the Company proposes to track the expense and revenue
6 associated with the Lancaster plant, which will become an
7 Avista Utilities resource beginning January l, 2010.
8 Q.Are you sponsoring any exhibits to be introduced
9 in this proceeding?
10 A.Yes. I am sponsoring Exhibit No.6, Schedules 1
11 through 4, which were prepared under my supervision and
12 direction.
.13
14
15
Q.Are other company witnesses providing testimony
regarding issues you are addressing?
A.Yes.Company witness Mr. Kalich provides
16 detailed testimony on the AURORA model used by the Company
17 to develop short-term power purchase expense, fuel expense
18 and short-term power sales revenue included in my exhibits.
19
20
21
II. Pro Form Exense Adjustment
Q.Please provide an overview of your pro form
22 adjustmnt to power supply expense.
23 A.The pro forma adjustment to power supply expense
24 involves the determination of revenues and expenses based
25 on the generation and dispatch of Company resources and.
215 Johnson, Di 2
Avista Corporation
.
.
10
11
12
13
14
15
16
17
18
19
.
1
2
3
expected wholesale market power prices as determined by the
AURORA -model simulation for the pro forma period under
normal weather and hydro generation conditions.In
4 addition, adjustments are made to reflect contract changes
5 between' test period and the pro forma period.The table
6 below shows total net power supply expense during the test
7 period and the pro forma period. For information purposes
8 only, the power supply expense currently in rates, which is
9 based on a calendar 2009 pro forma period, is also shown.
Power Supply Expense in Current Base Rates (Calendar 2009 pro forma)
~
$17 4,849,000
$180,395,000
$27,64,000
$208,040,000
$33,191,000
Idaho
Allocation
Actual Oct 07-Sep 08 Power Supply Expense
Adjustment to Test Period $9,789,095
July 2009 - June 2010 Pro forma Power Supply Expense
Increase from Expense in Current Rates $11,752,933
The net effect of my adjustments to the test year
power supply expense is an increase of $27,645,000
($208,040,000 - $180,395,000) on a system basis. The Idaho
allocation of this adjustment of $9,789,095 is incorporated
into the revenue requirement calculation for the Idaho
jurisdiction by Company witness Ms. Andrews.
The increase in power supply expense compared to the
pro forma level in current base rates is $33,191,000
(system) and $11,752,933 (Idaho allocation).The power
216 Johnson, Di 3
Avista Corporation
.supply expense in current base rates is based on a calendar1
2
3
year 2099 pro forma.
Q.What are the major factors driving the increased
4 power supply exense in the pro form year over the level
5 of power supply expense currently in base rates?
6
7
A.The level of power supply expense currently in
base rates is $174,849,000 (system numer).This expense
8 level is based on a calendar 2009 pro forma period. This
9 compares to the proposed pro forma power supply expense of
10 $208,040,000, an increase of approximately $33.2 million on
11 a system basis and an Idaho allocation of approximately
12 $1l. 8 million.
13 This increase in pro forma power supply expense over.14 the expense currently in base rates is based on numerous
15 factors, primarily reduced hydro generation due to the
16 elimination of the rate mitigation adjustment included in
17 the last case and higher retail loads.
18 Pro forma retail loads are 22.7 aMW higher than loads
19 that current rates are based on. The increased loads are
20 due to two factors. One is the natural increase in retail
21 loads of approximately 14.3 aM. The other 8.4 aMW of load
22 increase is due to the reduction in Potlatch generation.
23 Because Potlatch generation expense is directly assigned to
24 Idaho, the Potlatch load equivalent to their generation is
25 removed from system loads.The reduction in Potlatch.
217 Johnson, Di 4
Avista Corporation
.1
2
generation has the effect of increasing system loads for
rate making purposes, while at the same time reducing the
3 Potlatch power purchase expense directly assigned to Idaho.
4
5
Hydro generation is also lower than the level in
current base rates.Pro forma hydro generation is 533.3
6 aM compared to 563.1 aM in current base rates, a
7 reduction of 29..8 aM.This pro forma removes the
8 additional 26.5 aM of hydro generation incorporated in
9 last year's general rate case as the "rate mitigation
10 adjustment." The remaining reduction in hydro generation is
11 due to the reduction in Mid Columia purchased hydro
12 generation resulting from the expiration of the Wanapum
13 contract in November 2009..14 The table below shows the primary factors driving the
15 increase in power supply expense compared to the level in
16 current base rates.
.
218 Johnson, Di 5
Avista Corporation
.
1
2.3
4
5
6
7
8
9
10
11
12
13
14
15.
Power Supply Expense Change
July 2009. June 2010 Pro forma vs. 2009 Pro forma
System Load $11.0 $3.90
Rate Mitigation Removed $12.8 $4.53
Settlement Adjustments Removed $3.1 $1.10
Actual Transactions Mark-ta-Model $4.3 $1.52
Coyote Operating Margin -$0.5 -$0.18
Other $2.5 $0.89
Total Pro forma Increase $33.2 $11.8
III. PRO FORM POWER SUPPLY EXENSE
OVerview
Q. Please identify the specific power supply cost
items that are covered by your testimony and the total
adjustment being proposed.
A. Exhibit No.6, Schedule 1 identifies the power
supply expense and revenue items that fall within the scope
of my testimony.These revenue and expense items are
related to power purchases and sales, fuel expenses,
transmission expense, and other miscellaneous power supply
expenses and revenues.
Q. Wht is the basis for the adjustments to the test
period power supply revenues an exenses?
219 Johnson, Di 6
Avista Corporation
.1
2
A. The purpose of the adjustments to the test period
is to normalize power supply expenses for normal weather
3 and hydroelectric generation and to reflect known and
4 measurable changes for the pro forma period that rates will
5 be in effect.Adjustments are also made to reflect
6 contract changes from the test period to the pro forma
7 period.
8 The AURORA Model dispatches Company resources on an
9 hourly basis and calculates the level of generation from
10 the Company's thermal resources, fuel costs for thermal
11 resources, and the short-term purchases and sales necessary
12 to serve system requirements.
.13
14
Q.Have any chages been made in the calculation of
pro form power supply costs from the last general rate
15 case?
16 A.Yes.The primary change made in this general
17 rate case is to include the actual term power and natural
18 gas transactions already entered into for delivery in the
19
20
pro forma period.Term transactions are monthly and
quarterly transactions.This is done to more accurately
21 reflect the actual power supply expense the Company will
22 incur during the pro forma period.
23 As of November 30, 2008 Avista had entered into 33
24 forward electric contracts and 8 forward natural gas
25 contracts for delivery in the pro forma period.The.
220 Johnson, Di 7
Avista Corporation
.electric contracts include 15 physical purchases and 41
2
3
physical sales and 14 financial (fixed-for-floating swaps)
purchases.The natural gas transactions include 4
4 purchases and 4 sales.
5 The mechanics of including actual transactions in the
6 pro forma is to add the physical electric transactions as
7 resources and obligations in the AURORA model and include a
8 mark-to-model adjustment in the pro forma for the financial
9 electric and natural gas transactions. If the actual
10 transactions lower power supply expense (lower purchase
11 costs or higher sales revenue) as compared to the cost
12 produced by the AURORA model, then the lower cost is
.13
14
included in the pro forma expense.If the actual
transactions increase power supply expense (higher purchase
15 costs or lower sales revenue) as compared to the cost
16 produced by the AURORA model, then the higher cost is
17 included in the pro forma expense.
18 The Company's hedging program layers in purchase and
19 sales transactions prior to the delivery period, and some
20 of the actual transactions were entered into during the
21 period of high forward prices during the middle of 2008.
22 Because prices have declined since July 2008, the overall
23 impact of the actual transactions is an increase in the pro
24 forma expense.The table below shows the impact of the
25 actual transactions in the pro forma. Overall, the actual.
221 Johnson, Di 8
Avista Corporation
.
6.7
8
9
10
11
12
13
14
15
16
17
18
19.
1
2
transactions increase pro forma expense by $4,314,400 on a
system basis, $1,527,729 Idaho allocation, compared to what
3 expenses would be based solely on the AURORA model output.
4 Avista' s hedging strategy and risk management program are
5 explained in Mr. Storro's testimony.
System Idaho
Numbers Allocation
Physical Electric Transactions Mark to Market $43,304 $15,334
Financial Electric Transactions Mark to Market $2,923,297 $1,035,139
Natural Gas Transactions Mark to Market $1347800 $477256
Total Proforma Impact of Actual Transactions $4,314,400 $1,527,729
Detailed workpapers are provided for all the actual
transactions included in the pro forma.
Q. Are there any other chages in how the pro form in
this case was developed?
A. No. Other than including actual transactions and
the removal of the hydro rate mitigation adjustment, the
process to develop the pro forma net power supply expense
in this case is the same as in the 2008 general rate case.
A brief description of each adjustment is provided in
Exhibi t No.6, Schedule 2.Detailed workpapers have been
provided to the Commission coincident to this filing to
support each of the pro forma revenues and expenses. The
detailed workpapers for each adjustment show the actual
222 Johnson, Di 9
Avista Corporation
.1 revenue or expense in the test period, and the pro forma
2 revenue or expense.
3 Long-Te~ Contracts
4 Q. .How are long-term power contracts included in
5 the pro form?
6 A.Long-term power contracts are included in the pro
7 forma by including the energy receipt or obligation
8 associated with the contract in the AURORA model and
9 including the cost or revenue in the pro forma net power
10 supply expense.
11 Q.Are there any new power purchases or sales in the
12 pro form?
.13
14
A.Yes.The Company entered into a two-year
agreement to purchase generation from the Wells
15 hydroelectric plant that is assigned to the Colville Indian
16 Tribe, which I describe in more detail below.Also, the
17 purchase from Thompson River Cogen, a cogeneration plant in
18 Thompson Falls, Montana, that was included in the 2008 rate
19 case, was removed from this case because of the delays in
20 the start-up of the plant.
21 Q.Please describe the purchase of the Colville
22 Indian Tribe's Well's generation output?
23 A.Avista entered into a two-year agreement
24 beginning October 2008 and ending Septemer 2010 to
25 purchase the Colville Indian Tribe'S 4.5% share of the.
223 Johnson, Di 10
Avista Corporation
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2
output of the Wells hydroelectric generation. Prior to this
agreement, Avista purchased 3.34% of the Well's output at
3 actual production cost from the owner of Wells, Douglas
4 PUD.The additional 4.5% of Wells output assigned to the
5 Colville Indian Tribe was purchased through a competi ti ve
6 auction at the market prices at the time. The purchase of
7 the Colville Indian Tribe's share of Wells output at market
8 prices is the reason for the increase in Well's cost in the
9 pro forma.
10
11
Q. Why is this purchase imortant to the Comany?
A.This purchase was important because of the
12 capacity and ancillary products that come with a Mid
.13
14
Columia generation product.In addi tion to the energy,
Mid Columia generation has dYnamic capacity that the
15 Company uses for frequency regulation and load following.
16 The generation also comes with a "paper pond" that allows
17 the Company to shift generation from low load to high load
18 hours.
19 The amount of generation the Company has at the Mid
20 Columia is being reduced as the existing contracts with
21 Grant PUD expire and the amount of generation at Priest
22 Rapids (November 2005) and Wanapum (November 2009) are
23 reduced by roughly half. The Wells purchase makes up for a
24 good portion of the loss of capacity at Priest Rapids and
.
224 Johnson, Di 11
Avista Corporation
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2
Wanapum, and allows the Company to maintain regulation
functions at the Mid Columia.
3 Short-Te~ Power Purchases and Sales
4 Q.How are short-te~ transactions included in the
5 pro form?
6 A.After including the actual short-term
7 transactions explained earlier as resources and obligations
8 in the AURORA model, the balance of the short-term electric
9 power purchases and sales are an output of the AURORA
10 model. The model calculates both the volumes and price of
11 short-term purchases and sales that balance the system's
12 generation and long-term purchases with retail load and
.13
14
long-term obligations.The price of the short-term
transactions represents the price of spot market power as
15 determined by the AURORA model.
16 Therml Fuel Exense
17 Q.How are therml fuel expenses detexmned in the
18 pro form?
19 A.Thermal fuel expenses include Colstrip coal
20 costs, Kettle Falls wood waste costs and natural gas
21 expense for the Company's gas-fired resources including
22 Coyote Springs 2, Rathdrum, Northeast, Boulder Park, and
23 the Kettle Falls combustion turbine.Uni t coal cos ts at
24 Colstrip are based on the long-term coal supply and
25 transportation agreements. Unit wood fuel costs at Kettle.
225 Johnson, Di 12
Avista Corporation
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2
Falls are based on multiple shorter-term contracts with
fuel suppliers and inventory.Total fuel costs for each
3 plant are based on the unit fuel cost and the plant's level
4 of generation as determined by the AURORA model.Exhibit
5 No.6, Schedule 3 shows the pro forma fuel costs by month
6 for each plant. Mr. Kalich provides details and supporting
7 workpapers regarding the fuel costs for the Company's
8 thermal plants.
9 Transmission Exense
10 Q. What changes in transmission exense are in the
11 pro form comared to the test year or the 2008 rate case?
.
12
13
14
A.There is almost no change in transmission
expense.Transmission expense in the pro forma is $4,000
(system) higher than the test year actual expense and
15 $169,000 lower than the pro forma in the 2008 rate case.
16 Q.will there be additional transmission expense in
17 the pro form period that has not been included in this
18 case?
19 A.Yes, beginning January 1, 2010 the Company will
20 purchase 250 MW of BPA point-to-point transmission for the
21 Lancaster plant.The cost of this transmission will be
22 approximately $375,250 per month. The Company proposes to
23 track this expense in the PCA at 100 percent until such
24 time that this expense is included in base retail rates.
25.
226 Johnson, Di 13
Avista Corporation
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3
iV. PCA CALULTIONS
Proposed Chages to the PCA
Q.Is the Coman proposing any changes to the PCA
4 methodology?
5 A.' Yes.The Company is proposing four changes to
6 the PCA calculations. The first is to change the sharing
7 percentages between Customers and the Company from 90%/10%
8
9
to 95%/5%.The second change is to include third-party
transmission expense (Accounts 565710 & 565000)and
10 transmission revenue (Accounts 456100, 456016 & 456700) in
11 the PCA.The third change is to use the average cost of
12 production/transmission included in base rates as the
13 retail revenue credit instead of the marginal cost of power.14 currently used in the PCA. The fourth change is to include
15 the Production Tax Credit in the PCA.
16 The Company is also proposing to include the expenses
17 and revenues related to the Lancaster plant in the PCA
18 beginning January 1, 2010, until the expense and revenue
19 related to the Lancaster plant are included in base rates.
20 Customer/Comany Sharing
21 Q. Why is the Comany proposing a chage in the
22 sharing between customers an the Coman in the PCA?
23 A.The primary reason to change the sharing
24 methodology is the increased volatility of power supply
25 costs. The increased volatility is driven primarily by two.
227 Johnson, Di 14
Avista Corporation
.
.
.
1
2
3
4
factors. One is the overall level of prices. Higher
prices mean greater absolute variability due to hydro
generation and load variations.Also important is the
recent price volatility in the energy markets.For
5 example, actual prices varied from $88/MW in April 2008
6 when the Company was purchasing energy due to low hydro
7 generation from the delayed run-off to $25/MW in June when
8 the hydro run-off materialized and the Company was selling
9 surplus power. This kind of price volatility coupled with
10 hydro variation can cause very large changes in the
11 In April 2008 alone, theCompany's power supply expense.
12 Company's power supply expense exceeded the authorized
13 level by over $4.0 million (Idaho Allocation, over $14
14 million on a system basis), leading to a peA deferral of
15 over $3.5 million, with the Company absorbing over
16 $400,000.
17
18
An additional volatility the Company faces is the
price of natural gas.This is a significant source of
19 volatili ty with Coyote Springs 2 and will become even more
20 significant with the addition of Lancaster in 2010.A
21 rough rule of thum is that every $1/dth change in natural
22 gas prices changes Avista' s system power supply expense by
23 $10 million without the Lancaster plant.Natural gas
24 prices have varied by over $5/dth during 2008. This
25 variability caused by natural gas price will be even
228 Johnson, Di 15
Avista Corporation
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2
greater when the Company begins receiving power from the
Lancaster plant in 2010.
3 Transmission Exense an Revenue
4 Q.Why is the Comany proposing to include
5 transmission exense and revenues in the PCA?
6 A. ' Transmission expense is a significant component
7 of the Company's overall power supply expense. While much
8 of the transmission is purchased under long-term contracts,
9 some is purchased on a short-term basis and is subject to
10 variabili ty in the expense level.Including transmission
11 expense in the PCA tracks the variability in this power
12 supply related expense.
.13
14
including transmission revenue in the PCA is a
fairness issue.If customers are absorbing the majority
15 of any increases in transmission expense then it is fair
16 that they receive the majority of increases in transmission
17 revenue. The transmission revenue the Company is proposing
18 to include in the PCA is the sale of Avista transmission to
19 third parties.
20 Including transmission revenues and expenses in the
21 PCA is also consistent with the Company's Retail Revenue
22 Credi t proposal.The proposed Retail Revenue Credit
23 includes both the Production and Transmission components of
24 the retail rate.
.
229 Johnson, Di 16
Avista Corporation
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Finally, including transmission expense in the PCA is
necessary in order for the Company to include the expenses
3 associated with the Lancaster plant in the PCA. As stated
4 earlier in my testimony, beginning January i, 2010, Avista
5 will be assigned 250 MW of BPA point-to-point transmission
6 from th~ Lancaster plant.This transmission is the only
7 means to move the power from the Lancaster plant to
8
9
Avista's system.The anual cost of this transmission is
approximately $4.5 million or $375,250 per month.
10 Transmission expense must be included in the PCA in order
11 for the Company to recover all the costs associated with
12 the Lancaster plant. If the PCA is not modified to reflect
13 transmission expense in the PCA, then the Company proposes.14 that only the transmission expense for the Lancaster plant
15 be included in the PCA (at 100% of expense) until the costs
16 are included in base retail rates.
17 Retail Revenue Credit
18 Q.What change is the Comany proposing to the
19 Retail Revenue Credit rate?
20 A.The Company proposes that the average cost of
21 production and transmission be used as the retail revenue
22
23
credi t rate in the PCA.Currently, the retail revenue
credit rate is the marginal cost of power.The average
24 production and transmission cost represents the power
25 commodity component of retail rates and is the revenue.
230 Johnson, Di 17
Avista Corporation
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collected from customers to recover power and transmission
costs.Using the average cost of production and
3 transmission as the retail revenue credit in the PCA
4 ensures that the actual revenue collected from customers
5 when retail sales increase is credited back against the
6 increased power supply expense and only the difference
7 between the actual cost of power and the amount of revenue
8 collected from customers is included in the PCA.
9 The average production cost also works equally well
10 when actual sales are lower than authorized sales. In that
11 case, actual power supply expense is lower because loads
12 are lower.The retail revenue credit adjusts for the
13 actual revenue the Company did not receive from customers..14 The benefit of using the average cost of production
15 and transmission versus the marginal cost of power is that
16 the average cost of production works equitably for
17 cus tomers and the Company when sales are both higher and
18 lower than the authorized level.As a note, the average
19 cost of production was used in the PCA for the months of
20 October 2008 through Decemer 2008.Beginning January
21 2009, the retail revenue credit returned to being the
22 marginal cos t of power.
23 Inclusion of Production Tax Credit in the PCA
24 Q.Please explain the Production Tax Credit an how
25 the Comany proposes to include it in the PCA..
231 Johnson, Di 18
Avista Corporation
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A.' The Production Tax Credit (PTC) is a Federal
income tax credi t the Company receives based on energy
3 production at the Kettle Falls bio-fuel plant and for
4 increased generation from upgrades at Cabinet Gorge dam.
5 The amount of PTC included in this case is a system amount
6 of $2,766,722, which lowers customer's rates. The PTC for
7 ratemaking purposes is grossed up to a revenue level of
8 $4.26 million (system) using the conversion rate of 65%,
9 which is one minus the federal income tax rate. The PTC is
10 set to expire for Kettle Falls on December 31, 2009.
11 Q.Why is it appropriate to include the PTC in the
12 PCA?
.13
14
A.The PTC is a credit that is directly tied to the
level of generation at Kettle Falls and Cabinet Gorge. The
15 credit is accrued monthly based on the level of generation
16 at Kettle Falls and Cabinet Gorge.It is very similar to
17 other power supply expenses, such as fuel expense, which is
18 directly related to the level of production, and included
19 in the PCA.Because it is directly tied to the level of
20 generation at Kettle Falls and Cabinet Gorge it is an
21 appropriate revenue item to include in the PCA.
22 As noted earlier, the Kettle Falls portion of the PTC
23 is set to expire on Decemer 31, 2009.When the PTC
24 expires at the end of 2009, the PCA will properly account
25 for this change.By including the PTC in the peA,.
232 Johnson, Di 19
Avista Corporation
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customers will appropriately receive the full benefits from
the PTC through December 2009.If the PTC is not tracked
3 through the PCA, beginning January 2010 Avista would
4 inappropriately continue to flow a tax benefit to customers
5 that does not exist.
6 The Company proposes that Idaho's share of the system
7 PTe amount of $4.26 million be included in the authorized
8 level of power supply expense in the PCA, which would then
9 be compared with the actual PTC credit each month in the
10 actual power supply expense in the PCA.The differences
11 between the actual PTC and the authorized PTC will flow
12 through the PCA in the same manner as other power supply
13 expenses and revenues..14
15
Inclusion of Lancaster Exense and Revenue in the PCA
Q.How does the Comany propose including the
16 expense and revenue related to the Lancaster plant in the
17 PCA
18
19
A.Avista Utili ties will begin purchasing the output
of the Lancaster plant January 1, 2010.The Company
20 proposes that the expense and revenues related to the
21 Lancaster plant be included in the PCA until they are
22 reflected in base retail rates.
23 The Lancaster plant has several cost components.
24 Three cost components are part of the Lancaster power
25 purchase agreement and include a fixed capital paYment, a.
233 Johnson, Di 20
Avista Corporation
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fixed O&M payment and a variable O&M payment. All three of
these expenses will be recorded in Account 555, Purchased
3 Power Expense, which is an account tracked by the PCA. The
4 capital payment and the fixed O&M payment will be
5 relatively constant month to month, and the variable O&M
6 expense will be dependent on the amount of generation at
7 the plant.
8 Other Lancaster plant costs include natural gas fuel
9 expense and the natural gas pipeline transportation
10 expense, both of which are included in Account 547, Fuel
11 Expense, and the BPA transmission that is recorded in
12 Account 565, Transmission Expense.As explained earlier,
13 the Company is proposing in this filing that Transmission.14 Expense and Transmission Revenue be included in the peA
15 calculation.
16 The Company is proposing that the fixed expenses
17 related to the Lancaster plant be isolated and tracked in
18 the PCA at 100% of the actual expense. The fixed expenses
19 include the capacity payment (capital payment and fixed O&M
20 payment), the natural gas pipeline transportation payment
21 and the BPA transmission payment. These fixed payments do
22 not vary and would otherwise be 100% included in base
23 rates.
24 The Company proposes that the variable expenses and
25 revenue from the Lancaster plant be included in the PCA in.
234 Johnson, Di 21
Avista Corporation
.a manner similar to other expenses and revenues that would1
2
3
be sl.bject to the Company's proposed 95%/5%
Customer /Company PCA sharing.The variable expenses
4 related to the Lancaster plant include the variable O&M
5 paYment., natural gas fuel expense and the net impact of
either reduced electrici ty purchases or increased6
7 electrici ty sales.Tracking the variable expense and
8 revenue in the PCA at the proposed 95%/5% sharing
9 arrangement is similar to how these expenses are tracked
10 for other resources.
11 New Authorized Power Supply an Transmission Exense
12 Q.What is the authorized power supply expense and
13 revenue proposed by the Company for the PCA?.14 A.The proposed authorized level of annual system
15 power supply expense is $192,927,906. This is the sum of
16 Accounts 555 (Purchased Power), 50l (Thermal Fuel), 547
17 (Fuel), less Account 447 (Sale for Resale). The proposed
18 level of Transmission Expense is $14, l68, 901. The proposed
19 level of Transmission Revenue is $9,478,694.
20 The level of retail sales MW and the retail revenue
21 credit will also be updated. The proposed authorized level
22 of retail sales to be used in the PCA is the July 2009
23 through June 2010 pro forma retail sales.The proposed
24 retail revenue credit is $47. 85/MW, which is the average
25 cost of production/transmission in this filing..
235 Johnson, Di 22
Avista Corporation
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The proposed authorized PCA expense and revenue is
shown in Exhibit 6, Schedule 4.
Q.Does that conclude your pre-filed direct
4 testimony?
5 A. Yes.
.
.
236 Johnson, Di 23
Avista Corporation
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I. INTRODUCTION
Q.Please state your nae, emloyer and business
3 address.
4 A.My name is Don F. KopczYnski and I am employed as
5 the Vice President of Transmission and Distribution
6 Operations for Avista Utilities, at 1411 East Mission
7 Avenue, Spokane, washington.
8 Q.Would you briefly describe your educational
9 backgroun and professional exerience?
10 A.Yes.Prior to joining the Company in 1979, i
11 earned a Bachelor of Science Degree in Engineering from the
12 University of Idaho. I have also earned a Master's Degree
13 in Management from Washington State University and a.14
15
Master's Degree in Organizational Leadership from Gonzaga
Uni versi ty .Over the past 30 years I have spent
16 approximately 16 years in Energy Delivery, managing
17 Engineering, various aspects of Operations, and Customer
Service.In addition, I spent three years managing the18
19
20
Energy Resources Department,including Power Supply,
Generation and Production, and Natural Gas Supply.More
21 recently, I worked in the areas of Corporate business
22 analysis and development, and served in a variety of
23 leadership roles in subsidiary operations for Avista Corp.
24 I was appointed General Manager of Energy Delivery in 2003
25 and Vice President in 2004.I serve on several boards,.
237 KopczYnski, Di
Avista Corporation
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including the Eastern washington University Electrical
Engineering and Computer Science Advisory Board, washington
3 State Electrical Board, and the washington State University
4 Engineering Advisory Board.
5
6
Q. . Wht is the scope of your testimony?
A.i will provide an overview of the Company's
7 electric and natural gas energy delivery facilities and
8 operations. i will also explain some of our recent efforts
9 to increase efficiency and improve customer service, such
10 as the newly formatted website and outsourcing of the bill
11 print and mail service, as well as sumarize Avista' s
12 cus tomer service programs in Idaho.A table of the
13 contents for my testimony is as follows:.14
15
16
17
18
19
20
21
22
23
24
Description Page
i.II.Introduction
Overview of Avista' s Energy
Delivery Operations
System Improvements & Efficiencies
Information Services Support
Cus tomer Support Programs
Page 1
III.
IV.
V.
Page 3
Page 6
Page 9
Page 10
Q.Are you sponsoring any exhibits in this
25 proceeding?
26
27
A.Yes. I am sponsoring Exhibit No.7, Schedules 1
and 2.Schedule 1 details the system improvements and
28 efficiencies the Company has undertaken. Schedule 2 shows.
238 Kopczynski, Di
Avista Corporation
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the detailed usage and numer of customers for each
customer class. These exhibits were prepared under my
3 direction.
4
5
6
7
II. OVRVIEW OF AVISTA' S ENRGY DELIVERY SERVICE
Q.Please provide an overview of the customers
8 served ~ Avista Utilities in Idaho.
9 A.Of the Company's 352,423 electric and 309,912
10 natural gas customers (Septemer 30, 2008), 120,972 and
11 72,326,respectively, were Idaho customers. Avista's
12 largest electric customer in Idaho is the potlatch
13 Corporation's Lewiston facility, with an annual usage of.14
15
approximately 898 million kWh.
Q.Please describe Avista Utilities' Idaho electric
16 and natural gas utility operat~ons.
17 A.The Company serves the Idaho counties of
18 Benewah, Bonner, Boundary, Clearwater, Idaho, Kootenai,
19 Latah, Lewis, Nez Perce, and Shoshone.Lumer and wood
20 products manufacturing is the dominant industry in our
21 Idaho service area. Approximately 34% of 2008 Idaho
22 electric retail usage was from residential customers, with
23 29% from commercial, 35% from industrial customers, and 2%
24 from pumping customers. Approximately 48% of natural gas
25 retail revenues were from residential customers, and 16%.
239 KopczYnski, Di
Avista Corporation
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from commercial and 37% from industrial and transportation
customers. The Company has seven transportation customers
3 in Idaho.
4 As detailed in the Company's 2007 electric Integrated
5 Resource Plan, Avista expected retail electric sales
6 growth to average 2.3% annually for the next ten years and
7 2.0% over the next twenty years in Avista's service
8 terri tory, primarily due to increased population and
9 business growth. The Company is currently in the process
10 of preparing its 2009 IRP, and the impacts of the current
11 economic climate will be reflected in that document to be
12 filed with the Commission in August 2009.
.13
14
Also, based on Avista's 2007 Natural Gas Integrated
Resource Plan, in Idaho the numer of customers were
15 projected to increase at an average anual rate of 3.0%,
16 with demand also growing at 3.0% per year.As with the
17 electric IRP, the impacts of the current economic climate
18 will be addressed in the Company's 2009 natural gas IRP
19 that will be filed with this Commission in Decemer 2009.
20 Q.Please describe the Comany's electric and
21 natural gas delivery facilities.
22
23
A.Avista Utilities operates a vertically-integrated
electric system.In addition to the hydroelectric and
24 thermal generating resources described by Company witness
25 Mr. Storro, the Company has approximately 4,052 miles of.
240 Kopczynski, Di
Avista Corporation
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lines in the following classes in Idaho: 286 miles of 230
kV transmission, 604 miles of 115 kV transmission, and
3 3, l62 miles of sub-transmission and distribution line at a
4
5
variety, of voltages.Avista also has 928 miles of
distribution underground cable;the predominant
6 distribution voltage is 13.2 kV. Avista owns and maintains
7 1876 miles of natural gas pipelines (excluding services) in
8 the state of Idaho of which 560 miles are steel and 1316
9
10
miles are polyethylene.All of these pipelines are
distribution, not transmission,operating at various
11 maximum allowable operating pressures (MAOPs) from 60 psig
12 to 720 psig. Avista has 69,337 natural gas service lines
13 in Idaho..14 Q.Please describe the Comany's operations centers
15 that support electric and gas customrs in Idaho.
16 A.The Company has construction offices in
17 Grangeville, Orofino, Lewiston-Clarkston, Moscow-Pullman,
18 Kellogg, St. Maries, Coeur d'Alene, Sandpoint and Bonner's
19 Ferry, and customer contact center operations in Lewiston
20 and Coeur d'Alene. Avista's four customer contact centers
21 in Coeur d' Alene, Lewiston, Spokane, and Medford, Oregon
22 are networked, allowing the full pool of regular and part-
23 time employees to respond to customer calls in all
24 jurisdictions.
.
241 KopczYnski, Di
Avista Corporation
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Q. Wht construction an maintenance programs does
the Comany have in place to maintain gas and electric
3 facilities?
4 A.' Avista Utilities utilizes Company seasonal and
5 regular crews for gas and electric construction, including
6 new and reconstructed lines, damage repair, and connecting
7 new cus tomers .The Company employs contract crews and
8 temporary and part-time employees to meet customer needs
9 during the peak construction season. The Company also has
10 several maintenance programs to maintain the reliability of
11 our electric and gas infrastructure. On the electric side,
12 this includes the Company's asset management program
.13
14
(including wood pole inspection and replacement) ,
vegetation management,electric transmission line
15 inspection and reconstruction. Company Witness Mr. Kinney
16 discusses this program in more detail. Regarding natural
17 gas operations, ongoing maintenance focuses on valve and
18 regulator stations, atmospheric corrosion protection, and
19 leak surveys.
20
21
22
III. SYSTEM IMPROVES AN EFFICIENCIES
Q.Has the Coman looked at undertaking additional
23 measures to either reduce costs or increase customr
24 service levels?
.
242 KopcZYnski, Di
Avista Corporation
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A. Yes.Avista Utili ties has undertaken a numer of
improvements and efficiency initiatives throughout our
3 service, area that are focused on either increasing customer
4 service and satisfaction, or increasing productivity and
5 reducing operating costs.We believe these measures have
6 served to mitigate the impact on customers of the proposed
7 rate increase.
8 Q.Please explain the system improvement measures
9 that Avista has implemented in Idaho.
10 A.Some of the recent improvements that the Company
11 has implemented are as follows:
.
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. We have updated our Integrated Voice Response
system to provide more assistance to our
customers to interact with our company.
. Our redesigned website - AvistaUtilities. com
provides cus tomers easy access to their
account where they can review and pay their
bill; it also provides current companyinformation.
. The Every Little Bit Energy Efficiency
Camoaign - We are able to show customers that
~every little bit" does add up and can make a
difference in their energy usage.
. Evaluating transmission and distribution
system efficiencies. By tracking the reduction
in losses across our transmission and
distribution system, Avista can verify the
life cycle cost benefit of the system
improvement.
. Avista has been able to complete numerous
small energy efficiency projects that have
resulted in energy conservation at company
offices and service centers..
243 Kopczynski, Di
Avista Corporation
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. We outsourced our bill orint and mailing
operations which now meets all requirements
for disaster recovery which ensures timely
delivery of customer information and customerbills.
.
. Avista is working through collaborative
efforts with the City of Spokane in a pilot
program to coordinate design locates as part
of the City's construction design process.
. Helped formulate the Spokane RegionalInfrastructure Efficiency Plan. The Joint
Utilities Coordination Council has resulted in
greater coordination and efficiencies across
the entire Spokane region.
. Craft Trainino this new learning network
gives us a delivery and a record-keeping
system that allows the Company to plan,
schedule and document our training programs
and requirements in a more efficient way.
. Implemented a new Asset Manaoement Prooram.
This new software allows detailed analysis of
the impacts of increased or decreased
reliability based on system configuration and
component reliability.
. The Company recently deployed a customsoftware application which provides the
Company with the ability to manage the
scheduling of planned outages for transmission
lines and line segments. This improvement tothe system has reduced operator time,
streamlined the scheduling process, andreduces errors.
. As of late 2008, all gas and electric crew
callouts in all jurisdictions will be handled
by the ARCOS Rostermonster system. The
expanded capabilities of ARCOS will allow us
to callout personnel from multiple lines with
less delay, thereby improving restoration time
for after-hour customer outages.
. The Company has recently started an evaluation
of the Fleet Department. Company employees
have identified process improvements in.
244 KopczYnski, Di
Avista Corporation
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addi tion to technological upgrades that will
benefit and modernize its fleet department.
. We have implemented a new Outage Management
System to help minimize the restoration time
of outages on our system.
. Our Mobile Dispatch Program reduces the time
it takes for the Company to process cus tomers '
na tural gas orders, and provide service. Wealso made outage information available to
customers on the Company's website athttp://ww.avistautilities.com/safety/outages/
pages / defaul t . aspx.
These programs are detailed further in Exhibit No.7,
18 and are examples of the extensive efforts of Avista to
19 identify and implement efficiency measures and/or
20 productivity while continuing to provide quality service to.21
22
23
24
iv. INFRMTION SERVICES SUPPORT
customers.
Q.Please exlain what expendi tures are directly
25 related to the Comany's Informtion Services being
26 captured in this case.
27 A.The expenditures that the Company has pro formed
28 in this case include the administrative and general (A&G)
29 expenses associated with incremental known and measureable
30 changes for labor and non-labor informtional services
31 costs planned for 2009 above the test period, which total
32 $2.6 million on a system basis (Idaho's share is
.
245 KOpczYnski, Di
Avista Corporation
9
.approximately $.7 million). They are related to the1
2
3
following:
1) additional labor dollars required to support
4 applications utilized by the Company in recent years, such
5 as the mobile dispatch and outage management applications,
6 improved web application support, and additional security
7 and compliance requirements; and
8 2) additional non-labor dollars required for hosting
9 fees, application fees, software maintenance and license
10 fees, and new and replacement software and hardware for
11 business applications.Company wi tness Ms . Andrews
12 includes these additional expenses in her pro forma
13 adjustments..14
15
16
v.CUSTOR SUPORT PROGRAS
Q.Please explain the customer support programs
17 that Avista provides for its customrs in Idaho.
18 A.Avista Utilities actively participated in the
19 energy affordability workshops in Case No. GNR-U-08-01. In
20 that case, workshop participants explored ways to address
21 energy affordabili ty and the ability of customers to pay
22 energy bills. Staff's comments in the above mentioned case,
23 among other issues, recommended that the Commission support
24 legislation to allow it to adopt a LlRAP program. The
25 Company continues to advocate the implementation of a Low.
246 KOpCZYnski, Di 10
Avista Corporation
.Income Rate Assistant Program (LlRAP) for its Idaho1
2
3
customers.
Avista Utilities offers a numer of programs for its
4 Idaho customers, such as energy efficiency programs,
5 Proj ect Share for emergency assistance to customers, a
6 Customer Assistance Referral and Evaluation Service (CARES)
7 program, senior programs, level pay plans, and payment
8 arrangements.Some of these programs will serve to
9 mitigate the impact on customers of the proposed rate
10 increase.
11 Q.Please describe Avista Utilities' demd~side
12 magement (DSM), or energy efficiency, programs.
.13
14
A.The Company's innovative Energy Efficiency
Tariff Rider is celebrating its fourteenth anniversary.
15 The tariff rider, the country's first distribution charge
16 to fund DSM and now replicated in many other states, has
17 provided consistent funding for the delivery of energy
18 efficiency services. Company witness Mr. Folsom provides
19 more detail about Avista Utilities' energy efficiency
20 services.
21 Q.Please describe the recent resul ts of the
22 Comany's Project Share efforts?
23 A.Proj ect Share is a communi ty- funded program
24 Avista sponsors to provide one-time emergency support to
25 families in the Company's region. Avista customers and.
247 KopCZYnski, Di 11
Avista Corporation
shareholders help support the fund with voluntary.1
2
3
contributions that are distributed through local community
action agencies to customers in need.Grants are
4 available to those in need without regard to their heating
5 source.. As of Novemer 2008 Avista Utilities' customers
6 donated $219,346 on a system basis, of which $67,468 was
7 directed to Idaho Community Action Agencies. In addition,
8 the Company contributed $74,781 to Idaho customers in
9 2008.
10
11
Q.Does the Comany offer a bill-averaging program?
A.Yes. Comfort Level Billing helps smooth out the
12 seasonal highs and lows of customers' energy usage and
13 provides the customer the option to pay the same bill.14 amount each month of the year.This allows customers to
15 more easily budget for energy bills and avoid higher
16
17
winter bills.This program has been well-received by
participating customers.Over 16,684, or 12%, of Idaho
18 electric and natural gas customers are on Comfort Level
19 Billing.
20 In addition,the Company's Contact Center
21 Representatives work with customers to set up paYment
22 arrangements to pay energy bills.In 2008, 32,228 Idaho
23 customers were provided with over 85,711 such paYment
24 arrangements.
25.
248 Kopczynski, Di 12
Avista Corporation
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Q. Please sumrize Avista's CARS program.
A.' In Idaho, Avista is currently working with over
3 1,255 special needs customers in the CARES program.
4 Specially-trained representatives provide referrals to area
5 agencies and churches for customers with special needs for
6 help with housing, utilities, medical assistance, etc. In
7 its comments in Case No. GNR-U-08-01, the I PUC Staff
8 "recommends that all utilities implement case management
9 programs if they have not already done so."
10 Q.Have these programs helped mitigate the impact
11 on customers in need?
12 A.Yes. Through these programs, the Company works
13 to build lasting ways to ease the burden of energy costs.14
15
for customers that have the greatest need.
In the 2007/2008 heating season,10,125 Idaho
16 customers received $2,814,506 in various forms of energy
17 assistance (Federal LIHEAP program, Project Share, and
18 local community funds). On September 30, 2008, President
19 Bush signed legislation that provides $5.1 billion for the
20 Low Income Home Energy Assistance Program (LIHEAP) for the
21 2008/2009 heating season. This increased funding will
22 serve an addi tional 2 million households and raise the
23 average grant from $355 to $550 and also allows states to
24 carryover any funds remaining to next years heating
25 season. Idaho's share of the LIHEAP funding was increased.
249 KopczYnski, Di 13
Avista Corporation
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.
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from $12,376,000 to $26,969,000. This bill also provides
increased funding for weatherization assistance programs.
These programs and the partnerships we have formed have
been invaluable to customers who often have nowhere else
to go for help.
Q.this conclude your pre-filed directDoes
testimony?
A. Yes.
250 KopczYnski, Di 14
Avista Corporation
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I. :INTRODUCTION
Q.Please state your na, emloyer an business
3 address.
4 A.My name is Scott J. Kinney.I am employed by
5 Avista Corporation as the Director of Transmission
6 Operations.My business address is 1411 East Mission,
7 Spokane, Washington.
8 Q.Please briefly describe your education backgroun
9 and professional experience.
10
11
A.I graduated from Gonzaga University in 1991 with
'a B. S . in Electrical Engineering.I am a licensed
12 Professional Engineer in the State of Washington. I joined
13 the Company in 1999 after spending eight years with the.Bonneville Power Administration.I have held several14
15 different positions in the Transmission Department.I
16 started at Avista as a Senior Transmission Planning
17 Engineer.In 2002, i moved to the System Operations
18 Department as a supervisor and support engineer. In 2004,
19 i was appointed as the Chief Engineer, System Operations.
20 In June of 2008 I was selected to my current position as
21 Director of Transmission Operations.
22
23
24
Q.What is the scope of your testimony?
A.My testimony describes Avista' s pro forma period
transmission revenues and expenses.I also discuss the
25 Transmission and Distribution expenditures that are part of.
251 Kinney, Di 1
Avista corporation
.the capital additions testimony provided by Company witness1
2
3
Mr. Dave DeFelice, as well as the Company's Asset
Management Program expenses.Company witness Ms. Andrews
4 incorporates the Idaho share of the net transmission
5 expenses,the transmission and distribution capital
6 addi tions, and the Asset Management Program O&M expenses
7 proposed in this case.
8
9
10
Q.Are you sponsoring any exhibits?
A.Yes. I am sponsoring Exhibit 8, Schedules 1 and
2.Schedule 1, provides the transmission pro forma
11 adjustments and Schedule 2, includes the Asset Management
12 Program Model.
.13
14
II. PRO FORM TRASMISSION EXPENSES
Q.Please describe the pro form transmssion
15 expense revisions included in this filing .
16 A.Adjustments were made in this filing to
17 incorporate updated information for any changes in
18 transmission expenses from the October 2007 to September
19 2008 test year to the July 2009 to June 2010 Pro forma
20 period.Each expense item described below is at a system
21 level, with the exception of the $71,000 Grid West
22 adjustment which is Idaho only, and is included in Exhibit
23 8, Schedule 1.
24 Northwest Power Pool (NWPP) - Avista pays its share
25 of the NWPP operating costs. The NWPP serves the utili ties.
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in the Northwest by providing regional transmission
planning, coordinated transmission operations, and Columia
3 River water coordination. There is no anticipated change
4 in NWPP costs in the pro forma period compared to the
5 2007/2008 test year actual expense of $31,000.
6 Colstrip Transmission - Avista is required to pay its
7 portion of the O&M costs associated with the Colstrip
8 transmission system pursuant to the joint Colstrip
9 In accordance wi th Northwes tern Energy's (NW)contract.
10 proposed Colstrip transmission plan provided to the
11 Company, NW will bill Avista $508,000 for Avista' s share
12 of the Colstrip O&M expense during the pro forma period.
13 This is a decrease of $82,000 from the actual expense of
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$590,000 incurred during the test year.
ColumiaGrid (RTO Development)In 2006, Avista
16 elected to fund the ColumiaGrid RTO development effort.
17 ColumiaGrid is a regional organization whose purpose is to
18 enhance transmission system reliability and efficiency,
19 provide cost-effective regional transmission planning,
20 develop and facilitate the implementation of solutions
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and expansion of theimprovedrelatingtouse
transmission system,reduceinterconnected Northwest
23 transmission system congestion, and support effective
24 market monitoring within the Northwest and the entire
25 Western interconnection.Under the amended ColumiaGrid
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funding agreement signed Septemer 1, 2006, Avista was
responsible for a total of $518,000, which represents
3 Avista' s share of the ColumiaGrid operating costs from
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Prior to the amended2006 through August 31, 2008.
agreement, Avista paid $104,000 of these costs.The
6 remaining balance ($414,000) was accrued over the remaining
7 20 months of the agreement at a monthly rate of $20,720.
8 Avista signed a 2 year general funding extension in
9 Under the new agreement Avista pays itsSeptember 2008.
10 share (lO. 03%) of the general ColumiaGrid expenses on a
11 Based on information provided bymonthly basis.
12 ColumiaGrid, Avista expects to pay a monthly fee of
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Therefore, the$20,000 though the 2 year extension.
ColumiaGrid cost for the pro forma period is anticipated
15 to be approximately $240,000 annually, which is $22,000
16 more than the actual costs of $218,000 paid during the test
17 period.
18 ColumiaGrid Planning - An additional service being
19 provided by ColumiaGrid is regional planning and
20 expansion. A functional agreement was developed and filed
21 with the Federal Energy Regulatory Commission (FERC) on
22 February 2, 2007 and approved on April 3, 2007.The
23 agreement does not have a termination date and funding is
24 on a two-year cycle with provisions to adjust for
25 Funding is based on a fixed amount, plus ainflation.
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portion is based on Avista' s load ratio compared to the
other mÉmers.ColumiaGrid provided the Company with
3 anticipated costs of $15,000 per month in the pro forma
4 period to support the ColumiaGrid planning effort going
5 This equates to $l80, 000 during the pro formaforward:
6 period, which is $76,000 over the test year actual costs.
7 ColumiaGrid Developmental and Staffing Reliability
8 Functional Agreement - During 2007 and 2008 ColumiaGrid
9 began an effort to evaluate opportunities to improve or
10 enhance reliability in theColumiaGrid footprint.This
11 effort included expanding the existing regional coordinated
12 evaluating combiningoutagemanagementprocess,
13 transmission control centers into a consolidated control
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center, improved system modeling, and exploring new market
products.The ColumiaGrid members agreed to fund this
evaluation effort through the end of 2008.The remaining
17 work associated with this project has been rolled into the
18 general funding agreement so Avista will not incur any
19 costs associated directly with this effort during the pro
20 Avista did fund $45,000 of this effort informa period.
21 the test year.
22 ColumiaGrid Open Access Same-Time Information System
23 A new service currently being developed by(OASIS)
24 ColumiaGrid and its memers is the development of a common
25 Open Access Same-Time Information System (OASIS).This
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service would provide transmission customers the ability to
purchase transmission capacity from all ColumiaGrid
3 members from one common OASIS site instead of having to
4 purchase transmission from each memer individually.The
5 ColumiaGrid members have signed a contract to evaluate and
6 develop this service. Avista' s portion of the development
7 cost is expected to be $100,000 during the pro forma
S period. Avista didn' t have any costs associated with this
9 effort during the test period.
10 Grid West (ID Direct)Included in transmission
11 expense is an annual amount of $71,000 to recover costs
12 associated with Grid West (and its forerunner, RTO West).
13 Avista signed an initial funding agreement in 2000, as did.14 all other Pacific Northwest investor-owned electric
15 utili ties, to provide funding for the start-up phase of
16 Grid West (then named "RTO West"). Grid West had planned
17 to repay the loans to Avista and other funding utilities
is through surcharges to customers once it became operational.
19 With the dissolution of Grid West, this repaYment did not
20 occur. As a result, Avista filed an application with the
21 Commission to defer these costs. The Commission approved,
22 on October 24, 2006, in Order No. 30151, the Company's
23 request for an order authorizing deferred accounting
24 treatment for loan amounts made to Grid West. In its Order
25 the IPUC found these costs to be "prudent and in the public.
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interest" and required the Company to begin amortization of
the Idaho share of the loan principal ($422,000) beginning
3 January 2007, for five years. During the pro forma period
4 Avista will amortize a total of $71,000 associated with
5 Grid West development costs.
6 Electric Scheduling and Accounting Services -The
7 $55,000 decrease in the pro forma period compared to test
8 year expense for electric scheduling and accounting
9 services is a result of continued reductions in services
10 provided by third party vendors.These services are no
11 longer required because of the development of an internal
12 accounting program and the development of a regional
13 transmission interchange tool by the Western Electricity.14 Coordinating Council (WECC). These new applications replace
15 the services provided by third parties.
16 Grant County Agreement - This will be discussed in
17 more detail in conjunction with the Seattle and Tacoma
18 revenues associated with the Main Canal and Sumer Falls
19 Projects.This agreement expired in October 2007 so no
20 additional costs will be incurred in the pro forma period.
21 In the test year Avista paid Grant County $51,000 per this
22 agreemen t .
23 OASIS Expenses The Open Access Same-Time
24 Information System (OASIS) expenses are associated with
25 travel and training costs for transmission pre-scheduling.
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and OASIS personnel.This travel is required to monitor
and adhere to the NERC reliability standards and FERC OASIS
3 requirements. The costs associated with OASIS expenses in
4 the pro forma period is $3,000 more than the test year.
5 The increase is a result of training required for a new
6 employee who replaced a retired employee in October 2008.
7 Power Factor Penalty - The power factor penalty costs
8 are associated with Bonneville Power Administration's (BPA)
9 General Transmission Rate Schedule.BPA charges a power
10 factor penalty at all interconnections with Avista that
11 exceed a given threshold for reactive power flow during the
12 month. If the reactive flow from BPA's transmission system
13 into Avista' s system or from Avista' s system to BPA's.14 system exceeds a given threshold then BPA bills Avista
15 according to its rate schedule. The charge includes a 12
16 month rolling ratchet paYment. Avista currently pays BPA a
17 power factor penalty at several interconnections.Avista
18 paid BPA a total of $178,000 during the test year and
19 anticipates paying a similar amount in the pro forma period
20 based on the ratchet clause in the rate schedule.
21 WECC - System Security Monitor & WECC Administration
22 and Net Operating Committee Systems - The total WECC fees.
23 have and will continue to increase from year to year. The
24 increase is driven primarily by compliance with mandatory
25 national reliability standards.WECC is responsible for.
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monitoring and measuring Avista's compliance with the
standard.s and therefore has substantially increased its
3 staff and other resources to meet this FERC requirement.
4 WECC is just beginning to develop its 2010 budget, so 2009
5 actual fees will be used for the pro forma period.The
6 WECC fees are paid in the first part of January every year.
7 WECC System Security Monitor fees in 2009 are $159,000
8 compared to test year fees of $171,000.This slight
9 decrease is the result of the completion of a significant
10 effort with regards to regional reliability coordination in
11 2008. The WECC Administrative and Net Operating fees have
12 been increased from $282,000 in 2008 to $329,000 for 2009.
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WECC - Loop Flow -LOOp Flow charges are spread
across all transmission owners in the West to compensate
15 utilities that make system adjustments to eliminate
16 transmission system congestion throughout the operating
17 year. Loop Flow charges can vary from year to year since
18 charges are dependent on transmission system usage and
19 congestion.Therefore a five year average is used to
20 determine future Loop Flow costs. The Loop Flow charge in
21 the pro forma period is expected to be $26,000.This is
22 $10,000 higher than actual test year charges of $16,000.
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III. PRO FORM TRASMISSION RES
Q.Please describe the pro form transmssion
3 revenue revisions included in this filing.
4 A.Adjustments were made in this filing to
5 incorporate updated information for any changes in
6 transmission revenue from the 2007/2008 test year compared
7 to the 2009/2010 Pro forma period.Each revenue item
8 described below is at a system level and is included in
9 Exhibi t 8, Schedule 1.
10 Borderline Wheeling - The Borderline Wheeling revenue
11 in the pro forma period is set at $5,354,000, which is a
12 three year average of the 2006, 2007, and 2008 actual
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revenue levels.Actual test year revenue was $5,375,000.
Avista typically uses a five year average of actual annual
15 revenue to estimate future Borderline Wheeling revenue.
16 This helps levelize the revenue requirement since it is
17 based on load demand that is sensitive to temperature
18 variation from year to year.For this case Avista is only
19 using a three year average since 2006, 2007 and 2008 are
20 the only years operating under new contracts signed with
21 BPA.The new Borderline Wheeling revenue methodology is
22 based on a Load Ratio Share1, which is quite different than
i Load Ratio Shae is the ratio of a Tranmission Cutomer's Network Load to the Tranmision
Provider's total load calculate on a rolling twelve-month basis..
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the previous revenue calculation under the old contracts.
Under the new contracts, BPA, as the network customer, will
3 pay a monthly demand charge, which will be determined by
4 multiplying its Load Ratio Share times one twelfth (1/12)
5 of the Transmission Provider's annual transmission revenue
6 requirement.
7 Seattle and Tacoma Revenues and Expenses Associated
8 with the Main Canal and Sumer Falls Projects - In March
9 of 2006, Seattle and Tacoma purchased interim long-term
10 firm point-to-point transmission service from Avista under
11 the Open Access Transmission Tariff to move generation from
12 their Main Canal and Sumer Falls facilities to their load.
These interim point-to-point transmission contracts.13
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replaced expired long-term contracts. The transmission was
purchased from April 2006 through October 2007.Avista
16 collected $128,000 in October 2007 under these contracts
17 and in turn paid $51,000 to Grant County PUD for use of its
18 system to transfer the entire output of the Main Canal and
19 Sumer Falls projects. The interim contracts were meant to
20 give Seattle and Tacoma time to build new transmission
21 facilities to bypass Avista and connect directly to BPA.
22 Pursuant to negotiations among Seattle, Tacoma, Grant
23 County PUD, Grand Coulee Project Hydroelectric Authority
24 and Avista, Seattle and Tacoma decided not to bypass
25 Avista' s transmission system. The parties agreed instead,.
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to a series of long term agreements with service to
commence March 1, 2008. Seattle and Tacoma have signed
3 similar contracts with Grant County PUD so Avista will not
4 incur any of the transmission expenses with Grant County
5 PUD that it did in 2007.Under the new Main Canal
6 agreement Avista charges Seattle and Tacoma during the
7 eight months the Main Canal project runs (March-October)
8 and only for that output not used for local load service.
9 The estimated revenue from Seattle and Tacoma for Main
10 Canal transmission usage will be $193,000, which is $38,000
11 more than collected during the test year.Under the new
12 Sumer Falls agreement, Seattle and Tacoma only use a
13 portion of Avista' s Stratford Switching Station and are.14
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charged a use-of-facilities fee based upon this limited
use.The estimated revenue from Seattle and Tacoma for
16 Sumer Falls during the pro forma period is $74,000, which
17 is $31,000 higher than actual test year revenue of $43,000.
18 The increase revenue from these two contracts in the pro
19 forma period compared to the test year is a result of
20 additional transmission usage by Seattle and Tacoma.
21 Grand Coulee Pro; ect Revenue The Grand Coulee
22 Project revenue is a result of a new contract signed in
23 March 2006 with the project owner for a fixed dollar
24 amount, replacing the previous contract which expired in
25 October 2005. The new contract results in monthly revenue.
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of $673 or annual revenue of $8,100 during the pro forma
period, which is the same as the test year.
3 OASIS Non-firm and Short-term firm Wheeling Revenue -
4 OASIS is an acronYm for Open Access Same-time Information
5 System.. This is the system used by utility transmission
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departments for purchasing and scheduling available
transmission for other utilities and independent
8 generators. OASIS revenues are revenues received from the
9 sale of transmission capacity to third parties, for
10 transmission above and beyond that needed by Avista to
11 serve native load.These revenues are credited back to
12 customers in a rate case, such as this one, to offset a
13 portion of the overall cost of transmission..14 Because these revenues vary year to year depending on
15 electric energy market conditions and available
16 transmission capacity (ATC) on adjacent utility systems,
17 Avista has, in previous rate cases, used the most recent
18 five-year average as being representative of future
19 expectations unless there are known events or factors that
20 occurred during the period that would cause the average to
21 not be representative of future expectations.In 2004,
22 there were some unusual events that caused Avista's OASIS
23 revenues ($5,475,000) to be significantly higher than the
24 other test years.
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The Bonneville Power Administration (BPA) had several
500 kV lines out of service for rebuild proj ects, which
3 resulted in a significant increase in Avista' s transmission
4 sales in 2004. During 2004 BPA was constructing' a new SOO
5 kV line from Bell substation in Spokane to Grand Coulee Dam
6 in central washington, installing fiber optic cable on
7 existing transmission lines,and installing new and
8 upgrading existing series capacitor banks on four of its
9 area SOO kV lines as part of the West of Hatwai
10 reinforcement proj ect .This construction resulted in
11 mul tiple prolonged transmission outages that significantly
12 reduced the BPA ATC on critical transmission paths from
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eas tern Montana.Avista owns rights and facilities in
these same transmission paths so Avista experienced a
15 significant increase in transmission sales and revenues
16 during the BPA outages.
17 Therefore, Avista did not include the 2004 revenue in
18 the calculation of the five-year average revenue. Avista
19 calculated the pro forma OASIS revenue based on revenue
20 from years 2003, 2005, 2006, 2007, and 2008. The resulting
21 average revenue is $3,310,000, which is $201,000 higher
22 than the test year actual revenue of $3,109,000.
23 Dry Gulch Revenue Dry Gulch revenue has been
24 adjusted to $269,000 for the pro forma period, which is an
25 $11,000 increase from the test year actual revenue of.
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$258,000.The current methodology used to forecast Dry
Gulch revenue is a five-year average of actual revenue. A
3 five-year average is used since the revenue can vary from
4 year to. year. The revenue is calculated using a 12-month
5 rolling ratchet based on monthly peak demands. Load peaks
6 are very sensitive to temperatures, which vary from year to
7 year.
8 PP&L Series Cap - 1978 - PP&L Series Cap revenue was
9 reduced from $9,000 in the test year to $0 in the pro forma
10 period since the 20 year amortization of the original
11 contract expires in June 2009. In 1989 Pacificorp paid the
12 company a lump sum of $178,222 in lieu of annual payments
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provided for under the original agreement.The lump sum
payment was amortized at $781 per month from August 1990
15 through June 2009.
16 Spokane Waste to Energy Plant -No adjustments to
17 Spokane Waste to Energy Plant revenue of $160,000 were made
18 for the pro forma period compared to the 2007 test year.
19 This revenue is the result of a long-term transmission
20 interconnection agreement with the City of Spokane.The
21 contract expires in February 2011.
22 Vaagen Wheeling - Vaagen Wheeling revenue was reduced
23 slightly to $112,000 for the pro forma period compared to
24 test actual revenue of $116,000. A five-year average is
25 used to determine the pro forma period revenue since.
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revenue can fluctuate year to year depending upon
transmission usage.
Northwestern Energy (NW)The revenue of $42,000
4 from NW in the test year was a result of a load following
5 contract that Avista signed in 2005 with NW.Under the
6 contract Avista provides up to 15 MW of energy to NW to
7 help them match hourly fluctuations in loads and resources.
8 This contract also included the purchase of firm
9 Since the contracttransmission capacity from Avista.
10 expired in Novemer of 2007 there isn' t transmission
11 revenue associated with the contract in the pro forma
12 period.
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Forfeited Deposits - Avista was reimbursed $40,000
period to conduct generationduringthetest
interconnection planning studies.Avista is required to
based on generationdetermineimpactssystem
17 interconnection requests to implement generation within its
18 Any potential customer can ask for aservice terri tory.
19 system evaluation to be performed to determine the impacts
20 of connecting a new generator to the Avista system.The
21 potential customers must reimburse Avista for these system
22 Since Avista can' t predict when these requestsstudies.
23 will occur, the Company is not forecasting any collection
24 of interconnection study fees in the pro forma period.
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iv.TRASMISSION AN DISTRIBUTION CAITAL PROJECTS
Q.Please describe the Comany's capital
3 transmission projects in 2009?
4 A.In 2007 the Company completed its 5-year (2003-
5 2007) $136.4 million transmission upgrade project that
6 significantly improved the infrastructure of the 230 kV
7 transmission system. With the completion of these projects
8 the transmission proj ect focus has shifted to improving the
9 115 kV transmission system to meet capacity needs,
10 eliminate thermal loading issues, replace deteriorated
11 equipment, and meet mandatory national reliability standard
12 requirements.Avista will need to continue to invest in
13 its transmission system going forward to maintain reliable.14 customer service and meet the reliability standards.A
15 recent report prepared by The Brattle Group for the Edison
16 Foundation describes the future investment challenge that
17 is facing the utility industry.The report describes how
18 utilities will need to continue replacement of aging
19 equipment while construction costs continue to increase.
20 In order to integrate renewable energy alternatives and
21 incorporate intelligent grid controls utilities will be
22 required to increase capital spending on both Transmission
23 and Distribution systems.
24 The major capital transmission costs (system) for
25 projects to be completed in 2009 are approximately $15.07.
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million tor specific transmission projects and transmission
system equipment replacement projects.The specific
3 transmission projects scheduled for 2009 completion will
4 cost $9.18 million and include:
. Lolo Substation ($2.05 million): This project involves
the rebuild of the existing Lolo substation to
increase the capacity of the substation bus, breakers,
and supporting equipment to match the upgraded area
transmission lines. The new Lolo substation design
significantly improves reliability and operatingflexibili ty. The substation rebuild is being
constructed in three phases. Phase 1 was completed in
2007 and Phase 2 is anticipated to be completed byDecemer of 2009. Approximately $0.80 million of work
was completed in 2008 and will be transferred to plant
in 2009 with the additional estimated amount of $1.25million.
. Spokane/Coeur d' Alene area relay upgrade phase 2
($1.25 million): This project involves the
replacement of older protective 115 kV system relays
wi th new micro-processer relays to increase system
reliability by reducing the amount of time it takes to
sense a system disturbance and isolate it from the
system. This is a five year project and is requiredto maintain compliance with mandatory reliabilitystandards.
. Power Circuit Breakers ($0.54 million): The Company
transfers all circuit breakers to plant upon receiving
them. In 2009 the Company will receive and replace 4
circui t breakers in its sys tem.
. SCADA Replacement ($0.74 million): The System Control
and Data Acquisition (SCADA) system is used by the
system operators to monitor and control the Avista
transmission system. The SCADA system will be
upgraded in 2009 to a new version provided by our
SCADA vendor. Several Remote Terminal Units (RTUs)
located at substations throughout Avista' s service
territory will also be replaced. The RTUs are part of
the transmission control system.
. Noxon-Pine Creek Fiber ($0.65 million): This project
is required to reinforce the optical fiber wire
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supported by the Noxon-pine Creek 230 line. This line
routes through the mountains of north Idaho and is
subjected to severe winter weather. Operational
history has demonstrated a need to reinforce the
communication circuit. This communication circuit is
part of the Noxon/Cabinet WECC certified RAS scheme
anq is required to meet reliability standards.
. System Replace/install Capacitor Bank ($0.80 million) :
This proj ect includes the construction of a 115 kVcapaci tor bank at Airway Heights ($0.60 million) to
support local area voltages during system outages.
The project is required to meet reliability compliance
and provide improved service to customers. Another
$0.20 million will be spent to replace leaking or old
capacitors on the Avista system.
. Benewah-Shawnee 230 kV Line Construct ($0.56 million) :
This work is necessary to increase separation between
the 230 kV and 115 kV conductors on this double
circui t line. The lines have contacted each other
during high winds resulting in line outages. In
addi tion to line work to increase phase clearance,
Avista plan to install a Hathaway-traveling wave
monitoring system to allow better accuracy of phase to
phase contacts. The 230 kV line was constructed to
meet reliability standard requirements.
. Mos230-Pullman 115 Reconductor ($0.59 million): The
transmission line is being upgraded from 1/0 Copper to
556 kcm Aluminum (100 MVA-Sumer) to mitigate thermaloverloads experienced during heavy sumer load
conditions. The line upgrade will improve load
service between Moscow and Shawnee.
. Burke 115 kV Protection and Metering ($0.53 million) -
This proj ect includes upgrading the Burke interchange
meters as well as 115 kV line relaying for the Burke-
pine Creek #3 and #4 lines. This proj ect is required
to meet reliability compliance standards. The
estimated cost of the relay upgrade is for $400,000
and the metering upgrade is estimated at $125,000.
. Beacon Storage Yard Oil Containment ($0.53 million):
The Beacon Storage Yard is a location where circuit
breakers and power transformers are staged for
rotation into existing substations or for new
construction. This site is near the Spokane River and
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this proj ect work will provide an oil containment
system to protect the local environment.
. The remaining transmission specific projects ($0.94
million total) being constructed in 2009 are smallerproj ects, including a line reconfiguration to provide
back up service, minor work associated with Colstrip
transmission, and re-insulating a 230 kV line due to
failing insulators. These smaller proj ects are
required to operate the transmission system safely andreliably.
The Company will also spend approximately $5.89 million in
14 transmission system equipment replacements associated with
15 storm damage or aging/obsolete equipment.A brief
16 description of the larger projects included in these
17 replacement efforts are given below.
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. Transmission Minor Rebuilds ($1.07 million): These
projects include minor transmission rebuilds as a
result of damage caused by storms, wind, fire, and thepublic.
. System Rebuild Transmission Condition ($0.93
million) : This proj ect includes transmission lines
that are determined to have a high probability of
falling down or be a high reliability risk and need to
be rebuilt during 2009. For example one specific
project identified for a rebuild in 2009 includes
sections of the Addy-Gifford 115 kV line.
. Interchange and Borderline Metering upgrades ($0.64
million): Interchange metering upgrades are required
for all of our interchange points with BPA and other
adjacent utilities. In 2009, we will complete
metering upgrades at Westside, Warden, and Noxon
Substations. Borderline metering upgrades are
required for all loads within Avista's Balancing
Authority. In 2009, we will complete our upgrades at
Mead and Noxon (230-13 kV) as well as one additional
upgrade at either Deer Park, Priest River, Loon Lake,
Spirit, or Wilbur.
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. pine Creek - Replace 115 kV Circuit Switcher & Cap
Bank ($0.35 million): The project scope and
preliminary engineering design work for this project
-was started in 2008 and included replacing the circuit
swi tcher and one 13 kV recloser due to equipment age.
After further investigation the project was expanded
to replace the other two 13 kV reclosers, the cap
bank, deteriorated station control wiring, and removal
of the small panel house including the obsolete RTU.
. Replacement Programs ($2.23 million): Avista has
several different equipment replacement programs to
improve reliability by replacing aged equipment that
is beyond its useful life. These programs include
transmission air switch upgrades, arrestor upgrades,
restoration of substation rock and fencing, recloserreplacements, replacement of obsolete circui tswi tchers, substation battery replacement, porcelain
cutout replacement, high voltage fuse upgrades, and
replacement of fuses with circui t swi tchers . All of
these individual projects improve system reliabilityand customer service.
Q.Please discuss the national reliability
standards?
A. The North American Electric Reliabili ty
27 Corporation (NERC) has developed national reliability
28 standards for utilities to follow to ensure interconnected
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30 upgrade projects in 2002, compliance with these standards
system reliability.When Avista started its transmission
31 was voluntary. The Energy Policy Act of 2005 required the
32 transition of the standards from voluntary to mandatory.
33 Beginning June 2007 the standards became mandatory and non-
34 compliance may result in monetary penalties.
35 The reliability standards include several transmission
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37 standards require utilities to plan and operate their
planning and operating requirements.The planning
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customers or impacting neighboring utilities for the loss
of transmission facilities.The transmission system must
4 be designed and operated so that the loss of up to two
5 facilities simultaneously will have no impact to the
6 interconnected transmission system.These requirements
7 drove the need for Avista to invest in its transmission
8 system.
9 Q.Please describe the Comany's distribution
10 projects in the State of Idaho that will be comleted in
11 2009?
12 A.Distribution Projects in Idaho (including
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transformation) for 2009 total $10.76 million.These
projects are necessary to meet capacity needs of the system
15 and rebuild aging distribution substations and feeders.
16 The following projects make up the $10.76 million.
17 . Plumer Substation Rebuild ($1. 53 million): This
18 project is required to replace the existing19 deteriorated wood substation, and increase the20 transformer capacity to meet existing system capacity21 needs. These costs don' t include the cost of the22 transformer, which was transferred to plant in 2008.
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24 . Idaho Road 115 kV Substation and Rathdrum 115-13 kV25 Sub Increase ($4.90 million) : These projects26 (including transformer costs) involve the construction
27 of the new Idaho Road 1l5-13 kV substation ($2.8728 million) and the addition of a second transformer and29 feeder at the Rathdrum substation ($2.03 million) to30 meet existing capacity needs in Post Falls and
31 Rathdrum Idaho. When completed these projects will32 provide improved service reliability to existing33 cus tomers .
34.
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. Wood Sub Rebuilds ($3.60 million) : Two wood
substations will be rebuilt in 2009. Deary l15-24 kV
Substation ($2.05 million including the transformer)and Craigmont 115-13 kV Substation ($1. 45 million)
will both be completely rebuilt in 2009. Both of
these substations are over 50 years old and have
reached the end of their useful lives. In addition,
the Deary transformer is in need of replacement due to
end of life and bushing related issues, so the
substation rebuild is in conjunction with thetransformer replacement ($0.45 million) . An
addi tional $100,000 for other system wood substations
that require timber replacement is also included in
this rebuild effort.
. Distribution Feeder Reconductor Projects ($0.73
million): These projects involve the reconductor of
sections of four feeders in Idaho. The feeders are
required to be reconductored to eliminate thermal
loading issues and improve service reliability to
existing customers during normal and outageconditions.
The Company also will spend approximately $25.27
million (system) in equipment replacements and minor
26 rebuilds associated with aging distribution equipment
27 discovered inspections,feeders with poorthrough
28 reliability performance, replacements from storm damage, or
29 relocation of feeder sections resulting from road moves. A
30 brief description of the proj ects included in these
31 replacement efforts is given below.
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33 . Electric Distribution Minor Blanket Projects ($7.9234 million): This effort includes the replacement of35 poles and cross-arms on distribution lines in 2009 as36 required, due to storm damage, wind, fires, or37 obsolescence.
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39 . Capital Distribution Feeder Repair Work ($4.1040 million): This work is to be done in conjunction with.
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the wood-pole management program. As feeders are
inspected as part of the wood-pole management program,
issues are identified unrelated to the condition of
the pole. This proj ect funds the work required to
resolve those issues (i.e. leaking transformers,transformers older than 1964, failed arrestors,missing grounds, damaged cutouts) .
. Wood Pole Replacement Program ($3.70 million): The
distribution wood-pole management program is a
strength evaluation of a certain percentage of the
pole population each year. Depending on the test
results for a given pole, that pole is either
considered satisfactory, reinforced with a steel stub,
or replaced.
. Electric Underground Replacement ($3.16 million):
Replace high and low voltage underground cable asrequired in 2009, due to cable failure orobsolescence.
. T&D Line Relocation ($2.30 million): Relocation of
transmission and distribution lines as required due to
road moves.
. Failed Electric Plant ($1.99 million): Replacement of
distribution equipment throughout the year as required
due to equipment failure.
. System - Dist Reliability - Improve Worst Feeders
($1. 10M total, $350K in Idaho): Based on a
combination of reliability statistics, includingCAIDI, SAIFI, and CEMI (Customers Experiencing
Mul tiple Interruptions), feeders have been selected
for reliability improvement work. This work is
expected to improve the reliability of these feeders.
. Open Wire Secondary ($1.0 million) - Avista has over
60 miles of secondary districts that consist of 2 120
volt to ground uninsulated (open wire) conductors
installed between poles and served by one overheadtransformer. These service installations wereinstalled in the 1950 i sand 1960 's. When there is
contact across the 120 volt conductor and the ground
wire due to trees or other causes, the conductor fails
resulting in customer outages. This project replaces
the open wire conductor with insulated conductor and
reduces the length of some of the secondary circuits.
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This effort should reduce the numer and length ofoutages and improve customer service.
V. AVISTA'S ASSET MAGEM. PROGRA
Q.Please provide additional backgroun to Avista's
6 continuing investment in its transmission an distribution
7 systems?
8 A.Like most U.S. utilities, after World War II,
9 Avista' s growth required installing or updating equipment
10 to meet rising electrical demand. Substations were built or
11 modified to meet increasing loads. The transmission system
12 expanded to bring new generating plant output to population
13 centers. Distribution systems grew and voltage levels were
14 increased to meet new housing and industrial needs..15 Avista's installed equipment is aging, and more
16 components are reaching the end of their life. Equipment
17 has become obsolete, and manufacturers no longer support
18 the aged equipment or produce replacement parts, which
19 makes it impractical to rebuild the equipment. Recognizing
20 the increasing cost of aging equipment failure, Avista
21 launched its Asset Management effort in March 2004.
22 Q.Please describe the Asset Magement mission and
23 process.
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A.Avista's Asset Management (AM) program manages
key electric transmission and distribution assets
26 throughout their life to provide the best value for our.
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customers. By minimizing life cycle costs and the cost per
kilowatt-hour to generate and deliver energy, we're able to
3 maximize system reliability and value for our customers.
4 The Asset Management process combines technology and
5 information in a manner that integrates data from a myriad
6 of sources into a comprehensive plan that maximizes the
7 value of capital assets.The process provides a
8 replacement or maintenance program that minimizes life
9 cycle costs and maximizes system reliability.
10 Technical experts evaluate each asset and develop a
11 comprehensive Asset Management Model. Available data is
12 examined and where it is not available, expert opinion from
13 the team fills in the gaps. Exhibit 8, Schedule 2 shows the.14 steps in the process for developing an Asset Management
15 Plan. The foundation for the plan involves determining the
16 future failure rates and impacts to the environment,
17 reliability, safety, customers, costs, labor, spare parts,
18 time, and other consequences.The fai lure model then
19 becomes the baseline to compare all other options. Given
20 this foundation, alternatives can be examined and evaluated
21 to define the optimal asset management plan.
22 Q.How has Avista implemnted and facilitated the
23 Asset Management process?
24 A.Avista has assigned two full-time engineers to
25 the formal Asset Management program. These individuals are.
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responsible for gathering information, prioritizing work
and executing efforts to best meet the Asset Management
mission.The engineers utilize a statistical Reliabiiíty
4 Centered Maintenance (RCM) software package to analyze
5 This software allows detailed analysis of thedata.
6 impacts of increased or decreased reliability based on
7 system configuration and component reliability.
8 Have an Avista Asset Management plans beenQ.
9 implemnted?
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Yes, several programs have been successfullyA.
implemented.Two of the successful programs underway are
12 Underground Cable Replacement and Wood Pole Management.
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underground Cable Replacement program hasThe
successfully reduced the numer of primary underground
15 distribution cable faults from 250 in 2004 to approximately
16 The replacement program eliminated180 events in 2007.
17 approximately 5,600 hours of outage time for our customers
18 and resulted in avoided costs impact of $175,000.For
19 2008, we were projected to have 550 faults prior to
20 starting this program and now we are on track to have less
21 than 150 faults by years end. This equates to avoided cost
22 The increased emphasis on cableimpact of $1,000,000.
23 replacement has stabilized the fault rate per mile of cable
24 This marks significant progressduring the past 4 years.
25 after a four-fold increase in the fault rate since 1992.
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The Asset Management team also studied the Wood Pole
Maintenance program.After completing an optimization
3 analysis and the revenue requirement model, the data
4 indicated that distribution poles should be inspected on a
5 20-year cycle and transmission poles inspected on a 15-year
6 cycle.
7 Under the new Wood Pole maintenance program Avista
8 tested twice as many Distribution poles in 2007 as in 2006.
9 For 2008 through November, we inspec ted over 11, 600
10 Distribution Wood Poles and over 2,500 Transmission Wood
11 Poles.Our annual goal is to inspect 12,000 Distribution
12 and 3,000 Transmission poles each year. As a result of the
13 2008 inspections, Avista reinforced 980 poles, replaced 432.14 poles, and replaced 950 cross-arms.The Operations and
15 Maintenance portion of the Avista rate request to support
16 Wood Pole maintenance work in 2010 totals $852,000
17 (system). This represents an increase of $207,000 (system)
18 above the 2007/2008 test year.
19 Q.Wht is the Comany's request with regards to
20 Asset Management capital expenditures and O&:M expenses?
21 A.Avista is not asking for any planned 2010 capital
22 Asset Management additions to be included in this case.
23 For Asset Management proj ects that require additional
24 O&M, proposed 2010 O&M expenses are $12,505,000 (system)
25 compared to 2007/2008 test year expenses of $7,896,000.
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(system) .This represents an increase of $4,609,000
(system), above the 2007/2008 test year included in this
3 rate case. As shown in Table 1 below, Asset Management O&M
4 additions have been divided into six major categories:
5 Substati~m,Distribution,Transmission,vegetation
6 Management, Wood Pole Management and Spokane Downtown
7 Network.Cost adjustments also include adjustments for
8 inflation of 6% to bridge the time between the test year
9 and 2010.
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Table 1:
.SubstationDistribution
Transmission
vegetation Management
Wood Pole Managemnt
Network
Total AdditionalRequested
Asset Maagement
Operations &: MaintenanceAmunt Above 2007/2008 Test period
(System) Pro form
$ 616,000
$ 458,000
$ 401,000
$ 2,813,000
$ 207,000
$ 114,000
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$4,609,000
Q.Please describe Avista's Substation Asset
13 Management Plan.
14 A.Avista operates 157 transmission and distribution
15 substations. A significant portion of the equipment and
16 substation structures are more than 40 years old and have
17 operated beyond normal industry expectations.This older
18 equipment has reached a point in its lifecycle where
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planned replacement or maintenance will add value to our
customers by improving reliability and safety, and avoiding
3 outage costs. Costs to support the Substation maintenance
4 work totals approximately $2,073,000 (system) in the 2010
5 pro forma period. This is an additional $616,000 compared
6 to the 2007/2008 test period.
7 The Substation plan includes:
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. Power Transformers: . More than 26% of Avista' s
Substation Transformers are over 40 years old.
These aging transformers need to be either
maintained or replaced depending on condition.
. Circui t Breakers: The Power Circuit Breaker Planhas been an ongoing and successful programmaintaining approximately 300 High Voltage Oil
Circuit Breakers prior to establishing an Asset
Management Program. However, Avista has not yet
reached the target of a 10 year Circuit Breaker
maintenance cycle and is currently at a 15 year
cycle. The requested increased funding will allow
more Circuit Breaker maintenance each year.
. Circuit Switchers: Avista uses 120 Circuit
Switchers to protect substation transformers at
smaller Substations as well as 115 kV substation
Capacitor Banks. Avista' s analysis indicates
periodic maintenance based on the age of the
Circuit Switcher should extend the life of thesedevices by 25% based on a graduated cycle plan
determined by age. It is anticipated that the
program will result in approximately $180,000 of
avoided outage related costs to our customers.
. Reclosers: The Recloser/Medium Voltage Circuit
Breaker plan covers about 415 substation and 145
Line Reclosers/Medium Voltage Circuit Breakers. Our
current maintenance practice strives to sustain theSubstation Reclosers/Medium Voltage Circuit
Breakers on a 10-year cycle and to refurbish any
failed or replaced ones to use as spares for futureneeds..
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. Rock and Fence: The Substation Rock and Fence plan
covers the maintenance and replacement of Rock andFence for Avista' s 166 substations. Avistaanticipates an average of 4 Substations will
require repairs to the fence or rock ground cover
in order to ensure safety by preventing publicaccess and maintain the required insulating
properties of the Substation Rock. O&M funding is
;increased by a relatively small amount for minor
repairs to Rock and Fence above current levels.
. Relavs: The Relay plan covers the maintenance and
replacement of over 6000 separate relay hardware
devices that provide protection for Avista' S
generation, transmission and distribution systems.
Regulatory requireménts for relay testing and
record keeping have increased in recent years as
part of new mandatory reliability standards.
Q. Please describe Avista' s distribution Asset
21 Management Plan.
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A.Avista's distribution system includes 324 feeders
and over 12,000 miles of conductors, poles, underground
cable, distribution transformers, and various other
25 distribution system components. Avista has developed
26 operations and maintenance plans for the distribution
27 system totaling approximately $569,000 for the 2010 Pro
28 forma period. This amount is $458,000 above that included
29 in the 2007/2008 test period.
30 The distribution plan includes:
31 . Animal Guards: Data shows that animals are the32 second-leading cause of outages at Avista, ranking33 second only behind weather, and accounting for 1934 percent of all outages. Outages caused by squirrels35 and birds are an increasing, on-going and36 persistent problem on the distribution system.37 Statistics indicate that 60 feeders were the38 subject of almost half of all animal-caused.
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outages. Four of those 60 most vulnerable feeders
were recently retrofitted with animal guards.
Animal-caused outages have decreased to almost zero
on all four feeders, compared to 10 or more per
month during warm weather in previous years. Avista
has included additional O&M funding to begin
implementing a four-year program to install animal
guards on the remainder of the 60 most vulnerablefeeders.
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. Underground Cable: Over 6 million feet of
unjacketed underground cable was installed prior to
1982 i it has been subject to a replacement programsince 1984. After 2008, there will be
approximately 750,000 feet of pre-1982 cable still
left to be replaced. Though primarily a capital
intensive program, there is some related
maintenance costs associated with undergroundcable.
. Exacter Testing: This is a new test using an
inexpensive method to detect distribution equipment
problems before they fail. The new method detects
radio frequency failure signatures of distribution
equipment and uses a library to identify the
problem. Using our Geographical Information
System, we can then identify the component and plan
the replacement prior to equipment failure. This
will add $30,000 to the 2010 budget.
Q. Please describe chages to Avista' s vegetation
33 Management Plan.
34 A.Avista's system includes over 12,000 miles of
35 distribution circuits and over 2,200 miles of transmission
36 lines that require vegetation management.Avista's
37 vegetation management work is almost entirely contracted
38 out. The primary contractor for this work is Asplundh Tree
39 Experts.Over the past few years, Avista's vegetation
40 management has experienced higher than anticipated rates of
41 inflation over 6% due to labor, fuel costs and equipment.
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Our goal is to clear 1,550 miles per year, whichcosts.
resul ts in a 5 yea~ cycle.
For the transmission system, three factors require -an
spending on vegetationincreasefromthecurrent
management.FERC Reliability Standard FAC-003-1 has
6 changed the way we manage the transmission system right of
7 ways for vegetation.vegetation line patrols have been
8 increased to an annual basis for all 200 kV and higher
9 vol tages. WECC has also applied these same requirements to
10 4 other lower voltage line identified as critical to grid
11 reliabili ty. These expanded requirements have expanded the
12 areas requiring action to include more difficult to access
13 portions of the right of way.These difficult access
14 portions have steep rocky hillsides and wet bottom draws
15 and require crews to hike in and cut the vegetation by
16 hand, often taking one to two weeks to clear one span. The
17 new regulations also require clearances to account more
18 stringently for line sag and sway necessitating clear
19 cutting timber through draws where trees have been left to
20 grow for the past 20 - 30 years. This work is very costly
21 and has added significantly to our anticipated costs.
22 The second factor is the change in access road
23 maintenance requirements included in updates of our Special
24 Use Permits with the Forest Service.This will require
25 Avista to spend more money annually to maintain roads on a
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planned basis. When combined with increase requirements to
patrol transmission lines by FERC and WECC requirements,
3 the roads will be used more frequently and must be
4 maintained more frequently.
5 The third factor driving the costs up has been a
6 higher than anticipated inflation rate of around 6% that is
7 Per FERC requirements, Avistaanticipated to continue.
8 inspects all 230kV transmission lines annually to identify
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In addition to the 230kVvegetation management needs.
transmission lines,Avista also patrols the ll5kV
11 transmission lines once every three years.
12 Along with increased requirements for the transmission
13 systems, the natural gas right-of-ways now require more
14 vegetation management to support leak surveys required by
15 CFR 49, Part 192.723 and washington State WAC 480-93-188 on
16 high pressure gas pipelines. Avista has 198 miles of high
17 pressure gas pipeline and our plan is to perform vegetation
18 management on a five year cycle for an average of 40 miles
19 per year.
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The Company plans to spend $8,390,000 in Operations
and Maintenance support of the gas,forfunding
vegetation managementdistributionandtransmission
programs.This is an increase of $2,813,000 above the
24 2007/2008 Operations and Maintenance spending for this
25 area.
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Q. Please describe Avista' s Transmission Asset
Management Plan.
A.The Avista transmission system is comprised of
4 over 2,300 miles of lines crossing an extreme variety of
5 terrain. The 976 miles of 230kV transmission system is
6 cri tical to serving Avista' s customers and to the stability
7 of transmission resources throughout the region. The 115kV
8 system, comprised of 1675 miles, serves Avista customers
9 and neighboring utilities throughout large portions of
10 Eastern Washington and Northern Idaho. Approximately 75% of
11 the transmission system components are over 35 years old.
12 A more rigorous inventory of the 115kV system is underway.
13 Preliminary results of this survey show over 20% of the.14 115kV system is pre-1930. Almost all Asset Management work
15 on the Transmission system is capital work, however, as
16 Asset Management completes more models in the future, some
i 7 O&M funding may be required to support future programs.
18 Avista is requesting $507,000 in Operations and Maintenance
19 funding for support of the transmission system under this
20 proposal to protect our current wood poles from wild fires
21 in key areas. This is an increase of $401,000 above the
22 2007/2008 Operations and Maintenance spending for this
23 area.
24 The transmission plan includes:
25 . Fire Retardant Coatings for Transmission Poles:26 Random fires can have a significant impact on the.
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reliabili ty of Avista' s transmission system. During
the past five years, Avista has lost at least 60
wooden poles to brush fires. Protective coatings
are now available that can protect wood poles for20 minutes, or more, from close contact with
flames. The coating is especially effective against
brush fires. A neighboring utility has used the
coating and reported 80% survival rate of wood
poles in situations where 20% survival would havebeen more typical. Avista proposes a four-year
program to apply fire retardant coating to critical
transmission lines in high fire areas.
Q.Please describe Avista's Network Asset Management
15 Plan.
16 A.The Network consists of an underground
17 distribution system that feeds the core of downtown Spokane
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the region's economic hub wi th a very rel iable
The Network includesnetworked distribution system.
underground vaul ts ,manholes,handholes,substations,
21 network protectors, network transformers, and numerous
22 miles of duct banks and cables.The structural integrity
23 of these vaults, manholes and handholes is vi tal to public
24 safety because they are typically located under heavily-
25 used streets and sidewalks. Reliability is also essential,
26 because the Network serves the businesses, banks and other
27 critical services located in downtown Spokane.The
28 Operations and Maintenance portion of the Avista rate
29 request to support Network maintenance work totals
30 approximately $114,000. During the 2007/2008 test year no
31 Network asset management work was performed..
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The Network plan includes inspecting and maintaining
an aging system:
. Vaults: Almost 60% of the vaults are more than 50
years old. Avista plans to add inspection of vacantvaul ts and additional maintenance acti vi ties such
as vault cleanings to prevent debris build-up and
fire hazards. When necessary an entire vault will
need to be replaced wi th a new one.
. The Manholes/Handholes: Nearly 98% of manholes are
approaching 100 years of age. Avista plans to
inspect them on a five-year cycle and perform
maintenance based on the resul ts of the
inspections. Replacement of manholes and handholes
may also be required.
Q.this your pre-filed directDoescomlete
testimony?
A. Yes, it does.
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I. J:NTRODUCTJ:ON
Q.Please state your na, emloyer an business
3 address.
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A.My name is Dave B. DeFelice.I am employed by
Avista Corporation as a Senior Business Analyst.My
6 business address is 1411 East Mission, Spokane, washington.
7 Q.Please briefly describe your education backgroun
8 and professional experience.
9 A.I graduated from Eastern Washington University in
10 June of 1983 with a Bachelor of Arts Degree in Business
11 Administration majoring in Accounting.I have served in
12 various positions within the Company, including Analyst
13 posi tions in the Finance Department (Rates Section and.14
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Plant Accounting)and in the Marketing/Operations
Departments, as well.In 1999, i accepted the Senior
16 Business Analyst position that focuses on economic analysis
17 of various project proposals as well as evaluations and
18 recommendations pertaining to business policies and
19 practices.
20 Q.AS a Senior Business Analyst, what are your
21 responsibilities?
22 A.As a Senior Business Analyst I am involved in
23 financial analysis of numerous projects within various
24 departments such as Engineering,Operations,
25 Marketing/Sales and Finance..
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Q.' Wht is the scope of your testimony?
A. My testimony and exhibits in this proceeding will
3 cover the Company's proposed regulatory treatment of
4 capital -investments in utility plant through 2009.
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Q.Are you sponsoring any exhibits?
A.Yes.I am sponsoring Exhibit No.9, Schedule 1
7 (Capital Expenditures), and Schedule 2 (2009 Capital
8 Addi tions Detail), which were prepared under my direction.
9 II. CAPITAL INVSTM RECOVERY
10 Q.What does the Comany i s request for rate relief
11 include regarding new investment in utility plant to serve
12 customers?
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A.In this filing, we are proposing to include in
retail rates the costs associated with utility plant that
15 is in-service, and will be used to provide energy service
16 to our customers during the pro forma rate year. This is
17 consistent with prior ratemaking practice in the State of
18 Idaho. The methodology that we use is consistent with the
19 methodology we used in the last general rate cases filed in
20 2008, Case Nos. AVU-E-08-01 and AVU-G-08-01.
21 The utility plant investment that we have included in
22 this filing represents utility plant that will be "used and
23 useful II in providing service to customers during the
24 approximate period that new retail rates from this filing
25 will be in effect.The costs associated with the.
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investment will be "known and measurable," and finally,
including the costs associated with this investment in
3 retail rates provides a proper "matching" of revenues from
4 customers with the costs associated with providing service
5 to customers (including the cost of utility plant to serve
6 cus tomers) .
7 In the IPUC's Order No. 29602, in Case Nos. AVU-E-04-1
8 and AVU-G-04-1, dated October 8, 2004, the Commission
9 stated, at page 10, that:
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"Once a test year is selected, adjustments are
made to test year accounts and rate base to
reflect known and measurable changes so that test
year totals accurately reflect anticipated
amounts for the future period when rates will be
in effect. The Idaho Supreme Court has described
"rate base" as "the utility's capital investment
amount." Industrial Customers of Idaho Power v.Idaho PUC 134 Idaho 285, 291, 1 P. 3d 786, 792
(2000) . Adjustments to test year accounts
generally fall into three categories: 1)
normalizing adjustments made for unusual
occurrences, like one-time events or extreme
weather conditions, so they do not unduly affect
the test year; 2) annualizing adjustments made
for events that occurred at some point in the
test year to average their effect as if they had
been in existence during the entire year; and 3)
known and measurable adjustments made to include
events that occur outside the test year but will
continue in the future to affect Company income
and expenses."
If utility plant investment that is being used to
34 serve customers is not reflected in retail rates then the
35 retail rates will not be " just,reasonable,and
36 sufficient," i.e., it would not be just or reasonable for
37 customers to receive the benefit provided by the utility.
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investment without paying for it, and the retail rates
would not provide revenues II sufficient II to provide recovery
3 of the costs associated with providing service to
4 customers.
5 Q.Is the Comany' s application of these ratemking
6 principles in this filing consistent with prior general
7 rate cases?
8 A.Yes. In prior cases, the obj ective has been the
9 same to include in retail rates the investment, or rate
10 base, that is providing service to customers, and ensure
11 that there is a proper matching of revenues and expenses
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AVU-E-08-01 and AVU-G-08-01,the Commission approved
during the period that rates are in effect.In Case Nos.
including capital investment through Decemer 31, 2008, for
15 rates that were effective October 1, 2008.
16 Q.Bow does new investment in utility plant change
17 rate base over time for ratemking purposes?
18 A.Historically, the annual dollars spent by the
19 Company on new utility plant were generally relatively
20 close to the level of depreciation expense i with the
21 exception of years where the Company invested in major new
22 utility projects. 1 i will use an example to illustrate, in
1 Recogng that a porton of the costs associated with capital addtions are offet by additional
revenues..
291 DeFelice, Di 4
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general terms, how new investment in utility plant changes
rate base over time. Let's assume that the Company i s rate
3 base (adjusted net plant in service used to serve
4 customers) at the beginning of Year 1 is $1.5 billion.
5 Also assume that depreciation expense in Year 1 is $80
6 million, and the Company's new investment in utility plant
7 in Year 1 is also $80 million.During Year 1, rate base
8 increased by $80 million (new investment), and decreased by
9 $80 million (depreciation), and ended up at the same level
10 of $1.5 billion at the end of the year. In this simplified
11 example, the Company i s rate base is $1.5 billion, both at
12 the beginning of Year 1, and at the end of Year 1.
13 For ratemaking purposes, the $1.5 billion of rate base.14 is representative of the level of plant investment used to
15 serve customers, both at the beginning of the year and at
16
17
the end of the year.Over time, if depreciation expense
continues to be approxima tely equal to new plant
18 investment, rate base would continue at a relatively
19 constant $1.5 billion. Under these circumstances, the use
20 of the $1.5 billion rate base amount from a prior year,
21 i.e., a historical test year, would be adequate for setting
22 rates for the upcoming year (pro forma rate year), because
23 there is little change in the net plant investment used to
24 serve customers.
.
292 DeFelice, Di 5
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In 'a similar manner, in prior general rate cases we
have used a rate base amount from a historical test year as
the starting point for the pro forma rate year.If there
4 were no ,major plant additions between the historical test
5 year and the upcoming pro forma rate year, the historical
6 test year rate base amount would be used for the pro forma
7 rate year as being representative of the net plant used to
8 serve cus tomers .
9 However, if there were known major plant additions
10 that would be in service for the pro forma rate year, such
11 as the addition of Coyote Springs II for Avista, the major
12 transmission upgrades, and the hydroelectric upgrades, then
13 rate' base for the pro forma rate year is adjusted for these.14 major investments, so that rate base for the pro forma rate
15 year is representative of the level of investment used to
16 serve customers.
17 Q.Is Avista' s new investment in utility plant
18 exceeding its anual depreciation exense, causing an
19 increase in rate base from the test year to the pro form
20 rate year?
21 A.Yes.Avista i S investment in plant in 2009 is
22 well above the annual depreciation expense, and will result
23 in an increase in net plant in service (rate base) that
24 will be used to serve customers in the pro forma rate year.
25 Much of this new investment in plant for 2009 is spread.
293 DeFelice, Di 6
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.among many different utility plant categories, as opposed1
2
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to a few maj or plant additions.
Therefore, the Company's pro forma adjustment for new
4 investme.nt in plant in this filing, as in the previous
5 general rate case filing, involves a more detailed analysis
6 of the net change in rate base from the historical test
7 period to the pro forma rate year.The end resul t ,
8 however, is the same in this case as in all prior cases -
9 to reflect in retail rates the level of net plant
10 investment that is used to serve customers during the pro
11 forma rate year, and to have a proper matching of revenues
12 and expenses.
.13
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15
Q.How was rate base for the pro form rate year
developed for this filing?
A.As in prior rate cases, Avista started with rate
16 base for the historical test year, which for this case is
17 the average of monthly averages for the twelve months ended
18 Septemer 30, 2008.Adjustments were made to reflect new
19 additions and accumulated depreciation through Decemer
20 2009, such that the proposed rate base reflects the net
21 plant in service that will be used to serve customers
22 during the pro forma rate year. Later in my testimony, I
23 will provide the details of the adjustments to rate base.
24 The recent rate case (Case Nos. AVU-E-08-01 and AVU-G-
25 08-01) concluded with new retail rates effective October 1,.
294 DeFelice, Di 7
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.2008. As noted earlier, recovery of costs associated with1
2
3
new capital additions through December 31, 2008 was
included in retail rates.wi th regard to the proper
4 "matching" of revenues and expenses, it can be said that
5 some of the new capital through Decemer 31, 2008 was not
6 in place at the time new retail rates went into effect on
7 October 1, 2008. However, it is also true that the costs
8 of new capital already added, and to be added, in 2009 is
9 currently not recovered in retail rates. Although we know
10 that a perfect matching of revenues and expenses would be
11 difficult to achieve, it is very important that, during
12 this period of high capital investment, retail rates
13 reflect the true costs of providing service to customers,.14 in order to afford the Company the opportunity to recover
15 its costs and continue to attract capital under reasonable
16 terms.
17 with regard to the current filing, Avista is hopeful
18 that new retail rates from this case will be effective by
19 or before mid-2009.Furthermore, new rates from the next
20 general rate case will likely not be effective until
21 sometime well into 2010.Decemer 3l, 2009 represents an
22 approximate mid-point of the period in which retail rates
23 would be in place from this case and the next case.
24 Including new capital investment through the mid-point of
25 the "rate year" (approximately mid-2009 through mid-2010).
295 DeFelice, Di 8
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will allow the Company the opportunity to recover the costs
associated with capital investment that will serve
customers over the course of the rate year.
The following chart illustrates the capital additions
for 2008 and 2009 that will be completed and in service
through Decemer 31 , 2009 .Since this case reflects
capital additions through only December 31, 2009, during
the first part of 2010 (which is the rate year associated
with the current case), new capital investment will
incurred in order to serve customers, but the costs will
not be reflected in the customers' rates.
Illustration 1
AVISTA UTILITIES
CAPITAL ADDmONS 10081010
$600
_.._.._..-.._.._..-.._..-...
!.
!
i
:1
121112010
l ~oo~
.j
~l
d $200
2008 2009 2010
Q.You stated earlier that new utility investment in
15 2008 and 2009 will be substantially higher than the annual
16 Wht is driving the significant
17 investment in new utility plant?
depreciation expense.
.
296 DeFelice, Di 9
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A. As we explained in the recent general rate case,
the Company is being required to add significant new
transmission and distribution facilities,including
4 strengthening the "back bone" of our system, due in part to
5 continued customer growth in our service area, reliability
6 requirements, and capacity upgrades. Other issues driving
7
8
the need for capital investment include an aging
infrastructure,physical degradation,and municipal
9 compliance issues (i.e., street/highway relocations), etc.
10 Company witness Mr. Kinney provides additional testimony on
11 some of these capital requirements.
12 In addition, although in recent months the rapid
13 increase in the cost of materials (concrete, copper, steel,.14 etc.) has subsided, they are still orders of magnitude
15 higher than what they were even a few years ago, causing
16 the cost of these new facilities to be significantly higher
17 than in the pas t .Because the cost of adding new
18 facilities is significantly higher than the original cost
19 of existing facilities, the investment in new facilities
20 will be significantly higher than the annual depreciation
21 expense on the existing facilities.
22 Q.Wht is causing the substantial increase in raw
23 materials for Avista, and the utility industry in general?
24 A.In Septemer 2007,The Edison Foundation
25 commissioned a study from The Brattle Group titled, "Rising.
297 DeFelice, Di 10
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Utili ty Construction Costs: Sources and Impacts," which
identified cost trends specifically related to the utility
3 industry pertaining to critical materials and equipment, as
4 well as labor support services used for building capital
5 infrastructure. The study identifies the reasons for
6 drastic cost increases in critical raw materials, such as
7 global competition and an aging domestic utility
8 infrastructure as well as the need for additional
9 infrastructure to accommodate growth in the near future.
10 Q.What are some of the key cost drivers that are
11 ci ted in the study?
12 A.The study, at page 16, cites four major cost
13 drivers," (1) material input costs, including the cost of.14 raw physical inputs, such as steel and cement as well as
15 increased costs of components manufactured from these
16 inputs (e.g., transformers, turbines, pumps); (2) shop and
17 fabrication capacity for manufactured components (relative
18 to current demand); (3) the cost of construction field
19 labor, both unskilled and craft labor; and (4) the market
20 for large construction proj ect management, i . e. , the
21 queuing and bidding for proj ects . "The study goes on to
22 compare cost trends for various raw materials, critical
23 equipment and labor services relative to the general
24 inflation rate (GDP deflator).In addition, a cost trend
25 is sumarized by three key utility functional plant.
298 DeFelice, Di 11
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categories, including generation, transmission, and
distribution plant. The study concludes that these
3 inflation impacts have been outside the utility industry's
4 control.
5
6
Illustration 2 below depicts what has occurred to
infrastructure costs nationally.From the chart, it is
7 apparent that starting in 2003, costs of distribution,
8 transmission and generation infrastructure increased at a
9 far more significant rate than the overall economy, as
.
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18
19
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25.
measured by the GDP deflator.
Illustration 2
Natonal A,eraie Utillt Infastucure Cost Indices
160
! 1SO
~
~ 140
.¡ 130
iS
120
-Tot P1.aø.A1 si Geroi -Ga Tlog -Trall -Ditlbiioi-oDd
19
180
no
110 ---------
100 - ----
90
191 1m 19 19 19 19 191 19 19 200 201 200 20 20 20 20 2001
Yea
Souer. The H..cI.WIim..O Biileâ, No, 165 ..d the U.S. Bue.. of EcOlomic Ji,...Sile ..... of all reOlai c...trci.. ..d
eqpmei colt iD.. forlhe spcied comODeDI'. "1si UIil) CO.triiOD Coll: Sou. ..d Jmpa Prd by Th.llnle Grou forTh EcI... Fouaclii.. Seplber 20
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Q. Is there specific evidence that Avista is
experiencing cost escalations similar to that indicated in
3 the study?
4 A.Yes. As we explained in the recent general rate
5 case, a sample was compiled of some materials and equipment
6 that Avista routinely uses in order to support various
7 infrastructure construction efforts that are part of the
8 Company's annual capital requirements of purchases made
9 from 2003 through 2008.The sample of materials was
10 grouped into categories for typical electric and gas
11 distribution capital projects as well as major electric
12 substation projects. The cost sumary indicated that the
13 cost of the materials reviewed has risen sharply in most.14 categories from 2003 to 2008.For the distribution plant
15 group of materials, the average annual escalation impact
16 from 2003 through 2007 is approximately 37%, which is equal
17 to a cumulative increase over the four-year period of 178%.
18 The escalation for the substation group of materials and
19 equipment has been approximately 12% per year for the
20 purchases Avista has made from 2003 to 2008, or a
21 cumulative increase of 55%.
22 Q.Wht is the historical and projected level of
23 annual capital spending for Avista?
24 A.Avista's capital requirements have steadily
25 increased from approximately $100 million to over $200.
300 DeFelice, Di 13
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million over the last several years.Exhibi t No . 9 ,
Schedule, 1 reflects the trend that Avista has experienced
3 and what is planned for in the near future.
4 This chart not only shows the total magnitude of
5 capital. expenditures, but also clearly shows that the
6 amount of capital projects is well in excess of revenue-
7 supported capi tal expendi tures to connect new cus tomers ,
8 and beyond the level of revenues that is being collected
9 from customers related to existing plant.The difference
10 between the total capital requirements, less the new
11 revenue related capital, and allowed revenues represent a
12 significant discrepancy that is negatively impacting the
13 Company..14 Q.What is the likelihood that Avista's capital
15 investmnt will continue at this level?
16 A.There are many factors that will influence
17 capital expenditures going forward. One factor is the cost
18 of raw materials is expected to continue to cause the cost
19 of new capital expenditures to significantly exceed the
20 cost of existing capital facilities that are to be replaced
21 and the fact that there is more demand for capital projects
22 for such things as compliance work with municipal highway
23 and road proj ects, sewer proj ects, etc. Also, as critical
24 systems age, there will be more utility plant that will be
25 reaching the end of physical life and, in some cases, plant.
301 DeFelice, Di 14
Avista Corporation
.1 may be replaced prior to the end of its physical life based
2 on power. efficiency improvements that can be recognized.
3 III. DESCRIPTION OF CAITAL PROJECTS
4 Q.For the 2009 capital projects pro for.d in this
5 filing, please provide a description of the projects.
6 A.Exhibi t No.9, Schedule 2 details the capi tal
7 projects that will be transferred to plant in service in
8 2009 and included in this filing. A short description of
9 these projects with system costs follows:
10 Generation ($37.9 million):
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Thermal - Kettle Falls Capital Projects - $1,735,000
The primary proj ect at the Kettle Falls Generating
Station is the replacement of the steam turbine
control system. Other smaller projects include the
replacement of wood screw conveyors which feeds wood
into the hopper, the replacement of ash screws in the
ash removal system, and a continuation of a project toreplace the travelling grate in the boiler.
Thermal - Colstrip Capital Additions- $6,200,000
The Colstrip capital additions for 2009 include major
emission control proj ects for units 3 & 4. Boiler
modifications are being made to reduce Mercury
emissions on units 3&4 to comply with Montana state
law. Also Low NOx burners are being installed on unit
4 to comply wi th Montana DEQ requirements. These NOx
modifications were previously installed on unit 3.
2009 is a regular overhaul year with additional major
capi tal work scheduled for unit 4 including cooling
tower fill replacement, an LP turbine overhaul, an air
pre-heater overhaul, a generator rewind kit, and a
variety of additional smaller capital projects to be
completed during the outage.
Thermal - Other Small Projects - $84,000
Please refer to the workpapers of Mr. DeFelice for
detailed listing of projects.
.
302 DeFelice, Di 15
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Hydro - Cabinet Gorge Capital Project - $804,000
Replace a major component of the Cabinet Unit 1Turbine (discharge ring) ..
Hydro - Little Falls Capital Project - $525,000
Replace the roof at the Little Falls HED.
Hydro - Long Lake Capital Project - $597,000
Replace the scroll case drain system and installation
of dam safety monitoring systems for the forebay,
tailrace, and sump.
Hydro - Noxon Capital Project -
Replacement of the Generator
(GSU) needed to accommodate the
the turbine improvements.
$1,295,000
Step Up Transformers
increased power due to
Hydro - Upper Falls Capital Projects - $1,910,000
This proj ect will replace the old plant control and
locate all new equipment from the Post Street
Substation to the Upper Falls plant. In addition, new
equipment will be installed to both modernize the
uni t, enhance the protection schemes, and to automate
the plant from the Generation Control Center.
Hydro - Noxon Capital Projects - $17,171,000
Projects include finishing the replacement of the Unit
1 stator core and stator windings, installation of a
new high efficiency turbine runner, and mechanical
overhaul on unit #1.
Hydro Clark Fork implement PME Agreement
$2,107,000
Multiple projects are planned for 2009 as part of the
protection, mitigation and enhancement (PME) plan.
These projects were agreed to as part of the
settlement agreement and FERC license received in
2001.
Hydro - Other Small Projects - $l,l42,OOO
There are a numer of proj ect improvements planned for
2009. These include beginning a system station sumpcontrol and monitoring systems to facilitate
anticipated license conditions, and other smallproj ects . Please refer to the workpapers of Mr.
DeFelice for detailed listing of projects.
Other - Northeast Combustion Turbine - $944,000
The control system at the Northeast Combustion Turbine
will be upgraded for standby reserve. This project is.
303 DeFelice, Di 16
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a continuation from 2008 in that air permit issues
prevented this item from being completed.
Other - Coyote Springs 2 (CS2 ) Capital Proj ects -
$575,000In 2009, capital costs include a spare GSU
transformer. The previous spare was installed after a
tra~sformer failed in the spring of 2008. The capital
cost of the new spare will largely be offset by an
insurance settlement. Other smaller projects plannedfor 2009 include the purchase of a spare station
serviced transformer (reliability), duct burner fuel
sys tem upgrades (capaci ty increase), s team turbine
control upgrades (reliability), and several smaller
PGE/Avista shared projects (safety/reliability).
Other - Coyote Springs 2 (CS2) LTSA - $2,000,000LTSA (Long Term Service Agreement) costs are
apportioned between capi tal and O&M based on predicted
gas turbine hardware replacement schedules for the
duration of the contract. These costs cover the
maintenance agreement with General Electric and coverthe gas turbine and auxiliaries.
.Other Small Projects - $819,000
This work is primarily to install an Uninterruptable
Power Supply (UPS) system at the Boulder Park power
station to protect the engine generators and other
station auxiliaries. Currently when there is a loss
of station service, most of the control system will
shut down after only a few minutes. This system will
allow for an orderly control of the equipment during
these events. Please refer to the workpapers of Mr.
DeFelice for detailed listing of other projects.
Electric Transmission ($15.1 million):
The electric transmission proj ects that will transfer
to plant in service are described in detail in Mr.Kinney's direct testimony at pages 17 through 21. A
listing of these projects follows:
Lolo 230-Rebuild 230 kV Yard - $2 i 050,000
Spokane-CDA 115 kV Line Relay Upgrades - $1,250,000
Power Circuit Breakers - $540,000
SCADA Replacement - $740,000
Noxon-Pinecreek 230kV: Ready Fiber Optic - $650,000
System-Replace/install Capacitor Banks - $800,000
Benewah-Shawnee 230 kV Construction - $560,000
Mos23-N Moscow 115 Recond - $585,000.
304 DeFelice, Di 17
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Burke 115 kV Protection & Metering - $525,000
Beacon Storage Yard Oil Containment - $527,000
Other small specific transmission projects - $936,000
Transmission Minor Rebuild - $1,069,000
System Rebuild Transmission ~ $928,000
Interchange and Borderline Metering Upgrades
$642,000
pine Creek - $350,000
Replacement Programs - $2,234,000
Other small transmission projects - $670,000
Electric Distribution ($46.7 million):
The electric distribution proj ects that will transfer
to plant in service are described in detail in Mr.Kinney's direct testimony at pages 22 through 24. A
listing of these projects follows:
.
Electric Distribution Minor Blanket - $7,922,000
Capital Distribution Feeder Repair Work - $4,100,000
Wood Pole Management - $3,700,000
Electric Underground Replacement - $3,156,000
T&D Line Relocation - $2,297,000
Failed Electric Plant - $1,987,000
Sys-Dist Reliability-Improve Fdrs - $1,100,000
Open Wire Secondary Elimination - $1,000,000
Plumer-Increase Capacity/Rebuild - $1,525,000
Idaho Road Sub/Rathdrum - $4,896,000
System Wood Substation Rebuilds - $3,600,000
Distribution Feeder Reconductor - ID - $727,000
The electric distribution projects specific to the
Washington jurisdiction that are not described in
detail in Mr. Kinney's direct testimony follows:
Spokane Electric Network Capacity - $1,615,000
Terre View 115-Sub Construct (WSU) - $1,962,000
Otis Orchards Substation - $980,000
Othello Transformer Replacement - $665,000
Northeast Substation - $225,000
Valley Mall Transfer Capacity - $200,000
Distribution Feeder Reconductor - WA - $1,050,000
Network Transformers & Network Protectors - $800,000
Addi tional distribution proj ects follows:
Power Transformer-Distribution - $680,000
Installation of distribution power transformers asrequired..
305 DeFelice, Di 18
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ID AM - $600,000
The 4-year Automated
completed in late 2008.
for network optimization.
Meter Reading Proj ect was
Additional capital will be.
WSDOT Highway Franchise Consolidation - $800,000
In order to operate our electric system wi thin State
highway rights of way, the Company needs to establish
new Franchises. Existing franchises have expired and
Avista must seek new agreements with the State or risk
penalties or non-approval by the State.
Other small distribution proj ects - $1,083,000
Please refer to the workpapers of Mr. DeFelice for
detailed listing of proj ects.
General ($14.8 million):
Security Initiative - $508,000
Various security measures including cameras and access
controls for the office and branch facilities.
Next Generation Radio System - $1,500,000Antiquated Radio system technology necessary to
operate the business is being refreshed to comply with
changing FCC regulation.
Structures and Improvements - $3,360,000
This is a group of capital maintenance projects that
Facilities Management coordinates at the Spokane
Central Operating Facilities and Avista branch
facilities - offices and service centers. For 2009,
some of the proj ects include: roof replacements, land
acquisition for facility expansion, HVAC system
replacement at some branch offices, energy efficiency
projects, security projects, emergency generators,
asphalt overlays and replacement, and office furniture
additions and replacement.
Stores Equipment - $598,000
Equipment utilized in warehouses and/or
recovery operations throughout the service
This includes equipment such as forklifts,
shelving, cutting/binding machines, etc.
investmentterritory.
man lifts,
Tools, Lab & Shop Equipment - $1,285,000
Expenditures in this category include all large tools
and instruments used throughout the company for gas
and/or electric construction and maintenance work,
distribution, transmission, or generation operations,.
306 DeFelice, Di 19
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telecommunications, and some fleet equipment (hoists,
winch, etc) not permanently attached to the vehicle..
Productivity Initiative - $1,147,000
Various initiatives that increase
benefits based on future avoided costs.
productivi ty
HVAC Renovation Proj ect - $4,159,000
The heating, ventilating, and air conditioning systemsthroughout the Spokane Central Operating Facilities
are approximately fifty years old and are in need ofreplacement. The proj ect involves replacing central
air handling units and distribution systems in three
buildings - the Spokane Service Center, the general
office building, and the cafeteria auditorium
building. The building envelope of the general office
building will also be renovated with high efficiency
glass and insulation. New controls will also be
installed which will enable energy conservation.
Spokane Central Operating Facility Crescent
Realignment - $1,500,000
Vacate a city street that bisects the Spokane campus
to eliminate public traffic across parking lots and
operating facilities, improving facility safety andsecurity.
Other Small Projects - $750,000
These proj ects include communication and
initiatives, radio equipment, telephone
office and other general facility upgrades.
securitysystems,
Transportation ($9.6 million):
Transportation Equipment - $9,635,000
Expendi tures are for the scheduled replacement of
trucks, off-road construction equipment and trailers
that meet the company's guidelines for replacementincluding age, mileage, hours of use and overall
condition. In addition, includes additions to the
fleet for new posi tions or crews working to support
the maintenance and construction of our electric andgas operations.
Technology ($11.5 million):
Information Technology Refresh Blanket - $4,410,000
A program to replace obsolete technology according to
Avista's refresh cycles that are generally driven by.
307 DeFelice, Di 20
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hardware/software manufacturer and industry trends tomaintain business operations..
Information Technology Expansion Blanket - $981,000
A program to deliver technology associated with
expansion of existing solutions.
AFM Product Development Program - $1,115,000
Deliver enhancements to the electric and natural gas
Facility Management technology system.
Nucleus Product Development Program - $556,000
Deliver enhancements to the Nucleus energy resource
management technology system.
Web Product Development Program - $627,000
A program to deliver enhancements to the Customer
based Web technology system.
Mobile Dispatch Upgrade - $800,000
Upgrade the Mobile Dispatch application system from
V7.7 to V8.
Mobile Dispatch 2 - $1,372,000
Implement Mobile Dispatch application for electric
service and meter shop processes.
Other Small Technology Projects - $1,655,000
These proj ects include various small technology
projects including, technology to provide for field
office use of Learning Management System, a Meter Data
Management solution, a work management technology
system to the Generation Production and Substation
Support organization, and replacement of existing Real
Estate permits application which is end-of-life with
Valumation Contract Management System.
Jackson Prairie Storage ($0.3 million):
Jackson Prairie Storage Project - $306,000
This completes the capital project that Avista and its
partners started for an expansion project at Jackson
Prairie for deliverability that was in service in the
fall of 2008.
Natural Gas Distribution ($22.2 million):
Replace Deteriorated Pipe - $1,000,000
This annual proj ect will replace sections of existing
gas piping that are suspect for failure or have.
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deteriorated within the gas system. This project will
address the replacement of sections of gas main that
no longer operate reliably and/ or safely. Sections ofthe. gas system require replacement due to many factors
including material failures, environmental impact,
increase leak frequency, or coating problems. Thisproj ect will identify and replace sections of main to
improve public safety and system reliability.
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Gas, Replacement Street and Highways - $1,200,000
This annual proj ect will replace sections of existing
gas piping that require replacement due to relocation
or improvement of streets or highways in areas where
gas piping is installed. Avista installs many of its
facilities in public right-of-way under established
franchise agreements. Avista is required under the
franchise agreements, in most cases, to relocate its
facilities when they are in conflict with road or
highway improvements.
Gas Non-Revenue Blanket - $2,500,000
This annual proj ect will replace sections of existing
gas piping that require replacement to improve theoperation of the gas system but are not directly
linked to new revenue. The project includes relocation
of main related to overbuilds, improvement in
equipment and/or technology to improve system
operation and/or maintenance, replacement of obsolete
facilities, replacement of main to improve cathodic
performance, and projects to improve public safety
and/ or improve sys tem rel iabi 1 i ty .
East Medford Reinforcement Project - $4,451,000
This Oregon gas distribution project is not includedin this filing.
Replace Gas ERT' s w/ Batteries ~10yrs - $2,700,000
This project will replace Gas ERT's that are greater
than 10 years old, which is their economic life. ERT
battery life is finite and although that life is
greater than 10 years, it is cost effective to replace
the ERTS' s prior to them failing in the field. This
proj ect will ensure continued reliable metering
operation by ensuring the ERT technology operates
properly. Approximately 12,000 ERT's will be replacedin Washington and 21, 000 in Oregon.
Kettle Falls Relocation - $5,198,000
This multi-phased project installed a new gate station
in 2008 on the west side of Spokane to serve the.
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existing high pressure (HP) distribution and future
replacement pipe that is part of the Kettle Falls HP
mai~. The existing Kettle Falls Gate Station and HP
Kettle Falls main have experienced significant
encroachment due to growth in the north Spokane area.
Sections of the main will be relocated to ensure
continued safe reliable operation of the pipe system.
The new gate station will improve the safety and
reliability of operating the high pressure main and
improve the gate station delivery capacity into the
Kettle Falls HP system. Future phases of this project
will re-route sections of the existing HP Kettle Falls
main to improve system capacity and public safety.
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US2 North Spokane HP Reinforcement (Kaiser Property) -
$1,199,000
This proj ect will reinforce the north central portion
of Spokane near US2 by extending the existing HP
piping system and installing a new regulator station
to reinforce the existing distribution system. The
north Spokane distribution system experiences low
pressures during high system demand in the winter.
The area fails the gas planning model for a designday. Growth in the area has reduced Avista' s ability
to reliably serve gas from its existing distribution
system during a design day. This proj ect will improve
delivery pressure and reliability.
Other Small Projects - $3,901,000
Please refer to the workpapers of Mr. DeFelice for
detailed listing of projects.
iV. ADSTM MEODOLOGY
Q.What was the general approach to comuting the
36 pro form adjustments for investment in capital projects?
37 A.The Company used the same general approach that
38 was used in the previous general rate case. The 2008 and
39 2009 capital investments were tracked separately to
40 simplify the computation and to make it easier to follow.
41 For each vintage, capital additions, depreciation and DFIT
42 were computed to derive rate base at Decemer 31, 2008 and.
310 DeFelice, Di 23
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.1 Decemer 31, 2009 and to compute operating expenses in the
2 pro forma rate year.
3 Q.Wht reports or data were used in the
4 comutation?
5 A.The Company maintains results of. operations
6 reports that are prepared for each service and jurisdiction
7 on an average of monthly averages (AM) basis and on an end
8 of period (EOP) basis that were used in this computation.
9 Actual 2008 plant additions were used from the plant
10 accounting system to determine the month of addition and
11 the amount of additions that were for revenue producing
12 projects.Capital additions for 2009 (described above)
13 were based on specific capital requirements for 2009..14 Capital additions for 2009 that were for revenue producing
15 projects were separated out and excluded. The Company did
16 not include any 2010 capital additions in this filing.
17 Q.Are the comutations for all services and
18 jurisdictions the sam?
19 A.Yes, they are.Because of this, only the Idaho
20 electric data will be used below to describe the
21 methodology for computing the adjustments. The adjustments
22 for Idaho gas were computed in a similar manner.
23 Q.Please exlain in detail the comutation of the
24 adjustment as it relates to rate base.
.
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.1 A.There are three steps to determine the rate base
2 adjustment at December 31, 2008 and Decemer 31, 2009, as
3 follows:
4 Step 1 - Adjust AH Septemer 30, 2008 to BOP Decemer 31,
5 2008 (Pro For. Capital Additions 2008 Adjustmnt)
6
7 The first step was to determine an adjusted December
8 31, 2008 EOP net plant balance that includes only the AM
9 revenue producing capital through September 30, 2008. The
10 Company's December 31, 2007 EOP results of operations
11 reports was the starting point.
12 The gross plant at Decemer 31, 2007 at EOP includes
13 all revenue producing capital added in 2007.Since the
14 test period begins with October 1, 2007, it is necessary to.15
16
remove the average of monthly averages of those additions
for the last three months of 2007, since 2007 test year
17 includes AM customers and revenue (this is explained
18 further below). The 2008 capital additions, excluding all
19 revenue producing capital, were added.In addition, the
20 average of monthly averages of the revenue producing
21 capital for the nine months ended Septemer 30, 2008 was
22 also added.
23 The EOP gross plant at December 31, 2008 was computed
24 as follows:
25
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EOP Gross Plant at 12131/07 per Results of Operations
Add: 2008 Capital Additions (Excluding Revenue Producing)
($OOO's)
$912,978
$32,380
Less: October - December 2007 Revenue Producing Capital
Additions
Add: January - September 2008 AMA Revenue Producing
Capital Additions
($1,590)
$2.821
EOP Adjusted Gross Plant at 12131/08 $946.589
The pro forma capital additions 2008 adjustment in
Company witness Ms. Andrews' testimony at Exhibit No. lO,
Schedule 1, page 8, for gross plant of $27,213,000 was
computed by subtracting the AM gross plant balance used in
the filing of $919,376,000 from the calculated EOP adjusted
gross plant balance of $946,589,000.Addi tional details
regarding these adjustments are provided in Ms. Andrews'
workpapers .
This same process was used for both accumulated
depreciation and deferred income taxes, to arrive at EOP
adjusted amount at Decemer 31, 2008 for the 2008 vintage
plant assets. The pro forma capital additions adjustment
for accumulated depreciation of $19,393,000 was computed by
subtracting the AM accumulated depreciation balance used
in the filing of $314,219,000 from the calculated EOP
adjusted accumulated depreciation balance of $333,612,000.
The pro forma capital additions adjustment for DFIT of
($4,162,000) was computed by subtracting the AM DFIT
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balance used in the filing of ($82,407,000) from the
calculated EOP adjusted DFIT balance of ($86,5695,000).
3 Step 2 - Adjust 2008 vintage Plant to EOP Decemer 31, 2009
4 (Pro For. Capital Additions 2009 Adjustmnt - Part A)
5 The second step was to determine rate base at Decemer
6 Only31, 2009 for the 2008 vintage plant assets.
7 accumulated depreciation and deferred taxes are impacted.
8 Depreciation expense of $25,467,000 was computed on gross
9 plant at December 31, 2008, adjusted for projected 2009
10 retirements, using the average effective depreciation rates
11 by functional plant group.Depreciation expense on the
12 2008 revenue producing capital additions has been excluded.
13 The deferred tax impact on the 2008 vintage plant assets,.14
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was ($3,460,000). These changes to rate base at December
3l, 2009 are added to the 2009 vintage plant additions
16 (discussed below) to derive the pro forma capital additions
17 adjustment for 2009, detailed in Ms. Andrews' testimony at
18 Exhibi t No. 10, Schedule 1, page 8.Addi tional details
19 regarding these adjustments are provided in Ms. Andrews'
20 workpapers .
21 Step 3 - Add 2009 Vintage Plant to EOP Decemr 31, 2009
22 (Pro For. Capital Additions 2009 Adjustmnt - Part B)
23 The capital additions for 2009 were sumarized by
24 functional plant categories and either directly assigned or
25 allocated to the services and jurisdictions based on
26.standard Company practices.The amount of revenue
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producing capital additions in 2009 by service and
jurisdiction was excluded. The additions were further
3 summarized by the month they are expected to be transferred
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to plan,t in service.using the average effective
depreciation rates by functional plant group,AM
6 depreciation expense was computed in order to include the
7 partial year convention of depreciation that will actually
8 be recorded in 2009.
9 For the Idaho electric service, plant additions were
10 $47,447,000, depreciation expense was $846,000 and DFIT was
11 ($778,000). These 2009 costs are added to the 2008 vintage
12 plant 2009 costs (discussed above) to derive the pro forma
13 capital additions adjustment to rate base for 2009..14 A sumary of the pro forma capital additions 2009
15 adjustment follows:
DFIT
Part A Part B Total
2008 Vintage 2009 Vintage Adjustment to
Plant Plant Rate Base
$0 $47,447 $47,447
$25,467 $846 $26,313
($3,460)($778)($4,238)
($OOO's)
Plant in Service
Accumulated Depreciation
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18 Q.Wht other impact does the 2008 and 2009 capital
19 additions have on this case in addition to the rate base
20 imact?
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A., Depreciation expense and property taxes have been
computed for the 2008 and 2009 plant vintages for the pro
3 forma rate year.
4 The pro forma capital additions 2007 pre-tax
5 depreciation adjustment of $246,000 is computed as follows:
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($OOO's)
Estimated full-year of depreciation expense on the 2008 vintage plant balanceat December 31,2009 $25,360
12 Months Ended September 30, 2008 test year depreciation expense,adjusted for the depreciation true-up adjustment. $25,111State Taxes ~
Pro forma Capital Additions 2007 Adjustment - Depreciation Expense ~
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10 The pro forma capital additions 2009 pre-tax
11 depreciation and property tax adjustment of $2,603,000 is
12 computed as follows:
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($OOO's)
Estimated full-year of depreciation expense on the 2009 vintage plant balanceat December 31, 2009 $1 ,932
Estimated full-year of propert taxes on the 2009 vintage plant balance atDecember 31, 2009 $699State Taxes ~
Pro Forma Capital Additions 2009 Adjustment - Depreciation and Property Tax $2.603
Expense
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V. OTHER CONSIDERATIONS
Q.Wht is the rationale behind the remval of
3 capital exenditures for connecting new customers?
4 A.The pro forma capital expenditures for 2009 that
5 the Company included in this filing excludes distribution
6 related capital expenditures made that are associated with
7 connecting new customers to the Company's system.The
8 Company recognizes the fact that new customers provide
9 incremental revenue that helps offset the revenue
10 requirements of the distribution related capital additions
11 that the Company incurs to provide service to those
12 customers. These adjustments completely eliminated the AN
13 2008 and EOP 2009 capital activity related to new customer.14 connections in order to avoid an unintended mismatch of
15 revenues exceeding the cost to serve customers.
16 Q.In addi tion to excluding capi tal addi tions
17 related to new customers, does the Comany address the
18 2009/2008 revenue difference in other ways?
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A.Yes.The production property adjustment
(discussed in Ms. Andrews'testimony)addresses the
21 production and transmission related retail revenue that
22 would be produced by the change in retail load expected in
23 2009/2010 compared to the 2008 normalized test year. All
24 pro forma production and transmission rate base and related
25 expenses from these capital additions adjustments, are.
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reduced in order to reflect the amount needed to be
recovered from 2008 sales volumes.
VI. CONCLUSION
Q. What is the impact of the pro form adjustment?
A. The proposed adjustment will result in a closer
matching of revenues to cost of service to customers during
the period new rates will be in effect from this general
rate proceeding.without the proposed adjustment, the
Company would not have the opportunity to earn its allowed
rate of return on investment during the rate year.
Q.this conclude your pre-filed directDoes
testimony?
A. Yes, it does.
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