UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
X |
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF |
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THE SECURITIES EXCHANGE ACT OF 1934 |
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For the fiscal year ended December 31, 2009 |
OR
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF |
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THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from ................... to .................................................................
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Exact name of registrants as specified in |
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Commission |
their charters, address of principal executive |
IRS Employer |
File Number |
offices, zip code and telephone number |
Identification Number |
1-14465 |
IDACORP, Inc. |
82-0505802 |
1-3198 |
Idaho Power Company |
82-0130980 |
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1221 W. Idaho Street |
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Boise, ID 83702-5627 |
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(208) 388-2200 |
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State of incorporation: Idaho |
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Websites: www.idacorpinc.com and www.idahopower.com |
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Name of exchange on |
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SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: |
which registered |
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IDACORP, Inc.: Common Stock, without par value |
New York |
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SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: |
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Idaho Power Company: Preferred Stock |
Indicate by check mark whether the registrants are
well-known seasoned issuers, as defined in Rule 405 of the Securities Act.
IDACORP, Inc. |
Yes |
( X ) |
No |
( ) |
Idaho Power Company |
Yes |
( ) |
No |
( X ) |
Indicate by check mark if the registrants are not required
to file reports pursuant to Section 13 or Section 15(d) of the Act.
IDACORP, Inc. |
Yes |
( ) |
No |
( X ) |
Idaho Power Company |
Yes |
( ) |
No |
( X ) |
Indicate by check mark whether the registrants (1) have
filed all reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter period
that the registrants were required to file such reports), and (2) have been
subject to such filing requirements for the past 90 days. Yes ( X ) No ( )
Indicate by check mark whether the registrant has submitted
electronically and posted on its corporate Web site, if any, every Interactive
Data File required to be submitted and posted pursuant to Rule 405 of
Regulation S-T during the preceding 12 months (or for such shorter period that
the registrant was required to submit and post such files). Yes ___No ___
1
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrants knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. ( X )
Indicate by check mark whether the registrants are large
accelerated filers, accelerated filers, non-accelerated filers, or smaller
reporting companies.
IDACORP, Inc.: |
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Large accelerated filer |
( X ) |
Accelerated filer |
( ) |
Non-accelerated filer |
( ) |
Smaller reporting company |
( ) |
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Idaho Power Company: |
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Large accelerated filer |
( ) |
Accelerated filer |
( ) |
Non-accelerated filer |
( X ) |
Smaller reporting company |
( ) |
Indicate by check mark whether the registrants are shell
companies (as defined in Rule 12b-2 of the Act).
IDACORP, Inc. |
Yes |
( ) |
No |
( X ) |
Idaho Power Company |
Yes |
( ) |
No |
( X ) |
Aggregate market value of voting and non-voting common stock
held by nonaffiliates (June 30, 2009):
IDACORP, Inc.: |
$1,224,885,216 |
Idaho Power Company: |
None |
Number of shares of common stock outstanding at January 31,
2010:
IDACORP, Inc.: |
47,951,829 |
Idaho Power Company: |
39,150,812 all held by IDACORP, Inc. |
Documents Incorporated by Reference: |
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Part III, Items 10 - 14 |
Portions of IDACORP, Inc.s definitive proxy statement to be filed pursuant to Regulation 14A for the Annual Meeting of Shareholders to be held on May 20, 2010. |
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This combined Form 10-K represents separate filings by
IDACORP, Inc. and Idaho Power Company. Information contained herein relating
to an individual registrant is filed by that registrant on its own behalf.
Idaho Power Company makes no representation as to the information relating to
IDACORP, Inc.s other operations.
Idaho Power Company meets the conditions set forth in
General Instruction (I)(1)(a) and (b) of Form 10-K and is therefore filing this
Form with the reduced disclosure format.
2
COMMONLY USED TERMS |
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AFUDC |
- |
Allowance for Funds Used During Construction |
APCU |
- |
Annual Power Cost Update |
Cal ISO |
- |
California Independent System Operator |
CalPX |
- |
California Power Exchange |
CAMP |
- |
Comprehensive Aquifer Management Plan |
CO2 |
- |
Carbon Dioxide |
cfs |
- |
Cubic feet per second |
EIS |
- |
Environmental impact statement |
EPS |
- |
Earnings per share |
ESA |
- |
Endangered Species Act |
ESPA |
- |
Eastern Snake Plain Aquifer |
FASB |
- |
Financial Accounting Standards Board |
FCA |
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Fixed Cost Adjustment mechanism |
FERC |
- |
Federal Energy Regulatory Commission |
FIN |
- |
Financial Accounting Standards Board Interpretation |
Fitch |
- |
Fitch, Inc. |
FPA |
- |
Federal Power Act |
GAAP |
- |
Generally Accepted Accounting Principles |
HCC |
- |
Hells Canyon Complex |
Ida-West |
- |
Ida-West Energy, a subsidiary of IDACORP, Inc. |
IDWR |
- |
Idaho Department of Water Resources |
IE |
- |
IDACORP Energy, a subsidiary of IDACORP, Inc. |
IERCo |
- |
Idaho Energy Resources Co., a subsidiary of Idaho Power Company |
IFS |
- |
IDACORP Financial Services, a subsidiary of IDACORP, Inc. |
IPUC |
- |
Idaho Public Utilities Commission |
IRP |
- |
Integrated Resource Plan |
IWRB |
- |
Idaho Water Resource Board |
kW |
- |
Kilowatt |
LGAR |
- |
Load Growth Adjustment Rate |
maf |
- |
Million acre feet |
MD&A |
- |
Managements Discussion and Analysis of Financial Condition and Results of Operations |
Moodys |
- |
Moodys Investors Service |
MW |
- |
Megawatt |
MWh |
- |
Megawatt-hour |
NOx |
- |
Nitrogen Oxide |
NWRFC |
- |
National Weather Service Northwest River Forecast Center |
O&M |
- |
Operations and Maintenance |
OATT |
- |
Open Access Transmission Tariff |
OPUC |
- |
Oregon Public Utility Commission |
PCA |
- |
Power Cost Adjustment |
PCAM |
- |
Power Cost Adjustment Mechanism |
PURPA |
- |
Public Utility Regulatory Policies Act of 1978 |
RH BART |
- |
Regional Haze - Best Available Retrofit Technology |
RFP |
- |
Request for Proposal |
S&P |
- |
Standard & Poors Ratings Services |
SFAS |
- |
Statement of Financial Accounting Standards |
SO2 |
- |
Sulfur Dioxide |
SRBA |
- |
Snake River Basin Adjudication |
Valmy |
- |
North Valmy Steam Electric Generating Plant |
VIEs |
- |
Variable Interest Entities |
WECC |
- |
Western Electricity Coordinating Council |
3
TABLE OF CONTENTS |
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Page |
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Part I |
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Business |
5-14 |
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Risk Factors |
15-19 |
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Unresolved Staff Comments |
19 |
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Properties |
20-21 |
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Legal Proceedings |
21 |
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Submission of Matters to a Vote of Security Holders |
21 |
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21-22 |
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Part II |
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Market for Registrants Common Equity, Related Stockholder |
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Matters and Issuer Purchases of Equity Securities |
23-24 |
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Selected Financial Data |
25 |
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Managements Discussion and Analysis of Financial Condition and |
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Results of Operations |
25-61 |
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Quantitative and Qualitative Disclosures about Market Risk |
61-62 |
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Financial Statements and Supplementary Data |
63 |
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Changes in and Disagreements with Accountants on Accounting and |
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Financial Disclosure |
121 |
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Controls and Procedures |
121-126 |
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Other Information |
126 |
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Part III |
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Directors, Executive Officers and Corporate Governance* |
126 |
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Executive Compensation* |
126 |
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Security Ownership of Certain Beneficial Owners and Management and Related |
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Stockholder Matters* |
127 |
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Certain Relationships and Related Transactions, and Director Independence* |
127 |
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Principal Accountant Fees and Services* |
127-129 |
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Part IV |
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Exhibits and Financial Statement Schedules |
129-141 |
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142-143 |
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*Except as indicated in Item 12, IDACORP, Inc. information is incorporated by reference to IDACORP, |
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Inc.s definitive proxy statement for the 2010 Annual Meeting of Shareholders. |
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4
SAFE HARBOR STATEMENT
This Form 10-K contains forward-looking statements
intended to qualify for the safe harbor from liability established by the
Private Securities Litigation Reform Act of 1995. Forward-looking statements
should be read with the cautionary statements and important factors included in
this Form 10-K at Part II, Item 7- Managements Discussion and Analysis of
Financial Condition and Results of Operations - FORWARD-LOOKING INFORMATION.
Forward-looking statements are all statements other than statements of
historical fact, including without limitation those that are identified by the
use of the words anticipates, believes, estimates, expects, intends,
plans, predicts, projects, may result, may continue, or similar
expressions.
PART I - IDACORP, INC. AND IDAHO POWER COMPANY
OVERVIEW
IDACORP, Inc. (IDACORP) is a holding company formed in 1998
whose principal operating subsidiary is Idaho Power Company (Idaho Power).
IDACORP is subject to the provisions of the Public Utility Holding Company Act
of 2005, which provides certain access to books and records to the Federal
Energy Regulatory Commission (FERC) and state utility regulatory commissions
and imposes certain record retention and reporting requirements on IDACORP.
Idaho Power was incorporated under the laws of the state of
Idaho in 1989 as successor to a Maine corporation organized in 1915. Idaho
Power is an electric utility engaged in the generation, transmission,
distribution, sale and purchase of electric energy and is regulated by the FERC
and the state regulatory commissions of Idaho and Oregon. Idaho Power is the
parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal
Company (Bridger Coal), which supplies coal to the Jim Bridger generating plant
owned in part by Idaho Power.
IDACORPs other subsidiaries include:
IDACORP Financial Services, Inc. (IFS), an investor in affordable housing and other real estate investments;
Ida-West Energy Company (Ida-West), an operator of small hydroelectric generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA); and
IDACORP Energy (IE), a marketer of energy commodities, which
wound down operations in 2003.
IDACORPs business strategy emphasizes Idaho Power as
IDACORPs core business. Idaho Power is IDACORPs only reportable business
segment, contributing 98.6 percent of IDACORPs income from continuing
operations in 2009. Segment data is presented in Note 17 to the consolidated
financial statements. At December 31, 2009, IDACORP had 1,994 full-time
employees, 1,979 of which were employed by Idaho Power.
Idaho Power detailed a three-part strategy of responsible
planning, responsible development and protection of resources, and responsible
energy use to ensure adequate energy supplies. Idaho Power continues to
evaluate and refine its business strategy to ensure coordination among and
integration of all functional areas of the company. Idaho Powers business
strategy balances the interests of owners, customers and employees while
maintaining the companys financial stability and flexibility. The strategy includes:
RESPONSIBLE PLANNING: Idaho Powers planning process is
intended to ensure adequate generation and transmission resources to meet
population growth and increasing electricity demand. This planning process now
integrates Idaho Powers regulatory strategy and financial planning, including
the consideration of regional economic development in the growing communities
we serve.
RESPONSIBLE DEVELOPMENT AND PROTECTION OF RESOURCES: Idaho
Powers business strategy has included the development and protection of
generation, transmission, distribution and associated infrastructure, and the
natural resources Idaho Power depends upon. The strategy now includes specific
consideration of workforce planning, development and retention related to these
strategic elements.
5
RESPONSIBLE ENERGY USE: Idaho Powers business strategy has
included energy efficiency and demand response programs and preparation for
potential carbon and renewable portfolio standard legislation. The strategy
now includes targeted reductions relating to carbon emission intensity and public
disclosure of these reductions.
IDACORP and Idaho Power make available free of charge their
Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on
Form 8-K and all amendments to these reports filed or furnished pursuant to
Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as
reasonably practicable after the reports are electronically filed with or
furnished to the Securities and Exchange Commission. IDACORPs website is www.idacorpinc.com
and can also be accessed through a link to the IDACORP website on the Idaho
Power website at www.idahopower.com.
UTILITY OPERATIONS
Idaho Powers service territory covers approximately 24,000
square miles in southern Idaho and eastern Oregon, with an estimated population
of one million. Idaho Power holds franchises in 71 cities in Idaho and nine
cities in Oregon and holds certificates from the respective public utility
regulatory authorities to serve all or a portion of 25 counties in Idaho and
three counties in Oregon. As of December 31, 2009, Idaho Power supplied
electric energy to approximately 490,000 general business customers. Idaho
Powers principal commercial and industrial customers are involved in food
processing, electronics and general manufacturing, forest products, beet sugar
refining and winter recreation.
Weather, customer demand and economic conditions impact
electricity sales. Extreme temperatures increase sales to customers who use
electricity for cooling and heating, and moderate temperatures decrease sales.
Increased precipitation levels during the agricultural growing season reduce
electricity sales to customers who use electricity to operate irrigation pumps.
Rates and Revenues
Retail
Electric utilities have historically been recognized as
natural monopolies and have operated in a highly regulated environment in which
they have an obligation to provide electric service to their customers in
return for an exclusive franchise within their service territory with an
opportunity to earn a regulated rate of return. Idaho Power is under the
retail jurisdiction (as to rates, service, accounting and other general matters
of utility operation) of the Idaho Public Utilities Commission (IPUC) and the
Oregon Public Utility Commission (OPUC) and as a regulated electric utility,
Idaho Power is generally not subject to retail competition. The IPUC and the
OPUC determine the rates that Idaho Power charges to its general business
customers. Idaho Power is also under the retail regulatory jurisdiction of the
IPUC, the OPUC and the Public Service Commission of Wyoming as to the issuance
of debt and equity securities.
Approximately 95 percent of Idaho Powers general business
revenue comes from customers located in Idaho. Idaho Power uses general rate
cases, power cost adjustment mechanisms, a fixed cost adjustment (FCA)
mechanism, and subject-specific filings to recover its costs of providing
service and to earn a return on investment. Significant rate cases and
proceedings are discussed in more detail in Note 3 to the consolidated
financial statements.
Special Customer Electric Service Agreements
Micron: The IPUC authorized Idaho Power to amend
temporarily an electric service agreement with one of its largest customers,
Micron Technology, Inc. (Micron) for the period January 2009 through June 2009,
to provide Micron flexibility in restructuring its operations. Subsequently,
the IPUC approved an extension of the temporary amendment through December 31,
2009. The amendments did not have a significant impact on Idaho Powers 2009
earnings and are not expected to have a significant impact on 2010 earnings.
The IPUC approved a replacement agreement between Idaho Power and Micron on
February 12, 2010, providing operating and planning benefits to Idaho Power
while allowing Micron to reduce its contract demand from 85 MW to 60 MW.
6
Hoku: In September 2008, Idaho Power entered into an
electric service agreement with a new customer, Hoku Materials, Inc. (Hoku), to
provide electric service to Hokus polysilicon production facility under
construction in Pocatello, Idaho. The IPUC approved the electric service
agreement in March 2009. The initial term of the agreement was four years
beginning June 1, 2009, (this date was subsequently changed to December 1,
2009) with a maximum demand obligation during the initial term of 82 MW.
Hoku was still not taking service on December 1, 2009, and
Idaho Power agreed to temporarily waive the minimum billed energy charge in the
Hoku special contract, effective December 1, 2009. The temporary waiver would
remain in effect until the month the contract load factor first exceeds 70
percent of the total contract demand, or March 31, 2011, whichever comes
first. The IPUC has approved this waiver. While the multi-month delay in the
starting date for Hokus required energy purchases reduces Idaho Powers revenues,
the revenue reductions are largely offset by corresponding reductions in Idaho
Powers costs of providing service to Hoku.
Wholesale
As a public utility under Part II of the Federal Power Act
(FPA), Idaho Power has authority to charge market-based rates for wholesale
energy sales under its FERC tariff and to provide transmission services under
its Open Access Transmission Tariff (OATT). Idaho Powers OATT is revised each
year based on financial and operational data Idaho Power files annually with the
FERC in its Form 1. The Energy Policy Act of 2005 (Energy Act) granted the
FERC increased statutory authority to implement mandatory transmission and
reliability standards, as well as enhanced oversight of power and transmission
markets, including protection against market manipulation. Significant rate
cases and proceedings are discussed in more detail in Note 3 to the
consolidated financial statements.
Idaho Power has one firm wholesale power sales
contract with Raft River Electric Cooperative for up to 15 MW. This contract
expires in September 2010. However, Raft River Electric Cooperative has
provided notice that is intends to renew the contract, as allowed in the
original agreement, through September 2011.
Idaho Power has one wholesale reserve sales contract, with
United Materials of Great Falls, Inc. The agreement requires Idaho Power to
carry reserves in association with an energy sales agreement between Idaho
Power and United Materials from the Horseshoe Bend Wind Farm located in
Montana. The term of the agreement runs seasonally through May 2013.
Energy sales
The following table presents Idaho Powers revenues and
energy use by customer type for the last three years. Idaho Powers operations
are discussed further in Part II, Item 7 - MD&A - RESULTS OF OPERATIONS -
Utility Operations:
7
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Years Ended December 31, |
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2009 |
2008 |
2007 |
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Revenues (thousands of dollars) |
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Residential |
$ |
409,479 |
$ |
353,262 |
$ |
308,208 |
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Commercial |
|
232,816 |
|
203,035 |
|
170,001 |
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Industrial |
|
141,530 |
|
122,302 |
|
101,409 |
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Irrigation |
|
109,655 |
|
105,712 |
|
88,685 |
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Deferred revenue related to Hells Canyon |
|
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relicensing AFUDC |
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(9,715) |
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- |
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- |
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Total general business |
|
883,765 |
|
784,311 |
|
668,303 |
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Off-system sales |
|
94,373 |
|
121,429 |
|
154,948 |
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Other |
|
67,858 |
|
50,336 |
|
52,150 |
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Total |
$ |
1,045,996 |
$ |
956,076 |
$ |
875,401 |
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Energy use (thousands of MWh) |
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Residential |
|
5,300 |
|
5,297 |
|
5,227 |
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Commercial |
|
3,858 |
|
3,970 |
|
3,937 |
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Industrial |
|
3,140 |
|
3,355 |
|
3,454 |
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Irrigation |
|
1,650 |
|
1,922 |
|
1,924 |
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Total general business |
|
13,948 |
|
14,544 |
|
14,542 |
|
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Off-system sales |
|
2,836 |
|
2,048 |
|
2,744 |
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Total |
|
16,784 |
|
16,592 |
|
17,286 |
|
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Power Supply
Idaho Power primarily relies on company-owned hydroelectric,
coal and gas-fired generation facilities and long-term power purchase
agreements (PPAs) to supply the energy needed to serve customers. Idaho
Powers annual hydroelectric generation varies depending on water conditions in
the Snake River and market purchases and sales are used to balance supply and
demand throughout the year. Idaho Powers low-cost hydroelectric plants are
typically the companys largest source of electricity. Idaho Powers
generating plants and their capacities are listed in Item 2 - Properties.
Weather, customer growth and economic conditions impact
power supply costs. Drought conditions and customer growth cause a greater
reliance on more expensive purchased power to meet load requirements.
Conversely, favorable hydroelectric generation conditions increase production
at Idaho Powers hydroelectric generating facilities and reduce the need for
purchased power. Economic conditions can affect market price of natural gas
and coal, which may impact fuel expense and market prices for purchased power.
Idaho Powers system is dual peaking, with the larger peak
demand occurring in the summer. The all-time system peak demand is 3,214 MW,
set on June 30, 2008, and the all-time winter peak demand is 2,527 MW set on
December 10, 2009. During these and other similar heavy load periods Idaho
Powers system is fully committed to serve loads and meet required operating
reserves.
The following table presents Idaho
Powers total power supply for the last three years:
|
MWh |
Percent of total generation |
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|
2009 |
2008 |
2007 |
2009 |
2008 |
2007 |
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|
(thousands of MWhs) |
|
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Hydroelectric plants |
8,096 |
6,908 |
6,181 |
53% |
48% |
46% |
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Coal-fired plants |
6,941 |
7,279 |
7,144 |
45% |
50% |
52% |
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Natural gas fired plants |
242 |
217 |
223 |
2% |
2% |
2% |
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|
Total system generation |
15,279 |
14,404 |
13,548 |
100% |
100% |
100% |
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Purchased power - cogeneration and |
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|
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small power production (CSPP) |
970 |
757 |
777 |
|
|
|
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Purchased power - Other |
1,942 |
2,960 |
4,419 |
|
|
|
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Total purchased power |
2,912 |
3,717 |
5,196 |
|
|
|
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Total power supply |
18,191 |
18,121 |
18,744 |
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Hydroelectric Generation
Idaho Power operates 17
hydroelectric projects located on the Snake River and its tributaries.
Together, these hydroelectric facilities provide a total nameplate capacity of
1,709 MW and annual generation equal to approximately 8.6 million MWh under
median water conditions.
Because of its reliance on
hydroelectric generation, Idaho Powers generation operations can be
significantly affected by water conditions. The availability of hydroelectric
power depends on the amount of snow pack in the mountains upstream of Idaho
Powers hydroelectric facilities, reservoir storage, springtime snow pack
run-off, river base flows, spring flows, rainfall, amount and timing of water
leases, and other weather and stream flow management considerations. During
low water years, when stream flows into Idaho Powers hydroelectric projects
are reduced, Idaho Powers hydroelectric generation is reduced. This results
in less generation from Idaho Powers resource portfolio (hydroelectric,
coal-fired and gas-fired) available for off-system sales and, generally, an increased
use of purchased power to meet load requirements. Both of these situations - a
reduction in off-system sales and an increased use of more expensive purchased
power - result in increased power supply costs.
8
Stream flow conditions improved in 2009
resulting in an increase of 1.2 million MWh generated from Idaho Powers
hydroelectric facilities as compared to 2008. The observed stream flow data
released in August 2009 by the U.S. Army Corps of Engineers, indicated that
Brownlee reservoir inflow for April through July 2009 was 5.6 million acre-feet
(maf), or 89 percent of the National Weather Service Northwest River Forecast
Center (NWRFC) average, compared to 4.4 maf, or 70 percent of the NWRFC
average, in 2008.
Storage in selected federal reservoirs
upstream of Brownlee as of February 21, 2010, was 118 percent of average. The
stream flow forecast released on February 19, 2010, by the NWRFC predicts that
Brownlee reservoir inflow for April through July 2010 will be 2.9 maf, or 46
percent of the NWRFC average.
Power generation at the Idaho Power hydroelectric power
plants on the Snake River also depends on the state water rights held by Idaho
Power and the long-term sustainability of the Snake River, tributary spring
flows and the Eastern Snake Plain Aquifer that is connected to the Snake
River. Idaho Power continues to participate in water management issues in
Idaho that may affect those water rights and resources with the goal to
preserve, to the fullest extent possible, the long-term availability of water
for use at Idaho Powers hydroelectric projects on the Snake River. For
further information see Part II, Item 7 MD&A LEGAL MATTERS Snake
River Basin Water Rights.
Idaho Power is subject to the provisions of the Federal
Power Act (FPA) as a public utility and as a licensee as therein defined
and is subject to regulation by the FERC. As a licensee under Part I of the
FPA, Idaho Power and its licensed hydroelectric projects are subject to
conditions set forth in the FPA and related FERC regulations. These conditions
and regulations include provisions relating to condemnation of a project upon
payment of just compensation, amortization of project investment from excess
project earnings, possible takeover of a project after expiration of its
license upon payment of net investment, severance damages and other matters.
Idaho Power obtains licenses for its hydroelectric projects
from the FERC, similar to other utilities that operate nonfederal hydroelectric
projects on qualified waterways. These licenses last for 30 to 50 years
depending on the size, complexity, and cost of the project. Idaho Power is
actively pursuing the relicensing of the Hells Canyon Complex and Swan Falls
projects. For further information on relicensing activities see Part II, Item
7 MD&A RELICENSING OF HYDROELECTRIC PROJECTS.
The state of Oregon has a Hydroelectric Act providing for
licensing of hydroelectric projects in that state. With respect to project
property located in Oregon, Idaho Powers Brownlee, Oxbow and Hells Canyon
facilities are subject to the Oregon Hydroelectric Act. Idaho Power has
obtained Oregon licenses for these facilities and these licenses are not in
conflict with the FPA or Idaho Powers FERC licenses.
Coal and Natural-Gas Combustion Generation
Idaho Power co-owns three coal-fired power plants and owns two natural gas
combustion turbine power plants. The coal-fired plants are: Jim Bridger
located in Wyoming; Boardman located in Oregon; and Valmy located in Nevada.
The natural gas-fired plants, Danskin and Bennett Mountain, are located in
Idaho.
Fuel supply-coal
Idaho Power, through its subsidiary IERCo, owns a one-third
interest in Bridger Coal, which owns the Jim Bridger mine that supplies coal to
the Jim Bridger generating plant (one-third owned by Idaho Power). The mine,
located near the Jim Bridger plant, operates under a long-term sales agreement
that provides for delivery of coal over a 51-year period ending in 2024 from
surface, high-wall, and underground sources. The Jim Bridger mine has
sufficient reserves to provide coal deliveries for the term of the sales
agreement. Idaho Power also has a coal supply contract providing for annual
deliveries of coal through 2014 from the Black Butte Coal Companys Black Butte
and Leucite Hills mines located near the Jim Bridger plant. This contract
supplements the Bridger Coal deliveries and provides another coal supply to
operate the Jim Bridger plant. The Jim Bridger plants rail load-in facility
and unit coal train allow the plant to take advantage of potentially lower-cost
coal from other mines for tonnage requirements above established contract
minimums.
NV Energy, as operator of the Valmy generating plant, has an
agreement with Arch Coal Sales Company, Inc. to supply coal to the plant
through 2011. As a 50 percent owner of the plant, Idaho Power is obligated to
purchase one-half of the coal, Idaho Powers portion ranging from 515,000 tons
to 762,500 tons annually. NV Energy also has a coal supply contract with Black
Butte Coal Companys Black Butte Mine for deliveries through 2015. Idaho Power
is obligated to purchase one-half of the coal purchased under this agreement
ranging from as low as 44,000 to as many as 500,000 tons annually.
9
The Boardman generating plant receives coal from the Powder
River Basin through annual contracts. Portland General Electric, as operator
of the Boardman plant, has two agreements with Foundation Coal West, Inc. to
supply all of Boardmans coal requirements in 2010 and additional deliveries through
2011. As a ten percent owner of the plant, Idaho Power is obligated to
purchase ten percent of the coal purchased under these agreements, which
cumulatively ranges from 175,000 to 225,000 tons annually.
Fuel supply-natural gas
Idaho Power owns and operates the Danskin and Bennett
Mountain combustion turbines, which are supplied gas through Northwest Pipeline
GPs (Northwest) pipeline. Gas is purchased as needs are identified for summer
peaks or to meet system requirements. Natural gas is transported under two
long-term agreements with Northwest. The first agreement, which runs into
2022, with annual extensions at Idaho Powers sole discretion, is for 24,523
million British thermal units (MMBtu) per day. Idaho Power also has the
ability to flow a total of 78,092 MMBtu on an alternate firm basis without
incurring a reservation charge on the additional amount. The second agreement,
beginning in 2012 and running through 2027, provides Idaho Power with
transportation capacity for 22,000 MMBtu per day. In addition to the two
long-term gas transportation agreements, Idaho Power has entered into a
long-term storage agreement with Northwest for 131,453 MMBtu of total storage
capacity at the Jackson Prairie Storage Project located in Lewis County, Washington.
As the project is developed, storage capacity will be phased into service and
allocated to Idaho Power on a monthly basis. Idaho Powers current storage
allotment is approximately 53 percent of its total, and its full allotment is
expected to be reached by January 2011. The firm storage contract expires in
2043, with bilateral termination rights at the end of the contract. Storage
gas will be purchased and stored with the intent of fulfilling needs as
identified for summer peaks or to meet system requirements.
Idaho Power plans to construct and operate the Langley Gulch
combined-cycle natural gas power plant. Construction is scheduled to begin
during the summer of 2010 with an on-line date targeted for the summer of
2012. Gas for Langley Gulch will be supplied through Northwests pipeline.
Procurement of gas will be managed to meet system requirements and fueling
strategies.
Purchased Power Agreements
Idaho Power has four firm wholesale purchased power
contracts. The first contract is with PPL Energy Plus, LLC, for 83 MW per hour
during heavy load hours, to address increased demand during June, July and
August. The contract term is through August 2011. The second contract is with
Raft River Energy I, LLC for 13 MW (nameplate generation) from its Raft River
Geothermal Power Plant Unit #1 located in southern Idaho. The contract term is
through April 2033. The third contract is with Telocaset Wind Power Partners,
LLC, for 101 MW (nameplate generation) from its Elkhorn Valley wind project
located in eastern Oregon. The contract term is through 2027. A fourth
contract is currently before the IPUC for authorization. This contract is with
USG Oregon LLC for 22 MW (estimated average annual output) from its
to-be-constructed Neal Hot Springs #1 geothermal power plant located near Vale,
Oregon. The contract term is 25 years with an option to extend. Commercial
operation is expected in late 2012.
Idaho Power has an exchange agreement with Clatskanie
Peoples Utility. The agreement is for the exchange of up to 18 MWs of energy
from the Arrowrock Project in southern Idaho for energy from Idaho Powers
system or power purchased at the Mid-Columbia trading hub. The initial term of
the agreement is January 1, 2010, through December 31, 2015. Idaho Power has
the right to renew the agreement for two additional five-year terms. Idaho
Power also has an exchange agreement with NV Energy that is pending approval
from the Public Utilities Commission of Nevada. The term of the agreement is
one business day following the Public Utilities Commission of Nevadas
approval, and continuing for two consecutive years, and provides for the
exchange of up to 45 MW of energy hourly.
CSPP Purchases
Pursuant to the requirements of Section 210 of PURPA, the
state regulatory commissions have each issued orders and rules regulating Idaho
Powers purchase of power from cogeneration and small power production (CSPP)
facilities. A key component of the PURPA contracts is the energy price
contained within the agreements. The PURPA regulations specify that a utility
must pay energy prices based on the utilitys avoided costs. The Published
Avoided Cost is a price established by the IPUC and OPUC to estimate Idaho
Powers cost of developing additional generation resources. The IPUC and OPUC
have established specific rules and regulations to calculate the published
avoided cost that Idaho Power is required to include in the PURPA contracts.
10
Idaho Power has contracts for the purchase of energy from a
number of private developers. Under these contracts:
Idaho Power is required to purchase all of the output from the facilities located inside its service territory.
Idaho Power is required to purchase the output of projects located outside its service territory if it has the ability to receive at the facilitys requested point of delivery on the Idaho Power system.
The IPUC jurisdictional portion of the costs associated with CSPP contracts is fully recovered through base rates and the PCA; the OPUC jurisdictional portion is recovered through general rate case filings and the Oregon power cost mechanism.
For IPUC jurisdictional contracts, projects that generate up to ten average MW of energy monthly are eligible for IPUC Published Avoided Costs for up to a 20-year contract term.
For OPUC jurisdictional contracts, projects with a nameplate rating of up to ten MW of capacity are eligible for OPUC Published Avoided Costs for up to a 20-year contract term.
If a PURPA project does not qualify for Published Avoided Costs,
Idaho Power is required to negotiate the terms, prices and conditions with the
developer. These negotiations reflect the characteristics of the individual
projects (i.e., operational flexibility, location and size) and the benefits to
the Idaho Power system and must be consistent with other similar energy
alternatives.
On March 12, 2009, the IPUC increased the Published Avoided
Cost rates. For example, the rate for a 20-year levelized 2009 contract
increased from $69.54/MWh to $88.92/MWh. This increase continues a favorable
climate for PURPA project development and may lead to additional PURPA
agreements. Those agreements may result in Idaho Power acquiring energy at
above wholesale market prices and at times when a surplus already exists as
well as requiring additional operational integration costs, thus increasing
costs to its customers. As noted above, substantially all CSPP costs are
recovered through base rates and Idaho Powers power supply cost mechanisms.
As of December 31, 2009, Idaho Power had signed agreements to
purchase energy from 96 CSPP facilities with contracts originally ranging from
one to 35 years. Eighty of these facilities, with a combined nameplate
capacity of 298 MW, were on-line at the end of 2009; the other 16 facilities
under contract, with a combined nameplate capacity of 266 MW, are projected to
come on-line during 2010 and 2011. The majority of the new facilities will be
wind resources which will generate on an intermittent basis. During 2009,
Idaho Power purchased 970,419 megawatt-hours (MWh) from CSPP facilities at a
cost of $59 million, resulting in a blended price of 6.1 cents per kilowatt
hour.
Wholesale Competition
The 1992 National Energy Policy Act and the FERCs
rulemaking activities have established the regulatory framework to open the
wholesale energy market to competition. Open-access transmission for wholesale
customers provides energy suppliers with opportunities to sell and deliver
electricity at market-based prices. Idaho Power actively monitors and
participates, as appropriate, in energy industry developments, to maintain and
enhance its ability to effectively participate in wholesale energy markets in a
manner consistent with its business goals.
Wholesale Energy Market Activities
Idaho Power participates in the wholesale energy market by
buying power to help meet load demands and selling power that is in excess of
load demands. Idaho Powers market activities are guided by a risk management
policy and frequently updated operating plans and influenced by customer loads,
market prices, and cost and availability of generating resources. Some of
Idaho Powers hydroelectric generation facilities are operated to optimize the
water that is available by choosing when to run generation units and when to
store water in reservoirs. These decisions affect the timing and volumes of
market purchases and market sales. Even in below normal water years, there are
opportunities to vary water usage to maximize generation unit efficiency,
capture marketplace economic benefits and meet load demand. Wholesale energy
market prices and compliance factors, such as allowable river stage elevation
changes and flood control requirements, influence these dispatch decisions.
11
Transmission Services
Idaho Powers generating facilities are interconnected through
its integrated transmission system and are operated on a coordinated basis to
achieve maximum load-carrying capability and reliability. Idaho Powers
transmission system is directly interconnected with the transmission systems of
the Bonneville Power Administration (BPA), Avista Corporation, PacifiCorp,
NorthWestern Energy and NV Energy. Such interconnections, coupled with
transmission line capacity made available under agreements with some of the
above entities, permit the interchange, purchase, and sale of power among all
major electric systems in the west interconnecting with the winter-peaking
northern and summer-peaking southern regions of the western power system.
Idaho Power provides wholesale transmission service and provides firm and non-firm
wheeling services for eligible transmission customers. Idaho Power is a member
of the Western Electricity Coordinating Council, the Western Systems Power
Pool, the Northwest Power Pool, the Northern Tier Transmission Group, and the
North American Energy Standards Board. These groups have been formed to more
efficiently coordinate transmission reliability and planning throughout the
western grid.
Resource Planning
Idaho Power filed its 2009 Integrated Resource Plan (IRP)
with the IPUC and OPUC in December 2009. Idaho Power updates the IRP every two
years. The IRP forecasts Idaho Powers load and resource situation for the
next 20 years, analyzes potential supply-side and demand-side options and
identifies near-term and long-term actions.
The four primary goals of the IRP are to:
(1) identify sufficient resources to reliably serve the growing demand for energy within Idaho Powers service area throughout the 20-year planning period;
(2) ensure the selected resource portfolio balances cost, risk and environmental concerns;
(3) give equal and balanced treatment to both supply-side resources and demand-side measures; and
(4) involve the
public in the planning process in a meaningful way.
The 2009 IRP analyzed supply-side resources, demand-side
management programs, and transmission options taking into account many factors
including the estimated costs of complying with potential carbon legislation as
part of determining the preferred resource portfolio. The preferred portfolio
positions Idaho Power for compliance with anticipated carbon regulations and a
federal Renewable Electricity Standard (RES). Due to the uncertainty regarding
future carbon regulations, no new conventional coal resources were selected in
the preferred portfolio.
During the development of the 2009 IRP, Idaho Power
conducted regular public meetings with the IRP Advisory Council (IRPAC). The
IRPAC members include the IPUC, the OPUC, political, environmental, and
customer representatives and representatives of other public interest groups.
IRPAC meetings also serve as the primary forum for involving the public in the
planning process.
During the time between resource plan filings, the public
and regulatory oversight of the activities identified in the IRP allows for
discussion and adjustment of the IRP as warranted. Idaho Power makes periodic
adjustments and corrections to the resource plan to reflect changes in
technology, economic conditions, anticipated resource development and
regulatory requirements.
Supply-side Resources
The foundation of Idaho Powers
energy resources is its company-owned generation facilities including 17
hydroelectric plants, two gas-fired plants and co-ownership in three coal-fired
plants (discussed in ITEM 2 PROPERTIES). To balance out its resource needs,
Idaho Power also utilizes long-term PPAs to supply the energy needed to serve
customers.
Idaho Power also has projects
identified for construction that including the 300-MW Langley Gulch
combined-cycle power plant, and a 49 MW expansion of the Shoshone Falls
hydroelectric facility. Idaho Power is also planning the Boardman to Hemingway
and the Gateway West transmission lines and constructing the Hemingway
substation to improve reliability, relieve congestion and provide system
flexibility (for more information see ITEM 7 MD&A LIQUIDITY AND CAPITAL
RESOURCES Capital Requirements Major Projects). The IRP also included
discussion related to the following resources:
Geothermal RFPs
Although the results of previously conducted geothermal request
for proposal (RFP) processes have been disappointing, Idaho Power continues to
work with project developers capable of delivering energy to the companys
service area. Idaho Power has included two 20-MW increments of geothermal
energy in the 2009 IRP preferred portfolio, one in 2012 and one in 2016.
12
Wind RFP
The 2009 IRP preferred portfolio includes 150 MW of wind
generation coming on-line in 2012. In May 2009, Idaho Power issued an RFP for
up to 150 MW of wind generation to come on-line no later than the end of 2012.
Idaho Power accelerated the release of the wind RFP to take advantage of the
benefits offered in the American Recovery and Reinvestment Act of 2009 (ARRA or
the economic stimulus package). Proposals were received in June 2009 and Idaho
Power expects to submit a contract to the IPUC for approval in the first half
of 2010.
Combined Heat and Power (CHP) RFP
CHP resources were not included in the 2009 IRP preferred
portfolio because of the level of uncertainty in being able to successfully
develop a CHP project. However, Idaho Power continues to work with large
customers and other parties to explore CHP development opportunities.
In November 2009, Idaho Power signed an agreement to jointly
investigate a CHP project with the Idaho Office of Energy Resources (IOER) and
Amalgamated Sugar, one of Idaho Powers large industrial customers. The
agreement establishes the framework for a CHP feasibility study to be performed
at Amalgamated Sugars Nampa, Idaho facility that could be as large as 100 MW.
IOER and Idaho Power will jointly fund the study.
Demand-Side Management Programs
In 2009, Idaho Power spent approximately $35 million on
energy efficiency and targeted demand reduction programs. Approximately $33
million of funding for these programs came from Idaho and Oregon energy
efficiency tariff riders. The balance of the funding comes from Idaho Power
base rates and from the remaining funds from the BPAs Conservation and
Renewables Discount, which was discontinued in 2007.
Idaho Power has several energy efficiency programs in place
and in development, targeting savings across the entire year and across a wide
range of customer segments. The emphasis of these programs is to reduce energy
consumption, especially during periods of high demand and minimize or delay the
need to build new supply-side alternatives. Idaho Powers programs include:
irrigation demand response and irrigation efficiency programs target irrigation customers with financial incentives for allowing Idaho Power to interrupt service to their irrigation pumps, and for either improving the energy efficiency of an irrigation system or installing a new energy efficiency system;
residential air conditioning equipment control measures;
residential energy efficiency programs targeted at new and existing homes, focusing on customer education and the application of energy efficiency remediation, including energy efficient building techniques, insulation augmentation, air duct sealing, and the use of efficient lighting; and
industrial and commercial facilities application of energy efficient techniques and technologies, operational and management processes to reduce energy consumption, and a new industrial peak reduction program.
Idaho Powers revised Irrigation Peak Rewards program design
was approved by the IPUC in January 2009. Participating customers receive a
credit on their bills in exchange for allowing Idaho Power, within specified
parameters, to interrupt service to their irrigation pumps during certain peak
hours in a six-week period in June and July. The cost of the program was $10
million in 2009 and is expected to increase to $11 million by 2011.
Idaho Powers voluntary Commercial Demand Response program
is for commercial and industrial customers larger than 200 kilowatts and was
approved in May 2009 by the IPUC. Idaho Power signed a five-year contract with
a third-party aggregator, EnerNOC, to operate the program and arranges with
Idaho Powers customers to achieve peak reductions. This program is
dispatchable (meaning Idaho Power will have flexibility to schedule peak
reduction benefits during times of greatest need) and is expected to increase
to 50 MW of summer peak demand reduction availability by 2012. The anticipated
cost of the program is approximately $12 million over its first five years.
Approximately $3 million of energy efficiency spending was
related to research, analysis and development, education, technology
evaluation, and market transformation. Some of this activity was done in
conjunction with the Northwest Energy Efficiency Alliance (NEEA). Idaho Power
contributed $1 million to the NEEA in 2009.
13
In 2009, Idaho Powers energy efficiency programs reduced
energy usage by approximately 160,000 MWh and the targeted demand reduction
programs resulted in a summer peak reduction of about 200 MW.
Environmental Regulation
Idaho Powers activities are subject to a broad range of
federal, state, regional and local laws and regulations designed to protect,
restore and enhance the quality of the environment including air, water, and
solid waste. Environmental regulation continues to impact Idaho Powers
operations due to the cost of installation and operation of equipment and
facilities required for compliance with such regulations, and the modification of
system operations to accommodate such regulations. In addition to generally
applicable regulations, the FERC licenses issued for Idaho Powers
hydroelectric generating plants have environmental requirements such as
aeration of turbine water to meet dissolved gas and temperature standards in
the tail waters downstream from the plants. Idaho Power monitors these issues
and reports the results to the appropriate regulatory agencies.
Idaho Power co-owns three coal-fired power plants and owns
two natural gas combustion turbine power plants that are subject to a broad
range of environmental requirements, including air quality regulation.
Idaho Powers environmental compliance costs will continue
to be significant for the foreseeable future especially with potential
additional regulation under discussion at the state and federal level. For a
more detailed discussion of these and other environmental issues, please see
Part II, Item 7 MD&A ENVIRONMENTAL ISSUES.
Idaho Power estimates its environmental expenditures, based
upon present environmental laws and regulations, will be as follows, excluding
Allowance for Funds Used During Construction (AFUDC) (in millions of dollars):
2010 |
2011 2012 |
||||
Studies and measures related to environmental concerns at hydroelectric facilities |
$ |
6 |
$ |
21 |
|
Investments in environmental equipment and facilities at thermal plants |
|
12 |
|
41 |
|
Total capital expenditures |
$ |
18 |
$ |
62 |
|
|
|
||||
Operating costs for environmental facilities - Hydroelectric |
$ |
16 |
$ |
41 |
|
Operating costs for environmental facilities - Thermal |
|
8 |
|
19 |
|
|
Total operations and maintenance |
$ |
24 |
$ |
60 |
|
|
|
|
|
IFS
IFS invests primarily in affordable housing developments,
which provide a return principally by reducing federal and state income taxes
through tax credits and accelerated tax depreciation benefits. IFS generated
tax credits of $8 million, $11 million and $15 million in 2009, 2008 and 2007,
respectively. IFSs portfolio also includes historic rehabilitation projects
such as the Empire Building in Boise, Idaho. IFS made $14 million and $8
million of new investments during 2009 and 2008, respectively, and will
continue to review future legislation for new opportunities for investment that
will be commensurate with the ongoing needs of IDACORP.
IFS has focused on a diversified approach to its investment
strategy in order to limit both geographic and operational risk. Over 90
percent of IFSs investments have been made through syndicated funds. At
December 31, 2009, the gross amount of IFSs portfolio equaled $197 million in
tax credit investments. These investments cover 49 states, Puerto Rico and the
U.S. Virgin Islands. The underlying investments include over 700 individual
properties, of which all but three are administered through syndicated funds.
IDA-WEST
Ida-West operates and has a 50 percent interest in nine
hydroelectric plants with a total generating capacity of 45 MW. Four of the
projects are located in Idaho and five are in northern California. All nine
projects are qualifying facilities under PURPA. Idaho Power purchased all of
the power generated by Ida-Wests four Idaho hydroelectric projects at a cost
of $9 million in 2009 and $8 million in both 2008 and 2007.
ITEM 1A. RISK FACTORS
The following are factors that could have a significant
impact on the operations and financial results of IDACORP, Inc. and Idaho Power
Company and could cause actual results or outcomes to differ materially from
those discussed in any forward-looking statements:
Reduced hydroelectric generation can reduce revenues and increase costs, and reduce earnings and cash flows. Idaho Power Company has a predominately hydroelectric generating base. Because of Idaho Power Companys heavy reliance on hydroelectric generation, water can significantly affect its operations. When hydroelectric generation is reduced, Idaho Power Company must increase its use of generally more expensive thermal generating resources and purchased power and opportunities for off-system sales are reduced, which reduces revenues. In addition, while Idaho Power Company can expect to recover the majority of the net power supply costs above the level included in its rates, recovery of the excess amounts does not occur until the subsequent power cost adjustment year.
Continuing declines in stream flows and over-appropriation of water in Idaho may reduce hydroelectric generation and revenues and increase costs. The combination of declining Snake River base flows, over-appropriation of water and drought conditions have led to disputes among surface water and ground water irrigators, and the state of Idaho. Recharging the Eastern Snake Plain Aquifer, which contributes to Snake River flows, by diverting surface water to porous locations and permitting it to sink into the aquifer is one proposed solution to the dispute. Diversions from the Snake River for aquifer recharge may further reduce Snake River flows available for hydroelectric generation and reduce Idaho Power Companys revenues and increase costs. Idaho Power Companys recent settlement agreement with the state of Idaho resolves litigation regarding certain Idaho Power Company water rights on the Snake River and provides for ongoing Snake River water issues to be addressed in the comprehensive aquifer management plan process. However, there is no assurance that this process will lead to increased Snake River stream flows for Idaho Power Companys hydroelectric projects. Idaho Power Company also has initiated legal action against the U.S. Bureau of Reclamation over the interpretation and effect of a 1923 contract with the U.S. Bureau of Reclamation on the operation of the American Falls Reservoir and the release of water from that reservoir to be used at Idaho Power Companys downstream hydroelectric projects. The comprehensive aquifer management plan process and the resolution of the litigation may affect Snake River flows available for hydroelectric generation and thereby reduce Idaho Power Company revenues and increase costs.
Idaho Power Companys reliance on coal and natural gas to fuel its power generation facilities exposes it to risk of increased costs and reduced earnings. In addition to hydroelectric generation, Idaho Power Company relies on coal and natural gas to fuel its generation facilities. Market price increases in coal and natural gas can result in reduced earnings. Increases in demand for natural gas, including increases in demand due to greater industry reliance on natural gas for power generation, may result in market price increases, short-term price volatility and/or supply availability issues. In addition, delivery of coal and natural gas depends upon gas pipelines, rail lines, rail cars and roadways. Any disruption in Idaho Power Companys fuel supply may require the company to find alternative fuel sources at higher costs, to produce power from higher cost generation facilities or to purchase power from other sources at higher costs.
Load growth in Idaho Power Companys service territory exposes it to greater market and operational risk and could increase costs and reduce earnings and cash flows.
o Increases in both the number of customers and the demand for energy have resulted and may continue to result in increased reliance on purchased power to meet customer load requirements. The price volatility of electricity has substantially increased from what it was at the inception of the power cost adjustment. While Idaho Power Company can expect to recover the majority of the net power supply costs above the amounts included in its rates, recovery of the excess amounts does not occur until the subsequent power cost adjustment year, and the remaining amount is absorbed by Idaho Power Company which could increase costs and reduce earnings and cash flows.
o Load growth can result in the need for additional investments in Idaho Power Companys infrastructure to serve the new load. If Idaho Power Company were unable to secure timely rate relief from the Idaho Public Utilities Commission, the Oregon Public Utility Commission or the Federal Energy Regulatory Commission to recover the costs of these additional investments, the resulting regulatory lag would have a negative effect on earnings and cash flows.
15
o Load growth can create planning and operating difficulties for Idaho Power Company that can negatively impact its ability to reliably serve customers.
Weather can reduce power sales and revenues and reduce earnings and cash flows. Warmer than normal winters, cooler than normal summers and increased rainfall during the irrigation seasons will reduce retail revenues from power sales and may impact the amount and timing of hydroelectric generation. Extreme weather events can disrupt transmission and distribution systems and cause service interruptions and extended outages, and potentially interrupt use of generation resources. Disruption in transmission and distribution systems increases operations and maintenance expenses and reduces earnings and cash flows.
Idaho Power Companys risk management policy and programs relating to hedging power and gas exposures and counterparty creditworthiness may not always perform as intended, and we may suffer economic losses. Idaho Power Company actively manages the market risk inherent in its energy related activities and counterparty credit positions. Idaho Power Company has procedures that monitor compliance with our risk management policies and programs, including verification of transactions, regular portfolio reporting of various risk management metrics and daily counterparty credit risk analysis. However, actual hydroelectric and thermal generation, transmission availability and market prices may be significantly different than those originally planned for when we enter into our risk management positions. The high volatility of these items creates uncertainty in the appropriate amount of hedging activity to pursue. Forecasts of future loads and available resources to meet those loads are inherently uncertain and may cause Idaho Power Company to over- or under-hedge actual resource needs, exposing the company to market risk on the over- or under-hedged position. Changes in market prices are also unpredictable and can at times result in Idaho Power Companys hedged positions performing less favorably than unhedged positions. In addition, Idaho Power Companys counterparty credit policies may not prevent counterparties from failing to perform, forcing the company to replace forward contracts with transactions in the open market. As a result, risk management decisions may have significant impacts if actual events result in greater losses or costs in delivering energy to customers and could negatively affect financial condition, results of operations or cash flows.
Increased capital expenditures can significantly affect liquidity. Increases in both the number of customers and the demand for energy require expansion and reinforcement of transmission and distribution systems and generating facilities. If Idaho Power Company does not receive timely regulatory recovery, Idaho Power Company will have to rely more on external financing for its future utility construction expenditures. These large planned expenditures may weaken the consolidated financial profile of IDACORP, Inc. and Idaho Power Company. Additionally, a significant portion of Idaho Power Companys facilities were constructed many years ago. Aging equipment, even if maintained in accordance with industry practices, may require significant capital expenditures. Failure of equipment or facilities used in Idaho Power Companys system could potentially increase repair and maintenance expenses, purchased power expenses and capital expenditures.
If the Idaho Public Utilities Commission, the Oregon Public Utility Commission or the Federal Energy Regulatory Commission grant less rate recovery in rate case filings than Idaho Power Company needs to cover increased costs of providing services, earnings and cash flows may be reduced. If the Idaho Public Utilities Commission, the Oregon Public Utility Commission or the Federal Energy Regulatory Commission grant less rate recovery in rate case filings than Idaho Power Company needs to cover increased costs of providing services, it may have a negative effect on earnings and cash flows and could result in downgrades of IDACORP, Inc.s and Idaho Power Companys credit ratings.
Climate change could affect customer demand and hydroelectric generation and disrupt transmission and distribution systems, reducing earnings and cash flows. Long-term climate change could affect Idaho Power Companys business in a variety of ways, including: (i) changes in temperature and precipitation could affect customer demand, (ii) extreme weather events could increase service interruptions, outages, and maintenance costs; (iii) changes in the amount and timing of snowpack and stream flows could adversely affect hydroelectric generation, and (iv) legislative and/or regulatory developments related to climate change could affect plans and operations including placing restrictions on the construction of new generation resources, the expansion of existing resources, or the operation of generation resources in general, and (v) consumer preference for, and resource planning decisions requiring, renewable or low GHG-emitting sources of energy could impact demand from existing sources and require significant investment in new generation and transmission resources. Any of these effects of climate change could reduce Idaho Power Companys earnings and cash flows.
16
Complying with environmental laws and regulations will increase capital expenditures and operating costs and may reduce Idaho Power Companys earnings and cash flows and ability to meet the electricity needs of its customers. Idaho Power Company is subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, natural resources and health and safety. Compliance with these environmental statutes, rules and regulations involves significant capital and operating expenditures. Congress is considering legislation to limit and reduce greenhouse gas emissions, and the Environmental Protection Agency is taking action to address climate change and regulate greenhouse gas emissions, including the adoption of new reporting requirements that apply to Idaho Power Companys facilities. The Environmental Protection Agency has also made an endangerment finding for greenhouse gas emissions from motor vehicles and has indicated that the Clean Air Act will require it to regulate carbon dioxide and other greenhouse gas emissions from major stationary sources, including Idaho Power Companys thermal facilities, once it adopts greenhouse gas emission standards for motor vehicles. The adoption of a mandatory federal program to reduce carbon dioxide and other greenhouse gas emissions would raise uncertainty about the future viability of fossil fuels, specifically coal, as an economical energy source for new and existing electric generation facilities. Mercury and other pollutant emissions from Idaho Power Companys thermal facilities are also subject to extensive regulation. The adoption of new statutes, rules and regulations to reduce emissions, including controls to reduce carbon dioxide, greenhouse gas, mercury or other pollutant emissions will result in increased capital expenditures and could increase the cost of operating coal-fired generating plants or make them uneconomical to operate and result in reduced earnings and cash flows.
Complying with state or federal renewable energy portfolio standards could increase capital expenditures and operating costs and reduce earnings and cash flows. A number of states have adopted renewable energy portfolio standards. Idaho Power Companys operations in Oregon will be required to comply with a ten percent renewable energy portfolio standard beginning in 2025, and it is possible that Idaho and other states in which Idaho Power Company operates or sells power could adopt renewable energy portfolio standards in the future. A bill passed by the U.S. House of Representatives on June 26, 2009, would, if enacted, require utilities to obtain as much as 20 percent of their electricity from renewable sources by 2020 and reduce demand by an additional 5 percent through conservation and increased energy efficiency. A bill pending in the U.S. Senate would require 15 percent of electricity from renewable sources by 2021. New state or federal renewable energy portfolio standards could increase capital expenditures and operating costs and reduce earnings and cash flows.
The listing as threatened or endangered under the Endangered Species Act of fish, wildlife or plant species that are found in the areas of Idaho Power Companys generation facilities or transmission lines may require mitigation, affect the location of a project or the ability to construct a project and result in increased capital expenditures and operating costs. Relicensing of the Hells Canyon and Swan Falls hydroelectric projects and the construction of Langley Gulch and the Gateway West and Boardman to Hemingway transmission lines require consultation under the Endangered Species Act to determine the effects of these projects on any listed species within the project areas. The recent listing of slickspot peppergrass as a threatened species will require an Endangered Species Act consultation for the transmission and water lines for Langley Gulch as well as for the Gateway West and Boardman to Hemingway transmission lines. This listing may also affect Idaho Power Companys ability to purchase wind power from any wind power farms that were to be built in these areas. Any negative effects of the listing of slickspot peppergrass or any other species under the Endangered Species Act may require mitigation, cause a delay in relicensing or construction of projects, affect the location or ability to construct a project and increase the costs of construction and operations.
Conditions that may be imposed in connection with hydroelectric license renewals may require large capital expenditures, increase operating costs, reduce hydroelectric production and reduce earnings and cash flows. Idaho Power Company is currently involved in renewing federal licenses for several of its hydroelectric projects. The Federal Energy Regulatory Commission may impose conditions with respect to environmental, operating and other matters in connection with the renewal of Idaho Power Companys licenses. These conditions could have a negative effect on Idaho Power Companys operations, require large capital expenditures and increase operating costs, reduce hydroelectric production and reduce earnings and cash flows.
17
Idaho Power Companys business is subject to substantial governmental regulation and may be adversely affected by increased costs resulting from, or liability under, existing or future regulations or requirements. Idaho Power Company is subject to extensive federal and state laws, policies, and regulations, as well as regulatory actions and regulatory audits, including those of the Federal Energy Regulatory Commission, the Environmental Protection Agency, the North American Electric Reliability Corporation, the Western Electricity Coordinating Council and the public utility commissions in Idaho, Oregon and Wyoming. Some of these regulations are changing or subject to interpretation, and failure to comply may result in penalties or other adverse consequences. Idaho Power Company has reported compliance issues to the Federal Energy Regulatory Commission, and the Western Electricity Coordinating Council has recently completed an audit of reliability standards. Compliance with these requirements directly influences Idaho Power Companys operating environment and may significantly increase Idaho Power Companys operating costs.
IDACORP, Inc., its affiliate IDACORP Energy and Idaho Power Company are subject to costs and other effects of legal and regulatory proceedings, settlements, investigations and claims. IDACORP, Inc., IDACORP Energy and Idaho Power Company are involved in a number of proceedings, including the California refund proceeding, a portion of which remains pending before the Federal Energy Regulatory Commission and the United States Court of Appeals for the Ninth Circuit; a refund proceeding affecting sellers of wholesale power in the spot market in the Pacific Northwest; and show cause proceedings originating at the Federal Energy Regulatory Commission, a portion of which remains pending in the United States Court of Appeals for the Ninth Circuit. It is possible that additional proceedings related to the western energy situation may be filed in the future against IDACORP, Inc., IDACORP Energy or Idaho Power Company. IDACORP, Inc. and Idaho Power Company are or may also be subject to costs and other effects of additional legal claims, actions and complaints, including those related to the Jim Bridger, Valmy and Boardman coal-fired plants, in which Idaho Power Company holds an ownership interest. State attorneys general have brought actions against companies, seeking additional disclosure of climate change-related risks and impacts, and private parties have brought tort actions against companies relating to their alleged contribution to climate change. If IDACORP, Inc., IDACORP Energy or Idaho Power Company are required to make payments in connection with any legal or regulatory proceeding, settlement, investigation or claim, earnings and cash flows could be negatively affected.
As a holding company, IDACORP, Inc. does not have its own operating income and must rely on the upstream cash flows from its subsidiaries to pay dividends and make debt payments. IDACORP, Inc. is a holding company and thus its primary assets are shares or other ownership interests of its subsidiaries, primarily Idaho Power Company. Consequently, IDACORP, Inc.s ability to pay dividends and to service its debt is dependent upon dividends and other payments received from its subsidiaries. IDACORP, Inc.s subsidiaries are separate and distinct legal entities and have no obligation to pay any amounts to IDACORP, Inc., whether through dividends, loans or other payments. The ability of IDACORP, Inc.s subsidiaries to pay dividends or make distributions to IDACORP, Inc. depends on several factors, including their actual and projected earnings and cash flow, capital requirements and general financial condition, regulatory restrictions, and the prior rights of holders of their existing and future first mortgage bonds and other debt securities.
A downgrade in IDACORP, Inc.s and Idaho Power Companys credit ratings could negatively affect the companies ability to access capital, increase their cost of borrowing, and require the companies to post collateral with transaction counterparties. Credit rating agencies periodically review the corporate credit ratings and long-term ratings of IDACORP, Inc. and Idaho Power Company. IDACORP, Inc. and Idaho Power Company also have borrowing arrangements that rely on the ability of the banks to fund loans or support commercial paper. Downgrades of IDACORP, Inc.s or Idaho Power Companys credit ratings, or those affecting relationship banks, could limit the companies ability to access capital, including the commercial paper markets, require the companies to pay a higher interest rate on their debt and require the companies to post collateral with transaction counterparties.
Volatility and decreased lending capacity in the financial markets may negatively affect IDACORP, Inc.s and Idaho Power Companys ability to access capital and/or increase their cost of borrowing. IDACORP, Inc. and Idaho Power Company require liquidity to pay operating expenses and principal of and interest on debt and to finance capital expenditures. Financial markets have experienced extreme volatility and disruption, causing the cost of borrowing to rise and the availability of liquidity and credit for borrowers to decrease; As a result, IDACORP, Inc. and Idaho Power Company may experience higher interest costs and/or be unable to access capital, including the commercial paper markets. These conditions may adversely affect IDACORP, Inc.s and Idaho Power Companys results of operations, financial condition and cash flows.
18
One or more of the banks participating in IDACORP, Inc.s and Idaho Power Companys credit facilities could default on their obligations to fund loans requested by the companies or could withdraw from participation in the credit facilities, which could negatively affect cash flows and the ability to meet capital requirements. IDACORP, Inc. and Idaho Power Company have $100 million and $300 million multi-year revolving credit facilities, respectively, with a group of lender banks that expire in April 2012. These facilities supplement operating cash flow and provide a primary source of liquidity. The facilities are also used as backup for commercial paper borrowings and are available for general corporate purposes. IDACORP, Inc. and Idaho Power Company are subject to the risk that one or more of the participating banks may default on their obligations to make loans under the credit facilities. IDACORP, Inc. and Idaho Power Companys inability to obtain loans under their respective credit facilities as needed could negatively affect cash flows and the ability to meet capital requirements.
IDACORP and Idaho Power Company may incur losses on their investments or be unable to sell their investments when they desire to do so, which could adversely affect their liquidity and financial condition. IDACORP and Idaho Power Company invest cash in short-term interest bearing accounts, including money market funds. Volatility in the financial markets may result in a lack of liquidity and declines in value of some money market funds. The companies may realize additional losses on some or all of their invested funds or be unable to sell their investments when they desire to do so. This could adversely affect IDACORPs and Idaho Power Companys liquidity and financial condition.
National and regional economic conditions may cause increased late payments and uncollectible accounts, which would reduce earnings and cash flows. Recent concerns over energy costs, the availability and cost of credit, declining business and increased unemployment have contributed to a recession. These factors have resulted, and may continue to result, in an increase in late payments and uncollectible accounts and reduce IDACORP Inc.s and Idaho Power Companys earnings and cash flows.
National and regional economic conditions, in conjunction with increased electric rates, may reduce energy consumption, which may reduce revenues and future growth. The present economic recession and increased rates may reduce the amount of energy our customers consume, result in a loss of customers and reduce customer growth. A decrease in overall customer usage may reduce revenues, earnings, and future growth.
Adverse results of income tax audits could reduce earnings and cash flows. The outcome of ongoing and future income tax audits could differ materially from the amounts currently recorded, and the difference could reduce IDACORPs and Idaho Power Companys earnings and cash flows.
Employee workforce factors could increase costs and reduce earnings. Idaho Power Company is subject to workforce factors, including, but not limited to, loss or retirement of key personnel, availability of qualified personnel, an aging workforce, and impacts of efforts to organize workforce, including the possible unionization of one or more segments of the workforce. The costs of attracting and retaining appropriately qualified employees to replace an aging workforce could reduce earnings and cash flows.
Terrorist threats and activities could result in reduced revenues and increased costs. IDACORP, Inc. and Idaho Power Company are subject to direct and indirect effects of terrorist threats and activities. Potential targets include generation and transmission facilities. The effects of terrorist threats and activities could prevent Idaho Power Company from purchasing, generating or transmitting power and result in reduced revenues and increased costs.
IDACORP, Inc. and Idaho Power Company could be vulnerable to security breaches or other similar events that could disrupt their operations, require significant capital expenditures and/or result in claims against the companies. In the normal course of business, Idaho Power Company collects, processes and retains sensitive and confidential customer and proprietary information. Despite the security measures in place, Idaho Power Companys facilities and systems, and those of third-party service providers, could be vulnerable to security breaches or other similar events that could interrupt operations, resulting in a shutdown of service and expose Idaho Power Company to liability. In addition, Idaho Power Company may be required to expend significant capital and other resources to protect against security breaches or to alleviate problems caused by security breaches.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None
ITEM 2. PROPERTIES
Idaho Powers system is comprised of 17 hydroelectric
generating plants located in southern Idaho and eastern Oregon, two natural
gas-fired plants located in southern Idaho and interests in three coal-fired
steam electric generating plants located in Wyoming, Nevada and Oregon. The
system also includes approximately 4,796 pole miles of high-voltage
transmission lines, 23 step-up transmission substations located at power
plants, 22 transmission substations, eight switching stations, 223 energized
distribution substations (excluding mobile substations and dispatch centers)
and approximately 26,675 pole miles of distribution lines.
Idaho Power holds FERC licenses for all of its hydroelectric
projects that are subject to federal licensing. These projects and the other
generating stations and their nameplate capacities are listed below:
|
Nameplate |
|
|||||
|
Capacity |
License |
|||||
Project |
(kW) |
Expiration |
|||||
Hydroelectric Developments: |
|
|
|
||||
|
Properties subject to federal licenses: |
|
|
|
|||
|
Lower Salmon |
60,000 |
2034 |
|
|||
|
Bliss |
75,000 |
2034 |
|
|||
|
Upper Salmon |
34,500 |
2034 |
|
|||
|
Shoshone Falls |
12,500 |
2034 |
|
|||
|
CJ Strike |
82,800 |
2034 |
|
|||
|
Upper Malad - Lower Malad |
21,770 |
2035 |
|
|||
|
Brownlee - Oxbow - Hells Canyon |
1,166,900 |
2005 |
(1) |
|||
|
Swan Falls |
27,170 |
2010 |
|
|||
|
American Falls |
92,340 |
2025 |
|
|||
|
Cascade |
12,420 |
2031 |
|
|||
|
Milner |
59,448 |
2038 |
|
|||
|
Twin Falls |
52,897 |
2040 |
|
|||
|
Other Hydroelectric: |
|
|
|
|||
|
Clear Lakes - Thousand Springs |
11,300 |
|
|
|||
|
|
Total Hydroelectric |
1,709,045 |
|
|
||
Steam and Other Generating Plants: |
|
|
|
||||
|
Jim Bridger (coal-fired) (2) |
770,501 |
|
|
|||
|
Valmy (coal-fired) (2) |
283,500 |
|
|
|||
|
Boardman (coal-fired) (2) |
64,200 |
|
|
|||
|
Danskin (gas-fired) |
270,900 |
|
|
|||
|
Salmon (diesel-internal combustion) |
5,000 |
|
|
|||
|
Bennett Mountain (gas-fired) |
172,800 |
|
|
|||
|
|
Total Steam and Other |
1,566,901 |
|
|
||
|
|
Total Generation |
3,275,946 |
|
|
||
|
|||||||
(1) Licensed on an annual basis while application for new multi-year license is pending. |
|||||||
(2) Idaho Powers ownership interests are 33 percent for Jim Bridger, 50 percent for Valmy and 10 percent for Boardman. Amounts shown represent Idaho Powers share. |
|||||||
|
|||||||
Relicensing of Idaho Powers hydroelectric projects is
discussed in Part II, Item 7 - MD&A RELICENSING OF HYDROELECTRIC
PROJECTS.
Idaho Power owns in fee all of its principal plants and
other important units of real property, except for portions of certain projects
licensed under the FPA and reservoirs and other easements. Idaho Powers property
is also subject to the lien of its Mortgage and Deed of Trust and the
provisions of its project licenses. In addition, Idaho Powers property is
subject to minor defects common to properties of such size and character that
do not materially impair the value to, or the use by, Idaho Power of such
properties. Idaho Power considers its properties to be well-maintained and in
good operating condition.
20
IERCo owns a one-third interest in Bridger Coal Company and
coal leases near the Jim Bridger generating plant in Wyoming from which coal is
mined and supplied to the plant.
Ida-West holds 50 percent interests in nine operating
hydroelectric plants with a total generating capacity of 45 MW. These plants
are located in Idaho and California.
Please see Note 10 to IDACORPs and Idaho Powers
consolidated financial statements.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
EXECUTIVE OFFICERS OF THE REGISTRANTS
The names, ages and positions of all of the executive
officers of IDACORP, Inc. and Idaho Power Company are listed below along with
their business experience during the past five years. Mr. J. LaMont Keen and
Mr. Steven R. Keen are brothers. There are no other family relationships among
these officers, nor is there any arrangement or understanding between any
officer and any other person pursuant to which the officer was elected.
J. LAMONT KEEN, 57
President and Chief Executive Officer of IDACORP, Inc., July 1, 2006 present.
President and Chief Executive Officer of Idaho Power Company, November 17, 2005 present.
Executive Vice President of IDACORP, Inc., March 1, 2002 July 1, 2006.
President and Chief Operating Officer of Idaho Power Company, March 1, 2002 November 17, 2005.
Senior Vice President Administration and Chief Financial Officer of IDACORP, Inc. and Idaho Power Company, May 1999 March 2002.
Member of the Boards of Directors of both IDACORP, Inc. and Idaho Power Company.
DARREL T. ANDERSON, 51
Executive Vice President Administrative Services and Chief Financial Officer of IDACORP, Inc. and Idaho Power Company, October 1, 2009 present.
Senior Vice President Administrative Services and Chief Financial Officer of IDACORP, Inc. and Idaho Power Company, July 1, 2004 October1, 2009.
Vice President, Chief Financial Officer and Treasurer of IDACORP, Inc. and Idaho Power Company, March 2002 July 2004
Vice President Finance and Treasurer of IDACORP, Inc. and Idaho Power Company, May 1999 March 2002.
DANIEL B. MINOR, 52
Executive Vice President Operations of Idaho Power Company, October 1, 2009 present.
Senior Vice President Delivery of Idaho Power Company, July 1, 2004 October 1, 2009.
Vice President Administrative Services & Human Resources of IDACORP, Inc. and Idaho Power Company, November 2003, July 2004
Vice President - Corporate Services of Idaho Power Company, May 2003 November 2003
Director of Audit Services of Idaho Power Company, July 2001 May 2003.
REX BLACKBURN, 54
Senior Vice President and General Counsel, IDACORP, Inc. and Idaho Power Company, April 1, 2009 present.
Lead Counsel of Idaho Power Company, January 1, 2008 March 31, 2009.
Lawyer at Blackburn and Jones, LLP, January 2003 December 31, 2007.
LISA A. GROW, 44
Senior Vice President Power Supply of Idaho Power Company, October 1, 2009 present.
Vice President Delivery Engineering and Operations of Idaho Power Company, July 20, 2005 September 30, 2009
General Manager of Grid Operations and Planning of Idaho Power Company, October 2004 July 20, 2005
Operations Manager (Grid Ops) of Idaho Power Company, March 2002 October 2004.
21
STEVEN R. KEEN, 49
Vice President and Treasurer of IDACORP, Inc. and Idaho Power Company, June 1, 2006 present.
President of IDACORP Financial Services, September 1998 May 31, 2007.
PATRICK A. HARRINGTON, 49
Corporate Secretary of IDACORP, Inc. and Idaho Power Company, March 15, 2007 present.
Senior Attorney, June 2003 March 15, 2007.
DENNIS C. GRIBBLE, 57
Vice President and Chief Information Officer of IDACORP, Inc. and Idaho Power Company, June 1, 2006 present.
Vice President and Treasurer of IDACORP, Inc. and Idaho Power Company, July 2004 June 1, 2006.
LORI D. SMITH, 49
Vice President Corporate Planning and Chief Risk Officer of IDACORP, Inc. and Idaho Power Company, January 1, 2008 present.
Vice President Finance and Chief Risk Officer of IDACORP, Inc. and Idaho Power Company, July 2004 January 1, 2008.
LUCI K. MCDONALD, 52
Vice President Human Resources of IDACORP, Inc. and Idaho Power Company, December 2004 present.
Corporate Staff Director of Human Resources of Boise Cascade Corporation, September 1999 November 2004.
NAOMI SHANKEL, 38
Vice President, Audit and Compliance of IDACORP, Inc. and Idaho Power Company, September 21, 2006 present.
Director, Audit Services of IDACORP, Inc. and Idaho Power Company, July 2003 September 21, 2006.
JEFFREY MALMEN, 42
Vice President Public Affairs of IDACORP, Inc. and Idaho Power Company, October 1, 2008 present.
Senior Manager Governmental Affairs of IDACORP, Inc. and Idaho Power Company, December xx, 2007 October 1, 2008
Chief of Staff of the Office of Idaho Governor C.L. Butch Otter, January 2007 November 2007
Chief of Staff of the Office of Idaho Congressman C.L. Butch Otter, January 2001 December 2006.
JOHN R. GALE, 59
Vice President Regulatory Affairs of Idaho Power Company, March 2001 present.
WARREN KLINE, 54
Vice President Customer Service and Regional Operations of Idaho Power Company, July 20, 2005 present.
General Manager of Regional Operations of Idaho Power Company, March 2002 July 20, 2005.
N. VERN PORTER, 50
Vice President Delivery Engineering and Operations, Idaho Power Company, October 1, 2009 present.
General Manager of Power Production of Idaho Power Company, April 22, 2006 October1, 2009.
Senior Manager of Power Supply Operations of Idaho Power Company, August 2003 April 22, 2006.
22
PART II
ITEM 5. MARKET FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
IDACORPs common stock, without par value, is traded on the
New York Stock Exchange. On February 19, 2010, there were 13,803 holders of
record and the stock price was $33.02 per share.
The outstanding shares of Idaho Powers common stock, $2.50
par value, are held by IDACORP and are not traded. IDACORP became the holding
company of Idaho Power on October 1, 1998.
The amount and timing of dividends paid on IDACORPs common
stock are within the sole discretion of IDACORPs Board of Directors. The
Board of Directors reviews the dividend rate quarterly to determine its
appropriateness in light of IDACORPs current and long-term financial position
and results of operations, capital requirements, rating agency requirements,
legislative and regulatory developments affecting the electric utility industry
in general and Idaho Power in particular, competitive conditions and any other
factors the Board of Directors deems relevant. The ability of IDACORP to pay dividends
on its common stock is dependent upon dividends paid to it by its subsidiaries,
primarily Idaho Power.
A covenant under IDACORPs credit facility and Idaho Powers
credit facility described in MD&A - LIQUIDITY AND CAPITAL RESOURCES -
Financing Programs Credit Facilities requires IDACORP and Idaho Power to
maintain leverage ratios of consolidated indebtedness to consolidated total
capitalization, as defined, of no more than 65 percent at the end of each
fiscal quarter.
Idaho Powers Revised Code of Conduct approved by the IPUC
on April 21, 2008, states that Idaho Power will not pay any dividends to
IDACORP that will reduce Idaho Powers common equity capital below 35 percent
of its total adjusted capital without IPUC approval. Idaho Power must obtain
approval of the OPUC before it could directly or indirectly loan funds or issue
notes or give credit on its books to IDACORP.
Idaho Powers ability to pay dividends on its common stock
held by IDACORP and IDACORPs ability to pay dividends on its common stock are
limited to the extent payment of such dividends would violate the covenants or
Idaho Powers Code of Conduct. At December 31, 2009, the leverage ratios for
IDACORP and Idaho Power were 51 percent and 53 percent, respectively. Based on
these restrictions, IDACORPs and Idaho Powers dividends were limited to $608
million and $514 million, respectively, at December 31, 2009.
Idaho Powers articles of incorporation contain restrictions
on the payment of dividends on its common stock if preferred stock dividends
are in arrears. Idaho Power has no preferred stock outstanding. IDACORP and
Idaho Power paid dividends of $57 million, $54 million and $53 million in 2009,
2008 and 2007, respectively.
The following table shows the reported high and low sales
price of IDACORPs common stock and dividends paid for 2009 and 2008 as
reported in the consolidated transaction reporting system.
|
Quarters |
||||||||
Common Stock, without par value: |
1st |
2nd |
3rd |
4th |
|||||
2009 |
|
|
|
|
|||||
|
High |
$ |
30.47 |
$ |
26.20 |
$ |
29.56 |
$ |
32.83 |
|
Low |
|
20.91 |
|
22.22 |
|
24.68 |
|
27.71 |
|
Dividends paid per share |
|
0.30 |
|
0.30 |
|
0.30 |
|
0.30 |
2008 |
|
|
|
|
|
|
|
|
|
|
High |
$ |
35.11 |
$ |
33.36 |
$ |
33.89 |
$ |
30.66 |
|
Low |
|
28.74 |
|
28.55 |
|
27.96 |
|
21.88 |
|
Dividends paid per share |
|
0.30 |
|
0.30 |
|
0.30 |
|
0.30 |
|
|
|
|
|
|
|
|
|
|
Issuer Purchases of Equity Securities:
23
None
Performance Graph
The following performance graph
shows a comparison of the five-year cumulative total shareholder return for
IDACORP common stock, the S&P 500 Index and the Edison Electric Institute
(EEI) Electric Utilities Index. The data assumes that $100 was invested on
December 31, 2004, with beginning-of-period weighting of the peer group indices
(based on market capitalization) and monthly compounding of returns.
Source: Bloomberg and Edison Electric Institute
|
|
|
EEI Electric |
|||
|
IDACORP |
S & P 500 |
Utilities Index |
|||
2004 |
$ |
100.00 |
$ |
100.00 |
$ |
100.00 |
2005 |
|
99.86 |
|
104.91 |
|
116.05 |
2006 |
|
136.18 |
|
121.46 |
|
140.14 |
2007 |
|
128.56 |
|
128.13 |
|
163.34 |
2008 |
|
111.83 |
|
80.73 |
|
121.03 |
2009 |
|
126.99 |
|
102.10 |
|
133.99 |
|
|
|
|
|
|
|
The foregoing performance graph and data shall not be deemed
filed as part of this Form 10-K for purposes of Section 18 of the Securities
Exchange Act of 1934 or otherwise subject to the liabilities of that section
and should not be deemed incorporated by reference into any other filing of
IDACORP or Idaho Power under the Securities Act of 1933 or the Securities
Exchange Act of 1934, except to the extent IDACORP or Idaho Power specifically
incorporates it by reference into such filing.
ITEM 6. SELECTED FINANCIAL DATA
IDACORP, Inc. |
|||||||||||
SUMMARY OF OPERATIONS |
|||||||||||
(thousands of dollars except per share amounts) |
|||||||||||
|
|
2009 |
|
2008 |
|
2007 |
|
2006 |
|
2005 |
|
Operating revenues |
$ |
1,049,800 |
$ |
960,414 |
$ |
879,394 |
$ |
926,291 |
$ |
842,864 |
|
Operating income |
|
203,583 |
|
190,667 |
|
152,078 |
|
169,704 |
|
154,653 |
|
Income from continuing operations |
|
124,375 |
|
98,245 |
|
81,803 |
|
100,075 |
|
85,716 |
|
Diluted earnings per share from |
|
|
|
|
|
|
|
|
|
|
|
|
continuing operations |
|
2.64 |
|
2.17 |
|
1.86 |
|
2.34 |
|
2.02 |
Dividends declared per share |
|
1.20 |
|
1.20 |
|
1.20 |
|
1.20 |
|
1.20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial Condition: |
|
|
|
|
|
|
|
|
|
|
|
Total assets |
$ |
4,238,727 |
$ |
4,022,845 |
$ |
3,653,308 |
$ |
3,445,130 |
$ |
3,364,126 |
|
Long-term debt (including current portion) |
|
1,419,070 |
|
1,269,979 |
|
1,168,336 |
|
1,023,773 |
|
1,039,852 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial Statistics: |
|
|
|
|
|
|
|
|
|
|
|
Times interest charges earned: |
|
|
|
|
|
|
|
|
|
|
|
|
Before tax (1) |
|
2.88 |
|
2.47 |
|
2.35 |
|
2.78 |
|
2.65 |
|
After tax (2) |
|
2.59 |
|
2.23 |
|
2.16 |
|
2.54 |
|
2.37 |
Book value per share (3) |
$ |
29.23 |
$ |
27.85 |
$ |
26.89 |
$ |
25.76 |
$ |
23.96 |
|
Market-to-book ratio (4) |
|
109% |
|
106% |
|
131% |
|
151% |
|
121% |
|
Payout ratio (5) |
|
45% |
|
55% |
|
65% |
|
48% |
|
79% |
|
Return on year-end common equity(6) |
|
8.9% |
|
7.5% |
|
6.8% |
|
9.5% |
|
6.2% |
|
|
|
|
|
|
|
|
|
|
|
|
|
The financial statistics listed above are calculated in the following manner: |
|||||||||||
(1) The sum of interest on long-term debt, other interest expense excluding the allowance for funds used during construction credits (AFUDC),and income before income taxes divided by the sum of interest on long-term debt and other interest expense excluding AFUDC credits. |
|||||||||||
(2) The sum of interest on long-term debt, other interest expense excluding AFUDC credits, and income from continuing operations divided by the sum of interest on long-term debt and other interest expense excluding AFUDC credits. |
|||||||||||
(3) Total equity at the end of the year divided by shares outstanding at the end of the year. |
|||||||||||
(4) The closing price of IDACORP stock on the last day of the year divided by the book value per share, which is described in (3) above |
|||||||||||
(5) Dividends paid per common share for the year divided by earnings per diluted share of the year. |
|||||||||||
(6) Net income divided by total equity at the end of the year. |
|||||||||||
|
In the second quarter of 2006, IDACORP management designated
the operations of two subsidiaries, IDACORP Technologies, Inc. and IDACOMM as
assets held for sale, and the companies were sold in July 2006 and February
2007, respectively. IDACORPs consolidated financial statements reflect the reclassification
of the results of these businesses as discontinued operations for all periods
presented. Beginning January 1, 2009, noncontrolling interests (previously
known as minority interests) were required to be classified as equity.
IDACORPs consolidated financial statements reflect the reclassification of
noncontrolling interests to equity for all periods presented.
ITEM 7. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
(Dollar amounts and Megawatt-hours (MWh) are in thousands
unless otherwise indicated).
INTRODUCTION:
In Managements Discussion and Analysis of Financial
Condition and Results of Operations (MD&A), the general financial condition
and results of operations for IDACORP, Inc. and its subsidiaries (collectively,
IDACORP) and Idaho Power Company and its subsidiary (collectively, Idaho Power)
are discussed.
IDACORP is a holding company formed in 1998 whose principal
operating subsidiary is Idaho Power. IDACORP is subject to the provisions of the
Public Utility Holding Company Act of 2005, which provides certain access to
books and records to the Federal Energy Regulatory Commission (FERC) and state
utility regulatory commissions and imposes certain record retention and
reporting requirements on IDACORP.
25
Idaho Power is an electric utility with a service territory
covering approximately 24,000 square miles in southern Idaho and eastern
Oregon. Idaho Power is regulated by the FERC and the state regulatory
commissions of Idaho and Oregon. Idaho Power is the parent of Idaho Energy
Resources Co., (IERCo) a joint venturer in Bridger Coal Company, which supplies
coal to the Jim Bridger generating plant owned in part by Idaho Power.
IDACORPs other subsidiaries include:
IDACORP Financial Services, Inc. (IFS), an investor in affordable housing and other real estate investments;
Ida-West Energy Company (Ida-West), an operator of small hydroelectric generation projects that satisfy the requirements of PURPA; and
IDACORP Energy (IE), a marketer of energy commodities, which wound down operations in 2003.
On February 23, 2007, IDACORP completed the sale of all of
the outstanding common stock of IDACOMM to American Fiber Systems, Inc.
While reading the MD&A, please refer to the accompanying
consolidated financial statements of IDACORP and Idaho Power, which present the
financial position at December 31, 2009 and 2008, and the results of operations
and cash flows for each company for the years ended December 31, 2009, 2008 and
2007.
FORWARD-LOOKING INFORMATION:
In connection with the safe harbor provisions of the Private
Securities Litigation Reform Act of 1995, IDACORP and Idaho Power are hereby
filing cautionary statements identifying important factors that could cause
actual results to differ materially from those projected in forward-looking
statements, as such term is defined in the Reform Act, made by or on behalf of
IDACORP or Idaho Power in this Annual Report on Form 10-K, in presentations, in
response to questions or otherwise. Any statements that express, or involve
discussions as to expectations, beliefs, plans, objectives, assumptions or
future events or performance, often, but not always, through the use of words
or phrases such as anticipates, believes, estimates, expects,
intends, plans, predicts, projects, may result, may continue or
similar expressions, are not statements of historical facts and may be
forward-looking. Forward-looking statements involve estimates, assumptions and
uncertainties and are qualified in their entirety by reference to, and are
accompanied by, the following important factors, which are difficult to
predict, contain uncertainties, are beyond IDACORPs or Idaho Powers control
and may cause actual results to differ materially from those contained in
forward-looking statements:
The effect of regulatory decisions by the Idaho Public Utilities Commission, the Oregon Public Utility Commission and the Federal Energy Regulatory Commission affecting our ability to recover costs and/or earn a reasonable rate of return including, but not limited to, the disallowance of costs that have been deferred;
Changes in and compliance with state and federal laws, policies and regulations, including new interpretations by oversight bodies, which include the Federal Energy Regulatory Commission, the North American Electric Reliability Corporation, the Western Electricity Coordinating Council, the Idaho Public Utilities Commission and the Oregon Public Utility Commission, of existing policies and regulations that affect the cost of compliance, investigations and audits, penalties and costs of remediation that may or may not be recoverable through rates;
Changes in tax laws or related regulations or new interpretations of applicable law by the Internal Revenue Service or other taxing jurisdiction;
Litigation and regulatory proceedings, including those resulting from the energy situation in the western United States, and penalties and settlements that influence business and profitability;
Changes in and compliance with laws, regulations and policies including changes in law and compliance with environmental, natural resources and endangered species laws, regulations and policies and the adoption of laws and regulations addressing greenhouse gas emissions, global climate change, and energy policies;
Global climate change and regional weather variations affecting customer demand and hydroelectric generation;
26
Over-appropriation of surface and groundwater in the Snake River Basin resulting in reduced generation at hydroelectric facilities;
Construction of power generation, transmission and distribution facilities, including an inability to obtain required governmental permits and approvals, rights-of-way and siting, and risks related to contracting, construction and start-up;
Operation of power generating facilities including performance below expected levels, breakdown or failure of equipment, availability of transmission and fuel supply;
Changes in operating expenses and capital expenditures, including costs and availability of materials, fuel and commodities;
Blackouts or other disruptions of Idaho Power Companys transmission system or the western interconnected transmission system;
Population growth rates and other demographic patterns;
Market prices and demand for energy, including structural market changes;
Increases in uncollectible customer receivables;
Fluctuations in sources and uses of cash;
Results of financing efforts, including the ability to obtain financing or refinance existing debt when necessary or on favorable terms, which can be affected by factors such as credit ratings, volatility in the financial markets and other economic conditions;
Actions by credit rating agencies, including changes in rating criteria and new interpretations of existing criteria;
Changes in interest rates or rates of inflation;
Performance of the stock market, interest rates, credit spreads and other financial market conditions, as well as changes in government regulations, which affect the amount and timing of required contributions to pension plans and the reported costs of providing pension and other postretirement benefits;
Increases in health care costs and the resulting effect on medical benefits paid for employees;
Increasing costs of insurance, changes in coverage terms and the ability to obtain insurance;
Homeland security, acts of war or terrorism;
Natural disasters and other natural risks, such as earthquake, flood, drought, lightning, wind and fire;
Adoption of or changes in critical accounting policies or estimates; and
New accounting or Securities and Exchange Commission requirements, or new interpretation or application of existing requirements.
Any forward-looking statement speaks only as of the date on
which such statement is made. New factors emerge from time to time and it is
not possible for management to predict all such factors, nor can it assess the
impact of any such factor on the business or the extent to which any factor, or
combination of factors, may cause results to differ materially from those
contained in any forward-looking statement.
EXECUTIVE OVERVIEW:
Business Strategy
IDACORPs business strategy emphasizes Idaho Power as
IDACORPs core business. Idaho Power detailed a three-part strategy of
responsible planning, responsible development and protection of resources, and
responsible energy use to ensure adequate energy supplies. Idaho Power
continues to evaluate and refine its business strategy to ensure coordination
and integration with all functional areas of the company. Idaho Powers
business strategy balances the interest of owners, customers and employees
while maintaining the companys financial stability and flexibility. The
strategy includes:
RESPONSIBLE PLANNING: Idaho Powers planning process is
intended to ensure adequate generation and transmission resources to meet
population growth and increasing electricity demand. This planning process now
integrates Idaho Powers regulatory strategies and financial planning,
including the consideration of regional economic development in the growing
communities we serve.
27
RESPONSIBLE DEVELOPMENT AND PROTECTION OF RESOURCES: Idaho
Powers business strategy has included the development and protection of
generation, transmission, distribution and associated infrastructure, and
natural resources Idaho Power depends upon. The strategy now includes
consideration of workforce planning, development and retention related to these
strategic elements.
RESPONSIBLE ENERGY USE: Idaho Powers business strategy has
included energy efficiency and demand response programs and preparation for
potential carbon and renewable portfolio standard legislation. The strategy
now includes targeted reductions relating to carbon emission intensity and public
disclosure of reporting these reductions.
2009 Financial Results
IDACORPs net income and earnings per diluted share for the
last three years were as follows:
|
2009 |
2008 |
2007 |
|||
Net Income Attributable to IDACORP, Inc. |
$ |
124,350 |
$ |
98,414 |
$ |
82,339 |
Average outstanding shares - diluted (000s) |
|
47,182 |
|
45,379 |
|
44,365 |
Earnings per diluted share |
$ |
2.64 |
$ |
2.17 |
$ |
1.86 |
|
|
|
|
|
|
|
The following table presents a reconciliation of IDACORP net
income for 2008 to 2009 (in millions):
Net Income Attributable to IDACORP, Inc. - 2008 |
|
|
$ |
98.4 |
|
Change in Idaho Power net income before taxes: |
|
|
|
|
|
|
Rate and other regulatory changes, net of PCA and FCA mechanisms |
$ |
48.8 |
|
|
|
Reduced sales volumes |
|
(23.3) |
|
|
|
Increase in other operations and maintenance expense, excluding FCA |
|
(2.8) |
|
|
|
Increase in depreciation expense |
|
(8.5) |
|
|
|
2008 OATT rate refund |
|
5.0 |
|
|
|
2008 investment impairment |
|
6.8 |
|
|
|
Other net increases |
|
0.3 |
|
|
Decrease in income tax expense |
|
2.1 |
|
|
|
|
Total increase in Idaho Power net income |
|
|
|
28.4 |
Decreased net income at IFS (net of tax) |
|
|
|
(2.9) |
|
Decrease in expenses at holding company (net of tax) |
|
|
|
0.7 |
|
Other net decreases (net of tax) |
|
|
|
(0.2) |
|
|
Net Income Attributable to IDACORP, Inc. - 2009 |
|
|
$ |
124.4 |
|
|
|
|
|
Changes to the Idaho power cost adjustment (PCA)
mechanism and base rate increases that both took effect in the first quarter of
2009, positively impacted net income as did decreased net power supply costs.
Earnings in 2009 also increased due to a May 2009 Oregon Public Utility
Commission (OPUC) stipulation allowing the deferral for future recovery of $6.4
million of excess power supply costs incurred in 2007.
Idaho Powers retail customer sales volumes decreased
four percent in 2009 as compared to 2008. Irrigation usage decreased 14
percent primarily due to increased precipitation. Economic factors and energy
conservation also contributed to the reduction in sales volume.
Other O&M expense increased due to an increase in
payroll related expenses and uncollectible accounts and was partially offset by
decreases in outside services and other office expenses. Depreciation expense
increased mainly due to the accelerated depreciation of the existing meter
infrastructure. Two items that positively impacted the comparison of 2009 to
2008 results relate to 2008 activities that did not recur in 2009; an OATT rate
refund ordered by the FERC that reduced transmission revenue and an impairment
of investments.
Idaho Powers 2009 effective income tax rate decreased
primarily due to examination settlements and the timing and amount of other
regulatory flow-through tax adjustments, partially offset by the tax expense on
higher pre-tax income.
There was no accelerated amortization of deferred
investment tax credits during 2009 as the Idaho jurisdictional earnings
exceeded 9.5 percent of the Idaho retail common equity, as permitted by the
Idaho 2009 settlement agreement.
28
Regulatory Matters
Idaho Power has a number of pending or recently completed
regulatory filings. Regulatory matters are discussed in more detail later in
the MD&A.
Idaho 2009 Settlement Agreement: In January 2010,
the IPUC approved a settlement agreement among Idaho Power, several of Idaho
Powers customers, the IPUC staff and others with respect to rates for 2009
2011. The settlement contains four important elements: (1) a general rate freeze
until January 1, 2012, with some exceptions; (2) a specified distribution of
the expected 2010 PCA decrease to directly reduce customer rates, providing
some general rate relief to Idaho Power and resetting base level power supply
costs for the PCA going forward; (3) use of investment tax credits to get to a
9.5 percent return on equity in the Idaho jurisdiction; and (4) an equal
sharing of any Idaho earnings exceeding the authorized level of 10.5 percent.
Oregon 2009 General Rate Case: In December 2009,
Idaho Power filed a Joint Stipulation and testimony in support of a stipulation
that would settle the revenue requirement issues surrounding the general rate
case filed on July 31, 2009. If approved by the OPUC, the Joint Stipulation
would result in a $5 million, or 15.4 percent, increase to base rates. The new
rates reflect a return on equity of 10.175 percent and an overall rate of
return of 8.061 percent. The requested effective date for new rates is March
1, 2010.
Oregon 2010 Annual Power Cost Update: In October
2009, Idaho Power filed the October Update portion of its 2010 annual power
cost update (APCU). The filing reflects that revenues associated with Idaho
Powers base net power supply costs would increase $2.6 million over the
previous October Update, an average 8.2 percent increase. The actual impact of
the 2010 APCU will be determined once the March Forecast portion is filed in
March 2010 and combined with the October Update. Final rates are expected to
become effective on June 1, 2010.
Oregon Excess Power Cost Deferrals May-December 2007
Excess Power Costs: In May 2009, the OPUC adopted a stipulation allowing
Idaho Power to defer excess net power supply costs of $6.4 million (including
interest through the date of the order) for the period May 1 through December
31, 2007. Idaho Power recorded this deferral in the second quarter of 2009.
Idaho and Oregon Rate Orders: Idaho Power received
five additional rate orders from the IPUC and the OPUC at the end of May 2009.
The IPUC rate orders are for the Fixed Cost Adjustment mechanism, Idaho Energy
Efficiency Rider, Advanced Metering Infrastructure (AMI), and PCA, and the OPUC
rate order is for the Annual Power Cost Update. Each of these orders increases
rates, but only the AMI order, relating to the installation of new meters,
increases Idaho Powers rate base.
Open Access Transmission Tariff (OATT) Amended Legacy
Agreements: In 2009, Idaho Power submitted filings to the FERC to increase
rates under two agreements Idaho Power has with PacifiCorp and to terminate
certain contract services, replacing them with OATT service. The FERC accepted
one of Idaho Powers filings, effective June 13, 2009, for a net annualized
revenue increase of $3.2 million. The FERC accepted the second filing and
suspended the rates, setting the case for settlement judge procedures and
hearing. Idaho Power began collecting the new rates effective August 19, 2009,
with a net annualized revenue increase of $3.7 million. Settlement discussions
are ongoing. The impact of these revised agreements on 2010 transmission
revenue is expected to be a $3.8 million increase as compared with 2009.
Integrated Resource Plan (IRP): Idaho Power filed
the 2009 IRP with the IPUC and OPUC in December, 2009. The IRP addresses
available supply-side and demand-side resource options, planning period load
forecasts, potential resource portfolios, a risk analysis and near-term and
long-term action plans.
Liquidity
29
IDACORP and Idaho Power expect to continue financing capital
requirements with a combination of internally generated funds and externally
financed capital. In 2009, IDACORP issued 489,360 common stock shares through
its continuous equity program at an average price of $28.79 per share for
proceeds of $14 million. In March 2009, Idaho Power issued $100 million of its
6.15% First Mortgage Bonds and in November 2009, Idaho Power issued $130
million of its 4.5% First Mortgage Bonds. In December 2009, Idaho Power repaid
$80 million of its 7.2% First Mortgage Bonds. These matters are discussed in
more detail in LIQUIDITY AND CAPITAL RESOURCES later in the MD&A.
Capital Requirements: Idaho Power has several major projects in development.
The most significant projects are summarized here and are discussed further in
LIQUIDITY AND CAPITAL RESOURCES Capital Requirements Major Projects.
Langley Gulch power plant: Langley Gulch will be a natural gas-fired combined cycle combustion turbine (CCCT) generating plant with a summer nameplate capacity of approximately 300 MWs and a winter capacity of approximately 330 MWs. The plant will be constructed at an estimated cost of $427 million near New Plymouth, Idaho commencing in summer 2010, and is anticipated to achieve commercial operation by November 1, 2012. Contract incentives may advance the commercial operation date to July 1, 2012. Idaho Power received cost recovery and ratemaking assurances from the IPUC for this project.
Transmission Projects: The Boardman-Hemingway Line is a
proposed 500-kV line between a substation near Boardman, Oregon and the
Hemingway substation. Idaho Power estimates total construction costs of $600
million and expects its share of the project to be between 30 and 50 percent.
Idaho Power estimates the project will be completed in 2015. Idaho Power and
PacifiCorp are jointly exploring Gateway West, a project to build transmission
lines between Windstar, a substation located near Douglas, Wyoming and Hemingway
substation. The current estimated cost for Idaho Powers share of the project
is between $300 million and $500 million. Initial phases of the project could
be completed by 2014. Idaho Powers share may change and the timing of the
projects segments may be deferred and constructed as demand requires.
Pension Plan: As Idaho Powers pension plan is below
the minimum required funding levels at January 1, 2010, future minimum
contributions are required. Based on the assumptions allowed under the PPA,
WRERA, Treasury guidance and IRS guidance, IDACORP and Idaho Power were not
required to contribute to the pension plan in 2009, and estimated minimum
required contributions will be approximately $6 million in 2010, $44 million in
2011, $47 million in 2012, $39 million in 2013, and $40 million in 2014. On
October 20, 2009, Idaho Power filed an application with the IPUC requesting the
clarification of a pension recovery method for cash contributions made to the
pension plan. On February 17, 2010, the IPUC approved a recovery methodology
that would permit Idaho Power to include in future rate cases a reasonable
amortization and recovery of cash contributions. The amortization of deferred
pension costs is expected to match the revenues received as future pension
contributions are recovered through rates. Approximately $29 million, $8
million and $3 million of pension expenses were deferred as a regulatory asset
in 2009, 2008, and 2007, respectively.
Other Issues
Water Management Issues: Power generation at the
Idaho Power hydroelectric power plants on the Snake River depends on the state
water rights held by Idaho Power and the long-term sustainability of the Snake
River, tributary spring flows and the Eastern Snake Plain Aquifer that is
connected to the Snake River. Idaho Power continues to participate in water
management issues in Idaho that may affect those water rights and resources
with the goal to preserve, to the fullest extent possible, the long-term
availability of water for use at Idaho Powers hydroelectric projects on the
Snake River. For a further discussion of water management issues see LEGAL
MATTERS Snake River Basin Water Rights.
Environmental Issues: Long-term climate change could
significantly affect Idaho Powers business and climate change regulations are
expected to have major implications for Idaho Power and the energy industry.
On September 17, 2009, IDACORPs and Idaho Powers Board of Directors approved
guidelines that established a goal to reduce the carbon dioxide (CO2)
emission intensity of Idaho Powers utility operations. The guidelines are
intended to further prepare Idaho Power for potential legislative and/or
regulatory restrictions on greenhouse gas (GHG) emissions while minimizing the
costs of complying with such restrictions on Idaho Powers customers.
30
Idaho Power, along with its partners in its coal plants, is
required to monitor and report quarterly to the Environmental Protection Agency
(EPA) their GHG emissions beginning January 1, 2010. The EPA has indicated
that it will begin to regulate GHG emissions from stationary sources, including
Idaho Powers facilities, through its new source review and operating permit
programs when the regulations relating to GHG emissions from motor vehicles are
finalized. Idaho Powers thermal facilities are also subject to EPA and/or
state-promulgated (i) national ambient air quality standards including those
for ozone and fine particulate matter, (ii) laws and regulations limiting
mercury emissions, (iii) regional haze best available retrofit technology
requirements and (iv) new source review and performance standards. Idaho
Powers environmental compliance costs will continue to be significant for the
foreseeable future, particularly in light of possible additional regulation at
the federal and state levels. These issues are discussed in more detail in
ENVIRONMENTAL ISSUES.
Boardman Coal Plant: On January 14, 2010, Portland General Electric
announced that it intended to pursue an alternative operating plan, subject to
regulatory approval for its Boardman coal-fired electricity generation plant.
Under the plan, near-term expenditures for pollution control equipment would be
significantly reduced and the plant would either cease to operate in 2020, or
it would discontinue the use of coal as a fuel source. Idaho Power is a ten
percent owner of the plant, representing 64,200 kW of nameplate capacity. At
December 31, 2009, Idaho Powers net book value in the Boardman plant was $20
million with annual depreciation of approximately $1.2 million.
American Recovery and Reinvestment Act of 2009:
Under the ARRA, Idaho Power submitted a grant application to the Department of
Energy (DOE) in August 2009, requesting $47 million. This grant would match a
$47 million investment by Idaho Power in Smart Grid technology as well as other
incremental projects. In October 2009, Idaho Power received notice that its
application was selected for negotiation. Negotiations with the DOE on the
grant agreement terms are expected to be completed in the first quarter of
2010.
Key Operating and Financial Metrics
|
2010 |
2009 |
|
|
Estimate |
Actual |
|
Idaho Power Operation & Maintenance Expense (Millions) |
$295-$305 |
$293 |
|
Idaho Power Capital Expenditures (Millions) |
$355-$365 |
$273 |
|
Idaho Power Hydroelectric Generation (Million MWh) |
6.5-8.5 |
8.1 |
|
Non-regulated subsidiary earnings and holding company expenses (Millions) |
$0-$3.0 |
$1.8 |
|
Effective Income Tax Rates: |
|
|
|
|
Idaho Power |
13% - 17% |
23% |
|
Consolidated IDACORP |
6% - 10% |
15% |
|
|
|
|
The range for capital expenditures includes amounts for
Langley Gulch power plant, the Hemingway-Bowmont transmission line, the
Hemingway substation and expenditures for the siting and permitting of major
transmission expansions for the Boardman to Hemingway and Gateway West
transmission projects.
The projected range for annual hydroelectric generation is
based on 2009-2010 Snake River Basin snowpack at 60 percent of average on
February 21, 2010, with reservoir storage levels in selected federal reservoirs
upstream of Brownlee at approximately 118 percent of average as of February 21,
2010.
The effective income tax rate ranges include the utilization
of up to $25 million of additional deferred investment tax credit (ADITC)
amortization at Idaho Power. The rates do not reflect discrete events such as
examination settlements or method changes.
RESULTS OF OPERATIONS:
This section of the MD&A takes a closer look at the
significant factors that affected IDACORPs and Idaho Powers earnings over the
last three years. In this analysis, the results of 2009 are compared to 2008
and the results of 2008 are compared to 2007.
The following table presents earnings (losses) for IDACORP
and its subsidiaries:
31
|
2009 |
2008 |
2007 |
||||
Idaho Power |
$ |
122,559 |
$ |
94,115 |
$ |
76,579 |
|
IDACORP Financial Services |
|
521 |
|
3,426 |
|
7,112 |
|
IDACORP Energy |
|
(238) |
|
406 |
|
(171) |
|
Ida-West Energy |
|
2,727 |
|
2,353 |
|
2,223 |
|
Holding company expenses |
|
(1,219) |
|
(1,886) |
|
(3,471) |
|
Discontinued operations |
|
- |
|
- |
|
67 |
|
|
Net Income Attributable to IDACORP, Inc. |
$ |
124,350 |
$ |
98,414 |
$ |
82,339 |
Average outstanding shares - diluted (000s) |
|
47,182 |
$ |
45,379 |
|
44,365 |
|
Earnings per diluted share |
$ |
2.64 |
|
2.17 |
$ |
1.86 |
|
|
|
|
|
|
|
|
|
Utility Operations
Operating environment: Idaho Power primarily uses
its hydroelectric and coal-fired generation facilities and long-term power
purchase agreements to supply the energy needed to serve customers. Regional
energy market purchases and sales are used to balance supply and demand
throughout the year.
Idaho Power develops operation plans during the year to
provide guidance for generation resource utilization and energy market
activities. Idaho Powers energy risk management policy and unit operating
requirements provide the framework for the plans. The plans incorporate
forecasts for generation unit availability, reservoir storage and stream flows,
gas and coal prices, customer loads and energy market prices.
In developing its plans, Idaho Power determines to what
extent its own resources can be used to meet forecast loads and when to
transact in the regional energy market. The allocation of hydroelectric
generation between heavy load and light load hours or calendar periods is also
a consideration. This allocation is intended to utilize the flexibility of the
hydroelectric system to shift generation to high value periods, while operating
within the constraints imposed on the system.
Hydroelectric generation depends on stream flows in the
Snake River, on which most of Idaho Powers hydroelectric facilities are
built. Stream flows are dependent on the amount of snow pack in the mountains
upstream of Idaho Powers hydroelectric facilities, springtime snow pack
run-off, river base flows, spring flows, rainfall and other weather and stream
flow management considerations. Idaho Power also leases water from third
parties to augment stream flows and increase its ability to meet mid-summer
electricity demands with lower-cost hydroelectric generation and to offset the
impact of drought and changing water use patterns in southern Idaho.
When hydroelectric generation is reduced, Idaho Power has
less electricity available for off-system sales and, most likely, will increase
its use of purchased power to meet load requirements, resulting in increased
power supply costs. During good water years, increased off-system sales and
the decreased need for purchased power reduce power supply costs.
Regional energy market prices can also be affected by
hydroelectric generating conditions. In times with high hydroelectric
generation the availability of abundant energy tends to reduce wholesale
prices, and during low hydroelectric generation wholesale prices tend to be
higher.
A combination of increased precipitation, higher reservoir
storage releases and the purchase of leased water resulted in 8.1 million MWh
generated from Idaho Powers hydroelectric facilities in 2009, compared to 6.9
million MWh in 2008 and 6.2 million in 2007. Hydroelectric generation was
99
percent of the 30-year average in 2009. The observed stream flow data released
in August 2009, by the U.S. Army Corps of Engineers, Northwest Division
indicated that Brownlee reservoir inflow for April through July 2009 was 5.6
million acre-feet (maf), compared to 4.4 maf in April-July 2008. Annual
Brownlee reservoir inflow for 2009 was 11.3 maf, or 70 percent of the NWRFC
average compared to 10.1 maf in 2008 and 8.5 maf in 2007. Storage in selected
federal reservoirs upstream of Brownlee as of February 21, 2010, was 118
percent of average. The stream flow forecast released on February 19, 2010, by
the NWRFC predicts that Brownlee reservoir inflow for April through July 2010
will be 2.9 maf, or 46 percent of the NWRFC average.
The following table presents
Idaho Powers energy sales and supply (in MWhs) for the last three years:
32
|
2009 |
2008 |
2007 |
||||
General business sales |
|
13,948 |
|
14,544 |
|
14,542 |
|
Off-system sales |
|
2,836 |
|
2,048 |
|
2,744 |
|
|
Total energy sales |
|
16,784 |
|
16,592 |
|
17,286 |
Hydroelectric generation |
|
8,096 |
|
6,908 |
|
6,181 |
|
Coal generation |
|
6,941 |
|
7,279 |
|
7,145 |
|
Natural gas and other generation |
|
242 |
|
217 |
|
222 |
|
|
Total system generation |
|
15,279 |
|
14,404 |
|
13,548 |
Purchased power |
|
2,912 |
|
3,716 |
|
5,196 |
|
Line losses |
|
(1,407) |
|
(1,528) |
|
(1,458) |
|
|
Total energy supply |
|
16,784 |
|
16,592 |
|
17,286 |
|
|
|
|
|
|
|
Idaho Powers modeled median
annual hydroelectric generation is 8.6 million MWh, based on hydrologic
conditions for the period 1928 through 2009 and adjusted to reflect the current
level of water resource development.
General Business Revenue: Rate actions have
significantly impacted general business revenue over the last three years. The
following table presents significant rate increases during that period. These
and other rate actions are discussed further in REGULATORY MATTERS and in
Note 3 to the consolidated financial statements.
|
|
Percentage |
Annualized $ |
|
Description |
Effective Date |
Increase |
increase (millions) |
|
2007-2008 PCA |
6/1/2007 |
14.5 |
$ |
78 |
2007 Idaho general rate case |
3/1/2008 |
5.2 |
|
32 |
2008-2009 PCA |
6/1/2008 |
10.7 |
|
73 |
Danskin Plant |
6/1/ 2008 |
1.37 |
|
9 |
2008 Idaho general rate case |
2/1/2009 |
3.1 |
|
21 |
2008 Idaho general rate case |
3/19/2009 |
0.9 |
|
6 |
2009-2010 PCA |
6/1/2009 |
10.2 |
|
84 |
AMI |
6/1/2009 |
1.8 |
|
11 |
|
|
|
|
|
The primary influences on electricity sales volumes are
weather, customer demand and economic conditions. Extreme temperatures
increase sales to customers who use electricity for cooling and heating, and
moderate temperatures decrease sales. Precipitation levels during the
agricultural growing season affect sales to customers who use electricity to
operate irrigation pumps. Increased precipitation reduces electricity usage by
these customers. The following table presents Boise, Idaho weather conditions
for the last three years:
|
2009 |
2008 |
2007 |
Normal |
Heating degree-days (1) |
5,612 |
5,586 |
5,128 |
5,727 |
Cooling degree-days (1) |
1,188 |
1,068 |
1,290 |
807 |
Precipitation (inches) |
11.3 |
9.3 |
8.1 |
12.1 |
(1) Heating and cooling degree-days are common measures used in the utility industry to analyze the demand for electricity and indicate when a customer would use electricity for heating and air conditioning. A degree-day measures how much the average daily temperature varies from 65 degrees. Each degree of temperature above 65 degrees is counted as one cooling degree-day, and each degree of temperature below 65 degrees is counted as one heating degree-day. |
||||
|
33
The following table presents Idaho Powers general business
revenues, MWh sales and average and year-end number of customers for the last
three years:
|
2009 |
2008 |
2007 |
|||||
Revenue |
|
|
|
|
|
|
||
|
Residential |
$ |
409,479 |
$ |
353,262 |
$ |
308,208 |
|
|
Commercial |
|
232,816 |
|
203,035 |
|
170,001 |
|
|
Industrial |
|
141,530 |
|
122,302 |
|
101,409 |
|
|
Irrigation |
|
109,655 |
|
105,712 |
|
88,685 |
|
|
Deferred revenue related to Hells Canyon relicensing AFUDC |
|
(9,715) |
|
- |
|
- |
|
|
|
Total |
$ |
883,765 |
$ |
784,311 |
$ |
668,303 |
MWh |
|
|
|
|
|
|
||
|
Residential |
|
5,300 |
|
5,297 |
|
5,227 |
|
|
Commercial |
|
3,858 |
|
3,970 |
|
3,937 |
|
|
Industrial |
|
3,140 |
|
3,355 |
|
3,454 |
|
|
Irrigation |
|
1,650 |
|
1,922 |
|
1,924 |
|
|
|
Total |
|
13,948 |
|
14,544 |
|
14,542 |
Customers (average) |
|
|
|
|
|
|
||
|
Residential |
|
405,144 |
|
402,520 |
|
397,285 |
|
|
Commercial |
|
64,151 |
|
63,492 |
|
61,640 |
|
|
Industrial |
|
127 |
|
122 |
|
126 |
|
|
Irrigation |
|
18,753 |
|
18,401 |
|
18,043 |
|
|
|
Total |
|
488,175 |
|
484,535 |
|
477,094 |
Customers (year-end) |
|
|
|
|
|
|
||
|
Residential |
|
406,631 |
|
404,373 |
|
400,637 |
|
|
Commercial |
|
64,349 |
|
64,125 |
|
62,765 |
|
|
Industrial |
|
129 |
|
125 |
|
123 |
|
|
Irrigation |
|
18,818 |
|
18,542 |
|
18,126 |
|
|
|
Total |
|
489,927 |
|
487,165 |
|
481,651 |
|
|
|
|
|
|
|
|
|
2009 vs. 2008:
Rates: Rate changes positively impacted general business
revenue by $128 million in 2009 as compared to 2008. PCA rate increases
accounted for $79 million of the increases and base rate changes contributed
$49 million. Also, a new tiered rate structure for residential and small
commercial customers was implemented February 1, 2009, as part of the general
rate case. The table below presents the residential rates by tier.
Idaho Residential Rate Structure |
|||||
February 1, 2008 |
Summer |
Non-Summer |
February 1, 2009 |
Summer |
Non-Summer |
0-300 kWh |
5.6973 cents |
5.6973 cents |
0-800 kWh |
5.9750 cents |
5.5792 cents |
Above 300 kWh |
6.4125 cents |
5.6973 cents |
801-2,000 kWh |
7.2798 cents |
6.1991 cents |
|
|
|
Above 2,000 kWh |
8.7358 cents |
7.1290 cents |
Customers: General business revenues increased $10 million due to customer growth of one percent.
Usage: Changes in usage decreased general business
revenue $38 million. Irrigation usage decreased 14 percent primarily due to
increased precipitation. Commercial and industrial usage also declined due to
a weaker economy and increased energy efficiency. Idaho Power does have in
place the Load Growth Adjustment Rate (LGAR) and FCA mechanisms, both of which
diminish the impact of changes in sales volumes from levels included in base rates.
2008 vs. 2007:
Rates: Rate changes positively impacted general business revenue by $114 million in 2008 as compared to 2007. PCA rate increases accounted for $82 million of the increases and base rate changes contributed $31 million of the increase.
Customers: General business customer growth of two percent increased revenue $8 million.
34
Usage: Changes in usage, primarily resulting from cooler
summer temperatures, decreased general business revenue $5 million.
Off-system sales: Off-system sales consist primarily
of long-term sales contracts and opportunity sales of surplus system energy.
The following table presents Idaho Powers off-system sales for the last three
years:
|
2009 |
2008 |
2007 |
|||
Revenue |
$ |
94,373 |
$ |
121,429 |
$ |
154,948 |
MWh sold |
|
2,836 |
|
2,048 |
|
2,744 |
Revenue per MWh |
$ |
33.28 |
$ |
59.29 |
$ |
56.47 |
|
|
|
|
|
|
|
2009 vs. 2008: Off-system sales revenue declined 22
percent in 2009 due to lower market prices, partially offset by increased
sales. Prices for wholesale power in the Northwest were much lower than in
2008 due to an abundance of energy in the region during the spring and fall and
due to lower energy commodity prices. Improved hydroelectric generating
conditions and lower system load increased the amount of electricity available
for sale.
The off-system sales revenue per MWh is nearly 40 percent
lower than the purchased power cost per MWh. In accordance with Idaho Powers
risk management policy, Idaho Power made forward purchases of energy for
delivery in the third quarter of 2009. Most of the purchases were identified
and made months in advance when market prices were higher. In the third
quarter, reduced demand and improved generating conditions caused regional
energy market prices to drop and Idaho Power to have additional surplus energy
available for sale off-system into that lower price energy market.
2008 vs. 2007: Off-system sales revenue declined 22
percent in 2008. Sales volumes decreased due to changes to Idaho Powers risk
management policy guidelines implemented in 2008 that resulted in less forward
sales activity. Revenue per MWh increased due to the impact of higher energy
commodity prices through much of 2008.
Other revenues: The following table presents the
components of other revenues:
|
2009 |
2008 |
2007 |
||||
Transmission services and property rental |
$ |
36,037 |
$ |
31,456 |
$ |
38,663 |
|
Energy efficiency |
|
31,821 |
|
18,880 |
|
13,487 |
|
|
Total |
$ |
67,858 |
$ |
50,336 |
$ |
52,150 |
|
|
|
|
|
|
|
|
2009 vs. 2008: Other revenues increased $18 million due mainly to the following:
Transmission revenues increased $5 million due primarily to OATT rate refunds ordered by the FERC reducing 2008 revenues. Idaho Power recorded approximately $4 million of refunds related to transmission sales from prior years. The OATT is discussed in more detail in Note 3 to the consolidated financial statements; and
Energy efficiency revenues increased $13 million. These revenues
mirror program expenditures and result in a zero net impact on net income.
Energy efficiency revenues and expenses have steadily increased as program
activity has increased.
2008 vs. 2007: Other revenues decreased $2 million due mainly to the following:
Transmission revenues decreased $7 million, due primarily to the aforementioned OATT rate refunds and to OATT rate decreases; and
Energy efficiency revenues increased $5 million.
Energy efficiency activities are funded through a rider
mechanism on customer bills. Energy efficiency program expenditures are
reported as an operating expense with an equal amount of revenues recorded in
other revenues, resulting in no net impact on earnings. The cumulative
variance between expenditures and amounts collected through the rider is
recorded as a regulatory asset or liability pending future collection from or
obligation to customers. An asset balance indicates that Idaho Power has spent
more than it has collected and a liability balance indicates that Idaho Power
has collected more than it has spent. At December 31, 2009, Idaho Powers
rider balance was a regulatory asset of $11 million.
35
Purchased power: The following table presents Idaho
Powers purchased power expenses and volumes:
|
2009 |
2008 |
2007 |
|||
Expense |
$ |
160,569 |
$ |
231,137 |
$ |
289,484 |
MWh purchased |
|
2,912 |
|
3,716 |
|
5,196 |
Cost per MWh purchased |
$ |
55.14 |
$ |
62.20 |
$ |
55.71 |
|
|
|
|
|
|
|
2009 vs. 2008: Purchased power expense decreased $71
million due to lower system load and more favorable hydroelectric generating
conditions, which decreased the amount of purchased power Idaho Power needed to
serve loads.
2008 vs. 2007: Purchased power expense decreased $58
million due to improved hydroelectric generation
conditions and more normal weather, which allowed Idaho Power to better utilize
its own generation resources. Despite improved water conditions in the
region, overall market prices remained higher early in the year due to a
gradual spring runoff and a need to re-fill reservoirs. In addition, increases
in energy commodity prices impacted the electricity market.
Fuel expense: The following table presents Idaho
Powers fuel expenses and generation at its coal and natural gas generating
plants:
|
2009 |
2008 |
2007 |
|||||
Expense |
|
|
|
|
|
|
||
|
Coal |
$ |
130,234 |
$ |
132,015 |
$ |
114,837 |
|
|
Natural gas and other |
|
19,332 |
|
17,388 |
|
19,485 |
|
|
|
Total fuel expense |
$ |
149,566 |
$ |
149,403 |
$ |
134,322 |
MWh generated |
|
|
|
|
|
|
||
|
Coal |
|
6,941 |
|
7,279 |
|
7,145 |
|
|
Natural gas and other |
|
242 |
|
217 |
|
222 |
|
|
|
Total MWh generated |
|
7,183 |
|
7,496 |
|
7,367 |
Cost per MWh |
|
|
|
|
|
|
||
|
Coal |
$ |
18.76 |
$ |
18.14 |
$ |
16.07 |
|
|
Natural gas |
$ |
79.88 |
$ |
80.13 |
$ |
87.77 |
|
|
Weighted average, all sources |
$ |
20.82 |
$ |
19.93 |
$ |
18.23 |
|
|
|
|
|
|
|
|
2009 vs. 2008: Fuel expense remained nearly the same
due to offsetting variances. The decrease in generation is due to lower system
loads and lower wholesale energy prices, which resulted in reduced dispatch due
to economics, and an unplanned mid-year maintenance outage at Boardman. Coal
prices were higher in 2009 due to an increase in operating costs at Bridger
Coal Company, which supplies coal to the Jim Bridger plant, as well as higher
prices for coal delivered to the Boardman plant.
2008 vs. 2007: Fuel expense increased $15 million
due to higher coal prices at the Valmy and Jim Bridger plants. Coal prices at
Valmy increased 13 percent due to higher transportation costs. Production
costs at Bridger Coal Company were 13 percent higher due to difficulties with
its underground longwall mining operation in January and February, the
continued transition to underground mining operations, and rising prices for
fuel and other commodities. The increases were partially offset by a nine
percent reduction in fuel expense at Idaho Powers natural gas fired plants,
which had favorable market conditions in the fourth quarter due to pipeline
transportation constraints in the region.
PCA: PCA expense represents the effects of the Idaho
and Oregon power supply costs deferral mechanisms, which are discussed in more
detail below in REGULATORY MATTERS Power Supply Cost Deferrals. In each
year presented, net power supply costs were higher than the amounts estimated
in the annual PCA forecast, resulting in the deferral of costs for recovery in
subsequent rate years. As the deferred costs are recovered in rates, the
deferred balances are amortized.
36
The following table presents the components of the PCA:
|
2009 |
2008 |
2007 |
||||
Idaho power supply cost deferral |
$ |
(42,533) |
$ |
(108,688) |
$ |
(118,850) |
|
Oregon power supply cost deferral |
|
184 |
|
(5,196) |
|
(1,994) |
|
Oregon 2007 excess power cost order |
|
(6,358) |
|
- |
|
- |
|
Amortization of prior year authorized balances |
|
115,417 |
|
66,471 |
|
(287) |
|
|
Total power cost adjustment |
$ |
66,710 |
$ |
(47,413) |
$ |
(121,131) |
|
|
|
|
|
|
|
|
2009 vs. 2008: The $114 million change in the PCA is
due primarily to lower deferral of power supply costs and higher amortization
of previously deferred power supply costs. In addition, an order from the OPUC
that allows Idaho Power to defer for future recovery $6 million of costs
incurred in 2007 was recorded in May 2009.
2008 vs. 2007: The $74 million change in 2008 PCA
expense is due primarily to higher amortization from prior year excess net
power supply costs to match increased revenues.
Other operations and maintenance (O&M) expenses:
2009 vs. 2008: Other O&M expenses increased $6 million due
primarily to an $8 million increase in labor related charges and a $2 million
increase in charges for uncollectible accounts, partially offset by decreases
of $4 million in legal, other contracted services and office supplies due to
cost containment measures.
The deterioration of the economy across Idaho Powers
service area led to an increase in uncollectible accounts to approximately $5
million representing approximately a half percent of general business revenues
for 2009. The reserve for uncollectible accounts has also increased over 2008
levels most notably the residential and commercial reserves.
2008 vs. 2007: Other O&M expenses increased $8
million due mainly to an $11 million increase in labor related charges, a $2
million increase due to new water leases, a $2 million increase in uncollectible
accounts due to economic conditions, and an increase of $4 million for workers
compensation, legal and other outside services. The increases were partially
offset by a $6 million decrease in FCA charges, a $3 million decrease in
transmission costs due to lower purchased power volumes and lower thermal
O&M expense of $4 million due to lower annual outage costs.
Energy efficiency: Energy efficiency activities are
funded through a rider mechanism on customer bills. Energy efficiency program
expenditures are reported as an operating expense with an equal amount of
revenues recorded in other revenues, resulting in no net impact on earnings.
Energy efficiency expenses were $32 million, $19 million and $14 million in
2009, 2008 and 2007, respectively.
Gain on the sale of emission allowances: Gain on
sale of emission allowances was $0.3 million, $0.5 million and $3 million in
2009, 2008 and 2007, respectively. The bulk of Idaho Powers accumulated
excess emission allowances were sold from 2005 to 2007.
Non-utility Operations
IFS: IFS contributed $1 million, $3 million and $7
million to net income in 2009, 2008 and 2007, respectively; principally from
the generation of federal income tax credits and accelerated tax depreciation
benefits related to its investments in affordable housing and historic
rehabilitation developments.
IFS made $14 million in new investments in 2009 and $8
million in 2008. IFS generated tax credits of $8 million, $11 million and $15
million during 2009, 2008 and 2007, respectively. IFS will continue to pursue
new opportunities for investment commensurate with the ongoing needs of
IDACORP.
Ida-West: Ida-West had net income of $3 million in
2009 and $2 million in 2008 and 2007. Ida-West continues to hold joint venture
investments in independent power projects.
37
Energy Marketing: In 2003, IE wound down its power
marketing operations, closed its business locations and sold its forward book
of electricity trading contracts to Sempra Energy Trading. In 2007, all
trading contracts expired. IE has not recorded any material net income for the
years presented. Currently, IE has no operations but has been working to
settle outstanding legal matters surrounding transactions in the California
energy markets in 2000 and 2001.
Discontinued Operations: Discontinued operations
presents the results of operations of IDACOMM, Inc. prior to its sale in early
2007.
Income Taxes
Idaho Power is currently evaluating a tax accounting method change that
would allow a current income tax deduction for repair related expenditures on
its utility assets that are currently capitalized for book and tax purposes.
The deduction would be computed for tax years 1999 and forward. Idaho Power
has the ability to apply for this method change following the automatic consent
procedures and could make such application with the filing of IDACORPs 2009
consolidated federal income tax return in September 2010. Idaho Powers
prescribed regulatory accounting treatment requires immediate income
recognition for temporary tax differences of this type. A regulatory asset is
established to reflect Idaho Powers ability to recover increased income tax
expense when such temporary differences reverse.
Status of audit proceedings:
In December 2008, the IRS began its examination of IDACORPs 2006 tax
year. The 2006 exam was completed in May 2009. The IRS began its examination
of IDACORPs 2007-2008 tax years in July 2009 and completed the exam in
December. The 2006 examination report was submitted to the U.S. Congress Joint
Committee on Taxation (JCT) for review in June 2009 and was accepted without
change in July. Tax years 2007-2008 did not require JCT review. The
settlement of these years resulted in a net income tax benefit of $4 million
for 2009 at both IDACORP and Idaho Power.
In May 2009, IDACORP formally
entered the IRS Compliance Assurance Process (CAP) program for its 2009 tax
year. The CAP program provides for IRS examination throughout the year. The
2009 examination is expected to be completed in 2010. In January 2010, IDACORP
was accepted into CAP for its 2010 tax year. IDACORP and Idaho Power are
unable to predict the outcome of these examinations.
Specifically within the 2009 CAP examination, the IRS began
its audit of Idaho Powers current method of uniform capitalization. In
September 2009, the IRS issued Industry Director Directive #5 (IDD) which
discusses the IRSs compliance priorities and audit techniques related to the
allocation of mixed service costs in the uniform capitalization methods of
electric utilities. The IRS and Idaho Power are jointly evaluating the impact
the IDD guidance has on Idaho Powers uniform capitalization method. Idaho
Power expects that the examination will be completed during 2010.
LIQUIDITY AND CAPITAL RESOURCES:
Operating Cash Flows
IDACORPs operating cash flows are driven principally by
Idaho Power. General business revenues and the costs to supply power to
general business customers are factors that have the greatest impact on Idaho
Powers operating cash flows, and are subject to risks and uncertainties
relating to weather and water conditions and Idaho Powers ability to obtain
rate relief to cover its operating costs and provide a return on investment.
IDACORPs and Idaho Powers operating cash inflows for the
year ended December 31, 2009, were $284 million and $272 million,
respectively. These amounts were an increase of $148 million and $153 million,
respectively, compared to the year ended December 31, 2008. The following are
significant items that affected operating cash flows in 2009:
In 2009, PCA rates more closely matched actual net power supply costs than in 2008. This more timely recovery of current costs improved cash flows by approximately $65 million compared to 2008. In addition, the collection of deferred net power supply costs increased $49 million compared to 2008.
Changes in net cash paid and refunded for income taxes improve cash flows by $42 million and $50 million at IDACORP and Idaho Power, respectively, primarily due to audit settlements.
38
A refund of $13 million was made to Idaho Powers transmission customers upon a final order from the FERC on Idaho Powers OATT. The OATT is discussed further in Note 3 to the consolidated financial statements.
Net income increased by approximately $26 million and $28 million
at IDACORP and Idaho Power, respectively, compared to 2008.
IDACORPs and Idaho
Powers operating cash flows for the year ended December 31, 2008 were $137
million and $120 million, respectively. These amounts were an increase of $56
million and $38 million, respectively, compared to the year ended December 31,
2007. The following are significant items that affected operating cash flows
in 2008:
Collection of previously deferred net power supply costs increased $66 million compared to 2007.
Income tax payments increased $17 million and $33 million for IDACORP and Idaho Power, respectively, due to the timing of and increases in taxable income.
Investing Cash Flows
Idaho Powers construction expenditures were $252 million,
$244 million and $287 million in 2009, 2008 and 2007, respectively. Idaho
Power is experiencing a cycle of heavy infrastructure investment needed to
address customer growth, peak demand growth, and aging plant and equipment.
Net proceeds from the sales of emission allowances provided
investing cash of approximately $2 million, $3 million and $20 million in 2009,
2008 and 2007, respectively. The changes were primarily caused by changes in
the number of allowances sold each year as well as changes in market prices.
In August 2007, Idaho Power
reimbursed IDACORP for the $44 million refundable tax deposit IDACORP made on
Idaho Powers behalf with the IRS related to a disputed income tax assessment.
In May 2008, Idaho Power withdrew $20 million from the deposit and in December
2008 the remainder of the deposit was applied to accrued taxes and interest.
Income tax matters are discussed further in Note 2 to the consolidated
financial statements.
In 2009 and 2008, Idaho Power had cash inflows of $2 million
and $5.7 million, respectively, from the sale of Southwest Intertie Project
rights-of-way. IDACORP made cash investments in affordable housing through IFS
of $6 million and $8 million in 2009 and 2008, respectively. In 2009, IFS
received $9 million from the sale of investments.
Financing Cash Flows
Debt: On December 1, 2009, Idaho Power repaid $80
million of its 7.2% First Mortgage Bonds. On November 20, 2009, Idaho Power
issued $130 million of its 4.5% First Mortgage Bonds, Secured Medium Term
Notes, Series H, due March 1, 2020. On August 20, 2009, Idaho Power completed
the remarketing of its $166.1 million Pollution Control Revenue Refunding Bonds
and on August 25, 2009, Idaho Power used the proceeds from the remarketed bonds
plus other funds to prepay its $170 million Term Loan Credit Agreement. The
Pollution Control Revenue Refunding Bonds and Term Loan Credit Agreement are
discussed further in Note 4 to the consolidated financial statements. On March
30, 2009, Idaho Power issued $100 million of its 6.15% First Mortgage Bonds,
Secured Medium-Term Notes, Series H, due April 1, 2019. On February 27, 2009,
IFS repaid $7 million of its outstanding debt. IDACORP and Idaho Power reduced
short-term debt by $94 million and $109 million, respectively.
On July 10, 2008, Idaho Power issued $120 million of its
6.025% First Mortgage Bonds, Secured Medium-Term Notes, Series H, due July 15,
2018. On October 18, 2007, Idaho Power issued $100 million of 6.25% First
Mortgage Bonds, Secured Medium-Term Notes, Series G, due October 15, 2037. On
June 22, 2007, Idaho Power issued $140 million of 6.30% First Mortgage Bonds,
Secured Medium-Term Notes, Series F, due June 15, 2037. These issuances were
used to retire short-term and long-term debt and finance capital expenditures.
39
Equity: IDACORP has entered into Sales Agency
Agreements as a means of selling its common stock from time to time in
at-the-market offerings. Under these agreements IDACORP sold 881,337 shares in
2007 at an average price of $32.32. In 2008, IDACORP sold 1,453,967 shares an
average price of $28.72. In 2009, IDACORP received $14 million, net of agents
fees, from the issuance of 489,360 shares. The average price of the shares
sold was $28.79. IDACORPs current Sales Agency Agreement is with BNY Mellon
Capital Markets, LLC. As of December 31, 2009, there were 2.1 million shares
remaining on the current agency agreement.
IDACORP uses original issue common stock for its Dividend Reinvestment and
Stock Purchase Plan and 401(k) plan for the purpose of adding additional common
equity to its capital structure. Under these plans, IDACORP issued 366,673
shares in 2009, 280,250 shares in 2008 and 250,020 shares in 2007, for proceeds
of $9.6 million, $8.4 million and $8.4 million, respectively.
IDACORP issued 25,800 shares in 2009, 30,700 shares in 2008
and 10,070 shares in 2007, in connection with the exercise of stock options,
for proceeds of $0.6 million, $0.9 million and $0.3 million, respectively.
IDACORP and Idaho Power paid dividends of $57 million, $54
million and $53 million in 2009, 2008 and 2007, respectively. IDACORP made
capital contributions of $20 million, $37 million and $51 million to Idaho
Power in 2009, 2008 and 2007, respectively.
Financing Programs
IDACORPs consolidated capital structure consisted of common
equity of 49 percent and debt of 51 percent at December 31, 2009. Idaho
Powers consolidated capital structure consisted of common equity of 47 percent
and debt of 53 percent at December 31, 2009.
Shelf Registrations: IDACORP currently has
approximately $574 million remaining on its shelf registration statement that
can be used for the issuance of debt securities and common stock. Effective
with the November 20, 2009, issuance noted above, Idaho Power has no securities
remaining registered on its shelf registration statement. Idaho Power intends
to file a new shelf registration statement that can be used for the issuance of
first mortgage bonds and unsecured debt. Please see Note 4 to IDACORPs and
Idaho Powers consolidated financial statements for more information regarding
long-term financing arrangements.
Credit Facilities: IDACORP and Idaho Power each have
a five-year credit agreement that terminates on April 25, 2012, which is used
for general corporate purposes and commercial paper back-up and provides for
the issuance of loans and standby letters of credit. IDACORPs facility
permits borrowings of up to $100 million at any one time outstanding, which may
be increased upon request to $150 million. Idaho Powers facility permits
borrowings of up to $300 million at any one time outstanding, which may be
increased upon request to $450 million. Each company may request one-year
extensions of the then existing termination date. Interest on borrowings under
the facilities is a Eurodollar rate or a floating rate, plus a margin
determined by the companys ratings on its senior unsecured long-term debt
securities. The companies also pay a utilization fee and a facility fee.
Each facility contains a covenant requiring a leverage ratio
of consolidated indebtedness to consolidated total capitalization of no more
than 65 percent as of the end of each fiscal quarter. At December 31, 2009,
the leverage ratio for IDACORP was 51 percent and for Idaho Power was 53
percent. There are additional covenants, subject to exceptions, that prohibit
or restrict: certain investments or acquisitions; mergers or sale or
disposition of property without consent; the creation of certain liens; and any
agreements restricting dividend payments to the company from any material
subsidiary. At December 31, 2009, IDACORP and Idaho Power were in compliance
with all facility covenants.
The events of default under the facilities include: nonpayment
of principal, interest and fees, when due or subject to a grace period;
materially false representations or warranties; breach of covenants, subject in
some instances to grace periods; bankruptcy or insolvency-related events;
default in the payment of indebtedness in excess of $25 million, defaults that
will permit acceleration of such debt, or the acceleration of any of such debt;
the acquisition of 20 percent of the outstanding voting shares of the company;
the failure of IDACORP to own all of the outstanding voting stock of Idaho
Power; unfunded liabilities of all single employer plans under the Employee
Retirement Income Security Act of 1974 (ERISA) exceeding $75 million; and
environmental proceedings, investigations or violations of law, which could
reasonably be expected to have a material adverse effect.
40
The facilities were amended effective February 2, 2010 at
the request of IDACORP and Idaho Power because of their concern about
continuing compliance with the unfunded liability provisions. The amendments
removed representations and default provisions relating to unfunded liabilities
of all single employer plans in excess of $75 million and replaced them with
representations and default provisions relating to meeting the minimum funding
standards and not requesting a funding waiver under the Internal Revenue Code
or ERISA. Unfunded liabilities will now be relevant and measured only upon
notice of termination of a plan and will then constitute a default only if they
exceed $75 million.
A default or an acceleration of indebtedness of IDACORP or
Idaho Power in excess of $25 million, including indebtedness under the
applicable facility, will result in a cross default under the other facility.
Upon any bankruptcy or insolvency-related event of default, the obligations of
the lenders to make loans under the facility will automatically terminate and
all unpaid obligations will become due and payable. Upon any other event of
default, the lenders holding 51 percent of the outstanding loans or of the aggregate
commitments may terminate or suspend the obligations to make loans or declare
the obligations to be due and payable.
A ratings downgrade would result in an increase in the cost
of borrowing, but would not result in a default or acceleration of the debt
under the facilities. If Idaho Powers ratings are downgraded below investment
grade, Idaho Power must extend or renew its authority for borrowings under its
IPUC and OPUC regulatory orders. The IPUC order provides that Idaho Powers
authority will continue for 364 days from such downgrade, if Idaho Power
promptly notifies the IPUC and files to continue its original authority to
borrow. The Oregon statutes permit the issuance of short-term debt without
approval of the OPUC.
Without additional approval from the IPUC, the OPUC and the
Public Service Commission of Wyoming, the aggregate amount of short-term
borrowings by Idaho Power at any one time outstanding may not exceed $450
million.
The following table outlines available liquidity as of
December 31, 2009 and 2008.
|
IDACORP(2) |
Idaho Power |
||||||
|
2009 |
2008 |
2009 |
2008 |
||||
|
|
|||||||
Revolving credit facility |
$ |
100,000 |
$ |
100,000 |
$ |
300,000 |
$ |
300,000 |
Commercial paper outstanding |
|
(53,750) |
|
(13,400) |
|
- |
|
(108,950) |
Floating rate draw |
|
- |
|
(25,000) |
|
- |
|
- |
Identified for other use (1) |
|
- |
|
- |
|
(24,245) |
|
(24,245) |
Net balance available |
$ |
46,250 |
$ |
61,600 |
$ |
275,755 |
$ |
166,805 |
(1) Port of Morrow and American Falls bonds that holders may put to Idaho Power. |
||||||||
(2) Holding company only. |
||||||||
|
At February 19, 2010, IDACORP had no loans and $25 million
of commercial paper outstanding and Idaho Power had no loans and no commercial
paper outstanding.
Certain of Idaho Powers derivative instruments contain
provisions that require Idaho Powers unsecured debt to maintain an investment
grade credit rating from each of the major credit rating agencies. If Idaho
Powers unsecured debt were to fall below investment grade, it would be in
violation of these provisions, and the counterparties to the derivative
instruments could request immediate payment or demand immediate and ongoing
full daily collateralization on derivative instruments in net liability
positions. Credit-contingent features are also discussed in Note 15 to the
consolidated financial statements.
Credit Ratings
Access to capital markets at a
reasonable cost is determined in large part by credit quality. The following
table outlines the current S&P, Moodys and Fitch Ratings, Inc. (Fitch)
ratings of IDACORPs and Idaho Powers securities:
41
|
S&P |
Moodys |
Fitch |
|||
|
Idaho Power |
IDACORP |
Idaho Power |
IDACORP |
Idaho Power |
IDACORP |
Corporate Credit Rating |
BBB |
BBB |
Baa 1 |
Baa 2 |
None |
None |
Senior Secured Debt |
A- |
None |
A3 |
None |
A- |
None |
Senior Unsecured Debt |
BBB |
BBB- |
Baa 1 |
Baa 2 |
BBB+ |
BBB |
Short-Term Tax-Exempt Debt |
BBB-/A-2 |
None |
Baa 1/ |
None |
None |
None |
|
|
|
VMIG-2 |
|
|
|
Commercial Paper |
A-2 |
A-2 |
P-2 |
P-2 |
F-2 |
F-2 |
Credit Facility |
None |
None |
Baa 1 |
Baa 2 |
None |
None |
Rating Outlook |
Stable |
Stable |
Negative |
Negative |
Negative |
Negative |
These security ratings reflect the views of the rating
agencies. An explanation of the significance of these ratings may be obtained
from each rating agency. Such ratings are not a recommendation to buy, sell or
hold securities. Any rating can be revised upward or downward or withdrawn at
any time by a rating agency if it decides that the circumstances warrant the
change. Each rating should be evaluated independently of any other rating.
Capital Requirements
Idaho Power is experiencing a cycle of heavy infrastructure
investment, adding capacity to its baseload generation, transmission system and
distribution facilities to ensure adequate supply of electricity, to provide
service to new customers and to maintain system reliability. Idaho Powers
aging hydroelectric and thermal generation facilities require continuing
upgrades and component replacement, and the costs related to relicensing
hydroelectric facilities and complying with the new licenses are substantial.
Due to the heavy infrastructure requirements from 2010-2012, Idaho Power will
continue to focus on critical infrastructure needs that relate to system
reliability and resource adequacy and has reduced ongoing capital expenditures
and major projects from prior estimates. The table below presents the low and
high ranges of the capital expenditure categories. Idaho Power expects that
total capital expenditures will be at or slightly above $1 billion from
2010-2012. Internal cash generation after dividends is expected to provide
less than the full amount of total capital requirements for 2010 through 2012.
While IDACORP and Idaho Power expect minimal need for external financing in
2010, except for issuances under the dividend reinvestment and employee-related
plans, and potential pre-funding of 2011 debt maturities should IDACORP and
Idaho Power decide to access the capital markets, IDACORP has access to its
registered securities including its Continuous Equity Program (CEP) which has
approximately 2.1 million shares of common stock available and Idaho Power
intends to file a new shelf registration statement that can be used for the
issuance of first mortgage bonds and unsecured debt. IDACORP and Idaho Power
expect to continue financing capital requirements with a combination of
internally generated funds and externally financed capital.
The following table presents Idaho Powers estimated cash
requirements for construction, excluding AFUDC, for 2010 through 2012 (in
millions of dollars):
|
2010 |
2011-2012 |
|||
Ongoing capital expenditures |
$ |
155-160 |
$ |
352-380 |
|
Advanced Metering Infrastructure (AMI) |
|
23-25 |
|
23-25 |
|
Langley Gulch Power Plant (detailed below) |
|
138-140 |
|
175-180 |
|
Other major projects |
|
39-40 |
|
90-95 |
|
|
Total |
$ |
355-365 |
$ |
640-680 |
|
|
|
|
|
|
Major Projects:
AMI: The AMI project provides the means to
automatically retrieve energy consumption information, eliminating manual meter
reading expense. Idaho Power intends to install this technology for
approximately 99 percent of its customers and is on pace to complete the
installations by the end of 2011. The total cost estimates for the project are
approximately $74 million. Idaho Power has expended approximately $24 million
of the total costs as of December 31, 2009. The remaining costs are included
in the table above.
Langley Gulch Power Plant: On September 1, 2009, the
IPUC issued an order granting Idaho Powers March 6, 2009, request for a CPCN
authorizing Idaho Power to construct, own and operate the Langley Gulch power
plant. Langley Gulch will be a natural gas-fired CCCT generating plant with a
summer nameplate capacity of approximately 300 MWs and a winter capacity of
approximately 330 MWs. The plant will be constructed near New Plymouth, Idaho,
commencing in summer 2010, and is anticipated to achieve commercial operation
by November 1, 2012. Contract incentives may advance the commercial operation
date to July 1, 2012. The total cost estimate for the project including AFUDC
is $427 million, $54 million of which Idaho Power incurred as of December 31,
2009. The remaining costs are included in the table above. The plant will
connect to Idaho Powers existing grid.
42
Idaho Power requested in its application that the IPUC
provide Idaho Power with assurances of future ratemaking treatment for
construction costs up to Idaho Powers cost estimate. In the order, the IPUC
found that Idaho Power had satisfied statutory requirements that would entitle
Idaho Power to receive such ratemaking assurances. The order grants Idaho
Power assurance and pre-approval to include $396.6 million of construction
costs in Idaho Powers rate base when Langley Gulch achieves commercial
operation. The order contemplates that Idaho Power may request recovery of
additional costs if they exceed $396.6 million provided that Idaho Power is
able to demonstrate that the additional costs were reasonably and prudently
incurred.
Idaho Power is responsible for specific portions of the
Langley Gulch Project, which include permitting the site under the Payette
County planning and zoning ordinance, design and construction of the cooling
water pump station and pipeline from the Snake River to the site, design and
construction of the gas pipeline from the Williams Northwest Pipeline to the
site, and design and construction of the new electric transmission lines to the
existing grid. The cost of these activities are included in the $427 million
estimated total cost for Langley Gulch.
Other Major Projects:
Hemingway Station: Construction is underway for the
new 500-kV Hemingway station, located near Boise, Idaho. This station will
relieve capacity and operating constraints to ensure reliable service to Idaho
Powers network and native load customers. The station was originally part of
the Gateway West Project, but construction was accelerated to help meet
forecast deficits and improve reliability. The station is expected to be in
service by summer 2010 at a total cost of approximately $57 million. The 2010
cost estimate for the project, including substation interconnections, is $20
million and is included in the above table.
Hemingway-Bowmont Transmission Line: A part of the
Hemingway Station Project, the Hemingway-Bowmont transmission line, currently
under construction, is 12 miles of new 230-kV double circuit transmission line
that will provide power to the Treasure Valley in southwest Idaho. The project
is scheduled to be in service by summer 2010 at a total cost of approximately
$16 million. The 2010 cost estimate for the project is $6.5 million and is
included in the above table.
Boardman-Hemingway Line: The Boardman-Hemingway Line
is a proposed 500-kV transmission project between a substation near Boardman,
Oregon and the Hemingway station. This line will provide transmission service
for existing network and native load customers and other requests pursuant to
Idaho Powers OATT, and will improve reliability and relieve existing
congestion. The line will allow for the transfer of up to 1,500 MW of
additional energy between Idaho and the Northwest, depending on the outcome of
WECC rating studies to determine project capacity limits. On March 9, 2009,
Idaho Power initiated a community advisory project to engage the public in
route selection alternatives. Idaho Powers preferred route selection will be
processed in compliance with the National Environmental Policy Act and Oregon
Energy Facility Siting Council requirements. The initial phase of the project,
estimated at $50 million, will be funded primarily by Idaho Power and includes
the engineering, environmental review, permitting and rights-of-way. Cost
estimates for the 2010-2012 timeframe of the initial phase are included in the
table above. Total cost estimates for the project (including initial phase
project estimate and construction costs of the line) are approximately $600
million. Idaho Power expects its share of the project to be between 30 and 50
percent, to meet needs identified in the 2009 IRP and forecast growth of
network customers. Idaho Power and PacifiCorp are exploring potential joint
development and ownership opportunities regarding the Boardman-Hemingway
project. The Bonneville Power Administration is also currently investigating whether
participation in project may be feasible. This project is expected to be
completed in 2015 subject to siting, permitting and regulatory approvals.
Construction costs beyond the initial phase are not included in Idaho Powers
2010 to 2012 forecast.
Gateway West Project: Idaho Power and PacifiCorp are
jointly exploring the Gateway West project to build transmission lines between
Windstar, a substation located near Douglas, Wyoming and the Hemingway
station. This project will provide transmission service for existing network
and native load customers, forecasted growth and requests pursuant to Idaho
Powers OATT transmission obligations. The project is expected to improve
reliability and relieve existing congestion. Idaho Power and PacifiCorp have a
cost sharing agreement for expenses incurred for analysis work of the initial
phases.
43
Idaho Powers share of the initial phase of engineering,
environmental review, permitting and rights-of-way is approximately $40 million
and cost estimates for the 2010-2012 timeframe of the initial phase are
included in the above table. Construction costs are not included in Idaho
Powers 2010 to 2012 forecast. Initial phases of the project could be
completed by 2014 depending on the timing of rights-of-way acquisition, siting
and permitting, and construction sequencing. Idaho Powers share will vary by
segment across the project and the current estimated cost for its share is between
$300 million and $500 million. However, based on the 2009 IRP and the
withdrawal of some third-party transmission service requests, Idaho Powers
share may change and the timing of the projects segments may be deferred and
constructed as demand requires. The Bureau of Land Management has indicated
the draft environmental impact statement is expected to be issued during the
summer of 2010.
For a discussion of environmental considerations relating to
the above projects, see ENVIRONMENTAL ISSUES Endangered Species.
Hydroelectric projects: In the table above
Idaho Power has included costs relating to the relicensing of hydroelectric
facilities and complying with the renewed licenses. These costs total
approximately $25 million for the three year period. An additional $12 million
relating to future hydroelectric projects is also included in the table.
Environmental Regulation Costs: Idaho
Power anticipates approximately $42 million in annual capital and operating
costs for environmental facilities during 2010. Hydroelectric facility
expenses including costs for relicensing Hells Canyon and thermal plant
expenses account for approximately $22 million and $20 million, respectively.
From 2011 through 2012, total environmental related operating and capital costs
are estimated to be approximately $122 million. Expenses related to the
hydroelectric facilities are expected to be $62 million and include costs
associated with the relicensing of Hells Canyon. Thermal plant expenses are
expected to total $60 million during this period. These amounts are included
in the table above but do not include costs related to possible changes in the
environmental laws or regulations and enforcement policies that may be enacted
in response to issues such as climate change and other pollutant emissions from
coal-fired generation plants.
Other capital requirements: IDACORPs non-regulated
capital expenditures are expected to be $7 million in 2010 and primarily relate
to IFSs tax-structured investments. Currently there are no expenditures
anticipated for 2011 or 2012.
American Recovery and Reinvestment Act of 2009
Under the ARRA, Idaho Power submitted a grant application to
the Department of Energy (DOE) in August 2009, requesting $47 million. This
grant would match a $47 million investment by Idaho Power in Smart Grid
technology as well as other incremental projects. In October 2009, Idaho Power
received notice that its application was selected for negotiation.
Negotiations with the DOE on the grant agreement terms are expected to be
complete in the first quarter of 2010.
Off-Balance Sheet Arrangements
Idaho Power has agreed to guarantee the performance of
reclamation activities at Bridger Coal Company of which IERCo owns a one-third
interest. This guarantee, which is renewed each December, was $63 million at
December 31, 2009. Bridger Coal Company has a reclamation trust fund set aside
specifically for the purpose of paying these reclamation costs. At this time
Bridger Coal Company is revising their estimate of future reclamation costs.
To ensure that the reclamation trust fund maintains adequate reserves, Bridger
Coal Company has the ability to add a per ton surcharge if it is determined
that future liabilities exceed the trusts assets. Because of the existence of
the fund and the ability to apply a per ton surcharge, the estimated fair value
of this guarantee is minimal.
44
Contractual Obligations
The following table presents IDACORPs and Idaho Powers
contractual cash obligations for the respective periods in which they are due:
|
Payment Due by Period |
|||||||||||
|
Total |
2010 |
2011-2012 |
2013-2014 |
Thereafter |
|||||||
|
(millions of dollars) |
|||||||||||
Idaho Power: |
|
|
|
|
|
|
|
|
|
|
||
Long-term debt (1) |
$ |
1,414 |
$ |
1 |
$ |
222 |
$ |
72 |
$ |
1,119 |
||
Future interest payments (2) |
|
1,256 |
|
77 |
|
146 |
|
129 |
|
904 |
||
Operating leases |
|
15 |
|
3 |
|
3 |
|
3 |
|
6 |
||
Purchase obligations: |
|
|
|
|
|
|
|
|
|
|
||
|
Cogeneration and small power |
|
|
|
|
|
|
|
|
|
|
|
|
|
production |
|
2,214 |
|
83 |
|
222 |
|
229 |
|
1,680 |
|
Large power production (3) |
|
260 |
|
128 |
|
132 |
|
- |
|
- |
|
|
Fuel supply agreements |
|
383 |
|
64 |
|
117 |
|
107 |
|
95 |
|
|
Purchased power & transmission (4) |
|
89 |
|
44 |
|
31 |
|
6 |
|
8 |
|
|
Other (5) |
|
149 |
|
65 |
|
36 |
|
21 |
|
27 |
|
|
|
Total purchase obligations |
|
5,780 |
|
465 |
|
909 |
|
567 |
|
3,839 |
Pension and postretirement plans (6) |
|
256 |
|
13 |
|
106 |
|
95 |
|
42 |
||
Other long-term liabilities - Idaho Power |
|
4 |
|
3 |
|
1 |
|
- |
|
- |
||
|
Total Idaho Power |
|
6,040 |
|
481 |
|
1,016 |
|
662 |
|
3,881 |
|
Other: |
|
|
|
|
|
|
|
|
|
|
||
Long-term debt (1)(7) |
|
9 |
|
8 |
|
- |
|
- |
|
1 |
||
|
Total IDACORP |
$ |
6,049 |
$ |
489 |
$ |
1,016 |
$ |
662 |
$ |
3,882 |
|
(1) For additional information, see Note 4 to IDACORPs and Idaho Powers Consolidated Financial Statements. |
||||||||||||
(2) Future interest payments are calculated based on the assumption that all debt is outstanding until maturity. For debt instruments with variable rates, interest is calculated for all future periods using the rates in effect at December 31, 2009. |
||||||||||||
(3) Large power production relates to the Langley Gulch power plant and includes two contracts with Siemens Energy, Inc. relating to the purchase of a gas turbine and the purchase of a steam turbine and an Engineering, Procurement and Construction Services Agreement with Boise Power Partners Joint Venture, a joint venture consisting of Kiewit Power Engineers Co. and TIC-The Industrial Company, for design, engineering, procurement, construction management and construction services for Langley Gulch. |
||||||||||||
(4) Approximately $21 million of the obligations included in purchased power and transmission have contracts that do not specify terms related to expiration. As these contracts are presumed to continue indefinitely, 10 years of information estimated based on current contract terms, have been included in the table for presentation purposes. |
||||||||||||
(5) Approximately $51 million of the amounts in other purchase obligations are contracts that do not specify terms related to expiration. As these contracts are presumed to continue indefinitely, 10 years of information, estimated based on current contract terms, have been included in the table for presentation purposes. |
||||||||||||
(6) Idaho Power estimates pension contributions based on actuarial data. Idaho Power cannot estimate pension contributions beyond 2014 at this time. For more information on pension, please refer to Note 11 of IDACORPs and Idaho Powers Consolidated Financial Statements. |
||||||||||||
(7) Amounts include the obligations of IDACORPs subsidiaries other than Idaho Power, which is shown separately. |
||||||||||||
|
REGULATORY MATTERS:
Rate changes and regulatory decisions have a significant
impact on results of operations and cash flows. This section discusses several
important rate matters that have affected results during the past two years, as
well as significant pending regulatory issues. Regulatory matters and the
financial impact of rate decisions are also discussed in Note 3 to the
consolidated financial statements.
45
Idaho Power has continued to focus on timely recovery of its
costs through filings with the IPUC and OPUC. The table below summarizes the
most significant base rate changes during the last two years.
|
|
Annualized |
|
|
|
Effective |
$ Impact |
|
|
Description |
Date |
(millions) |
Notes |
|
Base rate increases |
|
|
|
|
Idaho |
|
|
|
|
2007 general rate case |
3/1/2008 |
$ |
32.1 |
No rates of return were specified in the settlement |
Danskin power plant |
6/1/2008 |
|
8.9 |
Adds $64.2 million to rate base for this project |
2008 general rate case |
2/1/2009 3/19/2009 |
|
20.9 6.1 |
Provides a return on equity of 10.5 percent and overall rate of return of 8.18 percent. Approximately $15 million related to increases in base net power supply costs. Allowed Idaho Power to include in rates approximately $10.6 million relating to AFUDC on the Hells Canyon Complex relicensing project. |
AMI |
6/1/2009 |
|
10.5 |
Order is based on Idaho Powers projected investment in AMI through December 31, 2009. Allowed Idaho Power to begin three-year accelerated depreciation of existing metering equipment on June 1, 2009. The associated increase in annualized depreciation expense is $9.2 million. |
Oregon |
|
|
|
|
2008 annual power cost update |
6/1/2008 |
|
4.8 |
Represents a 15.7 percent increase in Oregon rates. |
Depreciation filing |
1/1/2009 |
|
(0.4) |
|
AMI |
6/1/2009 |
|
0.8 |
Authorizes accelerated depreciation and recovery of existing meters in the Oregon jurisdiction over an 18-month period beginning January 2009. The associated increase in annual depreciation expense is $0.8 million |
2009 annual power cost update |
6/1/2009 |
|
3.9 |
Represents an 11.5 percent increase in Oregon rates. |
|
|
|
|
|
2009 Idaho Settlement Agreement
On January 13, 2010, the IPUC approved a settlement
agreement among Idaho Power, several of Idaho Powers customers, the IPUC staff
and others. Significant elements of the settlement agreement include:
A general rate moratorium in effect until January 1, 2012. The moratorium does not apply to other specified revenue requirement proceedings, such as the PCA, the FCA, pension funding, AMI, energy efficiency rider, and government imposed fees.
A specified distribution of the expected 2010 PCA. This distribution is intended to reduce customer rates, provide some general rate relief to Idaho Power and reset base power supply costs for the PCA. The associated rate change is expected to become effective June 1, 2010. This provision is in anticipation of a significant reduction in PCA rates for the 2010-2011 PCA year. The PCA reduction will be allocated as follows:
o The first $40 million will be allocated equally between customers and Idaho Power. Idaho Powers share would be applied to increase permanent base rates on a uniform percentage basis to all customer classes and contract customers. The customers share would be a direct PCA rate reduction.
o All of the next $20 million will be allocated to customers as a direct PCA rate reduction.
o PCA reductions in excess of $60 million will be applied to absorb any increase in the base level of net power supply expenses.
o If the PCA reduction exceeds $60 million plus the increase in base net power supply expenses, the next $10 million will be allocated equally between Idaho Power and customers.
o Any remainder will go entirely to customers.
A provision to share earnings with customers if Idaho Powers actual rate of return on equity is more than 10.5 percent in any calendar year from 2009 to 2011 in its Idaho jurisdiction. Idaho Power will share with Idaho customers 50 percent of any returns in excess of 10.5 percent.
46
A provision to allow the accelerated amortization of accumulated deferred investment tax credits (ADITC) if Idaho Powers actual rate of return on equity is below 9.5 percent in any calendar year from 2009 to 2011 in its Idaho jurisdiction. Idaho Power would be permitted to amortize additional ADITC in an amount up to $45 million over the three-year period, but could use no more that $15 million in any one year unless there is a carryover. Carryover amounts are added to the $15 million annual allowance up to a maximum amortization of $25 million in any one year.
Because Idaho Powers Idaho-jurisdiction return on equity
was between 9.5 and 10.5 percent, the sharing and accelerated amortization provisions
were not triggered in 2009.
The settlement agreement also included a provision to
reestablish the base level for net power supply costs effective with the June
1, 2010, PCA rate change. On January 19, 2010, Idaho Power filed with the IPUC
a request to increase base net power supply costs by $74.8 million in the Idaho
jurisdiction. This amount, which is subject to approval by the IPUC, reflects
the maximum increase to Idaho Powers base net power supply costs, which would
be used for both base rates and PCA calculations. The actual change in net
power supply costs for rate purposes will depend upon the amount approved by
the IPUC as well as the amount of any PCA decrease determined for the 2010-2011
PCA year. Written comments or protests with respect to Idaho Powers
application are due March 11, 2010.
2009 Oregon Rate Case: On December 16, 2009, Idaho
Power filed a Joint Stipulation and testimony in support of a stipulation that
would settle the revenue requirement issues surrounding the general rate case
filed on July 31, 2009. If approved by the OPUC, the Joint Stipulation would
result in a $5 million, or 15.4 percent, increase to base rates. The new rates
reflect a return on equity of 10.175 percent and an overall rate of return of
8.061 percent. The requested effective date for new rates is March 1, 2010.
Power Supply Cost Deferrals
Idaho Powers power supply costs can vary significantly from
year to year, primarily because of weather, loads and commodity markets. Idaho
Power has power cost adjustment mechanisms in both Idaho and Oregon. These
mechanisms allow Idaho Power to recover from or refund to customers a majority
of the fluctuations in power supply costs. Because of these mechanisms, the
primary financial impacts of power supply cost variations is that cash is paid
out but recovery from customers does not occur until a future period, resulting
in fluctuations in operating cash flows from year to year.
The following table summarizes Idaho Powers deferred power
supply cost activity during the last two years.
|
Idaho |
Oregon (1) |
Total |
|||
Balance at January 1, 2008 |
$ |
92,322 |
$ |
5,100 |
$ |
97,422 |
Costs deferred through PCA and PCAM |
|
108,688 |
|
5,196 |
|
113,884 |
Prior costs expensed and recovered through rates |
|
(64,030) |
|
(2,441) |
|
(66,471) |
SO2 allowances credited to account (2) |
|
(2,184) |
|
(175) |
|
(2,359) |
Interest and other |
|
6,025 |
|
598 |
|
6,623 |
Balance at December 31, 2008 |
$ |
140,821 |
$ |
8,278 |
$ |
149,099 |
Costs deferred through PCA and PCAM |
|
42,533 |
|
(184) |
|
42,349 |
Prior costs expensed and recovered through rates |
|
(113,134) |
|
(2,283) |
|
(115,417) |
SO2 allowances credited to account(2 |
|
(2,034) |
|
(83) |
|
(2,117) |
Interest and other |
|
3,226 |
|
1,135 |
|
4,361 |
2007 Excess power costs order |
|
- |
|
6,358 |
|
6,358 |
Balance at December 31, 2009 |
$ |
71,412 |
$ |
13,221 |
$ |
84,633 |
(1) Oregon power supply cost deferrals are subject to a statute that specifically limits rate amortizations of deferred costs to six percent of gross Oregon revenue per year (approximately $2 million). Deferrals are amortized sequentially. |
||||||
(2) The IPUC has allowed Idaho Power to retain its PCA sharing percentage of the gain from sales of SO2 allowances as a shareholder benefit with the remainder recorded as a customer benefit, substantially all of which was used to reduce the PCA. Proceeds from the sale of renewable energy certificates (RECs) are also expected to reduce the PCA. RECs are acquired by Idaho Power through purchases of renewable energy. |
||||||
|
47
PCA Workshops: In its order approving Idaho Powers
2008-2009 PCA, the IPUC directed Idaho Power to set up workshops with the IPUC
Staff and several of Idaho Powers largest customers to address issues not
resolved in that PCA filing. The workshops resulted in the following changes
to the PCA mechanism, effective February 1, 2009:
PCA sharing ratio the PCA allocates the deviations in net power supply expenses between customers (95 percent) and shareholders (5 percent). The previous sharing ratio was 90/10.
LGAR the LGAR is an element of the PCA formula that is intended to eliminate recovery of power supply expenses associated with load growth resulting from changing weather conditions, a growing customer base, or changing customer use patterns. The 2007 general rate case reset the LGAR from $29.41 to $62.79 per MWh, but applied that rate to only 50 percent of the load growth beginning in March 2008. The stipulation agreed on a new formula for calculating the LGAR. Based on the final rates approved by the IPUC in the 2008 general rate case and the supporting data, the current LGAR is $26.63 per MWh, effective February 1, 2009.
Use of Idaho Powers operation plan power supply cost forecast the operation plan forecast may better match current collections with actual net power supply costs in the year they are incurred and result in smaller amounts being included in the following years true-up rate, beginning with the 2009-2010 PCA filing.
Inclusion of third-party transmission expense transmission expenses paid to third parties to facilitate wholesale purchases and sales of energy, including losses, are a necessary component of net power supply costs. Deviation in these costs from levels included in base rates is now reflected in PCA computations.
Adjusted distribution of base net power supply costs base net
power supply costs are distributed throughout the year based upon the monthly
shape of normalized revenues for purposes of the PCA deferral calculation.
Fixed Cost Adjustment Mechanism (FCA)
The FCA mechanism began as a pilot program for Idaho Powers
Idaho residential and small general service customers, running from 2007
through 2009. The FCA is a rate mechanism designed to remove Idaho Powers
disincentive to invest in energy efficiency programs by separating (or
decoupling) the recovery of fixed costs from the variable kilowatt-hour charge
and linking it instead to a set amount per customer. On October 1, 2009, Idaho
Power filed an application with the IPUC to make the FCA mechanism permanent
beginning January 1, 2010. The application is being processed under modified
procedure.
Idaho Power accrued $6.6 million related to the FCA in 2009;
subject to IPUC approval, recovery should begin June 1, 2010. The IPUC
approved a rate increase effective June 1, 2009, through May 31, 2010, to
recover $2.7 million of fixed costs under-recovered during 2008. The IPUC
approved a rate reduction, effective June 1, 2008 through May 31, 2009, to
return $2.4 million of fixed costs over-recovered in 2007.
Langley Gulch Power Plant Ratemaking Treatment
On September 1, 2009, the IPUC issued an order providing
cost recovery and ratemaking assurances related to Idaho Powers Langley Gulch
project. The IPUC found that Idaho Power had satisfied statutory requirements
that would entitle Idaho Power to receive such ratemaking assurances and
granted Idaho Power assurance and pre-approval to include $396.6 million of
construction costs in Idaho Powers rate base when Langley Gulch achieves
commercial operation. The order contemplates that Idaho Power may request
recovery of additional costs if they exceed $396.6 million; provided that Idaho
Power is able to demonstrate that the additional costs were reasonably and
prudently incurred. Please see further discussion of the Langley Gulch project
in LIQUIDITY AND CAPITAL RESOURCES - Major Projects - Langley Gulch Power
Plant.
Pension Expense
In the 2003 Idaho general rate case, the IPUC disallowed
recovery of pension expense because there were no current cash contributions
being made to the pension plan. On June 1, 2007, the IPUC issued an order
authorizing Idaho Power to account for its defined benefit pension expense on a
cash basis. The IPUC acknowledged that it is appropriate for Idaho Power to
seek recovery in its revenue requirement of reasonable and prudently incurred
pension expense based on actual cash contributions. Idaho Power deferred
approximately $29 million, $8 million and $3 million of pension expense to a
regulatory asset in 2009, 2008, and 2007 respectively. Idaho Power does not receive
a carrying charge on the current deferral balance.
48
On October 20, 2009, Idaho Power filed an application with
the IPUC to implement a mechanism to track and recover annually cash
contributions made to the pension plan. Estimated minimum required
contributions will be approximately $6 million in 2010, $44 million in 2011 $47
million in 2012, $39 million in 2013, and $40 million in 2014. In its
comments, the IPUC Staff recommended against establishing an annual tracking
mechanism but supported allowing the inclusion in a future rate case of
reasonable amortization of cash contributions. Idaho Power met with the IPUC
Staff to clarify its understanding of their recommendation. As a result of the
meeting, Idaho Power filed reply comments with the IPUC stating that is was not
opposed to the Staffs recommendation with the clarification that the IPUC will
approve amortization of future deferred cash contributions at the same time and
in the same amounts as will be approved for recovery. On February 17, 2010, the
IPUC issued its order approving the recovery methodology agreed to by Idaho
Power and the IPUC Staff as clarified in Idaho Powers reply comments. The
IPUC also approved a carrying charge on the difference between actual contributions
and the recovery of these amounts in rates.
Idaho Power recovers pension expense in its Oregon
jurisdiction on the accrual basis.
Idaho Energy Efficiency Rider (Rider)
Idaho Powers Rider is the chief funding mechanism for Idaho
Powers investment in energy efficiency, conservation, and demand response
programs. Effective June 1, 2009, Idaho Power collects 4.75 percent of base
revenues, or approximately $29-$33 million annually, under the Rider.
In the 2008 general rate case, Idaho Power requested that
the IPUC explicitly find that Idaho Powers expenditures between 2002 and 2007
of $29 million of funds obtained from the Rider were prudently incurred and no
longer subject to potential disallowance. In 2009, the IPUC approved a
stipulation identifying $14.3 million of Rider funding as prudent, and on
January 25, 2010, Idaho Power and the IPUC Staff filed a stipulation for
approval by the IPUC to find the remaining expenditures through 2007 were
prudently incurred.
On October 5, 2009, Idaho Power and other investor-owned
electric utilities serving in Idaho began a series of informal public workshop
with the IPUC Staff to discuss how energy efficiency evaluation and prudency
will be determined on a prospective basis. As a result a Memorandum of Understanding
(MOU) written by Staff, Idaho Power and other investor-owned electric utilities
in Idaho has been signed outlining a process for future energy expenditure
approval. This document was filed with the IPUC on January 25, 2010.
In the first quarter of 2010, Idaho Power expects to request
a similar prudency determination from the IPUC for Rider expenditures in 2008
and 2009. Idaho Power spent approximately $19 million in 2008 and $33 million
in 2009 for rider-funded energy efficiency and demand response initiatives in
its Idaho and Oregon jurisdictions combined. The increase in spending in 2009
reflects Idaho Powers growing emphasis on these programs, such as
implementation of a revised irrigation peak rewards program and commercial
demand response program in 2009.
FERC OATT Proceeding: In 2006, Idaho Power moved
from a fixed rate to a formula rate for its open access transmission tariff
(OATT), which allows transmission rates to be updated each year. The FERC
accepted Idaho Powers new formula rates, effective June 1, 2006, subject to
refund pending the outcome of a hearing and settlement process.
While the majority of issues related to Idaho Powers 2006
revised OATT filing have been resolved, Idaho Power is awaiting an order upon
reconsideration from the FERC regarding the treatment of Legacy Agreements.
These agreements are contracts for transmission service that were in existence
before the implementation of the OATT in 1996. The impact of FERCs ruling is
being mitigated by revising certain of the Legacy Agreements as provided for in
the agreements. Revisions are expected to increase annual transmission revenue
by approximately $3.8 million in 2010 compared to 2009.
Idaho Powers OATT is discussed further in Note 3 to the
consolidated financial statements.
FERC Compliance Program: The FERC issued Policy
Statements on Enforcement in 2005 and 2008 and a Policy Statement on Compliance
in 2008. These statements encourage companies to self-report to the FERC
matters that constitute or may constitute violations of the Federal Power Act
(FPA), the Natural Gas Act, the Natural Gas Policy Act and the requirements of
FERC rules, regulations, orders and tariffs. The Policy Statements identify
self-reporting as a factor the FERC will consider in determining the proper
remedy for a violation and emphasize the role compliance programs play in
identifying and correcting violations and in evaluating whether and the extent
to which penalties may be imposed.
49
Idaho Power has implemented a compliance program to ensure
that its operations conform to the FERCs requirements and to provide a means
of identifying, correcting and if warranted, self-reporting any such matters to
the FERC. Idaho Power also self-reports matters relating to transmission reliability
standards to the WECC. In 2007, FERC Order No. 693 approved mandatory
reliability standards developed by the North American Electric Reliability
Corporation. In 2008, FERC Order No. 706 also approved Critical Infrastructure
Protection Reliability Standards (CIP) developed by the North American Electric
Reliability Corporation. The WECC, a regional electric reliability
organization, has responsibility for compliance and enforcement of these
standards. As part of its compliance program, Idaho Power has reported
compliance issues relating to the FERCs Standards of Conduct and Idaho Powers
OATT to the FERC, as well as matters relating to CIP and other reliability
standards to the WECC. Some of these matters have been resolved, while others
are being reviewed by the FERC or the WECC. Those matters that have been
resolved to date have resulted in no material impact to Idaho Power. Idaho
Power is unable to predict what action if any the FERC or the WECC will take
with regard to the unresolved matters. Idaho Power plans to continue its
policy of using its compliance program to reduce potential violations and to
self-report matters to the FERC and the WECC.
Bonneville Power Administration Residential Exchange
Program: The Pacific Northwest Electric Power Planning and Conservation
Act of 1980 (the Act), through the Residential Exchange Program (REP), has
provided access to the benefits of low-cost federal hydroelectric power to
residential and small farm customers of the regions investor-owned utilities
(IOUs). The REP is administered by the Bonneville Power Administration (BPA).
Pursuant to agreements between the BPA and Idaho Power, benefits from the BPA
were passed through to Idaho Powers residential and small farm customers
through electricity bill credits.
On May 3, 2007, the U.S. Court of Appeals for the Ninth
Circuit ruled that the agreements entered into between the BPA and the IOUs
(including Idaho Power) are inconsistent with the Act and shortly thereafter
suspended REP payments to Idaho Power and the IOUs. Effective June 1, 2007,
Idaho Power eliminated the credit on its customers bills. Subsequent BPA
filings and decisions have provided no REP benefits to Idaho Powers customers
and Idaho Power has filed petitions for review of these decisions with the U.S.
Court of Appeals for the Ninth Circuit.
Idaho Power has been working with the other northwest IOUs
and consumer-owned utilities, northwest state public utility commissions and
the BPA to resolve these issues.
Settlement efforts took place from August through November
of 2009 and parties in the case have agreed to the selection of a mediator,
with sessions expected to begin in the spring of 2010. Since these benefits
were passed through to Idaho Powers customers, the outcome of this matter is
not expected to have an effect on Idaho Powers financial condition or results
of operations.
Relicensing of Hydroelectric Projects:
Idaho Power, like other utilities that operate nonfederal
hydroelectric projects on qualified waterways, obtains licenses for its
hydroelectric projects from the FERC. These licenses last for 30 to 50 years
depending on the size, complexity, and cost of the project. Idaho Power is
actively pursuing the relicensing of the Hells Canyon Complex (HCC) and Swan Falls
projects.
The relicensing costs are recorded in construction work in
progress until new multi-year licenses are issued by the FERC, at which time
the charges will be transferred to electric plant in service. Relicensing
costs and costs related to new licenses will be submitted to regulators for
recovery through the ratemaking process. Relicensing costs of $117 million and
$4 million for HCC and Swan Falls, respectively, were included in construction
work in progress at December 31, 2009.
The IPUC authorized Idaho Power to include in rates
approximately $6.8 million annually ($10.6 million grossed up for income taxes)
of AFUDC relating to the HCC relicensing project. This became effective
February 1, 2009, and Idaho Power collected approximately $9.7 million in
2009. Collecting these amounts in current rates will reduce the relicensing
amount submitted to regulators for recovery through the ratemaking process.
50
Hells Canyon Complex: The most significant ongoing
relicensing effort is the HCC, which provides approximately 68 percent of Idaho
Powers hydroelectric generating nameplate capacity and 36 percent of its total
generating nameplate capacity. In July 2003, Idaho Power filed an application
for a new license in anticipation of the July 2005 expiration of the
then-existing license. Idaho Power is currently operating under an annual
license issued by the FERC and expects to continue operating under annual
licenses until the new license is issued.
Consistent with the requirements of the National Environmental
Policy Act of 1969, as amended (NEPA), the FERC Staff issued on August 31,
2007, a final environmental impact statement (EIS) for the HCC, which the FERC
will use to determine whether, and under what conditions, to issue a new
license for the project. The purpose of the final EIS is to inform the FERC,
federal and state agencies, Native American tribes and the public about the
environmental effects of Idaho Powers proposed operation of the HCC. Idaho
Power has reviewed the final EIS and is developing comments for filing with the
FERC. However, certain portions of the final EIS, involve issues that may be
influenced by the water quality certifications for the project under section
401 of the Clean Water Act and formal consultations under the Endangered
Species Act (ESA), which remain unresolved. Idaho Power anticipates filing
comments to the final EIS as the section 401 and ESA processes progress and the
manner in which they may affect pending issues becomes certain.
In conjunction with the issuance of the final EIS, on
September 13, 2007, the FERC requested formal consultation under the ESA with
the National Marine Fisheries Service (NMFS) and the U.S. Fish and Wildlife
Service (USFWS) regarding the effect of HCC relicensing on several aquatic and
terrestrial species listed as threatened under the ESA. However, formal
consultation has not yet been initiated and NMFS and USFWS continue to gather
and consider information relative to the effect of relicensing on relevant
species. Idaho Power continues to cooperate with the USFWS, the NMFS and the
FERC in an effort to address ESA concerns.
Because the HCC is located on
the Snake River where it forms the border between Idaho and Oregon, Idaho Power
has filed Water Quality Certification Applications, required under section 401
of the Clean Water Act, with the States of Idaho and Oregon requesting that
each state certify that any discharges from the project comply with applicable
state water quality standards. Temperature and other water quality issues are
of interest to various federal and state agencies, Native American tribes, and
other parties who may provide input to the states certification process.
Section 401 of the Clean Water Act requires that a state either approve or deny
a 401 water quality certification application within one-year of the filing of
the application or the state may be considered to have waived its certification
authority under the Act. As a consequence, Idaho Power has been filing and
withdrawing its section 401 certification applications with Oregon and Idaho on
an annual basis while it has been working through water quality certification
issues with the states. Most recently, on December 23, 2009, Idaho Power
withdrew the 401 certification applications filed with Oregon and Idaho, and
immediately refiled the applications, in order to allow Idaho Power additional
time to address unresolved issues associated with water quality certification
for the project. One such issue involves the Temperature Enhancement
Management Program that Idaho Power proposed in its application and whether
that program provides reasonable assurance that discharges from the HCC will
adequately address fall temperature water quality criteria below Hells Canyon
Dam. Idaho Power is continuing to work with Idaho and Oregon to ensure that
any discharges from the HCC will comply with the temperature and other
applicable necessary state water quality standards so that appropriate water
quality certifications can be issued for the project.
The FERC is expected to issue a license order for the HCC
once the ESA consultation and the section 401 certification processes are
completed.
Swan Falls Project: The license for the Swan Falls
hydroelectric project expires in June 2010. In June 2008, Idaho Power filed a
license application with the FERC. On January 9, 2009, the FERC issued a
scoping document giving notice of scheduled scoping meetings, soliciting
scoping comments and of its intent to prepare an EIS pursuant to the NEPA.
FERC held scoping meetings on February 10 and 11, 2009. On May 5, 2009, FERC
issued Scoping Document 2 for the project, advising that based on the scoping
meetings and comments received that staff will prepare an EIS, which the FERC
will use to determine whether, and under what conditions, to issue a new
hydropower license for the project. On June 16, 2009, FERC issued its Notice
of Application Ready for Environmental Analysis and Soliciting Comments,
Recommendations, Terms and Conditions, and Prescriptions. The deadline for
filing comments, recommendations, terms and conditions, and prescriptions was
August 15, 2009. Filings were made by the USFWS and state of Idaho. The FERC
expects to complete the EIS in 2010.
51
On June 6, 2008, Idaho Power filed an application with the
Idaho Department of Environmental Quality (IDEQ) for section 401 water quality
certification. On April 1, 2009, the IDEQ issued public notice, seeking public
comment on a draft section 401 certification for the project. No public
comments were submitted and the IDEQ issued the section 401 certification on
May 4, 2009.
Shoshone Falls Expansion: On August 17, 2006, Idaho
Power filed a license amendment application with the FERC, which would allow
Idaho Power to upgrade the Shoshone Falls project from 12.5 MW to 62.5 MW. The
license amendment is expected to be issued in 2010. In conjunction with the
license amendment application, Idaho Power has filed a water rights application
with the Idaho Department of Water Resources (IDWR).
LEGAL MATTERS:
Western Energy Proceedings at the FERC: Idaho Power and IE are parties to proceedings at
the FERC arising from the western energy situation the California energy
crisis that occurred during 2000 and 2001, and the energy shortages, high
prices and blackouts in the western United States. High prices for electricity
in California and in western wholesale markets during 2000 and 2001 caused
numerous purchasers of electricity in those markets to initiate proceedings
seeking refunds or other forms of relief.
The three major sets
of cases arising out of the western energy situation relate to (i) pricing of
sales in the California Independent System Operator (Cal ISO) and California
Power Exchange (CalPX) markets (the California refund proceeding); (ii) claims
of market manipulation and tariff violations in those markets, some of which
have been the subject of FERC show cause orders (the market manipulation
cases); and (iii) pricing of sales in the spot power markets in the Pacific
Northwest (the Pacific Northwest refund proceeding).
Proceedings in all
three sets of cases remain pending before the FERC. In addition, there are
pending in the United States Court of Appeals for the Ninth Circuit (Ninth
Circuit) approximately 200 petitions for review of numerous FERC orders
regarding the western energy situation, including the California refund
proceeding and the market manipulation cases. Decisions in these appeals may
have implications with respect to other pending cases, including those to which
Idaho Power or IE are parties.
Idaho Power and IE
have reached settlements with the principal parties to the California refund
proceeding and the market manipulation cases, but there remain claims by
parties that have not settled that represent a small minority of potential
refunds in those proceedings. Idaho Power and IE are unable to predict the
outcome of these matters, but believe that the settlement releases they have
obtained will restrict potential claims that might result from the disposition
of these two sets of proceedings and that these matters will not have a
material adverse effect on their consolidated financial positions, results of
operations or cash flows.
In the Pacific Northwest refund proceeding, after reviewing
the FERCs 2003 decision declining to order refunds, the Ninth Circuit remanded
the case to the FERC on April 16, 2009 to consider whether evidence of market
manipulation would have altered the agencys conclusions about refunds and to
include sales to the California Department of Water Resources (CDWR) in the
proceedings. Although the FERC has not yet acted on the remand from the Ninth
Circuit, in separate filings the California Parties (Pacific Gas & Electric
Company, San Diego Gas & Electric Company, Southern California Edison
Company, the California Public Utilities Commission, the California Department
of Water Resources and the California Attorney General) and the City of Tacoma,
Washington and the Port of Seattle, Washington asked the FERC to take actions
to reorganize and restructure the case so that they may pursue claims that all
spot market sales in the Cal ISO and CalPX markets and in the Pacific Northwest
from January 1, 2000 through June 20, 2001 should be repriced, and thereby
become subject to refund, because market manipulation and tariff violations
affected spot market prices. This would expand the scope of the refund period
in the Pacific Northwest proceeding from the December 25, 2000 through June 20,
2001 period previously considered by the FERC. In May 2009, the California
Parties requested that the FERC sever the CDWR sales from the Pacific Northwest
proceeding and consolidate the CDWR sales portion with ongoing proceedings in
cases that Idaho Power and IE have settled, as well as with a new complaint
filed on May 22, 2009 by the California Attorney General against some sellers,
but not including Idaho Power and IE. In August 2009, the City of Tacoma,
Washington and the Port of Seattle, Washington requested the FERC, either on a
summary basis or after new evidentiary hearings, to require refunds from all
sellers in the Pacific Northwest spot markets for the expanded period (January
1, 2000 through June 21, 2000). Idaho Power and IE are unable to predict the
outcome of these matters or estimate the impact they may have on their
consolidated financial positions, results of operations or cash flows.
52
Sierra Club Lawsuits at the Bridger and Boardman coal
fired plants in which Idaho Power has ownership interests: In February
2007, the Sierra Club and the Wyoming Outdoor Council filed a complaint against
PacifiCorp in the U.S. District Court in Cheyenne, Wyoming, alleging violations
of air quality opacity standards at the Jim Bridger coal-fired plant in
Sweetwater County, Wyoming. Opacity is an indication of the amount of light
obscured by the flue gas of a power plant. The complaint alleged thousands of
opacity permit violations by PacifiCorp and sought a declaration that
PacifiCorp had violated opacity limits, a permanent injunction ordering
PacifiCorp to comply with such limits, civil penalties of up to $32,500 per day
per violation, and reimbursement of plaintiffs costs of litigation, including
reasonable attorneys fees. Idaho Power is not a party to this proceeding but
has a one-third ownership interest in the plant. PacifiCorp owns a two-thirds
interest in and is the operator of the plant. On February 10, 2010, PacifiCorp
and plaintiffs reached an agreement in principle to the settlement of the
lawsuit in its entirety. The settlement is subject to the approval of the
Environmental Protection Agency and the court. If approved, the settlement
will not have a material adverse effect on Idaho Powers consolidated financial
positions, results of operations or cash flows.
In September 2008, the Sierra Club and four other non-profit
corporations filed a complaint against Portland General Electric Company (PGE)
in the U.S. District Court for the District of Oregon alleging opacity permit
limit violations at the Boardman coal-fired plant located in Morrow County,
Oregon. The complaint also alleged violations of the Clean Air Act, related
federal regulations and the Oregon State Implementation Plan relating to PGEs
construction and operation of the plant. The complaint sought a declaration
that PGE had violated opacity limits, a permanent injunction ordering PGE to
comply with such limits, injunctive relief requiring PGE to remediate alleged
environmental damage and ongoing impacts, civil penalties of up to $32,500 per
day per violation, and reimbursement of plaintiffs costs of litigation,
including reasonable attorneys fees. Idaho Power is not a party to this
proceeding but has a 10 percent ownership interest in the Boardman plant. PGE
owns 65 percent and is the operator of the plant. PGE has stated that it
cannot determine with certainty the total amount of monetary penalties and
damages asserted, but based solely on the complaint, the estimated amount is
$60 million.
Idaho Power is unable to predict the outcome of this matter
or estimate the impact it may have on its consolidated financial positions,
results of operations or cash flows.
Snake River Basin Water Rights: Idaho Power is
engaged in the Snake River Basin Adjudication (SRBA), general stream
adjudication, commenced in 1987, to define the nature and extent of water
rights in the Snake River basin in Idaho, including the water rights of Idaho
Power.
On March 25, 2009, Idaho Power and the State of Idaho
(State) entered into a settlement agreement with respect to the 1984 Swan Falls
Agreement and Idaho Powers water rights under the Swan Falls Agreement, which
settlement agreement is subject to certain conditions discussed below. The
settlement agreement will also resolve litigation between Idaho Power and the
State relating to the Swan Falls Agreement that was filed by Idaho Power on May
10, 2007, with the Idaho District Court for the Fifth Judicial Circuit, which
has jurisdiction over SRBA matters including the Swan Falls case.
The settlement agreement resolves the pending litigation by
clarifying that Idaho Powers water rights in excess of minimum flows at its
hydroelectric facilities between Milner Dam and Swan Falls Dam are subordinate
to future upstream beneficial uses, including aquifer recharge. The agreement
commits the State and Idaho Power to further discussions on important water
management issues concerning the Swan Falls Agreement and the management of
water in the Snake River Basin. It also recognizes that water management
measures that enhance aquifer levels, springs and river flows, such as aquifer
recharge projects, benefit both agricultural development and hydropower
generation and deserve study to determine their economic potential, their
impact on the environment and their impact on hydropower generation. These
will be a part of the Comprehensive Aquifer Management Plan (CAMP), approved by
the Idaho Water Resource Board (IWRB) for the Eastern Snake Plain Aquifer
(ESPA), which includes limits on the amount of aquifer recharge. Idaho Power
is a member of the ESPA CAMP advisory committee and implementation committee.
53
On April 24, 2009, the Governor of Idaho signed into law
legislation approving provisions contained in the settlement agreement. On May
6, 2009, as part of the settlement, Idaho Power, the Governor of Idaho and the
IWRB executed a memorandum of agreement relating to future aquifer recharge
efforts and further assurances as to limitations on the amount of aquifer
recharge. Idaho Power and the State also filed a joint motion to the SRBA
court to dismiss the Swan Falls case and enter the stipulated water right
decrees set forth in the settlement agreement. Parties representing
groundwater users in the ESPA objected to some of the language proposed by
Idaho Power and the State relating to water rights in the decrees to be entered
by the SRBA court as contemplated by the settlement agreement. Specifically,
the concerns relate to the language describing the subordination of the rights
and its interplay with the original Swan Falls settlement document and
implementing legislation. On January 4, 2010, the court issued an order
approving the overall settlement subject to certain modifications to the draft
water right decrees proposed by the company and the state. The company is
working with the state and the parties to reach agreement consistent with the
courts order regarding the language of the decrees.
Idaho Power has also filed an action in the U.S. District
Court of Federal Claims in Washington, D.C. in October, 2007 against the U.S.
Bureau of Reclamation relating to a contract right for delivery of water to its
hydropower projects on the Snake River to recover damages from the U.S. Bureau
of Reclamation for the lost generation resulting from reduced flows and a
prospective declaration of contractual rights so as to prevent the U.S. Bureau
of Reclamation from continued failure to fulfill its contractual and fiduciary
duties to Idaho Power. Trial of the matter has not been scheduled.
Idaho Power is unable to predict the outcome of these
matters or estimate the impact either may have on its consolidated financial
positions, results of operations or cash flows.
For further information regarding legal proceedings, see
Note 10 to the consolidated financial statements.
ENVIRONMENTAL ISSUES:
Global Climate Change:
Long-term climate change could significantly affect Idaho
Powers business in a variety of ways, including the following: (i) changes in
temperature and precipitation could affect customer demand, (ii) extreme
weather events could increase service interruptions, outages, and maintenance
costs; (iii) changes in the amount and timing of snowpack and stream flows
could adversely affect hydroelectric generation, and (iv) legislative and/or
regulatory developments related to climate change could affect plans and
operations including placing restrictions on the construction of new generation
resources, the expansion of existing resources, or the operation of generation
resources in general, and (v)
consumer preference for, and resource planning decisions requiring, renewable
or low GHG-emitting sources of energy could impact demand from existing sources
and require significant investment in new generation and transmission
resources.
Greenhouse Gas Emission Reduction Goals: In
September 2009, IDACORPs and Idaho Powers Board of Directors approved
guidelines that established a goal to reduce the carbon dioxide (CO2)
emission intensity of Idaho Powers utility operations. Idaho Powers goal is
to reduce its resource portfolios average CO2 emission intensity
for the 2010 through 2013 time period to a level of 10 to 15 percent below
Idaho Powers 2005 CO2 emission intensity of 1,194 lbs CO2/MWh.
Since Idaho Powers CO2 emission intensity
fluctuates with stream flows and production levels of anticipated renewable
resource additions, Idaho Power believes an average intensity reduction goal to
be achieved over several years is appropriate. Generation from Idaho
Power-owned and any renewable resources under contract for which Idaho Power
has long-term rights to the Renewable Energy Credits (RECs) will be included in
the denominator of this calculation. Idaho Powers progress toward achieving
this intensity reduction goal, as well as additional information on Idaho
Powers CO2 emissions, will be reported on Idaho Powers website.
The guidelines are intended to reduce Idaho Powers average CO2 emission
intensity in a manner that minimizes the costs of those reductions to Idaho
Powers customers.
In 2006 Idaho Powers and Ida-West ranked as one of the 30
lowest emitters of CO2/MWh produced among the nations 100 largest
electricity producers, according to a collaborative report from CERES, the
natural Resources Defense Council, Public Service Enterprise Group and PG&E
Corporation using publicly reported 2006 generation and emissions data.
In May 2009, Idaho Power submitted information to the Carbon
Disclosure Project (CDP), an independent, not-for-profit organization that
claims the largest database of corporate climate change information in the
world. The CDP posted responding companies information at its website in
September 2009. Idaho Powers estimated CO2 emission intensity
(Lbs/MWh) from its generation facilities as submitted to the CDP was 1,150 and
1,097 for 2007 and 2008, respectively. Idaho Power estimates that its CO2
emission intensity from Idaho Power-owned generation facilities for 2009 was
1,003 Lbs CO2/MWh.
54
Regulation of Greenhouse Gas Emissions: The American
Clean Energy and Security Act of 2009, H.R. 2454, Passed the U.S. House of
Representatives on June 26, 2009. Senate Environment and Public Works Chairman
Barbara Boxer (D-CA) and Senator John Kerry (D-MA) introduced a climate change
bill on the Senate floor on September 30, 2009. The timeline for action on the
Senate floor remains unclear and debate continues on the direction, scope and
timing of federal legislation to reduce GHG emissions. There are also state
and regional initiatives (including the western Regional Climate Action
Initiative) considering regional market-based mechanisms to reduce GHG
emissions.
Oregon enacted legislation in August 2007 establishing
economy-wide goals for the reduction of greenhouse gas emissions. Oregons
goals seek to (i) by 2010, cease the growth of Oregon greenhouse gas emission;
(ii) by 2020, reduce greenhouse gas levels to 10 percent below 1990 levels; and
(iii) by 2050, reduce greenhouse gas levels to at least 75 percent below 1990
levels. The legislation also calls for state government-developed policy
recommendations in the future to assist in the monitoring and achievement of
these goals. The impact of the enacted legislation on Idaho Power cannot be
determined at this time.
On January 14, 2010, Portland General Electric announced
that it intended to pursue an alternative operating plan for its Boardman power
plant. Under the alternative operating plan, near-term expenditures for
pollution control equipment would be significantly reduced and Boardman would
either cease to operate in 2020, or it would discontinue the use of coal as a
fuel source. Idaho Power is a ten percent owner of the plant, representing
64,200 kW of nameplate capacity.
In support of international efforts to reduce GHG emissions,
in January 2010, President Obama pledged to cut GHG emissions in the United
States from 2005 levels by 17 percent by 2020 and 80 percent by 2050. Any
international treaty creating mandatory GHG emission reduction requirements in
the United States would need to be ratified by the U.S. Senate and implemented
through legislation adopted by the U.S. Congress.
In September 2009, the EPA issued a final rule that requires
monitoring and reporting of GHG emissions by a number of entities beginning on
January 1, 2010. Most facilities will be required to report annually.
Electric generation facilities (including Idaho Powers facilities) already
reporting CO2 emissions under the Clean Air Act (CAA) Acid Rain
Program must report CO2, nitrous oxide and methane emissions to the
EPA on a quarterly basis.
In December 2009, the EPA issued an endangerment
finding for GHG emissions from motor vehicles which has been appealed to the
U.S. Court of Appeals for the District of Columbia Circuit. The endangerment
finding is required for the EPA and the Department of Transportation National
Highway Traffic Safety Administration to finalize their September 2009 proposal
to adopt national GHG emission standards for motor vehicles. On September 30,
2009, the EPA acknowledged that the CAA will require it to regulate GHG
emissions from stationary sources (including Idaho Powers thermal facilities)
through both its preconstruction and operating permit programs when it
finalizes its proposal to adopt national GHG emission standards for motor
vehicles. Under this proposed rule, EPA is seeking to establish an
applicability threshold of 25,000 tons of GHGs per year (CO2 equivalent)
for such programs.
Idaho Power will continue to monitor and evaluate any
proposed international, federal, state or regional GHG legislation or
initiatives as well as any judicial decisions that could affect its generating
facilities. The majority of current initiatives regarding GHG emissions
contemplate market-based compliance programs. The regulation of GHG emissions
under the CAA could result in GHG emission limits on stationary sources that do
not provide market-based compliance options such as cap-and-trade programs or
emission offsets. Such a program could raise uncertainty about the future
viability of fossil fuels, specifically coal, as an economical energy source
for new and existing electric generation facilities because new technologies
for reducing CO2 emissions from coal, including carbon capture
storage, are still in the development stage and are not yet proven. At this
time, however, Idaho Power is unable to estimate the costs of compliance with
any such legislation or initiatives because they are in the early stages of
development and final legislation, if adopted, could vary from current
proposals. In the 2009 IRP, Idaho Power did not include any new conventional
coal resources in the resource portfolio due to the uncertainty regarding
future carbon regulations.