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, 2007 |
OR
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
..................................................................
Exact name of registrants as specified in |
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Commission |
their charters, address of principal executive |
IRS Employer |
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File Number |
offices, zip code and telephone number |
Identification Number |
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1-14465 |
IDACORP, Inc. |
82-0505802 |
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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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Preferred Share Purchase Rights |
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SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: |
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Idaho Power Company: |
Preferred Stock |
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Indicate by check mark
whether the registrants are well-known seasoned issuers, as defined in Rule 405
of the Securities Act.
IDACORP, Inc. |
Yes |
( ) |
No |
( X ) |
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 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 |
Accelerated |
Non-accelerated |
Smaller reporting |
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filer |
( X ) |
filer |
( ) |
filer |
( ) |
company |
( ) |
|
Idaho Power Company: |
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Large accelerated |
Accelerated |
Non-accelerated |
Smaller reporting |
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filer |
( ) |
filer |
( ) |
filer |
( X ) |
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, 2007):
IDACORP, Inc.: |
$1,410,558,106 |
Idaho Power Company: |
None |
Number of shares of common
stock outstanding at January 31, 2008:
IDACORP, Inc.: |
45,069,259 |
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 |
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Regulation 14A for the 2008 Annual Meeting of Shareholders to be held on |
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May 15, 2008. |
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.
COMMONLY USED TERMS |
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AFDC |
- |
Allowance for Funds Used During Construction |
CAMP |
- |
Comprehensive Aquifer Management Plan |
CEP |
- |
Continuous Equity Program |
cfs |
- |
Cubic feet per second |
EIS |
- |
Environmental impact statement |
Energy Act |
- |
Energy Policy Act of 2005 |
EPS |
- |
Earnings per share |
ESA |
- |
Endangered Species Act |
ESPA |
- |
Eastern Snake Plain Aquifer |
FASB |
- |
Financial Accounting Standards Board |
FERC |
- |
Federal Energy Regulatory Commission |
FIN |
- |
Financial Accounting Standards Board Interpretation |
Fitch |
- |
Fitch, Inc. |
FPA |
- |
Federal Power Act |
GAAP |
- |
Generally Accepted Accounting Principles |
Ida-West |
- |
Ida-West Energy, a subsidiary of IDACORP, Inc. |
IDEQ |
- |
Idaho Department of Environmental Quality |
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. |
IPC |
- |
Idaho Power Company, a subsidiary of IDACORP, Inc. |
IPUC |
- |
Idaho Public Utilities Commission |
IRP |
- |
Integrated Resource Plan |
ITI |
- |
IDACORP Technologies, Inc. |
IWRB |
- |
Idaho Water Resource Board |
kW |
- |
Kilowatt |
maf |
- |
Million acre feet |
MD&A |
- |
Management's Discussion and Analysis of Financial Condition and Results of Operations |
Moody's |
- |
Moody's Investors Service |
MW |
- |
Megawatt |
MWh |
- |
Megawatt-hour |
NEPA |
- |
National Environmental Policy Act of 1996 |
O&M |
- |
Operations and Maintenance |
OPUC |
- |
Oregon Public Utility Commission |
PCA |
- |
Power Cost Adjustment |
PCAM |
- |
Power Cost Adjustment Mechanism |
PURPA |
- |
Public Utility Regulatory Policies Act of 1978 |
RFC |
- |
River Forecast Center |
RFP |
- |
Request for Proposal |
S&P |
- |
Standard & Poor's 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 |
Page |
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Part I |
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Business |
1-10 |
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Risk Factors |
10-13 |
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Unresolved Staff Comments |
13 |
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Properties |
14-15 |
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Legal Proceedings |
15 |
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Submission of Matters to a Vote of Security Holders |
15 |
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Executive Officers of the Registrants |
16-17 |
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Part II |
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Market for Registrant's Common Equity, Related Stockholder |
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Matters and Issuer Purchases of Equity Securities |
18-19 |
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Selected Financial Data |
20 |
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Management's Discussion and Analysis of Financial Condition and |
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Results of Operations |
21-64 |
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Quantitative and Qualitative Disclosures about Market Risk |
64-65 |
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Financial Statements and Supplementary Data |
66-119 |
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Changes in and Disagreements with Accountants on Accounting and |
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Financial Disclosure |
119 |
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Controls and Procedures |
120-125 |
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Other Information |
125 |
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Part III |
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Directors, Executive Officers and Corporate Governance* |
125 |
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Executive Compensation* |
125 |
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Security Ownership of Certain Beneficial Owners and Management and Related |
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Stockholder Matters* |
125-126 |
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Certain Relationships and Related Transactions, and Director Independence* |
126 |
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Principal Accountant Fees and Services* |
126-127 |
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Exhibits and Financial Statement Schedules |
128-139 |
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140-141 |
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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 2008 Annual Meeting of Shareholders. |
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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- "Management's Discussion and
Analysis of Financial Condition and Results of Operations (MD&A) - 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 (IPC). 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.
IPC 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. IPC 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 IPC.
IDACORP's 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.
IDACORP's strategy emphasizes
IPC as IDACORP's core business. IPC is experiencing moderate customer growth
in its service area, and this corporate strategy recognizes that IPC must make
substantial investments in infrastructure to ensure adequate electricity supply
and reliable service. IPC's regulatory plans for 2008 include finalizing the
2007 general rate case as well as additional initiatives designed to speed
recovery of the financial and operating costs of new facilities and system improvements.
IFS and Ida-West remain components of the corporate strategy.
On July 20, 2006, IDACORP
completed the sale of all of the outstanding common stock of IDACORP
Technologies, Inc. to IdaTech UK Limited, a wholly-owned subsidiary of Investec
Group Investments (UK) Limited, and on February 23, 2007, IDACORP completed the
sale of all of the outstanding common stock of IDACOMM, Inc. to American Fiber
Systems, Inc. IDACORP's consolidated financial statements reflect the
reclassification of the results of these businesses as discontinued operations
for all periods presented. Discontinued operations are discussed in more
detail in Note 16 to IDACORP's and IPC's Consolidated Financial Statements.
At December 31, 2007, IDACORP
had 2,044 full-time employees, 2,028 of which were employed by IPC.
IDACORP's only reportable business
segment is IPC, which contributed $77 million to income from continuing
operations in 2007.
IDACORP and IPC 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, through IDACORP's website at www.idahocorpinc.com and through a
link to the IDACORP website from the IPC website at www.idahopower.com.
UTILITY OPERATIONS:
IPC was incorporated under
the laws of the state of Idaho in 1989 as successor to a Maine corporation
organized in 1915. IPC's service territory covers a 24,000 square mile area in
southern Idaho and eastern Oregon, with an estimated population of 982,000.
IPC 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, 2007, IPC supplied electric energy to approximately 482,000
general business customers.
IPC is one of the nation's
few investor-owned utilities with a predominantly hydroelectric generating
base. IPC owns and operates 17 hydroelectric generation developments, two
natural gas-fired plants and one diesel-powered generator and shares ownership
in three coal-fired generating plants. These generating plants and their
capacities are listed in Item 2 - "Properties." IPC's coal-fired plants are in
Wyoming, Oregon and Nevada, and use low-sulfur coal from Wyoming and Utah.
The primary influences on
electricity sales are weather, customer growth and economic conditions.
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.
IPC's principal commercial
and industrial customers are involved in food processing, electronics and
general manufacturing, forest products, beet sugar refining and winter
recreation.
Regulation
IPC is under the regulatory
jurisdiction (as to rates, service, accounting and other general matters of
utility operation) of the FERC, the Idaho Public Utilities Commission (IPUC)
and the Oregon Public Utility Commission (OPUC). IPC is also under the
regulatory jurisdiction of the IPUC, the OPUC and the Public Service Commission
of Wyoming as to the issuance of debt and equity securities. IPC is subject to
the provisions of the Federal Power Act (FPA) as a "public utility" as therein
defined. IPC's retail rates are established under the jurisdiction of the
state regulatory commissions and its wholesale and transmission rates are
regulated by the FERC (see "Rates" below). Pursuant to the requirements of
Section 210 of PURPA, the state regulatory commissions have each issued orders
and rules regulating IPC's purchase of power from cogeneration and small power
production (CSPP) facilities.
IPC is subject to
the provisions of the FPA as a "licensee" as therein defined. As a licensee
under the FPA, IPC and its licensed hydroelectric projects are subject to the
provisions of Part I of the FPA. All licenses 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.
The state of Oregon has a
Hydroelectric Act providing for licensing of hydroelectric projects in that
state. IPC's Brownlee, Oxbow and Hells Canyon facilities are on the Snake
River where it forms the boundary between Idaho and Oregon and occupy lands in
both states. With respect to project property located in Oregon, these
facilities are subject to the Oregon Hydroelectric Act. IPC has obtained
Oregon licenses for these facilities and these licenses are not in conflict
with the FPA or IPC's FERC licenses (see Part II, Item 7 - "MD&A -
REGULATORY MATTERS - Relicensing of Hydroelectric Projects").
Rates
The rates IPC charges to its general
business customers are determined by the IPUC and the OPUC. Significant rate
cases and proceedings are discussed in more detail in Part II, Item 7 - "MD&A
- REGULATORY MATTERS." Approximately 95 percent of IPC's general business
revenue comes from customers in Idaho. IPC has a Power Cost Adjustment (PCA)
mechanism that provides for annual adjustments to the rates charged to its
Idaho retail customers. These adjustments are based on forecasts of net power
supply costs, which are fuel and purchased power less off-system sales, and the
true-up of the prior year's forecast. During the year, approximately 90
percent of the difference between the actual and forecasted costs is deferred
with interest. The ending balance of this deferral, called the true-up for the
current year's portion and the true-up of the true-up for the prior years'
unrecovered or over-recovered portion, is then included in the calculation of
the next year's PCA. IPC has also applied to the OPUC to implement a PCA
mechanism in Oregon similar to the one in Idaho.
Power Supply
IPC meets its system load
requirements using a combination of its own generation, mandated purchases from
private developers (see "CSPP Purchases" below) and purchases from other
utilities and power wholesalers. IPC's generating plants and capacities are
listed in Item 2 - "Properties."
IPC's system is dual peaking,
with the larger peak demand occurring in the summer. The all-time system peak
demand is 3,193 megawatts (MW), set on July 13, 2007. The previous hourly
system peak of 3,084 MW was set in 2006. The all-time winter peak demand is
2,464 MW set on January 24, 2008. The previous hourly system winter peak of
2,459 MW was set in 1998. IPC expects total system average load to grow 2.1
percent annually over the next three years.
Because of its reliance on
hydroelectric generation, IPC's generation operations can be significantly
affected by weather conditions. The availability of hydroelectric power
depends on the amount of snow pack in the mountains upstream of IPC's hydroelectric
facilities, reservoir storage, springtime snow pack run-off, river base flows,
spring flows, rainfall and other weather and stream flow management
considerations. During low water years, when stream flows into IPC's
hydroelectric projects are reduced, IPC's hydroelectric generation is reduced.
This results in less generation from IPC's resource portfolio (hydroelectric,
coal-fired and gas-fired) available for off-system sales and, most likely, 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.
The following table presents
IPC's system generation for the last three years:
MWh |
|
Percent of total generation |
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2007 |
|
2006 |
|
2005 |
|
2007 |
|
2006 |
|
2005 |
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(thousands of MWhs) |
|
|
|
|
|
|
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Hydroelectric |
6,181 |
9,207 |
6,199 |
46% |
57% |
46% |
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Thermal |
7,367 |
7,021 |
7,315 |
54% |
43% |
54% |
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Total system generation |
13,548 |
16,228 |
13,514 |
100% |
100% |
100% |
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Under normal stream flow
conditions, IPC's system generation mix is approximately 55 percent
hydroelectric and 45 percent thermal.
The generation from IPC's
hydroelectric facilities in 2007 was reduced due to poor stream flow conditions.
The observed stream flow data released on August 1, 2007, by the National
Weather Service's Northwest River Forecast Center (RFC) indicated that Brownlee
reservoir inflow for April through July 2007 was 2.8 million acre-feet (maf),
or 44 percent of the RFC average. Brownlee reservoir inflow for 2007 totaled
8.5 maf, or 56 percent of the RFC average.
Streamflow projections for
2008 are somewhat improved. Storage in selected federal reservoirs upstream of
Brownlee as of February 10, 2008 was 76 percent of average. The stream flow
forecast released on February 14, 2008, by the RFC predicts that Brownlee
reservoir inflow for April through July 2008 will be 5.7 maf, or 90 percent of
the RFC average.
IPC's generating facilities
are interconnected through its integrated transmission system and are operated
on a coordinated basis to achieve maximum load-carrying capability and
reliability. IPC's transmission system is directly interconnected with the
transmission systems of the Bonneville Power Administration, Avista
Corporation, PacifiCorp, NorthWestern Energy and Sierra Pacific Power Company.
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. IPC
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. See "Competition - Wholesale" below.
Fuel: IPC, 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 IPC) in Wyoming. 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. IPC also has a coal supply contract providing for annual deliveries
of coal through 2009 from the Black Butte Coal Company's 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 plant's 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.
The Bridger Coal mine experienced
difficulties in meeting its production volume and operating cost goals during
early 2008. The problems stemmed from soft floor and roof stability issues
that began in late December 2007 in the underground longwall mining operation
(longwall). The impact on December 2007 production was relatively minor;
however the problems persisted and January 2008 production volume was
approximately 20 percent of forecast. As of late February 2008, the longwall
was operating at normal production. IPC believes Bridger Coal's overall 2008
production and cost objectives are achievable by modifying the surface mine
operation plan to offset the underground mining difficulties. Using coal from
both mine and plant stockpiles, planned deliveries to the Jim Bridger power
plant continue and generation is not expected to be negatively impacted.
Sierra Pacific Power Company,
as operator of the North Valmy generating plant, has an agreement with Arch
Coal Sales Company, Inc. to supply coal to the plant through 2011. IPC, 50
percent owner of the plant, is obligated to purchase one-half of the coal,
ranging from 515,000 tons to 762,500 tons annually. Sierra Pacific Power
Company also has a coal supply contract with Black Butte Coal Company's Black
Butte Mine for deliveries through 2009. IPC is obligated to purchase one-half
of the coal purchased under this agreement, ranging from 450,000 to 600,000
tons annually.
The Boardman generating plant
receives coal from the Powder River Basin through annual contracts. Portland
General Electric, as operator of the Boardman plant, has an agreement with
Buckskin Mining Company to supply all of Boardman's coal requirements through
2008. As 10 percent owner of the plant, IPC is obligated to purchase ten
percent of the coal purchased under this agreement, ranging from 230,000 to
270,000 tons annually. A Request for Proposal to secure coal for the period
2009-2013 is in process.
IPC owns and operates the
Danskin and Bennett Mountain combustion turbines, which are supplied gas
through the Northwest Pipeline GP's pipeline. Gas is purchased as needs are
identified for summer peaks or to meet system requirements. The gas is
transported under a long-term agreement with Northwest Pipeline GP for 24,523
million British thermal units (MMBtu) per day. This agreement runs through
February 28, 2022, with annual extensions at IPC's sole discretion. IPC also
has the ability to flow a total of 73,569 MMBtu as alternate firm basis without
incurring a reservation charge on the additional amount. In addition to this agreement,
IPC has entered into a long-term agreement with Northwest Pipeline GP 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 IPC on a monthly basis. IPC's
current storage allotment is approximately 18 percent of its total, and its
full allotment is expected to be reached by January 2011. The firm storage
contract extends through November 1, 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.
Water Rights: Except as discussed below, IPC has acquired water
rights under applicable state law for all waters used in its hydroelectric
generating facilities. In addition, IPC holds water rights for domestic,
irrigation, commercial and other necessary purposes related to other land and
facility holdings within the state. The exercise and use of all of these water
rights are subject to prior rights, and with respect to certain hydroelectric
generating facilities, IPC's water rights for power generation are subordinated
to certain future upstream diversions of water for irrigation and other
recognized consumptive uses.
Over time, increased
irrigation development and other consumptive diversions have resulted in a
reduction in the stream flows available to fulfill IPC's water rights at
certain hydroelectric generating facilities. In reaction to these reductions,
IPC initiated and continues to pursue a course of action to determine and
protect its water rights. As part of this process, IPC and the state of Idaho
signed the Swan Falls agreement on October 25, 1984, which provided a level of
protection for IPC's hydropower water rights at specified plants by setting
minimum stream flows and establishing an administrative process governing the
future development of water rights that may affect IPC's hydroelectric generation.
In 1987, Congress passed, and the President signed into law, House Bill 519.
This legislation permitted implementation of the Swan Falls agreement and
further provided that during the remaining term of certain of IPC's project
licenses the relationship established by the agreement would not be considered
by the FERC as being inconsistent with the terms of IPC's project licenses or
imprudent for the purposes of determining rates under Section 205 of the FPA.
The FERC entered an order implementing the legislation on March 25, 1988.
In addition to providing for
the protection of IPC's hydroelectric water rights, the Swan Falls agreement
contemplated the initiation of a general adjudication of all water uses within
the Snake River basin. In 1987, the director of the Idaho Department of Water
Resources filed a petition in state district court asking that the court
adjudicate all claims to water rights, whether based on state or federal law,
within the Snake River basin. The court signed a commencement order initiating
the Snake River Basin Adjudication on November 19, 1987. This legal proceeding
was authorized by state statute based upon a determination by the Idaho
Legislature that the effective management of the waters of the Snake River
basin required a comprehensive determination of the nature, extent and priority
of all water uses within the basin. The adjudication is proceeding and is
expected to continue for at least the next several years. IPC has filed claims
to its water rights within the basin and is actively participating in the
adjudication in an effort to ensure that its water rights and the operation of
its hydroelectric facilities are not adversely impacted. In certain instances,
the adjudication of water rights in the Snake River Basin Adjudication (SRBA)
results in the initiation of litigation, called subcases, to determine the
scope and nature of a particular water right. IPC is involved in subcases
involving not only its water rights but also the water rights of other
claimants. One such subcase involves IPC's water rights at the Swan Falls
project on the Snake River and several other upstream hydroelectric projects
that are the subject of the Swan Falls Agreement. IPC also has initiated legal
action against the U.S. Bureau of Reclamation (USBR) over the interpretation
and effect of a 1923 contract with the USBR on the operation of the American
Falls Reservoir and the release of water from that reservoir to be used at IPC's
downstream hydroelectric projects.
Please see Part II, Item 7 - "MD&A
- LEGAL AND ENVIRONMENTAL ISSUES - Environmental Issues - Idaho Water
Management Issues" and "MD&A - REGULATORY MATTERS - Relicensing of
Hydroelectric Projects."
Integrated Resource Plan
(IRP): The IRP is IPC's business
plan for resource acquisition and is the starting point for demonstrating
prudence in IPC's resource decisions. IPC filed its 2006 IRP with the IPUC in
September 2006 and with the OPUC in October 2006. Prior to filing, the IRP
requires extensive involvement by IPC, the IPUC Staff, the OPUC Staff, and
customer and environmental representatives, as well as input on the cost of
generation technologies. The 2006 IRP identified IPC's forecast load and
resource situation for the next twenty years, analyzed potential supply-side
and demand-side options and identified near-term and long-term actions. The
two primary goals of the 2006 IRP were to (1) identify sufficient resources to
reliably serve the growing demand for electric service within IPC's service
area throughout the 20-year planning period and (2) ensure that the portfolio
of resources selected balances cost, risk and environmental concerns.
The IPUC accepted the 2006
IRP in March 2007. The OPUC acknowledged the 2006 IRP in September 2007 with
the stipulation that IPC not commit to the construction of a 250-MW pulverized
coal resource, identified to come on-line in 2013, until IPC presents an update
of the 2006 IRP to the OPUC no later than June 2008. With its acceptance of
the 2006 IRP, the IPUC requested that IPC align the submittal of its next IRP
with those submitted by other utilities. To comply with this request IPC
intends to provide an update on the status of the 2006 IRP to both the IPUC and
OPUC no later than June 2008 and file a new IRP in June 2009.
In a departure from the 2006
IRP, IPC plans to construct a natural gas-fired combined cycle combustion
turbine located close to its load center in southern Idaho. IPC determined
that coal-fired generation was not the best technology to meet its resource
needs by 2013 due to escalating construction costs, potential permitting
issues, and continued uncertainty surrounding future greenhouse gas laws and
regulations. See further discussion in Part II - Item 7 - "MD&A -
REGULATORY MATTERS - Integrated Resource Plan."
CSPP Purchases: As
mandated by the enactment of PURPA and the adoption of avoided cost rates by
the IPUC and the OPUC, IPC has entered into contracts for the purchase of
energy from a number of private developers. Under these contracts, IPC is
required to purchase all of the output from the facilities located inside the
IPC service territory. For projects located outside the IPC service territory,
IPC is required to purchase the output that IPC has the ability to receive at
the facility's requested point of delivery on the IPC system. The IPUC
jurisdictional portion of the costs associated with CSPP contracts are fully
recovered through base rates and the PCA. 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. The OPUC
jurisdictional portion of the costs associated with CSPP contracts is recovered
through general rate case filings. 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. The Published
Avoided Cost is a price established by the IPUC and OPUC to estimate IPC's cost
of developing additional generation resources. If a PURPA project does not
qualify for Published Avoided Costs, then IPC is required to negotiate the
terms, prices and conditions with the developer of that project. These
negotiations reflect the characteristics of the individual projects (i.e.,
operational flexibility, location and size) and the benefits to the IPC system
and must be consistent with other similar energy alternatives. During 2007 the
IPUC issued orders increasing the Published Avoided Cost and requiring
differentiation between heavy load and light load hour energy prices. See Part
II - Item 7 - "MD&A - REGULATORY MATTERS - Wind Integration Costs and PURPA
Avoided Cost Rate Computation."
On August 4, 2005, the IPUC
granted a temporary reduction in the eligible CSPP project size to 100 kW for
intermittent generation resources (such as wind) only and ordered IPC to study
the impacts of integrating this type of resource. IPC completed and filed with
the IPUC a wind generation integration study report on February 6, 2007.
Public workshops were conducted, comments were filed with the IPUC, and
information request responses were submitted to the IPUC. A proposed
settlement of this issue has been presented to the IPUC for its consideration.
In 2007, as required by the
OPUC, IPC filed new avoided costs for the state of Oregon and new standard
contracts. The OPUC has approved the new rates and standard contracts.
As of December 31, 2007, IPC
had signed agreements to purchase energy from 94 CSPP facilities with contracts
ranging from one to 30 years. Seventy-six of these facilities, with a combined
nameplate capacity of 231 MW, were on-line at the end of 2007; the other 18
facilities under contract, with a combined nameplate capacity of 267 MW, are
projected to come on-line between 2008 and 2010. The majority of the new
facilities will be wind resources which will generate on an intermittent
basis. During 2007, IPC purchased 777,147 megawatt-hours (MWh) from these
projects at a cost of $45 million, resulting in a blended price of 5.9 cents
per kilowatt hour.
Wholesale Energy Market
Activities: Guided by a risk
management policy and frequently updated operating plans, IPC participates in
the wholesale energy market by buying power to help meet load demands and
selling power that is in excess of load demands. IPC's market activities are
influenced by its customer loads, market prices, and cost and availability of
generating resources. Some of IPC's 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. Compliance factors, such as allowable river stage elevation changes
and flood control requirements, and wholesale energy market prices influence
these dispatch decisions.
Due to the uncertainty
regarding the regulation requirements of anticipated wind generation, IPC
terminated the wholesale contract for load following services provided to
NorthWestern Energy, effective December 31, 2007. The load following contract
required IPC to increase or decrease its generation by up to 30 MW to react to
NorthWestern's system load changes.
IPC has one firm wholesale
power sales contract. The sales contract is with the Raft River Electric
Cooperative for up to 15 MW. This contract expires in September 2008; however,
Raft River Electric Cooperative has provided notice that it intends to renew
the contract, as allowed in the original agreement, through September 2010.
IPC has one wholesale reserve
sales contract. The reserve contract is with United Materials of Great Falls,
Inc. (United Materials). This agreement requires IPC to carry up to 0.45 MW of
reserves associated with an energy sales agreement dated January 2004 between
IPC and United Materials from the Horseshoe Bend Wind Farm. The term of this
agreement began in January 2008, and runs seasonally through May 2013.
IPC has one firm wholesale purchased power contract. This contract is with PPL
Montana, LLC for 83 MW per hour during heavy load hours, to address increased
demand during June, July and August. The term of this contract began in June
2004 and runs through August 2009.
Transmission Services
IPC provides wholesale transmission
service and provides firm and non-firm wheeling services for eligible transmission
customers. IPC's system lies between and is interconnected with the winter-peaking
northern and summer-peaking southern regions of the western power system. This
geographic position allows IPC to provide transmission services and to reach a broad
power market.
IPC holds rights-of-way from
Midpoint substation in south-central Idaho through eastern Nevada to the Dry
Lake area northeast of Las Vegas, Nevada, known as the Southwest Intertie
Project (SWIP). In 2004, the Bureau of Land Management granted a five-year
extension to begin construction of a proposed 500-kilovolt transmission line
within the rights-of-way to December 2009. IPC obtained the rights-of-way to
construct a transmission line along this corridor, but no longer plans to build
the line. On March 31, 2005, IPC entered into an agreement with White Pine
Energy Associates, LLC (White Pine), an affiliate of LS Power Development, LLC,
which provides White Pine a three-year exclusive option to purchase the SWIP
rights-of-way from IPC. The option may be exercised in part or as a whole and,
if fully exercised, will result in a net pre-tax gain to IPC of approximately
$6 million.
Environmental Regulation
IPC's 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. Environmental
regulation continues to impact IPC's 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. IPC's compliance costs will continue to be significant for the
foreseeable future.
Based upon present
environmental laws and regulations, IPC estimates its 2008 capital expenditures
for environmental matters, excluding Allowance for Funds Used During
Construction (AFDC), will total $26 million. Studies and measures related to
environmental concerns at IPC's hydroelectric facilities account for $15
million, and investments in environmental equipment and facilities at the
thermal plants account for $11 million. For 2009 and 2010, environmental-related
capital expenditures, excluding AFDC, are estimated to be $65 million.
Anticipated expenses related to IPC's hydroelectric facilities account for $29
million, and thermal plant expenses are expected to total $36 million.
IPC anticipates approximately
$20 million in annual operating costs for environmental facilities during
2008. Hydroelectric facility expenses and thermal plant expenses account for
the majority of the costs at approximately $13 million and $7 million,
respectively. For 2009 and 2010, total environmental related operating costs
are estimated to be approximately $54 million. Expenses related to the
hydroelectric facilities are expected to be $39 million, and thermal plant
expenses are expected to be $15 million during this period.
Air Quality Issues: IPC owns two natural gas combustion turbine power
plants and co-owns three coal-fired power plants that are subject to air
quality regulation. The natural gas-fired plants, Danskin and Bennett
Mountain, are located in Idaho. The coal-fired plants are: Jim Bridger
located in Wyoming; Boardman located in Oregon; and North Valmy located in
Nevada. Please see Part II, Item 7 - "MD&A - LEGAL AND ENVIRONMENTAL
ISSUES - Environmental Issues - Air Quality Issues" for a discussion of these
matters.
Water: As required under the Federal Water Pollution
Control Act Amendments of 1972, IPC has received necessary environmental
permits and authorizations and has prepared necessary plans relating to
operations and water quality, such as effluent discharge, spill prevention and
countermeasures, and storm water pollution prevention.
The FERC licenses issued for
IPC's American Falls and Cascade hydroelectric generating plants require
aeration of turbine water to meet dissolved oxygen standards in the tail waters
downstream from the plants. In order to comply with the licenses, IPC
installed and operates aeration equipment at both plants and submits compliance
reports to the appropriate regulatory agencies.
The FERC licenses issued for
IPC's Milner, Shoshone Falls, Twin Falls, Upper Salmon, Lower Salmon, Bliss and
CJ Strike hydroelectric projects require dissolved oxygen and temperature
monitoring and reporting. IPC submits compliance reports to the appropriate
regulatory agencies.
The FERC license for the CJ
Strike project also requires monitoring of total dissolved gas during spill
periods. IPC installs monitors during periods of spill that record gas levels
in spilled water and reports the results to the appropriate regulatory
agencies.
Hazardous/Toxic Wastes and
Substances: Under the Toxic
Substances Control Act, the EPA has adopted regulations governing the use,
storage, inspection and disposal of electrical equipment that contains
polychlorinated biphenyls (PCBs). The regulations permit the continued use and
servicing of certain equipment (including transformers and capacitors) that
contain PCBs. IPC continues to meet federal requirements of the Toxic
Substances Control Act for the continued use of equipment containing PCBs. IPC
continues to eliminate PCBs as part of its long-term strategy. This program
will reduce costs associated with the long-term monitoring of PCB-containing
equipment, responding to spills and reporting to the EPA. In 2007, IPC spent
approximately $0.8 million identifying and eliminating PCBs.
For a discussion of other
environmental issues, including air quality, endangered species, and climate
change, please see Part II, Item 7 - "MD&A - Legal and Environmental Issues
- Environmental Issues."
Energy Efficiency
In 2007, IPC spent approximately $15.6
million to promote energy efficiency and summer peak reduction through its
Demand Side Management (DSM) programs. Major funding for program development,
implementation and administration comes from the Idaho and Oregon tariff riders
for DSM. From 2001 to March 2007, when funding was discontinued due to the
suspension of investor-owned utilities' participation in the Residential
Exchange Program of the Bonneville Power Administration (BPA), IPC also
received funding from the Conservation and Renewables Discount Program of the BPA.
Approximately $1.8 million was
spent on research, analysis and development, technology evaluation, market
transformation, and general overhead expenses. A portion of this activity was
accomplished in conjunction with the Northwest Energy Efficiency Alliance (NEEA).
IPC contributed $0.9 million to the NEEA.
The following energy
efficiency programs target savings across the entire year for a wide range of
customer segments with an emphasis on reducing energy during the summer peak:
Approximately $4.0 million was devoted to achieving summer peak reduction through focusing on irrigation pumping and residential air conditioning equipment control measures.
The residential energy efficiency programs targeted 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. This segment's 2007 spending was approximately $3.3 million.
Programs for new or existing industrial and commercial facilities focus on application of energy efficient techniques and technologies as well as operational and management processes to reduce energy consumption. Approximately $4.5 million was spent on these programs.
Approximately $2.0 million was devoted to irrigation efficiency programs. Irrigation customers can receive financial incentives for either improving the energy efficiency of an irrigation system or installing a new energy efficiency system.
In 2007, IPC's energy
efficiency programs reduced energy usage by approximately 91,000 MWh and the targeted
demand reduction programs resulted in a summer peak reduction of about 48 MW.
Competition
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.
Some state regulatory
authorities are in the process of changing utility regulations in response to
federal and state statutory changes and evolving competitive markets. These
statutory changes and conforming regulations may result in increased retail
competition. However, restructuring of the electric industry has stalled at
both the national level and in the Pacific Northwest.
Wholesale: The 1992 National Energy Policy Act and the FERC's
rulemaking activities have established the regulatory framework to open the
wholesale energy market to competition. This act permits entities to develop
independent electric generating plants for sales to wholesale customers, and
authorizes the FERC to order transmission access for third parties to
transmission facilities owned by another entity. This act does not, however,
permit the FERC to require transmission access to retail customers. Open-access
transmission for wholesale customers provides energy suppliers with
opportunities to sell and deliver electricity at market-based prices. IPC
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.
For more information, see
Part II, Item 7 - "MD&A - REGULATORY MATTERS - FERC Proceedings."
Utility Operating
Statistics
The following table presents IPC's
revenues and energy use by customer type for the last three years. IPC's
operations are discussed further in Part II, Item 7 - "MD&A - RESULTS OF
OPERATIONS - Utility Operations:"
Years Ended December 31, |
||||||||||
2007 |
|
2006 |
|
2005 |
||||||
Revenues (thousands of dollars) |
||||||||||
Residential |
$ |
308,208 |
$ |
299,594 |
$ |
299,488 |
||||
Commercial |
170,001 |
162,391 |
173,268 |
|||||||
Industrial |
101,409 |
102,958 |
118,259 |
|||||||
Irrigation |
88,685 |
71,432 |
76,255 |
|||||||
Total general business |
668,303 |
636,375 |
667,270 |
|||||||
Off-system sales |
154,948 |
260,717 |
142,794 |
|||||||
Other |
52,150 |
23,381 |
27,619 |
|||||||
Total |
$ |
875,401 |
$ |
920,473 |
$ |
837,683 |
||||
Energy use (thousands of MWh) |
||||||||||
Residential |
5,227 |
5,068 |
4,760 |
|||||||
Commercial |
3,937 |
3,761 |
3,639 |
|||||||
Industrial |
3,454 |
3,475 |
3,423 |
|||||||
Irrigation |
1,924 |
1,635 |
1,467 |
|||||||
Total general business |
14,542 |
13,939 |
13,289 |
|||||||
Off-system sales |
2,744 |
5,821 |
2,774 |
|||||||
Total |
17,286 |
19,760 |
16,063 |
|||||||
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 $15 million, $19 million
and $20 million in 2007, 2006 and 2005, respectively. IFS's portfolio also
includes historic rehabilitation projects such as, the Empire Building in
Boise, Idaho. IFS did not make any new investments during 2007.
IFS has focused on a
diversified approach to its investment strategy in order to limit both
geographic and operational risk. Over 90 percent of IFS's investments have
been made through syndicated funds. At December 31, 2007, the gross amount of
IFS's portfolio equaled $175 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. IPC purchased all of the power generated by Ida-West's four Idaho
hydroelectric projects at a cost of $8 million in both 2007 and 2006, and $7
million in 2005.
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. Idaho Power Company has a predominately hydroelectric generating base. Because of Idaho Power Company's heavy reliance on hydroelectric generation, the weather 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. Through its power cost adjustment in Idaho, Idaho Power Company can expect to recover approximately 90 percent of the increase in its Idaho jurisdictional net power supply costs, which are fuel and purchased power less off-system sales, above the level included in its base rates. The power cost adjustment recovery includes both a forecast and deferrals that are subject to the regulatory process. However, recovery of amounts above forecast in one power cost adjustment year does not occur until the subsequent power cost adjustment year. The non-Idaho net power supply costs are subject to periodic recovery from the Oregon and Federal Energy Regulatory Commission jurisdictional customers.
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 Company's revenues and increase costs. Idaho Power Company is also involved in legal actions involving the water rights it holds for hydroelectric purposes. One such action, initiated in the Snake River Basin Adjudication, involves Idaho Power Company's water rights at the Swan Falls project on the Snake River and several other upstream hydroelectric projects that are the subject of a 1984 agreement with the state of Idaho known as the Swan Falls Agreement. 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 Company's downstream hydroelectric projects. The resolution of these legal actions may affect Snake River flows available for hydroelectric generation and thereby reduce Idaho Power Company revenues and increase costs.
Load growth in Idaho Power Company's service territory exposes it to greater market and operational risk and could increase costs and reduce earnings and cash flows. 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.
o Through its annual power cost adjustment in Idaho, Idaho Power Company can expect to recover approximately 90 percent of the increase in its Idaho jurisdictional net power supply costs, which are fuel and purchased power less off-system sales, above the level included in its base rates. The remaining ten percent is absorbed by Idaho Power Company.
o Idaho Power Company's load growth adjustment rate adjusts the net power supply costs Idaho Power Company includes in its annual power cost adjustment for differences between actual load and the load used in calculating base rates. In periods of growing load, the marginal energy costs of serving new Idaho retail customers are subtracted from the power cost adjustment leaving Idaho Power Company with no opportunity between general rate case filings to recover these costs. If the Idaho Public Utilities Commission increases the rate or modifies the method used to calculate the load growth adjustment rate, or if customer load is higher than the load used to calculate base rates, Idaho Power Company's earnings and cash flows could be reduced.
o Since the Federal Energy Regulatory Commission implemented market-based wholesale power rates in 1997, the price volatility of electricity has substantially increased from what it was at the inception of the power cost adjustment. As Idaho Power Company's reliance on purchased power continues to increase, the risks associated with the remaining ten percent not recovered through the power cost adjustment could increase costs and reduce earnings and cash flows.
o Increased load growth can result in the need for additional investments in Idaho Power Company's 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 flow.
o Increased and unexpected load growth can create planning and operating difficulties for Idaho Power Company that can impact its ability to reliably serve customers.
Idaho Power Company's 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 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 Company's 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.
Changes in temperature and precipitation can reduce power sales and revenues. Warmer than normal winters, cooler than normal summers and increased rainfall during the irrigation seasons will reduce retail revenues from power sales.
Climate change could affect customer demand and hydroelectric generation and lead to restrictions on generation resources. Long-term climate change could significantly affect Idaho Power Company's business because changes in temperature, precipitation and snow pack conditions could affect customer demand and the amount and timing of hydroelectric generation. In addition, legislative and/or regulatory developments related to climate change could place restrictions on construction of new generation resources, the expansion of existing resources, or operation of generation resources.
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 and economic expansion may be limited. If the Idaho Public Utilities Commission, the Oregon Public Utility Commission or the Federal Energy Regulatory Commission were to 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 flow and could result in downgrades of IDACORP, Inc.'s and Idaho Power Company's credit ratings. Failure to obtain regular and timely rate relief may limit Idaho Power Company's possibilities for economic expansion.
Conditions that may be imposed in connection with hydroelectric license renewals may require large capital expenditures 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 Company's licenses. These conditions could have a negative effect on Idaho Power Company's operations, require large capital expenditures and reduce earnings and cash flows.
The cost of complying with environmental regulations can increase capital expenditures and operating costs and reduce earnings and cash flows. IDACORP, Inc. and Idaho Power Company are 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. These expenditures could become even more significant in the future if legislation and enforcement policies change. For instance, considerable attention has been focused on emissions from coal-fired generating plants, including carbon dioxide, and their potential role in contributing to global warming. The effects of mercury and other pollutant emissions from coal-fired plants are also being discussed. Governmental and non-governmental entities closely scrutinize these plants and bring enforcement actions to ensure compliance. The adoption of new statutes, rules and regulations to implement carbon dioxide, mercury or other emission controls could result in increased capital expenditures and could increase the cost of operating coal-fired generating plants, and reduce earnings and cash flows.
IDACORP, Inc., IDACORP Energy and Idaho Power Company are subject to costs and other effects of legal and regulatory proceedings, settlements, investigations and claims, including those that have arisen out of the western energy situation. IDACORP, Inc., IDACORP Energy and Idaho Power Company are involved in a number of proceedings including the California refund proceeding at the Federal Energy Regulatory Commission, which has been settled with the largest portion of the market participants but which has appeals pending at 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, in which the Federal Energy Regulatory Commission directed that no refunds be paid, but in connection with which the United States Court of Appeals for the Ninth Circuit issued a decision remanding the matter to the Federal Energy Regulatory Commission and which is presently the subject of rehearing applications pending before the United States Court of Appeals for the Ninth Circuit; show cause proceedings at the Federal Energy Regulatory Commission, which have been settled but have been appealed; claims pending before the United States Court of Appeals for the Ninth Circuit that the Federal Energy Regulatory Commission ordered refund period should have been expanded to include a longer time period; and the reversal by the United States Court of Appeals for the Ninth Circuit of Federal Energy Regulatory Commission rulings that market-based sellers' transactional reports satisfy the Federal Energy Regulatory Commission's filed-rate doctrine requirements as a means of expanding refunds from all sellers of wholesale power, which rulings have been remanded to the Federal Energy Regulatory Commission. To the extent the companies are required to make payments, earnings and cash flows will be negatively affected. 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.
Idaho Power Company's 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. Compliance with these requirements directly influences Idaho Power Company's operating environment and may significantly increase Idaho Power Company's operating costs.
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 Company's 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 Company's system could potentially increase repair and maintenance expenses, purchased power expenses and capital expenditures.
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 its ability 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, 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 Company's credit ratings could negatively affect the companies' ability to access capital and increase their cost of borrowing. On January 31, 2008, Standard & Poor's Ratings Services lowered the corporate credit rating and long-term ratings of IDACORP, Inc. and Idaho Power Company. In addition, two series of pollution control bonds issued for Idaho Power Company's benefit are supported by financial guaranty insurance policies. The interest rates on these bonds have increased significantly because of the ratings downgrades of the bond insurer. 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. Current or future downgrades of IDACORP, Inc.'s or Idaho Power Company's credit ratings, or those affecting bond insurers or relationship banks, could limit the companies' ability to access capital, including the commercial paper markets, and require IDACORP, Inc. and Idaho Power Company to pay a higher interest rate on their debt.
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.
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 IDACORP's and Idaho Power Company's earnings and cash flows.
Employee workforce factors could increase costs and reduce earnings. Idaho Power Company is subject to workforce factors, including loss or retirement of key personnel, availability of qualified personnel, and an aging workforce. Demographic factors in the workplace present challenges to employers nationwide and are of particular concern to the electric utility industry. Approximately one-half of the industry's workforce is age 45 or older, making the median age of utility workers higher than the national average. Idaho Power Company is confronted with the challenge of retaining its skilled workforce while recruiting new talent to offset critical losses due to retirements. The costs of attracting and retaining appropriately qualified employees to replace an aging workforce could reduce earnings and cash flows.
ITEM
1B. UNRESOLVED STAFF COMMENTS
None
ITEM 2. PROPERTIES
IPC's 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 4,747 miles of high-voltage
transmission lines, 23 step-up transmission substations located at power
plants, 20 transmission substations, eight switching stations, 222 energized
distribution substations (excluding mobile substations and dispatch centers)and
approximately 64,672 miles of distribution lines.
IPC 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 (4) |
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)(3) |
261,800 |
||||||||
Salmon (diesel-internal combustion) |
5,000 |
||||||||
Bennett Mountain (gas-fired) |
172,800 |
||||||||
Total Steam and Other |
1,557,801 |
||||||||
Total Generation |
3,266,846 |
||||||||
(1) Licensed on an annual basis while application for new multi-year license is pending. |
|||||||||
(2) IPC's ownership interests are 33 percent for Jim Bridger, 50 percent for Valmy and 10 percent for Boardman. Amounts |
|||||||||
shown represent IPC's share. |
|||||||||
(3) Includes unit under construction (estimated at 170,000 kW and commercial acceptance on April 1, 2008). |
|||||||||
(4) Nameplate capacity has been updated as part of the NERC reliability standards FAC-008 and 009 review process. |
|||||||||
See discussion of relicensing
in Part II, Item 7 - "MD&A - REGULATORY MATTERS - Relicensing of
Hydroelectric Projects."
At December 31, 2007, the
composite average ages of the principal parts of IPC's system, based on dollar
investment, were: production plant, 25 years; transmission lines and
substations, 23 years; and distribution lines and substations, 20 years. IPC
considers its properties to be well-maintained and in good operating condition.
IPC 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. IPC's property is also subject to the lien of its Mortgage and Deed
of Trust and the provisions of its project licenses. In addition, IPC's
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, IPC of
such properties.
Idaho Energy Resources Co.
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.
See Note 1 to IDACORP's and
IPC's Consolidated Financial Statements for a discussion of the property of
IDACORP's consolidated Variable Interest Entities.
See Note 7 to IDACORP's and
IPC's 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 President and
Chief Executive Officer, appointed July 1, 2006. Mr. Keen also serves as
President and Chief Executive Officer of Idaho Power Company, appointed
November 17, 2005. Mr. Keen was Executive Vice President of IDACORP, Inc.,
from March 1, 2002, to July 1, 2006, and President and Chief Operating Officer
of Idaho Power Company from March 1, 2002, to November 17, 2005. Mr. Keen was
Senior Vice President - Administration and Chief Financial Officer of IDACORP,
Inc. and Idaho Power Company from May 5, 1999, to March 1, 2002. Mr. Keen also
serves on the Board of Directors of both IDACORP, Inc. and Idaho Power
Company. Age 55.
DARREL T. ANDERSON Senior
Vice President - Administrative Services and Chief Financial Officer of
IDACORP, Inc. and Idaho Power Company, appointed July 1, 2004. Mr. Anderson
was Vice President, Chief Financial Officer and Treasurer of IDACORP, Inc. and
Idaho Power Company from March 1, 2002, to July 1, 2004, and Vice President -
Finance and Treasurer of IDACORP, Inc. and Idaho Power Company from May 5,
1999, to March 1, 2002. Age 49.
THOMAS R. SALDIN Senior Vice
President and General Counsel of IDACORP, Inc. and Idaho Power Company,
appointed October 1, 2004. Mr. Saldin was Executive Vice President and General
Counsel of Albertson's Inc., a supermarket chain, from January 29, 1999, to his
retirement on August 31, 2001. Age 61.
JAMES C. MILLER Senior Vice
President - Power Supply of Idaho Power Company, appointed July 1, 2004. Mr.
Miller was Senior Vice President - Delivery of Idaho Power Company from October
1, 1999, to July 1, 2004. Age 53.
DANIEL B. MINOR Senior Vice
President - Delivery of Idaho Power Company, appointed July 1, 2004. Mr. Minor
was Vice President - Administrative Services & Human Resources of IDACORP,
Inc. and Idaho Power Company from November 20, 2003, to July 1, 2004, Vice
President - Corporate Services of Idaho Power Company from May 15, 2003, to
November 20, 2003, and Director of Audit Services of Idaho Power Company from
July 2001, to May 15, 2003. Age 50.
STEVEN R. KEEN Vice President
and Treasurer of IDACORP, Inc. and Idaho Power Company, appointed June 1,
2006. Mr. Keen was President of IDACORP Financial Services from September 8,
1998 to May 31, 2007. Age 47.
PATRICK A. HARRINGTON
Corporate Secretary of IDACORP, Inc. and Idaho Power Company, appointed March
15, 2007. Mr. Harrington was Senior Attorney from June 7, 2003, to March 15,
2007, and Attorney III from 1996 to June 7, 2003. Age 47.
DENNIS C. GRIBBLE Vice
President and Chief Information Officer of IDACORP, Inc. and Idaho Power
Company, appointed June 1, 2006. Mr. Gribble was Vice President and Treasurer
of IDACORP, Inc. and Idaho Power Company, from July 15, 2004, to June 1, 2006
and Finance Controller of Idaho Power Company from January 1, 1997, to July 15,
2004. Age 55.
LORI D. SMITH Vice President
- Corporate Planning and Chief Risk Officer of IDACORP, Inc. and Idaho Power
Company, appointed January 1, 2008. Ms. Smith was Vice President - Finance and
Chief Risk Officer of IDACORP, Inc. and Idaho Power Company from July 15, 2004,
to January 1, 2008, and Director of Strategic Analysis of Idaho Power Company
from January 1, 2000 to July 15, 2004. Age 47.
LUCI K. MCDONALD Vice
President - Human Resources of IDACORP, Inc. and Idaho Power Company, appointed
December 6, 2004. Ms. McDonald was Corporate Staff Director of Human Resources
of Boise Cascade Corporation, a forest products company, from September 16,
1999, to November 19, 2004. Age 50.
GREGORY W. PANTER Vice
President - Public Affairs of IDACORP, Inc. and Idaho Power Company, appointed
April 1, 2001. Age 59.
NAOMI SHANKEL Vice President,
Audit and Compliance of IDACORP, Inc. and Idaho Power Company, appointed
September 21, 2006. Ms. Shankel was Director, Audit Services of IDACORP, Inc.
and Idaho Power Company from July 2003, to September 21, 2006. Ms. Shankel was
a member of the Finance Department of Idaho Power Company from April 4, 2001,
to July 2003. Age 36.
JOHN R. GALE Vice President -
Regulatory Affairs of Idaho Power Company, appointed March 15, 2001. Age 57.
LISA A. GROW Vice President -
Delivery Engineering and Operations of Idaho Power Company, appointed July 20,
2005. Ms. Grow was General Manager of Grid Operations and Planning of Idaho
Power Company from October 23, 2004, to July 20, 2005, Operations Manager (Grid
Ops) of Idaho Power Company from March 2, 2002, to October 23, 2004, and
Control Area Operations Leader from October 13, 2001, to March 2, 2002. Age
42.
WARREN KLINE Vice President - Customer Service and Regional
Operations of Idaho Power Company, appointed July 20, 2005. Mr. Kline was
General Manager of Regional Operations of Idaho Power Company from March 2,
2002, to July 20, 2005 and General Manger of Customer Service and Metering from
January 9, 1999, to March 2, 2002. Age 52.
PART II
ITEM
5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
IDACORP's common stock,
without par value, is traded on the New York Stock Exchange. On February 22,
2008, there were 14,839 holders of record and the stock price was $30.80 per
share.
The outstanding shares of IPC's
common stock, $2.50 par value, are held by IDACORP and are not traded. IDACORP
became the holding company of IPC on October 1, 1998.
The amount and timing of
dividends payable on IDACORP's common stock are within the sole discretion of
IDACORP's Board of Directors. The Board of Directors reviews the dividend rate
quarterly to determine its appropriateness in light of IDACORP's 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 IPC 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 IPC.
A covenant under the IDACORP
and IPC Credit Facilities described in "MD&A - LIQUIDITY AND CAPITAL
RESOURCES - Financing Programs - Debt Covenants" requires IDACORP and IPC to
maintain leverage ratios of consolidated indebtedness to consolidated total
capitalization of no more than 65 percent at the end of each fiscal quarter.
IPC's ability to pay dividends on its common stock held by IDACORP and IDACORP's
ability to pay dividends on its common stock are limited to the extent payment
of such dividends would cause their leverage ratios to exceed 65 percent. At
December 31, 2007, the leverage ratios for IDACORP and IPC were both 53
percent.
IPC's articles of
incorporation contain restrictions on the payment of dividends on its common
stock if preferred stock dividends are in arrears. IPC has no preferred stock
outstanding. IPC paid dividends to IDACORP of $53 million, $51 million and $51
million in 2007, 2006 and 2005, respectively.
The following table shows the
reported high and low sales price of IDACORP's common stock and dividends paid
for 2007 and 2006 as reported in the consolidated transaction reporting system.
2007 Quarters |
||||||||
Common Stock, without par value: |
1st |
|
2nd |
|
3rd |
|
4th |
|
High |
$39.19 |
$35.18 |
$36.57 |
$36.72 |
||||
Low |
32.00 |
31.22 |
30.07 |
32.36 |
||||
Dividends paid per share |
0.30 |
0.30 |
0.30 |
0.30 |
||||
|
||||||||
2006 Quarters |
||||||||
Common Stock, without par value: |
1st |
|
2nd |
|
3rd |
|
4th |
|
High |
$33.28 |
$35.20 |
$38.81 |
$40.17 |
||||
Low |
28.97 |
32.00 |
34.00 |
37.61 |
||||
Dividends paid per share |
0.30 |
0.30 |
0.30 |
0.30 |
||||
Issuer
Purchases of Equity Securities:
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, 2002, 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 |
|||
2002 |
$ |
100.00 |
$ |
100.00 |
$ |
100.00 |
2003 |
128.86 |
128.67 |
123.48 |
|||
2004 |
137.11 |
142.65 |
151.68 |
|||
2005 |
136.92 |
149.66 |
176.02 |
|||
2006 |
186.71 |
173.27 |
212.56 |
|||
2007 |
176.26 |
182.78 |
247.76 |
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 IPC under the
Securities Act of 1933 or the Securities Exchange Act of 1934, except to the
extent IDACORP or IPC 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) |
|||||||||||||||||||||
2007 |
2006 |
2005 |
2004 |
2003 |
|||||||||||||||||
Operating revenues |
$ |
879,394 |
$ |
926,291 |
$ |
842,864 |
$ |
827,856 |
$ |
823,002 |
|||||||||||
Operating income |
152,078 |
169,704 |
154,653 |
106,233 |
84,062 |
||||||||||||||||
Income from continuing operations |
82,272 |
100,075 |
85,716 |
80,781 |
49,732 |
||||||||||||||||
Diluted earnings per share from |
|||||||||||||||||||||
continuing operations |
1.86 |
2.34 |
2.02 |
2.10 |
1.30 |
||||||||||||||||
Dividends declared per share |
1.20 |
1.20 |
1.20 |
1.20 |
1.70 |
||||||||||||||||
Financial Condition: |
|||||||||||||||||||||
Total assets |
$ |
3,653,308 |
$ |
3,445,130 |
$ |
3,364,126 |
$ |
3,234,172 |
$ |
3,106,108 |
|||||||||||
Long-term debt |
1,168,336 |
1,023,773 |
1,039,852 |
1,058,152 |
1,013,757 |
||||||||||||||||
Financial Statistics: |
|||||||||||||||||||||
Times interest charges earned: |
|||||||||||||||||||||
Before tax (1) |
2.35 |
2.78 |
2.65 |
1.99 |
1.48 |
||||||||||||||||
After tax (2) |
2.16 |
2.54 |
2.37 |
2.32 |
1.77 |
||||||||||||||||
Market-to-book ratio (3) |
131% |
151% |
121% |
128% |
132% |
||||||||||||||||
Payout ratio (4) |
65% |
48% |
79% |
63% |
139% |
||||||||||||||||
Return on year-end common equity (5) |
6.8% |
9.6% |
6.2% |
7.2% |
5.4% |
||||||||||||||||
Book value per share (6) |
$ |
26.79 |
$ |
25.65 |
$ |
24.05 |
$ |
23.88 |
$ |
22.62 |
|||||||||||
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 |
|||||||||||||||||||||
(AFDC), and income before income taxes divided by the sum of interest on long-term debt and other interest expense excluding |
|||||||||||||||||||||
AFDC credits. |
|||||||||||||||||||||
(2) The sum of interest on long-term debt, other interest expense excluding AFDC credits, and income from continuing operations divided |
|||||||||||||||||||||
by the sum of interest on long-term debt and other interest expense excluding AFDC credits. |
|||||||||||||||||||||
(3) The closing price of IDACORP stock on the last day of the year divided by the book value per share, which is described in (6) below |
|||||||||||||||||||||
(4) Dividends paid per common share for the year divided by earnings per diluted share. |
|||||||||||||||||||||
(5) Net income divided by total shareholders' equity at the end of the year. |
|||||||||||||||||||||
(6) Total shareholders' equity at the end of the year divided by shares outstanding at the end of the year. |
|||||||||||||||||||||
In the second quarter of
2006, IDACORP management designated the operations of IDACORP Technologies,
Inc. and IDACOMM as assets held for sale. IDACORP's consolidated financial
statements reflect the reclassification of the results of these businesses as
discontinued operations for all periods presented. Discontinued operations are
discussed in more detail in Note 16 to IDACORP's and IPC's Consolidated
Financial Statements and in Part II, Item 7 - "MD&A - RESULTS OF OPERATIONS
- Non-utility Operations - Discontinued Operations."
IDACORP Energy, a marketer of
energy commodities, wound down operations in 2003.
ITEM 7. MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
(Dollar amounts and Megawatt-hours
(MWh) are in thousands unless otherwise indicated).
INTRODUCTION:
In Management's 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, IPC) are discussed.
IDACORP is a holding company
formed in 1998 whose principal operating subsidiary is IPC. 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.
IPC is an electric utility
with a service territory covering approximately 24,000 square miles in southern
Idaho and eastern Oregon. IPC is regulated by the FERC and the state
regulatory commissions of Idaho and Oregon. IPC 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 IPC.
IDACORP's other subsidiaries
include:
In the second quarter of
2006, IDACORP management designated the operations of IDACORP Technologies,
Inc. (ITI) and IDACOMM, Inc. (IDACOMM) as assets held for sale, as defined by
Statement of Financial Accounting Standards No. 144. IDACORP's consolidated
financial statements reflect the reclassification of the results of these
businesses as discontinued operations for all periods presented. Discontinued
operations are discussed in more detail later in the MD&A and in Note 16 to
IDACORP's and IPC's Consolidated Financial Statements.
On July 20, 2006, IDACORP
completed the sale of all of the outstanding common stock of ITI to IdaTech UK Limited,
a wholly-owned subsidiary of Investec Group Investments (UK) Limited.
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 IPC, which present the financial position at December 31, 2007 and 2006,
and the results of operations and cash flows for each company for the years
ended December 31, 2007, 2006 and 2005.
FORWARD-LOOKING
INFORMATION:
In connection with the safe
harbor provisions of the Private Securities Litigation Reform Act of 1995,
IDACORP and IPC 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 IPC 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 IDACORP's or IPC's control and may cause actual
results to differ materially from those contained in forward-looking
statements:
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:
2007 Financial Results
A summary of IDACORP's net income and
earnings per diluted share for the last
three years is as follows:
2007 |
|
2006 |
|
2005 |
|||||
Net income |
$ |
82,339 |
$ |
107,403 |
$ |
63,661 |
|||
Average outstanding shares - diluted (000s) |
44,291 |
42,874 |
42,362 |
||||||
Earnings per diluted share |
$ |
1.86 |
$ |
2.51 |
$ |
1.50 |
|||
The key factors affecting the
change in IDACORP's net income for 2007 include (amounts shown are net of
income taxes):
2007 |
|
2006 |
|
2005 |
|||||
Net income |
$ |
76,579 |
$ |
93,929 |
$ |
71,839 |
|||
The key factors affecting IPC's
net income for 2007 include (amounts shown are net of income taxes):
Non-GAAP Financial
Measures
The following discussion includes
financial information prepared in accordance with generally accepted accounting
principles (GAAP), as well as one additional financial measure, electric
utility margin, that is considered a "non-GAAP financial measure" under SEC
rules. Generally, a non-GAAP financial measure is a numerical measure of a
company's financial performance, financial position or cash flows that excludes
(or includes) amounts that are included in (or excluded from) the most directly
comparable measure calculated in accordance with GAAP. The most directly
comparable GAAP financial measure to electric utility margin is operating
income.
The presentation of electric
utility margin is intended to supplement the information available to investors
for evaluating IPC's operating performance. When viewed in conjunction with
IPC's operating income, electric utility margin provides a more complete
understanding of the factors and trends affecting IPC's business, and users can
assess which information best suits their needs. However, this measure is not
intended to replace operating income, or any other measure calculated in
accordance with GAAP, as an indicator of operating performance.
IPC's management uses
electric utility margin, in addition to GAAP measures, to determine whether IPC
is collecting the appropriate amount of energy costs from its customers to
allow recovery of operating costs. Electric utility margin also provides both
management and investors with a better understanding of the effects of
regulatory mechanisms on IPC's operating income. The primary limitation
associated with this measure is that IPC's electric utility margin may not be
comparable to other companies' electric utility margins. However, management
uses electric utility margin as an internal tool for evaluating and conducting
the business, and is therefore unburdened by this limitation.
The calculations of IPC's
electric utility margin for the last three years are as follows:
|
|
2007 |
|
2006 |
|
2005 |
||
General business revenue |
$ |
668,303 |
$ |
636,375 |
$ |
667,270 |
||
PCA amortization |
287 |
2,432 |
(27,791) |
|||||
Other revenues amortization |
||||||||
Irrigation load reduction |
- |
(5,400) |
(8,501) |
|||||
Rate case tax settlement |
- |
(4,745) |
(2,892) |
|||||
Total |
668,590 |
628,662 |
628,086 |
|||||
Power supply costs: |
||||||||
Off-system sales |
154,948 |
260,717 |
142,794 |
|||||
Purchased power |
(289,484) |
(283,440) |
(222,310) |
|||||
Fuel |
(134,322) |
(115,018) |
(103,164) |
|||||
PCA deferral |
120,844 |
27,094 |
30,786 |
|||||
Total |
(148,014) |
(110,647) |
(151,894) |
|||||
Third party transmission expense |
(10,470) |
(7,639) |
(6,292) |
|||||
Other revenues (excluding DSM) |
38,663 |
33,526 |
39,012 |
|||||
Electric utility margin |
$ |
548,769 |
$ |
543,902 |
$ |
508,912 |
||
Electric utility margin as a percentage of total |
||||||||
general business revenue, PCA amortization |
||||||||
and other revenues amortization |
82% |
87% |
81% |
|||||
The decline in electric
utility margin as a percentage of total general business revenue, PCA
amortization and other revenues amortization is a result of an increase in the
ten percent sharing component of the PCA due to below normal hydroelectric
production and the negative impact of the Load Growth Adjustment Rate (LGAR)
mechanism.
System load in 2007 was 1.0
million MWh greater than the base loads established in the 2005 general rate
case. This represents an increase of 274,000 MWh over 2006 total system
loads. The MWh increases, when combined with an increase in the LGAR in April
2007 from $16.84 per MWh to $29.41 per MWh, result in a decline in a component
of the PCA deferral as compared to 2006. This decline reduced electric utility
margin by $13.0 million.
The following table reconciles
electric utility margin to electric utility operating income (GAAP) for the
last three years:
|
|
2007 |
|
2006 |
|
2005 |
|
Electric utility margin |
$ |
548,769 |
$ |
543,902 |
$ |
508,912 |
|
Other operations and maintenance |
|||||||
(excluding third party transmission expense) |
(276,040) |
(257,171) |
(236,089) |
||||
Gain on sale of emission allowances |
2,754 |
8,257 |
1,172 |
||||
Depreciation |
(103,072) |
(99,824) |
(101,485) |
||||
Taxes other than income taxes |
(17,634) |
(18,661) |
(20,856) |
||||
Operating income - electric utility (GAAP) |
$ |
154,777 |
$ |
176,503 |
$ |
151,654 |
|
Business Strategy
IDACORP is focusing on a strategy
that emphasizes IPC as IDACORP's core business. IPC continues to experience moderate
customer growth in its service area, and this corporate strategy recognizes
that IPC must make substantial investments in infrastructure to ensure adequate
supply and reliable service. IPC's regulatory plans in 2008 include finalizing
the 2007 general rate case as well as additional initiatives designed to speed
recovery of the financial and operating costs of new facilities and system
improvements.
The strategy includes seeking timely rate recovery in both the Idaho and Oregon jurisdictions. The 2008 regulatory strategy includes filing for recovery of the investment and operating costs of IPC's new 170- MW natural gas-fired peaking plant expected to go on line in April 2008; pursuing a power cost adjustment mechanism in Oregon; and potential general rate case filings in both Idaho and Oregon.
IFS and Ida-West remain components of the corporate strategy. This strategy also
included the sale of non-core businesses. IDACORP completed the sales of ITI
on July 20, 2006, and IDACOMM on February 23, 2007.
Regulatory Matters
General rate case settlement: On June 8, 2007, IPC filed an application with the
IPUC requesting an average rate increase of approximately 10.35 percent, or
$63.9 million annually, for its Idaho customers in order to begin recovery of
its capital investments and higher operating costs. IPC also requested a
$29.16 per MWh LGAR, which adjusts the power supply costs IPC includes in the
PCA for differences between actual load and the load used in calculating base
rates. The existing LGAR is $29.41 per MWh. The impact of the new LGAR on IPC
will ultimately be determined by future load changes.
The parties to the proceeding
reached a settlement that includes an average annual increase of 5.2 percent
(approximately $32.1 million annually). The parties also agreed in the settlement
to make a good faith effort to develop a mechanism to adjust or replace the
current LGAR. As an interim solution, the parties have agreed to use the LGAR
of $62.79 per MWh recommended by the IPUC Staff in its testimony filed December
10, 2007, but to apply it to only fifty percent of the load growth occurring
during each month within the April 2008 - March 2009 PCA year.
The parties also agreed in
the settlement to participate in a good faith discussion regarding a forecast
test year methodology that balances the auditing concerns of the IPUC Staff and
intervenors with IPC's need for timely rate relief. The parties agreed that
such a methodology would begin with auditable numbers from which projections
would be made for the test year.
IPC filed a settlement
stipulation with the IPUC on January 23, 2008. The settlement is subject to
approval by the IPUC. The parties have requested in the stipulation that the
new rates become effective no later than March 1, 2008, but IPC is unable to
predict what relief the IPUC will grant or when the IPUC will issue its final
order.
Power Cost Adjustment: On June 1, 2007, IPC implemented its annual Power Cost
Adjustment (PCA), which resulted in a $77.5 million, or 14.5 percent on
average, increase in the rates of Idaho customers. The increase in rates is a
direct result of significantly below normal winter precipitation and
deteriorated stream flow conditions during the first half of 2007. In years
where water is plentiful and IPC can fully utilize its extensive hydroelectric
system, power production costs are lower and IPC can pass those benefits to its
customers in the form of rate reductions. In years when water is in short
supply, as it was this past winter, the higher costs of supplying power by
other means are shared with IPC's customers.
Emission allowances: In 2005 and early 2006, IPC sold 78,000 SO2
emission allowances for a total of $81.6 million, after subtracting transaction
fees. The sales proceeds allocated to the Idaho jurisdiction were
approximately $76.8 million ($46.8 million net of tax, assuming a tax rate of
approximately 39 percent). On May 12, 2006, the IPUC approved a stipulation
that allowed IPC to retain ten percent as a shareholder benefit with the
remaining 90 percent plus a carrying charge recorded as a customer benefit.
This customer benefit is included in IPC's PCA calculations as a credit to the
PCA true-up balance and is currently reflected in PCA rates during the June 1,
2007, through May 31, 2008, PCA rate year.
During 2007, IPC sold 35,000
SO2 emission allowances for a total of $19.6 million, after
subtracting transaction fees. The sales proceeds to be allocated to the Idaho
jurisdiction are approximately $18.5 million ($11.3 million net of tax,
assuming a tax rate of approximately 39 percent). On January 15, 2008, a
workshop was held to discuss whether the customer share of the Idaho
jurisdictional portion of the 2007 sales proceeds should once again be included
as a PCA credit or used to reduce investment costs in wind development, green
tags, or other options that would provide longer term customer benefits. Because
the workshop participants were unable to reach a consensus regarding the use of
the SO2 emission allowance proceeds, the IPUC determined that the
case would proceed under modified procedure. Written comments were due
February 25, 2008.
The bulk of IPC's accumulated
excess emission allowances were sold during the 2005-2007 period. IPC
currently has approximately 15,000 excess emission allowances and anticipates
accumulating a similar amount of excess allowances annually for the near
future. Tighter emission restrictions are expected in the long term, which may
cause IPC to use more emission allowances for its own requirements and reduce
the annual amount of excess allowances.
Record system peaks
IPC's service territory experienced
record-setting high temperatures during July 2007. Due to these weather
conditions and continued customer growth, IPC set three new all-time system
peaks between July 5 and July 13, 2007, with the highest, 3,193 MW, being set
on July 13, 2007. The previous hourly system peak of 3,084 MW was set in
2006. Although IPC was able to meet all of its load requirements during these
periods of increased demand, all available resources of IPC's system were fully
committed during several heavy load periods during the summer. The record-setting
temperatures also contributed to numerous wildfires throughout IPC's service
area. Although the wildfires damaged or destroyed several distribution and
transmission structures, the wildfires did not have a material impact to
earnings in 2007. The all-time winter peak demand is 2,464 MW set on January 24,
2008. The
previous hourly system winter peak of 2,459 MW was set in 1998.
Integrated Resource Plan
IPC filed its 2006 IRP with the IPUC
in September 2006 and with the OPUC in October 2006. The 2006 IRP previewed
IPC's load and resource situation for the next twenty years, analyzed potential
supply-side and demand-side options and identified near-term and long-term
actions.
The IPUC accepted the 2006
IRP in March 2007. The OPUC acknowledged the 2006 IRP in September 2007 with
the stipulation that IPC not commit to the construction of a 250-MW pulverized
coal resource, identified to come on-line in 2013, until IPC presents an update
of the 2006 IRP to the OPUC no later than June 2008. With its acceptance of
the 2006 IRP, the IPUC requested that IPC align the submittal of its next IRP
with those submitted by other utilities. To comply with this request, IPC
intends to provide an update on the status of the 2006 IRP to both the IPUC and
OPUC no later than June 2008 and file a new IRP in June 2009.
The near-term action plan in
the 2006 IRP indicated initial commitments to the construction of a coal-fired
base load resource would be necessary before the end of 2007 in order for a
project to be on-line in 2013. In order to meet this schedule, IPC screened
and evaluated coal-fired resources in 2006 and 2007. The results of this
evaluation indicated construction costs had escalated substantially since
resource cost estimates were prepared for the 2006 IRP. Due to such escalating
construction costs, potential permitting issues, and continued uncertainty
surrounding future greenhouse gas laws and regulations, IPC determined that
coal-fired generation was not the best technology to meet its resource needs in
2013. IPC plans to construct a natural gas-fired combined cycle combustion
turbine located closer to its load center in southern Idaho. IPC continues to
evaluate coal-fired resource opportunities, including expansion of its jointly-owned
facilities, clean coal technologies and potential power purchase agreements for
future energy needs.
Transmission Projects
IPC and PacifiCorp are jointly
exploring a project, called the Gateway West Project, to build two 500-kV lines
between the Jim Bridger plant in Wyoming and Boise. The lines would be
designed to increase electrical transmission capacity across southern Idaho in
response to increasing customer demand and growth. If built, it is expected
that the majority of the project would be completed between 2012 and 2014,
depending on the timing of acquisition of rights-of-way, siting and permitting,
and construction sequencing. IPC estimates that its share of project costs
would be between $800 million and $1.2 billion.
IPC is also exploring
alternatives for the construction of a 500-kV line between southwestern Idaho
and the Northwest, named the Hemingway-Boardman Line (formerly referred to as
the Idaho-Northwest Line). If built, the line could run from the proposed
Hemingway Station southwest of Boise to a proposed transmission station near
Boardman, Oregon and be in service as early as 2012. IPC has received inquiries
from other parties about participating in this project.
The proposed Gateway West and
Hemingway-Boardman transmission projects will be used both by wholesale
transmission customers and to serve IPC's native load consistent with IPC's Open
Access Transmission Tariff (OATT). Therefore these facilities will be subject
to both the FERC and state public utility commission regulation and rate making
policies.
Capital Requirements and
Cash Flows
IDACORP estimates that it will spend approximately $900 million on
construction expenditures over the next three years, excluding any estimated
expenditures for a Nominal 250-MW combined cycle combustion turbine expected to
be operational in mid-2012 and the transmission projects discussed above. This
amount reflects the need for additional resources in order for IPC to supply
power to its growing number of customers.
Forecasts indicate that
internal cash generation after dividends will provide less than the full amount
of total capital requirements for 2008 through 2010. IDACORP and IPC expect to
continue financing the utility construction program and other capital
requirements with internally generated funds and continued reliance on
externally financed capital.
The amount of internal cash
generation is dependent primarily upon IPC's cash flows from operations, which
are subject to risks and uncertainties relating to weather and water conditions
and IPC's ability to obtain rate relief to cover its operating costs and
provide a return on investment.
Idaho
Water Management Issues
Power generation at the IPC
hydroelectric power plants on the Snake River is dependent upon the state water
rights held by IPC 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. IPC continues to participate in water management issues in
Idaho that may affect those water rights and resources. This includes active
participation in the Snake River Basin Adjudication, a judicial action initiated
in 1987 to determine the nature and extent of water use in the Snake River
basin, judicial and administrative proceedings relating to the conjunctive
management of ground and surface water rights, and management and planning
processes intended to reverse declining trends in river, spring, and aquifer
levels and address the long-term water resource needs of the state. On
occasion, resolution of these water management issues involves litigation. IPC
is involved in legal actions regarding not only its water rights but also the
water rights of others. One such action, initiated in the Snake River Basin
Adjudication, involves IPC's water rights at the Swan Falls project on the
Snake River and several other upstream hydroelectric projects that are the
subject of a 1984 agreement with the state of Idaho known as the Swan Falls
Agreement. IPC also has initiated legal action against the U.S. Bureau of
Reclamation (USBR) over the interpretation and effect of a 1923 contract with
the USBR on the operation of the American Falls Reservoir and the release of
water from that reservoir to be used at IPC's downstream hydroelectric
projects. Although IPC intends to continue vigorously defending its water
rights and although none of the pending water management issues are expected to
impact IPC's hydroelectric generation in the near term, IPC cannot predict the
ultimate outcome of these matters or what effect they may have on its
consolidated financial positions, results of operations or cash flows. IPC's
ongoing participation in such issues will help ensure that water remains
available over the long-term for use at IPC's hydroelectric projects on the
Snake River.
CRITICAL ACCOUNTING
POLICIES AND ESTIMATES:
The preparation of financial
statements in accordance with GAAP requires management to apply accounting
policies and make estimates and judgments that affect the reported amounts of
assets, liabilities, revenues and expenses and related disclosure of contingent
assets and liabilities. These estimates involve judgment with respect to
numerous factors that are difficult to predict and are beyond management's
control. Management adjusts these estimates based on historical experience and
on other assumptions and factors that are believed to be reasonable under the
circumstances Actual amounts could materially differ from the estimates.
Management believes the
following accounting policies and estimates are the most critical to the
portrayal of their financial condition and results of operations and require
management's most difficult, subjective or complex judgments, often as a result
of the need to make estimates about the effect of matters that are inherently
uncertain and may change in subsequent periods.
Accounting for Rate
Regulation
In order to apply the accounting policies
and practices of Statement of Financial Accounting Standards (SFAS) 71, "Accounting
for the Effects of Certain Types of Regulation," a regulated company must
satisfy the following conditions: (1) an independent regulator must set rates;
(2) the regulator must set the rates to cover specific costs of delivering
service; and (3) the service territory must lack competitive pressures to
reduce rates below the rates set by the regulator. SFAS 71 requires companies
that meet the above conditions to reflect the impact of regulatory decisions in
their consolidated financial statements and requires that certain costs be
deferred as regulatory assets until matching revenues can be recognized.
Similarly, certain items may be deferred as regulatory liabilities and
amortized to the income statement as rates to customers are reduced.
IPC follows SFAS 71, and its
financial statements reflect the effects of the different rate making
principles followed by the jurisdictions regulating IPC. The primary effect of
this policy is that IPC has recorded $450 million of regulatory assets and $274
million of regulatory liabilities at December 31, 2007. While IPC expects to
fully recover these regulatory assets from customers through rates and refund
these regulatory liabilities to customers through rates, such recovery or
refund is subject to final review by the regulatory entities. If future
recovery or refund of these amounts ceases to be probable, or if IPC determines
that it no longer meets the criteria for applying SFAS 71, IPC would be
required to eliminate those regulatory assets or liabilities, unless regulators
specify some other means of recovery or refund. Either circumstance could have
a material effect on IPC's results of operations and financial position.
Pension and Other
Postretirement Benefits
IPC maintains a qualified defined
benefit pension plan covering most employees, an unfunded nonqualified deferred
compensation plan for certain senior management employees and directors, and a
postretirement medical benefit plan.
The expenses IDACORP and IPC
record for these plans depend on a number of factors, including the provisions
of the plans, changing employee demographics, actual returns on plan assets and
several assumptions used in the actuarial valuations upon which pension expense
is based. The key actuarial assumptions that affect expense are the expected
long-term return on plan assets and the discount rate used in determining
future benefit obligations. Management evaluates the actuarial assumptions on
an annual basis, taking into account changes in market conditions, trends and
future expectations. Estimates of future stock market performance, changes in
interest rates and other factors used to develop the actuarial assumptions are
uncertain. Actual results could vary significantly from the estimates.
The assumed discount rate is
based on reviews of market yields on high-quality corporate debt.
Specifically, IDACORP and IPC utilize data published in the Citigroup Pension
Liability Index and apply the rates therein against the projected cash outflows
of the plans. The discount rate used to calculate the 2008 pension expense
will be increased to 6.4 percent from the 5.85 percent used in 2007.
Rate-of-return projections
for plan assets are based on historical risk/return relationships among asset
classes. The primary measure is the historical risk premium each asset class
has delivered versus the return on 10-year U.S. Treasury Notes. This
historical risk premium is then added to the current yield on 10-year U.S.
Treasury Notes, and the result provides a reasonable prediction of future
investment performance. Additional analysis is performed to measure the
expected range of returns, as well as worst-case and best-case scenarios.
Based on the current interest rate environment, current rate-of-return
expectations are lower than the nominal returns generated over the past 20
years when interest rates were generally much higher.
Gross pension and other
postretirement benefit expense for these plans totaled $15 million, $16
million, and $14 million for the three years ended December 31, 2007, 2006 and
2005, respectively, including amounts allocated to capitalized labor and
amounts deferred as regulatory assets. For 2008, gross pension expense is
expected to total approximately $16 million, which takes into account the
increase in the discount rate noted above. No changes were made to the other
key assumptions used in the actuarial calculation.
Had different actuarial
assumptions been used, pension expense could have varied significantly. The
following table reflects the sensitivities associated with changes in the
discount rate and rate of return on plan assets actuarial assumptions on
historical and future pension and postretirement expense:
|
Discount rate |
Rate of return |
||||||
|
2008 |
2007 |
2008 |
2007 |
||||
|
(millions of dollars) |
|||||||
Effect of 0.5% increase |
$ |
(1.4) |
$ |
(1.7) |
$ |
(2.2) |
$ |
(2.2) |
Effect of 0.5% decrease |
1.7 |
2.7 |
2.2 |
2.2 |
||||
No cash contributions were
made to the qualified plan from 2005 through 2007, and none are expected in
2008. Under the non-qualified plan, IPC makes payments directly to
participants in the plan. Payments are expected to be approximately $2.7
million in 2008 and averaged approximately $2.5 million per year from 2005 to
2007. Gross postretirement plan contributions are expected to be approximately
$4.1 million in 2008, and averaged $4.3 million from 2005 to 2007.
Please refer to Note 8 and
Note 6 of IDACORP's and IPC's Consolidated Financial Statements, which contains
additional information about the pension and postretirement plans and the
regulatory treatment of pension expense, respectively.
Contingent Liabilities
Contingent liabilities are accounted for in accordance with SFAS 5, "Accounting
for Contingencies." According to SFAS 5, an estimated loss from a loss
contingency is charged to income if (a) it is probable that an asset had been
impaired or a liability had been incurred at the date of the financial
statements and (b) the amount of the loss can be reasonably estimated. If a
probable loss cannot be reasonably estimated no accrual is recorded but
disclosure of the contingency in the notes to the financial statements is
required. Gain contingencies are not recorded until realized.
IDACORP and IPC have a number
of unresolved issues related to regulatory and legal matters. If the
recognition criteria of SFAS 5 have been met, liabilities have been recorded.
Estimates of this nature are highly subjective and the final outcome of these
matters could vary significantly from the amounts that have been included in
the financial statements.
Impairment of Long-Lived Assets
Long-lived assets are periodically reviewed for impairment when events or
changes in circumstances indicate that the carrying amount of an asset may not
be recoverable as prescribed under SFAS 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets." SFAS 144 requires that if the sum of
the undiscounted expected future cash flows from an asset is less than the
carrying value of the asset impairment must be recognized in the financial
statements. Long-lived assets that were evaluated in 2007 include the
following:
Southwest Intertie
Project: IPC began developing the
Southwest Intertie Project (SWIP) in 1988. IPC's investment consists predominantly
of a federal permit for a specific transmission corridor in Nevada and Idaho
and also private rights-of-way in Idaho. The SWIP rights-of-way extend from
Midpoint substation in south-central Idaho through eastern Nevada to the Dry
Lake area northeast of Las Vegas, Nevada. In 2004 the Bureau of Land
Management granted a five-year extension to begin construction of a proposed
500kV transmission line within the rights-of-way before December 2009. On
March 31, 2005, IPC entered into an agreement with White Pine Energy
Associates, LLC (White Pine), an affiliate of LS Power Development, LLC, which
provides White Pine a three-year exclusive option to purchase the SWIP rights-of-way
from IPC. The option may be exercised in part or as a whole and, if fully
exercised, will result in a net pre-tax gain to IPC of approximately $6
million. Based on management expectations regarding SWIP, no impairment has
been identified.
Impairment of Equity-Method
Investments
IFS has affordable housing
investments with a net book value of $78 million at December 31, 2007, and Ida-West
has investments in four joint ventures that own electric power generation
facilities. Except for two investments now consolidated in accordance with
GAAP these investments are accounted for under the equity method of accounting
as described in Accounting Principles Board Opinion No. (APB) 18, "The
Equity Method of Accounting for Investments in Common Stock." The standard
for determining whether impairment must be recorded under APB 18 is whether the
investment has experienced a loss in value that is considered an other-than-temporary
decline in value. Impairment analyses on these investments were performed in
2007 and no impairment was noted. These estimates required IDACORP to make
assumptions about future stream flows, revenues, cash flows and other items
that are inherently uncertain. Actual results could vary significantly from
the assumptions used, and the impact of such variations could be material.
Unbilled Revenue
IPC's general business revenues
include an estimate of electricity delivered to general business customers that
has not been billed at the end of the period. Unbilled revenues estimates are
dependent upon a number of inputs that require management's judgment. Unbilled
revenue is calculated by taking daily estimates of MWhs delivered and applying
information from the meter-reading schedule to estimate the portion of MWhs
delivered that have not been billed. These unbilled MWhs are allocated to the
general business customer classes based on historical data. IPC then
calculates unbilled revenue based on the respective rates of each customer
class. Due to the seasonal fluctuations of IPC's load, the amount of unbilled
revenue increases during the summer and winter months and decreases during the
spring and fall.
Income Taxes
IDACORP and IPC account for income
taxes in accordance with SFAS No. 109, "Accounting for Income Taxes" and
FIN 48 "Accounting for Uncertainty in Income Taxes." Judgment and
estimation are used in developing the provision for income taxes and the
reporting of tax-related assets and liabilities. The interpretation of tax
laws can involve uncertainty, since tax authorities may interpret such laws
differently. Actual income taxes could vary from estimated amounts and may
result in favorable or unfavorable impacts to net income, cash flows, and tax-related
assets and liabilities.
RESULTS OF OPERATIONS:
This section of the MD&A
takes a closer look at the significant factors that affected IDACORP's and IPC's
earnings over the last three years. In this analysis, the results of 2007 are
compared to 2006 and the results of 2006 are compared to 2005.
The following table presents
earnings (losses) for IDACORP and its subsidiaries:
|
2007 |
|
2006 |
|
2005 |
||||
IPC - Utility operations |
$ |
76,579 |
$ |
93,929 |
$ |
71,839 |
|||
IDACORP Financial Services |
7,112 |
9,509 |
10,911 |
||||||
IDACORP Energy |
(171) |
5 |
4,881 |
||||||
Ida-West Energy |
2,223 |
2,564 |
2,381 |
||||||
Holding company expenses |
(3,471) |
(5,932) |
(4,296) |
||||||
Discontinued operations |
67 |
7,328 |
(22,055) |
||||||
Total earnings |
$ |
82,339 |
$ |
107,403 |
$ |
63,661 |
|||
Average outstanding shares - diluted (000s) |
44,291 |
42,874 |
42,362 |
||||||
Earnings per diluted share |
$ |
1.86 |
$ |
2.51 |
$ |
1.50 |
|||
Utility Operations
Operating environment: IPC is one of the nation's few investor-owned
utilities with a predominantly hydroelectric generating base. Because of its
reliance on hydroelectric generation, IPC's generation operations can be
significantly affected by weather conditions. The availability of
hydroelectric power depends on the amount of snow pack in the mountains
upstream of IPC's hydroelectric facilities, springtime snow pack run-off, river
base flows, spring flows, rainfall and other weather and stream flow management
considerations. During low water years, when stream flows into IPC's
hydroelectric projects are reduced, IPC's hydroelectric generation is reduced.
This results in less generation from IPC's resource portfolio (hydroelectric,
coal-fired and gas-fired) available for off-system sales and, most likely, 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. During
high water years, increased off-system sales and the decreased need for
purchased power reduce net power supply costs.
Operations plans are
developed during the year to provide guidance for generation resource
utilization and energy market activities (off-system sales and power
purchases). The plans incorporate forecasts for generation unit availability,
reservoir storage and stream flows, gas and coal prices, customer loads, energy
market prices and other pertinent inputs. Consideration is given to when to
use IPC's available resources to meet forecast loads and when to transact in
the energy market. The allocation of hydroelectric generation between heavy
load and light load hours or calendar periods is considered in development of
the operating plans. 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. IPC's energy risk
management policy, unit operating requirements and other obligations provide
the framework for the plans.
Stream flow conditions were
much lower in 2007 than 2006 resulting in 6.2 million MWh generated from IPC's
hydroelectric facilities, compared to 9.2 million MWh in 2006. The observed
stream flow data released on August 1, 2007, by the National Weather Service's
Northwest River Forecast Center (RFC) indicated that Brownlee reservoir inflow
for April through July 2007 was 2.8 million acre-feet (maf), or 44 percent of
the RFC average. Brownlee reservoir inflow for 2007 totaled 8.5 maf, or 56
percent of the RFC average. Storage in selected federal reservoirs upstream of
Brownlee as of February 10, 2008 was 76 percent of average. The stream flow
forecast released on February 14, 2008 by the RFC predicts that Brownlee
reservoir inflow for April through July 2008 will be 5.7 maf, or 90 percent of
the RFC average.
Generation
from thermal plants during 2007 was higher than 2006 due primarily to increased
generation to meet increased load requirements. In addition, the thermal
plants were under-utilized in 2006 due to an unanticipated outage at the
Boardman plant and a planned outage at the Valmy plant, of which IPC owns a ten
percent and 50 percent interest, respectively. Both units returned to service
in June 2006. Additionally, the Bennett Mountain combustion turbine suffered a
mechanical failure on July 11, 2006. IPC's investigation revealed that during
construction a bolt was negligently installed by a third party. The bolt came
loose, causing extensive mechanical damage. The plant was down from July 12
through September 6, 2006. Total repair costs were approximately $16 million.
In 2007, IPC received reimbursement for the bulk of the total repair costs from
its insurance carrier. With regards to the remaining repair costs, IPC has
reached an agreement in principle with the third party, which essentially makes
IPC whole.
IPC's
system is dual peaking, with the larger peak demand occurring in the summer.
The all-time system peak demand is 3,193 MW, set on July 13, 2007. The
previous hourly system peak of 3,084 MW was set in 2006. Although IPC was able
to meet all of its load requirements during these periods of increased demand,
all available resources of IPC's system were fully committed during several
heavy load periods in the summer. The all-time winter peak demand is 2,464 MW set on
January 24, 2008. The previous hourly system winter peak of 2,459 MW was
set in 1998. The following table
presents IPC's power supply for the last three years:
MWh |
|||||
Hydroelectric |
Thermal |
Total System |
Purchased |
|
|
Generation |
Generation |
Generation |
Power |
Total |
|
2007 |
6,181 |
7,367 |
13,548 |
5,196 |
18,744 |
2006 |
9,207 |
7,021 |
16,228 |
4,964 |
21,192 |
2005 |
6,199 |
7,315 |
13,514 |
3,894 |
17,408 |
IPC's modeled median annual
hydroelectric generation is 8.5 million MWh, based on hydrologic conditions for
the period 1928 through 2006 and adjusted to reflect the current level of water
resource development.
General Business Revenue: The primary influences on electricity sales are weather,
customer growth 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
IPC's general business revenues, MWh sales, average number of customers and
Boise, Idaho weather conditions for the last three years:
2007 |
|
2006 |
|
2005 |
|||||||
Revenue |
|||||||||||
Residential |
$ |
308,208 |
$ |
299,594 |
$ |
299,488 |
|||||
Commercial |
170,001 |
162,391 |
173,268 |
||||||||
Industrial |
101,409 |
102,958 |
118,259 |
||||||||
Irrigation |
88,685 |
71,432 |
76,255 |
||||||||
Total |
$ |
668,303 |
$ |
636,375 |
$ |
667,270 |
|||||
MWh |
|||||||||||
Residential |
5,227 |
5,068 |
4,760 |
||||||||
Commercial |
3,937 |
3,761 |
3,639 |
||||||||
Industrial |
3,454 |
3,475 |
3,423 |
||||||||
Irrigation |
1,924 |
1,635 |
1,467 |
||||||||
Total |
14,542 |
13,939 |
13,289 |
||||||||
Customers (average) |
|||||||||||
Residential |
397,285 |
387,707 |
373,602 |
||||||||
Commercial |
61,640 |
59,050 |
57,146 |
||||||||
Industrial |
126 |
130 |
129 |
||||||||
Irrigation |
18,043 |
18,081 |
17,942 |
||||||||
Total |
477,094 |
464,968 |
448,819 |
||||||||
Heating degree-days |
5,128 |
5,195 |
5,437 |
||||||||
Cooling degree-days |
1,290 |
1,209 |
965 |
||||||||
Precipitation (inches) |
8.1 |
12.1 |
13.6 |
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. Normal heating degree-days and cooling
degree-days are 5,727 and 807, respectively.
2007 vs. 2006:
2006 vs. 2005:
Off-system sales: Off-system sales consist primarily of long-term sales
contracts and opportunity sales of surplus system energy. The following table
presents IPC's off-system sales for the last three years:
|
2007 |
|
2006 |
|
2005 |
|||
Revenue |
$ |
154,948 |
$ |
260,717 |
$ |
142,794 |
||
MWh sold |
|
2,744 |
|
5,821 |
|
2,774 |
||
Revenue per MWh |
$ |
56.47 |
$ |
44.79 |
$ |
51.48 |
||
|
|
|
2007 vs. 2006: In 2007, the MWh volume sold decreased 53 percent
and revenues decreased 41 percent. Deteriorated stream flow conditions
throughout Southern Idaho decreased total system generation and electricity
available for surplus sales. Revenue decreases from lower sales volumes were
moderated by higher prices. Prior year prices were lower due to the abundance
of energy in the region.
2006 vs. 2005: In 2006, the MWh volume sold more than doubled and revenues
grew 83 percent. Improved stream flow conditions increased total system
generation and electricity available for surplus sales. Revenue increases from
higher sales volumes were moderated by lower prices caused by abundant energy
in the region. The volume increase was also impacted by early water year
indications suggesting continued drought conditions for 2006, prompting IPC to
make forward purchases in conformance with its risk management policy that were
subsequently sold. Additional sales activities are the result of conforming to
IPC's risk management policy, managing IPC's energy portfolio to meet customer
load, and IPC reacting to changes in market conditions to minimize net power
supply costs.
Other revenues:
The following table presents the components of other revenues:
|
2007 |
|
2006 |
|
2005 |
||||
Transmission services and property rental |
$ |
39,739 |
$ |
34,737 |
$ |
39,012 |
|||
Provision for rate refund |
(1,076) |
(1,211) |
- |
||||||
DSM |
13,487 |
- |
- |
||||||
Rate case tax settlement |
- |
(4,745) |
(2,892) |
||||||
Irrigation lost revenues |
- |
(5,400) |
(8,501) |
||||||
Total |
$ |
52,150 |
$ |
23,381 |
$ |
27,619 |
|||
2007 vs. 2006: Other revenues increased $28.8 million due mainly to the following:
2006 vs. 2005: Other revenues decreased $4 million due mainly to the following:
Purchased power: The following table presents IPC's purchased power
expenses and volumes:
|
2007 |
|
2006 |
|
2005 |
|||
Expense |
$ |
289,484 |
$ |
283,440 |
$ |
222,310 |
||
MWh purchased |
5,196 |
4,964 |
3,894 |
|||||
Cost per MWh purchased |
$ |
55.71 |
$ |
57.10 |
$ |
57.09 |
||
2007 vs. 2006: Purchased power expense grew two percent in 2007.
Deteriorated system generation, due to poor hydrologic conditions, combined
with the second year in a row of record high temperatures and demand during
July and August, led to increased purchases. This increase in purchases was
partially offset by a lower overall cost per MWh in 2007. During 2006, IPC made
forward purchases in conformance with its risk management policy in response to
early water year indications that suggested continued drought conditions.
Hydrologic conditions for 2006 turned out to be more favorable than forecasted
and actual market prices ended up being lower than the prices of the forward purchases.
These higher priced forward purchases inflated the cost per MWh that IPC
realized for 2006. IPC began utilizing financial hedge instruments in 2007 in
addition to physical forward power transactions for the purpose of mitigating
price risk related to conforming to IPC's energy risk management policy,
managing IPC's energy portfolio to meet customer load, and reacting to changes
in market conditions to minimize net power supply costs.
2006 vs. 2005: Purchased power expense grew 27 percent in 2006.
Record high temperatures and electricity demand, particularly in July 2006, led
to increased purchases during a period of high market prices. The increase was
also impacted by early water year indications suggesting continued drought
conditions for 2006, which prompted IPC to make forward purchases in
conformance with its risk management policy. Additional purchase activities
were the result of managing IPC's energy portfolio to meet customer load and
reacting to changes in market conditions to minimize net power supply costs.
Fuel expense: The following table presents IPC's fuel expenses and
generation at its thermal generating plants:
2007 |
|
2006 |
|
2005 |
||||
Fuel expense |
$ |
134,322 |
$ |
115,018 |
$ |
103,164 |
||
Thermal MWh generated |
7,367 |
7,021 |
7,315 |
|||||
Cost per MWh |
$ |
18.23 |
$ |
16.38 |
$ |
14.10 |
||
2007 vs. 2006: Fuel expense increased $19.3 million in 2007, as
compared to 2006. The increase is largely due to an 11 percent rise in average
prices accompanied by a five percent increase in MWh volume. Coal fuel expense
was up $7.3 million compared to 2006. The increase in coal prices was due to
higher market demand and higher rail transportation costs. Generation from the
coal fired power plants was up three percent in 2007. The increase in generation
is attributed to fewer planned and unplanned outages at Valmy and Boardman than
the previous year. Additional generation from combustion turbine plants
contributed $12 million to the overall increase in fuel expense in 2007. The
combustion turbine plants were readily available for dispatch in 2007 to meet
peak loads and as market conditions warranted. The Bennett Mountain plant was
not available during the summer of 2006 due to a turbine failure.
2006 vs. 2005: The increase in fuel expense was due primarily to a
$12.7 million increase in expense from higher coal and rail transportation
costs. The increased cost of coal was due primarily to higher market demand,
and the increased rail transportation costs are primarily driven by higher
diesel fuel costs, including an adjustable fuel surcharge. Higher natural gas
costs of $3 million also contributed to the increase. Generation from the coal
fired power plants was down four percent due to unplanned outages at Valmy and
Boardman. This decrease resulted in a $4 million decrease in fuel expense.
PCA: PCA expense represents the effects of the Idaho PCA and
Oregon deferrals of net power supply costs, which are discussed in more detail
below in "REGULATORY MATTERS - Deferred (Accrued) Net Power Supply Costs." In
2007, net power supply costs (fuel and purchased power less off-system sales) were
higher than the amounts reflected in the annual PCA forecast. This resulted in
the deferral of costs which will be recovered in subsequent rate years. As the
deferred costs are being recovered in rates, the deferred balances are
amortized. In 2006 and 2005 actual net power supply costs also exceeded the
amounts anticipated in the annual PCA forecast.
The following table presents
the components of PCA expense:
|
2007 |
|
2006 |
|
2005 |
||||
Current year net power supply cost deferral |
$ |
(120,844) |
$ |
(27,094) |
$ |
(30,786) |
|||
Amortization of prior year authorized balances |
(287) |
(2,432) |
27,791 |
||||||
Total power cost adjustment |
$ |
(121,131) |
$ |
(29,526) |
$ |
(2,995) |
|||
Other operations and
maintenance expenses:
2007 vs. 2006: Other operations and maintenance expenses increased
$22 million due mainly to the following:
2006 vs. 2005: Other operations and maintenance expenses increased $22 million due mainly to the following:
Demand-side management
(DSM): Beginning in January 2007, a
new IPUC accounting order became effective for the treatment of IPC's DSM
expenses. DSM costs were recorded in Other operations and maintenance expenses
and were offset by the same amount recorded in Other revenues, resulting in no
net effect on earnings.
IPC's DSM programs provide
opportunities for all customer classes to balance their energy needs with best-practice
energy usage to minimize consumption while realizing the benefits of reliable
electrical service. IPC's 2006 IRP laid the groundwork for the planning and
implementation of future programs, including the addition of three new DSM
programs. In addition to the DSM programs identified in the 2006 IRP, IPC has
also continued to pursue other customer-focused DSM initiatives, including
conservation programs and educational opportunities.
Gain on the sale of
emission allowances: Gain on sale of
emission allowances in 2007 decreased $5.5 million as compared to 2006 due to
recording the gain on the sale of 35,000 SO2 emission allowances in
2007 as compared to 78,000 in 2006. Gains in 2006 increased $7.1 million over
2005, which had minimal emission allowance sale activity.
Non-utility Operations
IFS: IFS contributed $7 million, $10 million, and $11
million to net income in 2007, 2006 and 2005, 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 did not make any new
investments during 2007 and generated tax credits of $15 million, $19 million
and $20 million during 2007, 2006 and 2005, respectively. IFS expects to make
future investments in line with the ongoing needs of IDACORP.
Ida-West: Ida-West recorded net income of $2 million, $3 million
and $2 million in 2007, 2006 and 2005, respectively. Ida-West continues to
manage its independent power projects.
In 2003 a $2.6 million bad
debt reserve was established on a note receivable from a partner in one of Ida-West's
joint ventures. No adjustments were made to this reserve in 2007 or 2006, but
in 2005 the reserve was reduced by $0.7 million based on updated estimates of
collectability.
Energy Marketing: IE recorded net income of $0 million in 2007 and 2006
and $5 million in 2005. 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.
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. These matters are discussed in "LEGAL AND ENVIRONMENTAL ISSUES -
Legal and Other Proceedings."
Discontinued Operations: In the second quarter of 2006, IDACORP management
designated the operations of ITI and IDACOMM as assets held for sale. The
operations of these entities are presented as discontinued operations in
IDACORP's financial statements.
On July 20, 2006, IDACORP
completed the sale of all of the outstanding common stock of ITI to IdaTech UK
Limited, a wholly-owned subsidiary of Investec Group Investments (UK) Limited.
IDACORP recorded a gain of $11.5 million, net of tax, or $0.27 per diluted
share from this transaction in the third quarter of 2006.
On February 23, 2007, IDACORP
completed the sale of all of the outstanding common stock of IDACOMM to
American Fiber Systems, Inc. for proceeds of $10 million. The sale of IDACOMM
did not have a material effect on IDACORP's financial position, results of
operations or cash flows.
Income from discontinued
operations was not material in 2007. A loss on disposal of IDACOMM of $3
million was offset by an income tax benefit of $3 million. Income from
discontinued operations was $7 million in 2006 and consisted of a loss from
operations of $8 million, gain on disposal of ITI of $14 million and an income
tax benefit of $1 million. The loss from discontinued operations of $22
million for 2005 consisted of a loss from operations of $27 million and an
income tax benefit of $5 million. The 2005 results also included a $10 million
goodwill impairment charge recorded at IDACOMM.
Income Taxes
FIN 48: In June 2006, the Financial
Accounting Standards Board (FASB) issued FASB Interpretation No. 48, "Accounting
for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109"
(FIN 48), to create a single model to address accounting for uncertainty in tax
positions. FIN 48 prescribes a minimum recognition threshold that a tax
position is required to meet before being recognized in a company's financial
statements and also provides guidance on derecognition, measurement,
classification, interest and penalties, accounting in interim periods,
disclosure, and transition. IDACORP and IPC adopted FIN 48 on January 1, 2007,
as required. IPC recorded an increase of $15.1 million to opening retained
earnings for the cumulative effect of adopting FIN 48.
Status
of audit proceedings: IPC is
disputing the Internal Revenue Service's
(IRS) disallowance of IPC's use of the simplified service cost method (SSCM) of
uniform capitalization for tax years 2001-2003. The dispute is under review
with the IRS Appeals Office. In December 2007, the Appeals Office informed
IDACORP that the IRS had completed their review of IPC's SSCM settlement
computations. After evaluating the IRS review findings, IPC adjusted its
measurement for the SSCM uncertain tax position which resulted in a $4.4
million reduction of the accrued liability for this item. IDACORP expects that
the appeals process and the U.S. Congress Joint Committee on Taxation review
process will be completed during 2008.
In
November 2007 the IRS began its examination of IDACORP's and IPC's 2004-2006
tax years. IDACORP and IPC are unable to predict the outcome of this
examination.
LIQUIDITY AND CAPITAL
RESOURCES:
Operating Cash Flows
IDACORP's and IPC's operating
cash flows for 2007 were both $81 million. These amounts were a decrease of
$89 million and $50 million, respectively, compared to 2006. The following are
significant items that affected operating cash flows in 2007:
IDACORP's and IPC's operating
cash flows for 2006 were $170 million and $131 million, respectively. These
amounts were an increase of $8 million and a decrease of $35 million compared
to 2005. The following are significant items that affected operating cash
flows in 2006:
IDACORP's operating cash
flows are driven principally by IPC. General business revenues and the costs
to supply power to general business customers have the greatest impact on IPC's
operating cash flows, and are subject to risks and uncertainties relating to
weather and water conditions and IPC's ability to obtain rate relief to cover
its operating costs and provide a return on investment.
Investing Cash Flows
IPC's construction expenditures were
$287 million in 2007, $222 million in 2006 and $186 million in 2005. IPC is
experiencing a cycle of heavy infrastructure investment needed to address
continued customer growth, peak demand growth, and aging plant and equipment.
Net proceeds from the sales
of emission allowances provided investing cash of approximately $20 million,
$11 million and $71 million in 2007, 2006 and 2005, respectively. The changes
were primarily caused by changes in the number of allowances sold each year as
well as changes in market prices. See further discussion in "REGULATORY
MATTERS - Emission Allowances."
In November 2006, IDACORP
made a refundable deposit of $45 million with the IRS related to a disputed
income tax assessment. In August 2007, IPC reimbursed IDACORP for the
refundable tax deposit IDACORP made on IPC's behalf. See Note 2 to IDACORP's
and IPC's Consolidated Financial Statements for more information about the income
tax assessment.
Financing Cash Flows
Debt issuances: On June 22, 2007, IPC issued $140 million of its
6.30% First Mortgage Bonds, Secured Medium-Term Notes, Series F, due June 15,
2037. IPC used the net proceeds to pay down outstanding commercial paper,
which had increased to $164 million in June 2007 because of increased capital
expenditures.
On October 18, 2007, IPC
issued $100 million of its 6.25% First Mortgage Bonds, Secured Medium-Term
Notes, Series G, due October 15, 2037. IPC used the net proceeds to retire $80
million of 7.38% First Mortgage Bonds due December 1, 2007, and paid down
outstanding commercial paper.
Equity issuances: On December 15, 2005, IDACORP entered into a Sales
Agency Agreement with BNY Capital Markets, Inc. (BNYCMI). Under the terms of
the Sales Agency Agreement, IDACORP may offer and sell up to 2,500,000 shares
of its common stock, from time to time in at-the-market offerings through
BNYCMI, as IDACORP's agent for such offer and sale. Under this program IDACORP
received $28 million from the issuance of 881,337 shares in 2007 and $21
million from the issuance of 536,518 shares in 2006. The average prices of the
shares issued in 2007 and 2006 were $32.32 and $39.24, respectively. As of
December 31, 2007, there were 1,082,145 shares available to be issued through
this program.
In April 2005, with the goal
of adding additional common equity to its capital structure, IDACORP began
using original issue common stock in its Dividend Reinvestment and Stock
Purchase Plan, rather than purchasing this stock on the open market. Beginning
in August 2005, IDACORP also began using original issue common stock for its
401(k) plan. Under these plans, IDACORP issued 250,020 shares in 2007 and
244,756 shares in 2006, for proceeds of $8.4 million and $8.7 million,
respectively.
IDACORP issued 10,070 shares
in 2007 and 406,623 shares in 2006 in connection with the exercise of stock
options, for proceeds of $0.3 million and $12 million, respectively.
IDACORP made capital
contributions of $51 million and $47 million to IPC in 2007 and 2006,
respectively.
Discontinued operations
Cash flows from discontinued
operations are included with the cash flows from continuing operations in
IDACORP's Consolidated Statements of Cash Flows. The cash flows of IDACORP's
discontinued operations have reduced net cash provided by operating activities
and increased net cash used in investing activities, except for the cash
received from the sales of ITI and IDACOMM. The absence of cash flows from
these discontinued operations is expected to positively impact liquidity and
capital resources in future periods.
Financing Programs
IDACORP's consolidated capital structure consisted of common equity of 47
percent and debt of 53 percent at December 31, 2007.
Shelf Registrations: IDACORP currently has $629 million remaining on two
shelf registration statements that can be used for the issuance of unsecured
debt (including medium-term notes) and preferred or common stock. IPC
currently has in place one shelf registration statement that can be used for
the issuance of an aggregate principal amount of $350 million of first mortgage
bonds (including medium-term notes) and unsecured debt. See Note 4 to IDACORP's
and IPC's Consolidated Financial Statements for more information regarding long-term
financing arrangements.
Credit Facilities: The following table outlines available liquidity as
of December 31, 2007 and 2006.
|
IDACORP |
IPC |
|
||||||
|
2007 |
2006 |
2007 |
2006 |
|
||||
|
|
|
|||||||
Revolving credit facility |
$ |
100,000 |
$ |
150,000 |
$ |
300,000 |
$ |
200,000 |
|
Commercial paper outstanding |
(49,860) |
(76,800) |
(136,585) |
(52,200) |
|||||
Identified for other use (a) |
- |
- |
(24,245) |
(24,245) |
|||||
Net balance available |
$ |
50,140 |
$ |
73,200 |
$ |
139,170 |
$ |
123,555 |
|
(a) Port of Morrow and American Falls bonds that holders may put to IPC. |
|
||||||||
On April 25, 2007, IDACORP
entered into an Amended and Restated Credit Agreement (IDACORP Facility) with
Wachovia Bank, National Association, as administrative agent, swingline lender
and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent, Keybank
National Association, Wells Fargo Bank, N.A. and Bank of America, N.A., as
documentation agents, Wachovia Capital Markets, LLC and J.P. Morgan Securities
Inc., as joint lead arrangers and joint book runners, and the other financial
institutions party thereto, as lenders. The IDACORP Facility amended and
restated a $150 million five-year facility that would have expired on March 31,
2010.
The Amended and Restated IDACORP
Facility is a $100 million five-year credit agreement that terminates on April
25, 2012. The IDACORP Facility, which is used for general corporate purposes
and commercial paper back-up, provides for the issuance of loans and standby
letters of credit not to exceed the aggregate principal amount of $100 million,
including swingline loans in an aggregate principal amount at any time
outstanding not to exceed $10 million. IDACORP has the right to request an
increase in the aggregate principal amount of the IDACORP Facility to $150
million and to request one-year extensions of the then existing termination
date. At December 31, 2007, no loans were outstanding on IDACORP's Facility
and $49.9 million of commercial paper was outstanding. At February 27, 2008, $55
million of commercial paper was outstanding.
On April 25, 2007, IPC
entered into an Amended and Restated Credit Agreement (IPC Facility) with
Wachovia Bank, National Association, as administrative agent, swingline lender
and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent, Keybank
National Association, US Bank National Association and Bank of America, N.A.,
as documentation agents, Wachovia Capital Markets, LLC and J.P. Morgan
Securities Inc., as joint lead arrangers and joint book runners, and the other
financial institutions party thereto, as lenders. The IPC Facility amended and
restated a $200 million five-year facility that would have expired on March 31,
2010.
The Amended and Restated IPC Facility
is a $300 million five-year credit agreement that terminates on April 25,
2012. The IPC Facility, which will be used for general corporate purposes and
commercial paper back-up, provides for the issuance of loans and standby
letters of credit not to exceed the aggregate principal amount of $300 million,
including swingline loans in an aggregate principal amount at any time
outstanding not to exceed $30 million. IPC has the right to request an
increase in the aggregate principal amount of the IPC Facility to $450 million
and to request one-year extensions of the then existing termination date. At
December 31, 2007, no loans were outstanding on IPC's Facility and $137 million
of commercial paper was outstanding. At February 27, 2008, $164 million of
commercial paper was outstanding.
Both the IDACORP Facility and
the IPC Facility have similar terms and conditions. Under the terms of the
facilities IDACORP and IPC may borrow floating rate advances and Eurodollar
rate advances. The floating rate is equal to the higher of (i) the prime rate
announced by Wachovia Bank or its parent and (ii) the sum of the federal funds
effective rate for such day plus 1/2 percent per annum, plus, in each case, an
applicable margin. The Eurodollar rate is based upon the British Bankers'
Association interest settlement rate for deposits in U.S. dollars published on
the REUTERS 01 (Telerate Page 3750 successor) as adjusted by the applicable
reserve requirement for Eurocurrency liabilities imposed under Regulation D of
the Board of Governors of the Federal Reserve System, for periods of one, two,
three or six months plus the applicable margin. The margin is based on the
applicable company's rating for senior unsecured long-term debt securities
without third-party credit enhancement as provided by Moody's and S&P,
based on the higher of the two ratings. If the ratings are split between
Moody's and S&P and the differential is two levels or more, the
intermediate rating at the midpoint will apply. If there is no midpoint, the
higher of the two intermediate ratings will apply. The margin for the floating
rate advances is zero percent unless the applicable company's rating falls
below Baa3 from Moody's or BBB- from S&P, at which time it would equal 0.50
percent. The margin for Eurodollar rate advances ranges from 0.15 percent to
0.575 percent depending upon the credit rating. In addition to the margin, if
the outstanding aggregate credit exposure exceeds 50 percent of the facility
amount, IDACORP or IPC, as applicable, would pay a utilization fee ranging from
0.05 percent to 0.10 percent on outstanding loans depending on the credit
rating. At December 31, 2007, the applicable margin under the IDACORP Facility
and the IPC Facility was zero percent for floating rate advances and 0.28
percent for IPC and 0.36 percent for IDACORP for Eurodollar rate advances. The
utilization fee was 0.05 percent for both companies. A facility fee, payable
quarterly, is calculated on the average daily aggregate commitment of the
lenders under the relevant credit facility and is also based on the applicable
company's rating from Moody's or S&P as indicated above. At December 31,
2007, the facility fee under the IDACORP and IPC Facilities was 0.09 percent
and 0.07 percent, respectively.
As a result of the S&P
ratings downgrade discussed below, as of January 31, 2008, the credit facility
fees changed for IPC. The margin for Eurodollar rate advances increased from
0.28 percent to 0.36 percent, and the facility fee increased from 0.07 percent
to 0.09 percent. All of the other fees discussed above stayed the same for
IPC. IDACORP's fees remain unchanged.
In
connection with the issuance of letters of credit, IDACORP and IPC, as
applicable, must pay (i) a fee equal to the applicable margin for Eurodollar
rate advances on the average daily undrawn stated amount under such letters of
credit, payable quarterly in arrears, (ii) a fronting fee at a per annum rate
of 0.125 percent on the average daily undrawn stated amount under each letter
of credit, payable quarterly in arrears and (iii) documentary and processing
charges in accordance with the letter of credit issuer's standard schedule for
such charges.
A ratings downgrade would
result in an increase in the cost of borrowing and of maintaining letters of
credit, but would not result in any default or acceleration of the debt under
either the IDACORP Facility or the IPC Facility.
The events of default under
both the IDACORP Facility and the IPC Facility include (i) nonpayment of
principal when due and nonpayment of reimbursement obligations under letters of
credit within one business day after becoming due and nonpayment of interest or
other fees within five days after becoming due, (ii) materially false
representations or warranties made on behalf of the applicable company or any
of its subsidiaries on the date as of which made, (iii) breach of covenants,
subject in some instances to grace periods, (iv) voluntary and involuntary
bankruptcy of the applicable company or any material subsidiary, (v) the non-consensual
appointment of a receiver or similar official for the applicable company or any
of its material subsidiaries or any substantial portion (as defined in the
applicable facility) of its property, (vi) condemnation of all or any
substantial portion of the property of the applicable company and its
subsidiaries, (vii) default in the payment of indebtedness in excess of $25
million or a default by the applicable company or any of its subsidiaries under
any agreement under which such debt was created or governed which will cause or
permit the acceleration of such debt or if any of such debt is declared to be
due and payable prior to its stated maturity, (viii) the applicable company or
any of its subsidiaries not paying, or admitting in writing its inability to
pay, its debts as they become due, (ix) the applicable company or any of its
subsidiaries failing to pay certain judgments, (x) the acquisition by any
person or two or more persons acting in concert of beneficial ownership (within
the meaning of Rule 13d-3 of the Securities Exchange Act of 1934) of 20 percent
or more of the outstanding shares of voting stock of the applicable company, (xi)
the failure of IDACORP to own free and clear of all liens, all of the
outstanding shares of voting stock of IPC, (xii) unfunded liabilities of all
single employer plans under the Employee Retirement Income Security Act of 1974
exceeding $75 million and (xiii) the applicable company or any subsidiary being
subject to any proceeding or investigation pertaining to the release of any
toxic or hazardous waste or substance into the environment or any violation of
any environmental law (as defined in the applicable facility) which could
reasonably be expected to have a material adverse effect (as defined in the
applicable facility). A default or an acceleration of indebtedness of IDACORP
or IPC in excess of $25 million, including indebtedness under the applicable facility
will result in a cross default under the other Facility.
Upon any event of default
relating to the voluntary or involuntary bankruptcy of IDACORP or IPC or the
appointment of a receiver, the obligations of the lenders to make loans under
the facility and of the letter of credit issuer to issue letters of credit 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 51 percent of the aggregate commitments (required
lenders) or the administrative agent with the consent of the required lenders
may terminate or suspend the obligations of the lenders to make loans under the
facility and of the letter of credit issuer to issue letters of credit under
the facility or declare the obligations to be due and payable. IDACORP and IPC
will also be required to deposit into a collateral account an amount equal to
the aggregate undrawn stated amount under all outstanding letters of credit and
the aggregate unpaid reimbursement obligations thereunder.
If there is a ratings
downgrade below investment grade (BBB- or higher by S&P and Baa3 or higher
by Moody's), then IPC's authority for continuing borrowings under its
regulatory approvals issued by the IPUC and the OPUC must be extended or
renewed during the occurrence of the ratings downgrade. The Oregon statutes,
however, permit the issuance or renewal of indebtedness maturing not more than
one year after the date of such issue or renewal without approval of the OPUC.
In an order issued May 6, 2005, the IPUC clarified that IPC's authority will
not terminate but will continue for a period of 364 days from any downgrade
below investment grade.
Debt Covenants: The IDACORP Facility and the IPC Facility each contain a covenant requiring the company to maintain 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, 2007, the leverage ratio for both IDACORP and IPC was 53 percent. At December 31, 2007, IDACORP was in compliance with all other covenants of the IDACORP Facility and IPC was in compliance with all other covenants of the IPC Facility. Both the IDACORP Facility and the IPC Facility contain additional covenants including:
(i) prohibitions against: investments and acquisitions by the applicable company or any subsidiary without the consent of the required lenders subject to exclusions for investments in cash equivalents or securities of the applicable company; investments by the applicable company and its subsidiaries in any business trust controlled, directly or indirectly, by the applicable company to the extent such business trust purchases securities of the applicable company; investments and acquisitions related to the energy business or other business of the applicable company and its subsidiaries not exceeding $750 million in the aggregate at any one time outstanding (provided that investments in non-energy related businesses do not exceed $150 million); and investments by the applicable company or a subsidiary in connection with a permitted receivables securitization (as defined in the facility);
(ii) prohibitions against the applicable company or any material subsidiary merging or consolidating with any other person or selling or disposing of all or substantially all of its property to another person without the consent of the required lenders, subject to exclusions for mergers into or dispositions to the applicable company or a wholly owned subsidiary and dispositions in connection with a permitted receivables securitization;
(iii) restrictions on the creation of certain liens by the applicable company or any material subsidiary subject to exceptions, including the lien of IPC's first mortgage indebtedness; and
(iv)
prohibitions on any material
subsidiary of the applicable company entering into any agreement restricting
its ability to declare or pay dividends to the applicable company except
pursuant to a permitted receivables securitization.
Credit Ratings
On January 31, 2008, Standard & Poor's
Rating Services lowered its corporate credit rating on IDACORP and IPC to 'BBB'
from 'BBB+'. The outlook for both companies changed to stable from negative.
S&P stated that its decision reflected a gradual deterioration of cash flow
coverage as well as a failure to sufficiently address long-term ratemaking
issues in the proposed Idaho general rate case settlement. Specifically,
S&P indicated that the proposed settlement fails to resolve issues such as
the use of a forecasted test year or the appropriate level of load growth
adjustment credit.
Access to capital markets at
a reasonable cost is determined in large part by credit quality. These
downgrades are expected to increase the cost of new debt issuances and
outstanding variable rate debt issuances within the downgraded ratings
categories. The following table outlines the current S&P, Moody's and
Fitch ratings of IDACORP's and IPC's securities:
|
S&P |
Moody's |
Fitch |
|||
|
IPC |
IDACORP |
IPC |
IDACORP |
IPC |
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 |
(prelim) |
(prelim) |
|||||
Short-Term Tax-Exempt Debt |
BBB-/A-2 |
None |
Baa |
None |
None |
None |
1/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 |
Stable |
Stable |
Stable |
Stable |
These security ratings and
the ratings discussed below 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.
Pollution Control Revenue
Refunding Bonds: Two series of bonds
have been issued for the benefit of IPC and are each supported by a financial
guaranty insurance policy issued by Ambac Assurance Corporation (Ambac). The
two series are the $116.3 million aggregate principal amount of Pollution
Control Revenue Refunding Bonds (Idaho Power Company Project) Series 2006
issued by Sweetwater County, Wyoming due 2026 (Sweetwater bonds), and the $49.8
million aggregate principal amount of Pollution Control Revenue Refunding Bonds
(Idaho Power Company Project) Series 2003 issued by Humboldt County, Nevada due
2024 (Humboldt bonds). The pollution control bonds currently bear interest at
an auction interest rate reset every 35 days for the Humboldt bonds and every
seven days for Sweetwater bonds.
The Humboldt bonds and
Sweetwater bonds are each rated "AAA" by S&P and "Aaa" by Moody's,
respectively. Fitch also rated each series of bonds.
On January 18, 2008, Fitch
announced that it had downgraded Ambac's insurer financial strength rating to
"AA" from "AAA" and was keeping the rating on negative watch. Fitch also
downgraded the Humboldt bonds and the Sweetwater bonds to "AA" from "AAA."
S&P's and Moody's ratings for the bonds remain unchanged. However, Moody's
placed Ambac's insurance financial strength rating on review for possible
downgrade on January 16, 2008, and, as a result of this review, Moody's-rated
securities that are guaranteed by Ambac were also placed under review for
possible downgrade, except those with higher public underlying ratings.
S&P also placed Ambac's financial strength, financial enhancement and
issuer credit ratings on CreditWatch with negative implications on January 18,
2008. On February 25, 2008, S&P affirmed Ambac's "AAA" financial strength
and financial enhancement ratings, but retained the negative watch.
The downgrade of Ambac and
the pollution control bonds has resulted in higher interest rates on the pollution
control bonds. Such downgrades could also result in a "failed auction", where
there are no purchasers for the bonds. A "failed auction" would result in the
existing holders having to hold the pollution control bonds at the maximum
interest rate of 14 percent for the Sweetwater bonds and at a specified rate
capped at 12 percent for the Humboldt bonds. If a "failed auction" occurs, new
auctions will continue to be every 35 days for the Humboldt bonds and every
seven days for the Sweetwater bonds. On February 27, 2008, auctions were held
for both series of pollution control bonds. The Sweetwater bonds had a
successful auction establishing a new interest rate of 7.95 percent. The
Humboldt bonds experienced a "failed auction" which resulted in a new interest
rate of 5.464 percent (currently based on LIBOR multiplied by 1.75) and the
Humboldt bonds continuing to be held by the current holders. IPC may exercise
certain options available with respect to these bonds to lessen interest rate
costs and volatility going forward. IPC may redeem the bonds at par plus
accrued and unpaid interest or convert them from the auction rate mode to
another interest rate mode.
Capital Requirements
Utility Construction Program:
IPC's construction program and related expenditures are subject to on-going
review and are revised to include changes in load growth, construction costs,
location of generation sources, transmission capacity, adequacy of rate recovery
and environmental concerns. Variations in the timing and amounts of capital
expenditures will result from regulatory and environmental factors, load
growth, other resource acquisition needs and the timing of relicensing expenditures.
IPC is experiencing a cycle
of heavy infrastructure investment needed to address continued customer growth,
peak demand growth, and aging plant and equipment. IPC's aging hydroelectric
and thermal facilities require continuing upgrades and component replacement.
In addition, costs related to relicensing hydroelectric facilities and
complying with the new licenses are substantial. Continuing load growth also
requires that IPC add to its transmission system and distribution facilities to
provide new service and to maintain reliability. As a result, IPC expects to
spend approximately $900 million in construction expenditures from 2008 to 2010,
which excludes any estimated expenditures for a Nominal 250-MW combined cycle
combustion turbine expected to be operational in mid-2012, the Gateway West
Project expected to be in service between 2012 and 2014, and the proposed
Hemingway-Boardman Line that could be in service as early as 2012. IPC expects
2008 capital expenditures to be between $280 and $300 million.
IPC and PacifiCorp are
jointly exploring a project, called the Gateway West Project, to build two 500-kV
lines between the Jim Bridger plant and Boise. If built, it is expected that
the majority of the project would be completed between 2012 and 2014, depending
on the timing of rights-of-way acquisition, siting and permitting, and
construction sequencing. IPC estimates that its share of project costs would
be between $800 million and $1.2 billion. IPC is exploring the construction of
a 500-kV line referred to as the Hemingway-Boardman Line. IPC and a number of
other utilities with proposed regional transmission projects in the Northwest
have begun to coordinate technical studies. See further discussion in "REGULATORY
MATTERS - Gateway West Project and Hemingway-Boardman Line."
Other Capital Requirements: IDACORP's non-regulated capital expenditures are
expected to be $25 million in 2008 and an aggregate of $25 million for 2009-2010.
These expenditures primarily relate to IFS's tax advantaged investments.
Internal cash generation
after dividends is expected to provide less than the full amount of total
capital requirements for 2008 through 2010. IDACORP and IPC expect to continue
financing capital requirements with internally generated funds and externally
financed capital.
Contractual Obligations
The following table presents IDACORP's
and IPC's contractual cash obligations for the respective periods in which they
are due:
Payment Due by Period |
|
||||||||||||||
Total |
2008 |
2009-2010 |
2011-2012 |
Thereafter |
|
||||||||||
|
(millions of dollars) |
|
|||||||||||||
IPC: |
|
||||||||||||||
Long-term debt (a) |
$ |
1,146 |
$ |
1 |
$ |
82 |
$ |
222 |
$ |
841 |
|
||||
Future interest payments (b) |
1,173 |
64 |
124 |
104 |
881 |
|
|||||||||
Operating leases (c) |
19 |
3 |
7 |
3 |
6 |
|
|||||||||
Uncertain tax positions (d) |
6 |
2 |
4 |
- |
- |
|
|||||||||
Purchase obligations: |
|
||||||||||||||
Cogeneration and small power |
|
||||||||||||||
production |
1,993 |
76 |
199 |
207 |
1,511 |
|
|||||||||
Fuel supply agreements |
210 |
54 |
69 |
32 |
55 |
|
|||||||||
Purchased power & transmission (e) |
65 |
38 |
10 |
5 |
12 |
|
|||||||||
Other (f) |
113 |
63 |
17 |
10 |
23 |
|
|||||||||
Total purchase obligations |
4,725 |
301 |
512 |
583 |
3,329 |
|
|||||||||
Pension and postretirement plans (h) |
64 |
6 |
14 |
15 |
29 |
|
|||||||||
Other long-term liabilities - IPC |
6 |
4 |
2 |
- |
- |
|
|||||||||
Total IPC |
$ |
4,795 |
$ |
311 |
$ |
528 |
$ |
598 |
$ |
3,358 |
|
||||
Other: |
|
||||||||||||||
Long-term debt (a)(g) |
26 |
10 |
9 |
1 |
6 |
|
|||||||||
Future interest payments (b)(g) |
7 |
1 |
1 |
1 |
4 |
|
|||||||||
Operating leases (g) |
2 |
1 |
- |
- |
1 |
|
|||||||||
Total IDACORP |
$ |
4,830 |
$ |
323 |
$ |
538 |
$ |
600 |
$ |
3,369 |
|
||||
(a) |
For additional information, see Note 4 to IDACORP's and IPC's Consolidated Financial Statements. |
|
|||||||||||||
(b) |
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, 2007. |
|
||||||||||||||
(c) |
Approximately $8 million of the obligations included in operating leases 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. |
|
||||||||||||||
(d) |
In addition to the amounts listed, approximately $17 million of federal income tax is estimated to be due in 2008, but would be |
|
|||||||||||||
fully offset by the $45 million tax deposit IDACORP made in 2006. |
|
||||||||||||||
(e) |
Approximately $11 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. |
|
||||||||||||||
(f) |
Approximately $40 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. |
|
||||||||||||||
(g) |
Amounts include the obligations of IDACORP's subsidiaries other than IPC, which is shown separately. |
|
|||||||||||||
(h) |
Based on current assumptions, no pension contributions will be required during the next five years. IPC cannot estimate |
|
|||||||||||||
contributions beyond 2012 at this time. Amounts include 10 years of postretirement and non-qualified pension contributions. |
|||||||||||||||
Environmental Regulation
Costs: IPC anticipates approximately
$20 million in annual operating costs for environmental facilities during
2008. Hydroelectric facility expenses and thermal plant expenses account for the
majority of the costs at approximately $13 million and $7 million,
respectively. From 2009 through 2010, total environmental related operating
costs are estimated to be approximately $54 million. Expenses related to the
hydroelectric facilities are expected to be $39 million and thermal plant
expenses are expected to total $15 million during this period.
These amounts do not include
costs related to possible changes in the environmental legislation and
enforcement policies that may be enacted in response to issues such as global
warming and mercury and other pollutant emissions from coal-fired generation
plants.
Off-Balance Sheet
Arrangements
The federal Surface Mining Control
and Reclamation Act of 1977 and similar state statutes establish operational,
reclamation and closure standards that must be met during and upon completion
of mining activities. These obligations mandate that mine property be restored
consistent with specific standards and the approved reclamation plan. The
mining operations at the Bridger Coal Company are subject to these reclamation
and closure requirements. IPC has agreed to guarantee the performance of
reclamation activities at Bridger Coal Company, of which Idaho Energy Resources
Co., a subsidiary of IPC, owns a one-third interest. This guarantee, which is
renewed each December, was $60 million at December 31, 2007. Bridger Coal has
a reclamation trust fund set aside specifically for the purpose of paying these
reclamation costs and expects that the fund will be sufficient to cover all
such costs. Because of the existence of the fund, the estimated fair value of
this guarantee is minimal.
LEGAL AND ENVIRONMENTAL
ISSUES:
Legal and Other
Proceedings
Wah Chang: On May 5, 2004, Wah Chang, a division of TDY
Industries, Inc., filed two lawsuits in the U.S. District Court for the
District of Oregon against numerous defendants. IDACORP, IE and IPC are named
as defendants in one of the lawsuits. The complaints allege violations of
federal antitrust laws, violations of the Racketeer Influenced and Corrupt
Organizations Act, violations of Oregon antitrust laws and wrongful
interference with contracts. Wah Chang's complaint is based on allegations
relating to the western energy situation. These allegations include bid
rigging, falsely creating congestion and misrepresenting the source and
destination of energy. The plaintiff seeks compensatory damages of $30 million
and treble damages.
On September 8, 2004, this
case was transferred and consolidated with other similar cases currently pending
before the Honorable Robert H. Whaley sitting by designation in the U.S.
District Court for the Southern District of California. The companies filed a
motion to dismiss the complaint, which the court granted on February 11, 2005.
Wah Chang appealed the dismissal to the U.S. Court of Appeals for the Ninth
Circuit on March 10, 2005. On November 20, 2007, the Ninth Circuit affirmed
the dismissal. On December 10, 2007, Wah Chang filed Petitions for Rehearing
and Rehearing En Banc with the Ninth Circuit, which were denied on January 15,
2008. If Wah Chang decides to seek Supreme Court review, time for filing its
petition for certiorari will expire on April 14, 2008. The companies cannot
predict whether Wah Chang will seek certiorari or whether the Supreme Court
will grant it. The companies intend to vigorously defend their position in
this proceeding and believe this matter will not have a material adverse effect
on their consolidated financial positions, results of operations, or cash
flows.
Western Energy Proceedings
at the FERC: IE and IPC are involved
in a number of FERC proceedings arising out of the western energy situation in
California and claims that dysfunctions in the organized California markets
contributed to or caused unjust and unreasonable prices in Pacific Northwest
spot markets, and may have been the result of manipulations of gas or electric
power markets. The following proceedings are included.
(1) California Refund: This proceeding originated with an effort by the state
of California to obtain refunds for a portion of the spot market sales from
sellers of electricity into California from October 2, 2000, through June 20,
2001. California is claiming that the sales prices were not just and
reasonable and were not in compliance with the FPA. The FERC issued an order
on refund liability on March 26, 2003 on which multiple parties, including IE,
sought rehearing. On October 16, 2003, the FERC denied the requests for
rehearing and required the California Independent System Operator (Cal ISO) to
make a compliance filing regarding refund amounts within five months, which has
been delayed on a number of occasions and has not yet been filed with the
FERC. On May 12, 2004, the FERC issued an order clarifying its earlier refund
orders. The FERC denied requests for rehearing on November 23, 2004. On
December 2, 2003, IE and others petitioned the United States Court of Appeals
for the Ninth Circuit for review of the FERC's orders on California refunds.
As additional FERC orders have been issued, further petitions for review have
been filed, including by IE, and have been consolidated with the appeals
already pending before the Ninth Circuit. On September 21, 2004, the Ninth
Circuit convened the first of its case management proceedings, a procedure
reserved to help organize complex cases, staying action on all of the
consolidated cases. On October 22, 2004, the Ninth Circuit severed several
issues related to the FERC's refund jurisdiction, established a schedule for
briefing and held oral argument on April 12 and 13, 2005. On September 6,
2005, the Ninth Circuit issued a decision in one of the severed cases
concluding that the FERC lacked refund authority over wholesale electrical
energy sales made by governmental entities and non-public utilities. On August
2, 2006, the Ninth Circuit issued its decision on a second severed case ruling
that all transactions that occurred within or as a result of the CalPX and the
Cal ISO were the proper subject of the refund proceeding; refused to expand the
proceedings into the bilateral market, approved the refund effective date as
October 2, 2000 but required FERC to reconsider based upon claims that some
market participants had violated governing tariff obligations (the California
Parties are seeking a refund effective date of May 1, 2000); and effectively
expanded the scope of the refund proceeding to transactions within the CalPX
and Cal ISO markets outside the 24-hour spot market and energy exchange
transactions. On August 8, 2005 the FERC issued an order establishing a
framework for those sellers wanting to make a cost filing to demonstrate that
the generally applicable FERC refund methodology interfered with the recovery
of costs. IE and IPC along with others made a cost filing on September 14, 2005.
During the next two months, the California entities on the one hand and IE and
IPC on the other submitted filings that argued the merits of the cost filings.
On March 27, 2006, the FERC rejected the IE/IPC cost filing and on April 26,
2006, IE and IPC sought rehearing of the rejection. That request remains
pending before the FERC. IE and IPC are unable to predict how or when the FERC
might rule on the request for rehearing.
Before
the rejection of the cost filing, on February 17, 2006, IE and IPC jointly
filed with the California Parties (Pacific Gas & Electric Company, San
Diego Gas & Electric Company, Southern California Edison Company, the
California Public Utilities Commission, the California Electricity Oversight
Board, the California Department of Water Resources and the California Attorney
General) an Offer of Settlement at the FERC settling
matters encompassed by the California Refund proceeding including IE's and IPC's
cost filing and refund obligation. A number of other parties, representing
substantially less than the majority of potential refund claims, chose to opt
out of the settlement.
On
May 12, 2006, the FERC issued an order determining the method that should be
used to allocate amounts approved in cost filings, approving the methodology
that IE and IPC and others had advocated prior to the time IE and IPC entered
into the February 17, 2006 settlement - allocating cost offsets to buyers in
proportion to the net refunds they are owed through the Cal ISO and CalPX
markets. On June 12, 2006, the California Parties requested rehearing, urging
the FERC to allocate the cost offsets to all purchasers from the Cal ISO and
CalPX markets and not just to that limited subset of purchasers who are net
refund recipients. On July 12, 2006, the FERC tolled the time to act on the
request for rehearing and has not issued orders on rehearing since that time.
IDACORP and IPC are unable to predict how or when the FERC might rule on the
request for rehearing.
The
FERC approved the February 17, 2006 Offer of Settlement on May 22, 2006. Under
the terms of the settlement, IE and IPC assigned $24.25 million of the rights
to accounts receivable from the Cal ISO and CalPX to the California Parties to
pay into an escrow account for refunds to settling parties. Amounts from that
escrow not used for settling parties and $1.5 million of the remaining IE and
IPC receivables that are to be retained by the CalPX are available to fund, at
least partially, payment of the claims of any non-settling parties if they prevail
in the remaining litigation of this matter. Any excess funds remaining at the
end of the case are to be returned to IPC and IE. Approximately $10.25 million
of the remaining IE and IPC receivables was paid to IE and IPC under the
settlement.
On June 21, 2006, the Port of
Seattle, Washington filed a request for rehearing of the FERC order approving
the settlement. On July 10, 2006, IPC and IE and the California Parties filed
a response to Port of Seattle's request for rehearing. On October 5, 2006, the
FERC issued an order denying the Port of Seattle's request for rehearing. On
October 24, 2006, the Port of Seattle petitioned the U.S. Court of Appeals for
the Ninth Circuit for review of the FERC orders approving the settlement. The
Ninth Circuit consolidated that review petition with the large number of review
petitions already consolidated before it. On October 25, 2007, the Ninth
Circuit severed the appeal of the FERC's orders approving the settlement with
the California Parties (along with appeals of two other similar cases) from the
remainder of the consolidated cases. The Ninth Circuit established a briefing
schedule for the three cases which currently concludes in late June 2008. A
date for argument has not yet been scheduled. IPC and IE are unable to predict
when or how the Ninth Circuit might rule on Port of Seattle's petition for
review.
A provision of the CalPX
participation agreement referred to as the chargeback provision was triggered
when a participant defaulted on a payment to the CalPX requiring other market
participants to pay their allocated share of the default amount to the CalPX.
This provision was triggered initially by the Southern California Edison and
Pacific Gas and Electric Company defaults. The FERC ordered the CalPX to hold
the chargeback funds until the conclusion of the California Refund proceeding.
Based upon the settlement between the California Parties and IE and IPC
discussed above, the FERC directed the return of IE's chargeback amounts,
totaling $2.27 million. On June 1, 2006, IE received approximately $2.5
million from the CalPX representing the return of $2.27 million in chargeback
funds plus interest.
On December 31, 2005, with
respect to the CalPX chargeback and the California Refund proceedings discussed
above, the CalPX and the Cal ISO owed $14 million and $30 million,
respectively, for energy sales made to them by IPC in November and December
2000. In the fourth quarter of 2005, IE reduced by $9.5 million to $32 million
its reserve against these receivables. This reserve was calculated taking into
account the uncertainty of collection, given the California energy situation.
Following payment of the $10.25 million to IE and IPC in June 2006, IE further
reduced the reserve by $24.9 million to $7.1 million. This reserve was
calculated taking into account several unresolved issues in the California
refund proceeding. Based on the reserve recorded as of December 31, 2007,
IDACORP believes that the future collectability of these receivables or any
potential refunds ordered by the FERC would not have a material adverse effect
on its consolidated financial position, results of operations or cash flows.
(2) Pacific Northwest Refund: These proceedings involved
arguments that the spot market in the Pacific Northwest was affected by the
dysfunction in the California market, warranting refunds. The FERC rejected
this claim on June 25, 2003, and denied rehearing on November 11, 2003 and
February 9, 2004. The FERC orders were appealed to the Ninth Circuit. Oral
argument was held on January 8, 2007. On August 24, 2007, the court filed an
opinion in the appeal, remanding to the FERC the orders that declined to
require refunds. The court's opinion instructed the FERC to consider whether
evidence of market manipulation submitted by the petitioners for the period
January 1, 2000 to June 21, 2001 would have altered the agency's conclusions
about refunds and directed the FERC to include sales to the California
Department of Water Resources in the proceeding. On September 18, 2007, the
court extended until November 16, 2007 the time for filing petitions for
rehearing to allow the parties' time to assess settlement prospects and
directed Senior Judge Edward Leavey of the Ninth Circuit to initiate mediation
efforts. The Ninth Circuit did not renew the extension of time and a number of
parties have sought rehearing of the Ninth Circuit's decision. IE and IPC are
unable to predict when the Ninth Circuit will rule on the requests for
rehearing or the outcome of these matters. The settlement in the California
Refund proceeding resolves all claims the California Parties have against IE
and IPC in the Pacific Northwest proceeding.
(3) Market Manipulation: These proceedings
include two FERC show cause orders which resulted from a ruling of the Ninth
Circuit that the FERC permit the California parties in the California refund
proceeding to submit materials to the FERC demonstrating market manipulation by
various sellers of electricity into California. On June 25, 2003, the FERC
ordered a large number of parties including IPC to show cause why certain
trading practices did not constitute gaming ("gaming") or anomalous market
behavior ("partnership") in violation of the Cal ISO and CalPX Tariffs. On
October 16, 2003, IPC reached agreement with the FERC Staff on the show cause
orders. The "gaming" settlement was approved by the FERC on March 3, 2004.
The FERC approved the motion to dismiss the "partnership" proceeding on January
23, 2004. Although the orders establishing the scope of the show cause
proceedings are presently the subject of review petitions in the Ninth Circuit,
the order dismissing IPC from the "partnership" proceedings was not the subject
of rehearing requests. Originally, eight parties requested rehearing of the
FERC's March 3, 2004 order approving the "gaming" settlement. The settlement
between the California Parties and IE and IPC discussed above in the California
refund proceeding approved by the FERC on May 22, 2006, results in the
California Parties and other settling parties withdrawing their requests for
rehearing of the settlement with the FERC Staff regarding allegations of "gaming."
On October 11, 2006, the FERC issued an order denying rehearing of its earlier
approval of the "gaming" allegations, thereby effectively terminating the FERC
investigations as to IPC and IE regarding bidding behavior, physical
withholding of power and "gaming" without finding of wrongdoing. On October
24, 2006, the Port of Seattle appealed the FERC order to the U.S. Court of
Appeals for the Ninth Circuit. That appeal was consolidated with the other
cases currently before the Ninth Circuit respecting Western energy matters. IE
and IPC are unable to predict when or how the Ninth Circuit will rule on the
petitions for review.
In addition to the two show
cause orders, on June 25, 2003, the FERC also issued an order instituting an
investigation of anomalous bidding behavior and practices in the western
wholesale markets for the time period May 1, 2000 through October 1, 2000 to
review evidence of economic withholding of generation. IPC, along with over 60
other market participants, responded to the FERC data requests and the FERC
terminated its investigations as to IPC on May 12, 2004. Numerous parties have
appealed the FERC's termination of this investigation as to IPC and over 30
other market participants. IE and IPC are unable to predict when the Ninth
Circuit will rule on the requests for rehearing or the outcome of these
matters.
Sierra Club Lawsuit-Bridger:
In February 2007, the Sierra Club and
the Wyoming Outdoor Council filed a complaint against PacifiCorp in federal
district court in Cheyenne, Wyoming alleging violations of air quality opacity
standards at the Jim Bridger coal fired plant (Plant) in Sweetwater County,
Wyoming. Opacity is an indication of the amount of light obscured in the flue
gas of a power plant. A formal answer to the complaint was filed by PacifiCorp
on April 2, 2007, in which PacifiCorp denied almost all of the allegations and
asserted a number of affirmative defenses. IPC is not a party to this
proceeding but has a one-third ownership interest in the Plant. PacifiCorp
owns a two-thirds interest and is the operator of the Plant. The complaint
alleges thousands of opacity permit limit violations by PacifiCorp and seeks a
declaration that PacifiCorp has 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 the plaintiff's costs of
litigation, including reasonable attorney fees.
The U.S. District Court has
set this matter for trial commencing in April 2008. Discovery in the matter
was completed on October 15, 2007. Also in October 2007, the plaintiffs and
defendant filed cross-motions for summary judgment on the alleged opacity
permit violations. The Court has not yet ruled on those motions. IPC
continues to monitor the status of this matter but is unable to predict its
outcome or what effect this matter may have on its consolidated financial
position, results of operations or cash flows.
Sierra Club Notice of
Intent to File Suit - Boardman: On
January 15, 2008, the Oregon Chapter of the Sierra Club, the Northwest
Environmental Defense Center, Friends of the Columbia Gorge, Columbia
Riverkeeper, and Hells Canyon Preservation Council (collectively, Sierra Club)
provided a 60-day notice to Portland General Electric Company (PGE) of intent
to file suit. Sierra Club alleges violations of opacity standards at the
Boardman coal-fired power plant located in Morrow County, Oregon of which IPC
owns ten percent. PGE owns 65 percent and is the operator of the plant. Opacity
is an indication of the amount of light obscured in the flue gas of a power
plant. Sierra further alleges violations of the Clean Air Act, related federal
regulations and the Oregon State Implementation Plan relating to PGE's
construction and operation of the plant. Sierra Club has not yet commenced
litigation. Sierra Club alleges thousands of opacity permit limit violations
by PGE from and before 2003, and claims that it will seek a declaration that
PGE has violated opacity limits, a permanent injunction ordering PGE to comply
with such limits, and civil penalties of up to $32,500 per day per violation. IPC
intends to monitor the status of this matter but is unable to predict its
outcome or what effect this matter may have on its consolidated financial
position, results of operations or cash flows.
Other Legal Proceedings: IDACORP and IPC are involved in lawsuits and legal
proceedings in addition to those discussed above and in Note 7 to IDACORP's and
IPC's Consolidated Financial Statements. Resolution of any of these matters
will take time, and the companies cannot predict the outcome of any of these
proceedings. The companies believe that their reserves are adequate for these
matters.
Environmental Issues
Idaho Water Management
Issues: From 2000 through 2005, and
throughout 2007, below normal precipitation and stream flows have exacerbated a
developing water shortage in Idaho, manifested by a number of water issues
including declining Snake River base flows and declining levels in the Eastern
Snake Plain Aquifer (ESPA), a large underground aquifer that has been estimated
to hold between 200 - 300 maf of water. These issues are of interest to IPC
because of their potential impacts on generation at IPC's hydroelectric
projects.
As a result of declines in river flows, in 2003 several surface water users filed delivery calls with the Idaho Department of Water Resources (IDWR), demanding that it manage ground water withdrawals pursuant to the prior appropriation doctrine of "first in time is first in right" and curtail junior ground water rights that are depleting the aquifer and affecting flows to senior surface water rights. These delivery calls have resulted in several administrative actions before the IDWR to enforce senior water rights as well as judicial actions before the state court challenging the constitutionality of state regulations used by the IDWR to conjunctively administer ground and surface water rights. Because IPC holds water rights that are dependent on the Snake River, spring flows and the overall condition of the ESPA, IPC continues to participate in these actions, as necessary, to protect its water rights.
IPC, together with other interested water users and state interests, also
continues to explore and encourage the development of a long-term management
plan that will protect the ESPA and the Snake River from further depletion. On
February 14, 2007, the Idaho Water Resource Board (IWRB) presented the
framework for an ESPA management plan to the Idaho Legislature recommending the
development of a Comprehensive Aquifer Management Plan (CAMP). The proposed
goal of the CAMP is to sustain the economic viability and social and
environmental health of the ESPA by adaptively managing a balance between water
use and supplies. The IWRB estimates that the development of the CAMP will
take 16 months. Through House Concurrent Resolution 28 and House Bill 320, the
2007 Idaho Legislature appropriated funds and directed the IWRB to proceed with
the development of the CAMP. Pursuant to the IWRB recommendation in the CAMP
Framework, an advisory committee has been established to make recommendations
to the IWRB on the development of the CAMP. IPC sits on the CAMP advisory
committee and will be working with the IWRB on the development of the CAMP.
IPC is also engaged in the
Snake River Basin Adjudication (SRBA), a 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 IPC. The initiation of the SRBA
resulted from the Swan Falls Agreement, an agreement entered into by IPC and
the Governor and Attorney General of Idaho in October 1984 to resolve
litigation relating to IPC's water rights at its Swan Falls project. IPC has
filed claims to its water rights for hydropower and other uses in the SRBA.
Other water users in the basin have also filed claims to water rights. Parties
to the SRBA may file objections to water right claims that adversely affect or
injure their claimed water rights and the court then adjudicates the claims and
objections and enters a decree defining a party's water right. IPC has filed
claims for all of its hydropower water rights in the SRBA, is actively
protecting those water rights, and is objecting to claims that may potentially
injure or affect those water rights. One such claim involves a notice of claim
of ownership filed on December 22, 2006, by the state of Idaho, for a portion
of the water rights held by IPC that are subject to the Swan Falls Agreement.
On May 10, 2007, in order to
protect its claims and the availability of water for power purposes at its
facilities, and in response to the claim of ownership filed by the State, IPC
filed a complaint and petition for declaratory and injunctive relief regarding
the status and nature of IPC's water rights and the respective rights and
responsibilities of the parties under the Swan Falls Agreement. The complaint
was filed in the Idaho District Court for the Fifth Judicial District, the
court with jurisdiction over the SRBA, against the state of Idaho, the
Governor, the Attorney General, the IDWR and the Director of the IDWR.
In conjunction with the
filing of the complaint and petition, IPC filed motions with the court to stay
all pending proceedings involving the water rights of IPC and to consolidate
those proceedings into a single action where all issues relating to the Swan
Falls Agreement can be determined.
IPC alleged in the complaint,
among other things, that contrary to the parties' belief at the time the Swan
Falls Agreement was entered into in 1984, the Snake River basin above Swan
Falls was over-appropriated and as a consequence there was not in 1984, and
there currently is not, water available for new upstream uses over and above
the minimum flows established by the Swan Falls Agreement; that because of this
mutual mistake of fact relating to the over-appropriation of the basin, the
Swan Falls Agreement should be reformed; that the State's December 22, 2006,
claim of ownership to IPC's water rights should be denied; and that the Swan
Falls Agreement did not subordinate IPC's water rights to aquifer recharge.
On May 30, 2007, the State
filed motions to dismiss IPC's complaint and petition. These motions were
briefed and, together with IPC's motions to stay and consolidate the
proceedings, were argued before the court on June 25, 2007.
On
July 23, 2007, the court issued an Order granting in part and denying in part
the State's motion to dismiss, consolidating the issues into a consolidated
subcase before the court, providing for discovery during the objection period
and setting a scheduling conference for December 18, 2007. In its Order, the
court denied the majority of the State's motion to dismiss, refusing to dismiss
the complaint and finding that the court has jurisdiction to hear and determine
virtually all the issues raised by IPC's complaint that relate to IPC's water
rights and the effect of the Swan Falls Agreement upon those water rights.
This includes the issues of ownership, whether IPC's water rights are
subordinated to recharge and how those water rights are to be administered
relative to other water rights on the same or connected resources. The court
did find that by virtue of a state statute the IDWR, and its director, could
not be parties to the SRBA and therefore stayed IPC's claims against the IDWR
and its director pending resolution of the issues to be litigated in the SRBA,
or until further order of the court.
Consistent
with IPC's motion to consolidate and stay proceedings, the court consolidated
all of the issues associated with IPC's water rights before the court and
stayed that proceeding to allow other parties that may be affected by the
litigation to file responses or intervene in the consolidated proceedings by
December 5, 2007. On December 18, 2007, the court held a status and scheduling
conference in the consolidated proceedings. Subsequently, the court issued a
scheduling order on December 20, 2007, with a trial scheduled to begin on
February 2, 2009. IPC is unable to predict the outcome of the consolidated
proceedings.
IPC has also recently filed two
actions in federal court against the United States Bureau of Reclamation to
enforce a contract right for delivery of water to its hydropower projects on
the Snake River. In 1923, IPC and the United States entered into a contract
that facilitated the development of the American Falls Reservoir by the U.S. on
the Snake River in southeast Idaho. This 1923 contract entitles IPC to 45,000
acre-feet of primary storage capacity in the reservoir and 255,000 acre-feet of
secondary storage that was to be available to IPC between October 1 of any year
and June 10 of the following year as necessary to maintain specified flows at
IPC's Twin Falls power plant below Milner Dam. IPC believes that the U.S. has
failed to deliver this secondary storage, at the specified flows, since 2001.
As a result, on October 15, 2007, IPC filed an action in the U.S. District
Court of Federal Claims in Washington, D.C. to recover damages from the U.S.
for the lost generation resulting from the reduced flows. On October 15, 2007,
IPC filed a second action in the United States District Court for the District
of Idaho in Boise, Idaho, to compel the U.S. to manage American Falls Reservoir
and the Snake River federal reservoir system to ensure that IPC's contract
right to secondary storage is fulfilled in the future. The U.S. Bureau of
Reclamation filed an answer in the case filed with the U.S. District Court for
the District of Idaho on February 15, 2008. No answer has been filed in the
case filed in the U.S. Court of Claims. IPC is unable to predict the outcome
of this litigation.
Air Quality Issues
IPC owns two natural gas combustion
turbine power plants and co-owns three coal-fired power plants that are subject
to air quality regulation. The natural gas-fired plants, Danskin and Bennett
Mountain, are located in Idaho. The coal-fired plants are: Jim Bridger (33
percent interest) located in Wyoming; Boardman (ten percent interest) located
in Oregon; and North Valmy (50 percent interest) located in Nevada. The Clean
Air Act establishes controls on the emissions from stationary sources like
those owned by IPC. The Environmental Protection Agency (EPA) adopts many of
the standards and regulations under the Clean Air Act, while states have the
primary responsibility for implementation and administration of these air quality
programs. IPC continues to actively monitor, evaluate and work on air quality
issues pertaining to the Clean Air Mercury Rule (CAMR), possible legislative
amendment of the Clean Air Act, emerging greenhouse gas programs at the
federal, regional and state levels, New Source Review permitting, National
Ambient Air Quality Standards (NAAQS), and Regional Haze - Best Available
Retrofit Technology (RH BART). Low nitrogen oxide (NOx) burner
technology and mercury continuous emission monitoring systems (mercury CEMS) installations
are progressing at all three coal-fired power plants.
National Ambient Air
Quality Standards: EPA-adopted NAAQS
for fine particulate matter became effective in December 2006. This new
standard has been challenged by a number of groups in the U.S. Court of Appeals
for the District of Columbia Circuit. All of the counties in Idaho, Nevada,
Oregon, and Wyoming where IPC's power plants operate are currently designated
as meeting attainment with federal air quality standards, including the new
particulate matter standard. Nevertheless, under the new fine particulate
standards, three years of data are being collected to determine the attainment
status of all U.S. counties. In July 2007, the EPA
proposed to revise the NAAQS for 8-hour ozone. For the primary (health-based)
standard, EPA is proposing that the standard be lowered from 0.08 parts per
million (ppm) to between 0.070 and 0.075 ppm. The EPA received public comment
for 90 days and held 4 public hearings. The impact of these new
standards will not be known until these data are collected, analyzed, and
released to the public and the associated regulatory programs are promulgated
and implemented.
Clean Air Mercury Rule: The CAMR, issued by the EPA on March 15, 2005, limits
mercury emissions from new and existing coal-fired power plants and creates a
market-based cap-and-trade program that will permanently cap utility mercury
emissions. On February 8, 2008, the U.S. Court of Appeals for the D.C. Circuit
vacated the CAMR and remanded it back to the EPA for reconsideration consistent
with the court's interpretation of the Clean Air Act. The EPA could appeal
this decision but, in the absence of an appeal, the impact of this decision
will not be known until such time as the EPA develops a new report in response
to the court's decision.
In response to the CAMR, the
Idaho Department of Environmental Quality (IDEQ) proposed two new rules to the
Idaho Environmental Quality Commission: a rule to opt out of the federal
mercury cap-and-trade program, and a rule to prohibit the construction and
operation of a coal-fired power plant in Idaho. In April 2006, the governor of
Idaho signed House Bill 791, which placed a two-year moratorium on applying for
or issuance of permits, licenses or construction of certain coal-fired power
plants in Idaho. The moratorium expires on April 7, 2008. During the 2007
Idaho state legislative session, the state did not reject the proposal to opt
out of the cap-and-trade program, therefore accepting the opt-out rule. In
January 2008, Senate Bill 1314 was introduced which, if enacted, would extend
the current moratorium for an additional two years. IPC has no current plans
impacted by the moratorium or opting out of the CAMR cap-and-trade program.
On October 10, 2006, the
Wyoming Environmental Quality Council (WEQC) approved the Wyoming Department of
Environmental Quality's (WDEQ) recommended Wyoming regulation to implement
CAMR. This rule will allocate mercury allowances to each plant based on heat-input
and hold back ten percent of the allocated allowances for new sources. This
rule will also allow plants to participate in the national cap-and-trade
program. Mercury CEMS are planned to be installed at the Jim Bridger plant in
2008 at an estimated cost of $0.2 million (IPC share). Until the mercury CEMS
are installed and operational, the amount of mercury emissions is not
definitively known. It is not possible at this time to determine the effect of
the allowance allocation rule on future operations and costs at the plant.
On December 15, 2006, the
Oregon Environmental Quality Commission adopted the Oregon Department of
Environmental Quality (ODEQ)-proposed utility mercury rule. IPC estimates that
capital expenditures for mercury controls at Boardman will be $9.2 million (IPC
share) with an annual incremental operations and maintenance cost of up to $0.8
million (IPC share). The mercury rule will provide a limited number of mercury
allowances to Boardman that may be used for trading.
The Nevada Department of
Environmental Protection has adopted a state CAMR that will provide mercury
allowances to each plant based on actual emissions until 2018, at which time
the allowance allocations will be reduced to meet the federal cap. To meet the
reduced allocations in the year 2018, mercury controls are expected to be
installed. Mercury CEMS are planned to be installed at the North Valmy plant
in 2008 at an estimated cost of $0.1 million (IPC share).
At
this time, it is uncertain how state mercury rules or requirements might be
impacted by the vacated CAMR and any resulting impacts to IPC.
Regional Haze - Best
Available Retrofit Technology: In
accordance with federal regional haze rules, the WDEQ and ODEQ are conducting
an assessment of emission sources pursuant to a RH BART process. Coal-fired
utility boilers are subject to RH BART if they were built between 1962 and 1977
and affect any Class I areas. This includes all four units at the Jim Bridger
and Boardman plants. The two units at the North Valmy plant were constructed
after 1977 and are not subject to the federal regional haze rule.
PacifiCorp submitted the RH
BART application for the Jim Bridger plant in January 2007. The WDEQ is still
evaluating the application and will go out for public comment. If there are no
appeals to the application, the WDEQ will prepare a State Implementation Plan
to present to the WEQC for approval and submittal to the EPA. The plant is
already in the process of installing low NOx burners and scrubber
upgrades that are proposed in the application. Over the next four years, these
upgrade expenditures are currently estimated at $27.7 million (IPC share), with
a total upgrade expenditures estimated at $34.3 million (IPC share).
PGE completed the RH BART
analysis for the Boardman plant and submitted it to the ODEQ on November 15,
2007. This analysis includes proposed emission control upgrades for the
Boardman plant to comply with RH BART requirements. Capital upgrade costs
required to meet RH BART standards could vary significantly depending on the
technology utilized. Because of the combined benefit of emission equipment
that reduces multiple pollutants simultaneously, upgrade plans under
consideration will also meet CAMR standards. Upgrade cost estimates to meet
both standards range from $30 million to $62 million (IPC share). Depending on
what pollution control equipment is required to meet the standards, an extended
maintenance outage may be necessary. No commitments are in place at this time
and the cost estimates are preliminary and subject to change. More detailed
information will be available after completion of the analysis for the Boardman
plant and approval of the RH BART proposals by state and federal environmental
regulators.
Greenhouse
Gases: IPC continues to monitor
and evaluate the possible adoption of national, regional, or state greenhouse
gas (GHG) regulations and judicial decisions that would affect electric
utilities. At the national level, numerous GHG bills have been introduced in
the U.S. Senate and House of Representatives during 2006 and 2007. Debate
continues in Congress on the direction and scope of U.S. policy on regulation
of GHGs. IPC anticipates new developments to occur in 2008.
The states of Arizona,
California, New Mexico, Oregon, Utah and Washington, along with the provinces
of British Columbia and Manitoba, Canada, have formed the Western Regional
Climate Action Initiative (WCI). On August 22, 2007, the WCI partners released
their regional goal to collectively reduce GHGs 15 percent below 2005 levels by
2020. The WCI partners have agreed to design a regional market-based multi-sector
mechanism, such as a load-based or deliverer-based cap and trade program, to
help achieve the goal. The states of Idaho, Nevada and Wyoming have not joined
the WCI. It is possible that these and other states in which IPC operates or
sells electricity into could join the WCI in the future.
California's governor signed an executive order in 2005 to reduce
GHGs in that state to designated historical levels. On September 27, 2006,
California's governor signed into law the Global Warming Solutions Act of 2006,
which established GHG reduction goals and a framework for achieving these
goals. On January 25, 2007, California enacted a GHG emission performance standard
applicable to all electricity generated within the state or delivered from
outside the state. Oregon passed the Global Warming Integration Act in June
2007, which, among other things, established the Oregon Global Warming
Commission and state-wide GHG emission reduction goals. IPC will continue to monitor developments with respect
to the implementation of this legislation; however, until the Oregon Global
Warming Commission makes its recommendations and the associated regulatory
programs are promulgated and implemented, it is not possible to determine the
effect of this legislation on IPC's operations, particularly the Boardman
facility. The Washington legislature passed a bill
in April 2007 that sets climate pollution reduction and clean energy goals.
Emission performance standards affecting electric utility contracts and power
plant projects are included. Other regional and state GHG initiatives appear
likely, although the states of Idaho, Nevada and Wyoming have not
adopted GHG legislation. National, regional or state
GHG requirements, if enacted and applicable, could result in significant costs
to IPC to comply with restrictions on carbon dioxide or other GHG emissions.
Information about IDACORP's carbon dioxide emissions is included
in the report Benchmarking Air Emissions of the 100 Largest Electric Power
Producers in the United States - 2004. This report was released by the
Ceres Investor Coalition, the Natural Resources Defense Council and the Public
Service Enterprise Group Inc. in April 2006. The report lists IDACORP's 2004
carbon dioxide emissions at 1,222.0 lbs/MWh, as compared to the reported
average for the 100 largest power producers of 1,341.8 lbs/MWh. IPC's carbon
dioxide emissions on a lbs/MWh basis fluctuate with the amount of hydroelectric
generation. Even during a low water year like 2004, IPC's emissions from
electricity generation were below the average of the 100 largest power
producers. During 2007, IPC's carbon dioxide emissions were approximately 1,153
lbs/MWh.
As part of IPC's resource planning protocol, the IRP process
considers potential GHG emissions regulation and other environmental factors
when evaluating potential portfolios. The
2006 IRP included a risk analysis of the costs associated with the regulation
of carbon dioxide emissions by analyzing low, expected and high cases of $0,
$14 and $50 respectively, per ton of carbon dioxide emitted. Environmental impacts have been and will continue to be
integral components of IPC's resource decisions.
Due to escalating
construction costs, potential permitting issues, and continued uncertainty
surrounding future GHG laws and regulations, IPC has determined that coal-fired
generation is not the best technology to meet its resource needs in 2013. IPC
has shifted its focus to the development of a combined-cycle natural gas-fired
resource located closer to its load center in southern Idaho. Also, IPC added
101 MW of contracted wind generation in December 2007 bringing IPC's total to
121 MW. Another 69 MW of contracted wind generation is under construction.
IPC is in the process of adding 45.5 MW of geothermal generation by 2011.
Additional wind and geothermal generation is anticipated through CSPP and
RFP-driven contracts.
In
April 2007, the U.S. Supreme Court issued its decision in Massachusetts v.
Environmental Protection Agency, a case involving the EPA's authority to
regulate carbon dioxide emissions from motor vehicles under the Clean Air Act.
The Court held that, with respect to mobile sources, the EPA has authority
under the Clean Air Act to regulate carbon dioxide as a pollutant and that the
EPA has a duty to determine whether carbon dioxide emissions contribute to
climate change or provide some reasonable explanation why it will not exercise
its authority. The decision, combined with stimulus from state, regional and
federal legislative and regulatory initiatives, judicial decisions and other
factors may lead to a determination by the EPA to regulate carbon dioxide
emissions from stationary sources, including electricity generators. IPC will
continue to monitor developments with respect to the possible regulation of GHG
emissions from stationary sources under the Clean Air Act.
New Source Review: EPA Region 8 began reviewing PacifiCorp operations,
including the Jim Bridger plant (of which IPC is a one-third owner) for
compliance with New Source Review (NSR) and New Source Performance Standards
(NSPS) through a Clean Air Act Section 114 information request sent in May
2003. PacifiCorp completed its phased response to the Section 114 request in
February 2004 with the submission of a large volume of documents to EPA
relating to historical activities at Bridger and other PacifiCorp power
plants. A number of utilities that have also been the subject of EPA NSR information
requests have engaged in settlement negotiations with the EPA to resolve
allegations of NSR and NSPS noncompliance. Prior settlements reached between the
EPA and utility companies around the country to resolve these issues have
resulted in commitments by the utility companies to install additional
pollution control equipment and to pay civil penalties. IPC cannot predict the
outcome of this matter.
Endangered Species
In December 1992, the U.S. Fish and
Wildlife Service (USFWS) listed several species of fish and five species of
snails living within IPC's
operating area as threatened or endangered species under the Endangered Species
Act. IPC continues to review and analyze the effect such designation has on
its operations and is cooperating with governmental agencies to resolve issues
related to these species.
On September 5, 2007, the
species of snail that had been listed as the "Idaho Springsnail" was delisted
by the USFWS. The delisting decision was based on recent studies that
indicated the species was synonymous with another common species. On December
21, 2006, IPC and the Governor of Idaho submitted a petition to the USFWS to de-list
the threatened Bliss Rapids snail. The petition was supported with data
collected by IPC over the past 14 years. The snail, which lives throughout the
middle Snake River, springs, and tributaries between Niagara Springs and King
Hill, was listed as threatened under the Endangered Species Act in 1992. As of
December 31, 2007, no decision on the delisting petition had been issued by the
USFWS.
Pursuant
to FERC License 1971, IPC owns and finances the operation of anadromous fish
hatcheries and related facilities to mitigate the effects of its hydroelectric
dams on fish populations. In connection with its fish facilities, IPC sponsors
ongoing programs for the control of fish disease, improvement of fish
production, and evaluation of hatchery performance. IPC's anadromous fish
facilities at Hells Canyon, Oxbow, Rapid River, Pahsimeroi and Niagara Springs
continue to be operated by the Idaho Department of Fish and Game. At December
31, 2007, the investment in these facilities was $24 million and the annual
cost of operation was $3 million.
Climate Change: IPC's substantial hydroelectric generation resources
neither burn nor consume fossil fuels to produce electric energy to meet the
needs of its customers. Given the debate concerning climate change, consensus
is growing that broad steps should be taken in all sectors of the nation's
economy to carefully consider ways of limiting and/or reducing greenhouse gas
emissions and mitigating climate change impacts while still providing necessary
services in a cost-effective manner. IPC intends to continue to add renewable
resources to its resource portfolio and will continue to monitor the climate
change debate, current climate change research, and recently enacted as well as
proposed legislation to identify the potential impacts of global climate change
on all aspects of its business. Long-term climate change could significantly
affect IPC's business in a variety of ways, including but not limited to, the
following: (a) changes in temperature, precipitation and snow pack conditions
could affect customer demand and the amount and timing of hydroelectric
generation; and (b) legislative and/or regulatory developments related to
climate change could affect plans and operations in various ways including
placing restrictions on the construction of new generation resources, the
expansion of existing resources, or the operation of generation resources in
general. IPC cannot, however, quantify the potential impact of global climate
change on its business at this time.
Renewable Portfolio
Standards: Legislation to adopt a
national renewable portfolio standard (RPS) has been introduced into but not
yet adopted by Congress. IPC expects debate to continue on a national RPS and
anticipates new developments in 2008.
A
number of states in which IPC operates or sells power into have enacted RPS
legislation. For example, Oregon law requires the state's largest utilities to
meet 25 percent of their electric load with renewable energy by 2025. Because
of its relatively small presence in the state, IPC is not currently subject to
the Oregon RPS. It is possible that Idaho and other states in which IPC
operates or sells power into could adopt similar RPS initiatives.
IPC
will continue to monitor RPS developments but cannot, at this time, predict the
impacts of state and federal RPS legislation on its business.
REGULATORY MATTERS:
General Rate Case
Idaho: On June 8, 2007, IPC filed an application with the
IPUC requesting an average rate increase of approximately 10.35 percent for its
Idaho customers in order to begin recovery of its capital investments and
higher operating costs. IPC's proposal would increase its revenues $63.9
million annually. The application included a requested return on equity of
11.5 percent and an overall rate of return of 8.561 percent. IPC filed its
case based upon a 2007 forecast test year, a first for IPC in the Idaho
jurisdiction. Since IPC's last general rate case filing in 2005, IPC projected
that it will have placed in service an additional $300 million of investment in
its electrical system during 2006 and 2007. IPC also requested a $29.16 per
MWh LGAR, which adjusts the power supply costs IPC includes in the PCA for
differences between actual load and the load used in calculating base rates.
The existing LGAR is $29.41 per MWh. The impact of the new LGAR on IPC will
ultimately be determined by future load changes.
IPUC Staff and intervenor
testimony was filed December 10, 2007. The parties to the proceeding reached a
settlement that includes an average annual increase of 5.2 percent
(approximately $32.1 million annually). Neither an overall rate of return nor
a return on equity is specified in the settlement. The currently authorized
rate of return would remain at 8.1 percent.
The parties to the proceeding
also agreed in the settlement to make a good faith effort to develop a
mechanism to adjust or replace the current LGAR. As an interim solution, the
parties have agreed to use the LGAR of $62.79 per MWh recommended by the IPUC
Staff on December 10, 2007, but to apply it to only 50 percent of the load
growth occurring during each month within the April 2008 - March 2009 PCA year.
The parties also agreed to
participate in a good faith discussion regarding a forecast test year
methodology that balances the auditing concerns of the IPUC Staff and
intervenors with IPC's need for timely rate relief. The parties agreed that
such a methodology would begin with auditable numbers from which projections
would be made for the test year.
IPC filed a settlement
stipulation with the IPUC on January 23, 2008. The settlement is subject to
approval by the IPUC. The parties have requested in the settlement stipulation
that the new rates become effective no later than March 1, 2008, but IPC is
unable to predict what relief the IPUC will grant or when the IPUC will issue
its final order.
Deferred (Accrued) Net Power
Supply Costs
IPC's deferred (accrued) net power
supply costs consisted of the following at December 31 (in thousands of
dollars):
|
2007 |
|
2006 |
|||
Idaho PCA current year: |
||||||
Accrual for the 2007-2008 rate year (1) |
$ |
- |
$ |
(3,484) |
||
Deferral for the 2008-2009 rate year (2) |
85,732 |
- |
||||
Idaho PCA true-up awaiting recovery (refund): |
||||||
Authorized May 2006 |
- |
(11,689) |
||||
Authorized May 2007 |
6,591 |
- |
||||
Oregon deferral: |
||||||
2001 costs |
2,993 |
6,670 |
||||
2005 costs |
- |
2,889 |
||||
2006 costs |
2,107 |
- |
||||
Total deferral (accrual) |
$ |
97,423 |
$ |
(5,614) |
||
(1) The 2007-2008 PCA reflected $69 million of emission allowance sales to be credited to customers. |
||||||
(2) The 2008-2009 PCA deferral balance reflects $17 million of emission allowance sales in 2007. |
Idaho: IPC has a PCA mechanism that provides for annual
adjustments to the rates charged to its Idaho retail customers. These
adjustments are based on forecasts of net power supply costs, which are fuel
and purchased power less off-system sales, and the true-up of the prior year's
forecast. During the year, 90 percent of the difference between the actual and
forecasted costs is deferred with interest. The ending balance of this
deferral, called the true-up for the current year's portion and the true-up of
the true-up for the prior years' unrecovered portion, is then included in the
calculation of the next year's PCA.
The true-up of the true-up
portion of the PCA provides a tracking of the collection or the refund of true-up
amounts. Each month, the collection or the refund of the true-up amount is
quantified based upon the true-up portion of the PCA rate and the consumption
of energy by customers. At the end of the PCA year, the total collection or
refund is compared to the previously determined amount to be collected or
refunded. Any difference between authorized amounts and amounts actually
collected or refunded are then reflected in the following PCA year, which
becomes the true-up of the true-up. Over time, the actual collection or refund
of authorized true-up dollars matches the amounts authorized.
On
May 31, 2007, the IPUC approved IPC's 2007-2008 PCA filing. The filing
increased the PCA component of customers' rates from the then-existing level,
which was $46.8 million below base rates, to a level that is $30.7 million
above those base rates. This $77.5 million increase is net of $69.1 million of
proceeds from sales of excess SO2 emission allowances. The new
rates became effective June 1, 2007.
On
June 1, 2006, IPC implemented the 2006-2007 PCA, which reduced the PCA
component of customers' rates from the then-existing level, which was
recovering $76.7 million above then-existing base rates, to a level that was
$46.8 million below those base rates, a decrease of approximately $123.5
million.
Idaho
Load Growth Adjustment Rate (LGAR):
On January 9, 2007, the IPUC issued an order resetting IPC's LGAR to $29.41 per
MWh, effective April 1, 2007. The LGAR subtracts the cost of serving
additional Idaho retail load from the net power supply costs IPC is allowed to
include in its PCA. The order revised the LGAR from the original rate of
$16.84 per MWh set when the PCA began in 1993. This amount was established as
the projected additional variable energy costs attributable to load growth and
was subtracted from each year's PCA expense. In its petition, IPC had
requested the use of the embedded cost of serving new load and a rate of $6.81
per MWh, but the IPUC in its order determined to use the projected marginal
cost, which resulted in the higher LGAR.
As
discussed above in "General Rate Case - Idaho", a settlement stipulation before
the IPUC in that rate case would reset the LGAR to $62.79 per MWh, but would
apply that rate to only 50 percent of the load growth occurring each month within
the April 2008 - March 2009 PCA year. In the current 2007 general rate, IPC
filed normalized firm base load of 15.6 million MWh as compared with 14.8
million MWh in the 2005 general rate case. Because the LGAR is reset in
general rate cases, IPC expects to update its filed base load on a more
frequent basis during periods of high load growth.
Emission Allowances: During 2007, IPC sold 35,000 SO2 emission
allowances for a total of $19.6 million, after subtracting transaction fees.
The sales proceeds to be allocated to the Idaho jurisdiction are approximately
$18.5 million ($11.3 million net of tax, assuming a tax rate of approximately
39 percent). On January 15, 2008, a workshop was held to discuss whether the
customer share of the Idaho jurisdictional portion of the 2007 sales proceeds
should once again be included as a PCA credit or used to reduce investment
costs in wind development, green tags, or other options that would provide
longer term customer benefits. Because the workshop participants were unable
to reach a consensus regarding the use of the SO2 emission allowance
proceeds, the IPUC determined that the case would proceed under modified
procedure. Written comments were due February 25, 2008.
In 2005 and early 2006, IPC
sold 78,000 SO2 emission allowances for a total of $81.6 million,
after subtracting transaction fees. The sales proceeds allocated to the Idaho
jurisdiction were approximately $76.8 million ($46.8 million net of tax,
assuming a tax rate of approximately 39 percent). On May 12, 2006, the IPUC
approved a stipulation that allowed IPC to retain ten percent as a shareholder
benefit with the remaining 90 percent plus a carrying charge recorded as a customer
benefit. This customer benefit is included in IPC's PCA calculations as a
credit to the PCA true-up balance and is currently reflected in PCA rates
during the June 1, 2007, through May 31, 2008, PCA rate year.
The bulk of IPC's accumulated
excess emission allowances were sold during the 2005-2007 period. IPC has
approximately 15,000 excess emission allowances currently and anticipates
realizing a similar amount annually into the near future. Tighter emission
restrictions are expected in the long term which may cause IPC to use more
emission allowances for its own requirements and reduce the annual amount of
excess emission allowances.
Oregon: On April 30, 2007, IPC filed for an accounting order
with the OPUC to defer net power supply costs for the period from May 1, 2007,
through April 30, 2008, in anticipation of higher than "normal" power supply
expenses. In the Oregon general rate case, "normal" power supply expenses were
set at a negative number (meaning that under normal water conditions IPC should
be able to sell enough surplus energy to pay for all fuel and purchased power
expenses and still have revenue left over to offset other costs). IPC
requested authorization to defer an estimated $5.7 million, which is Oregon's
jurisdictional share of the excess power supply costs. IPC also requested that
it earn its Oregon authorized rate of return on the deferred balance and
recover the amount through rates in future years, as approved by the OPUC. IPC
is awaiting an order from the OPUC.
On April 28, 2006, IPC filed
for an accounting order with the OPUC to defer net power supply costs for the
period of May 1, 2006, through April 30, 2007. IPC requested authorization to
defer an estimated $3.3 million, which is Oregon's jurisdictional share of the
excess power supply costs. IPC also requested that it earn its Oregon authorized
rate of return on the deferred balance and recover the amount through rates in
future years, as approved by the OPUC. On April 25, 2007, a tentative
settlement agreement was reached on the deferral application with the OPUC
Staff and the Citizens' Utility Board in the amount of $2 million. The parties
also agreed that IPC would file an application for an Oregon PCA mechanism.
The settlement stipulation was approved by the OPUC on December 13, 2007.
The timing of future recovery
of Oregon power supply cost deferrals is subject to an Oregon statute that
specifically limits rate amortizations of deferred costs to six percent per
year. IPC is currently recovering through rates power supply costs associated
with the western energy situation of 2001. Full recovery of the 2001 deferral
is not expected until 2009. The 2006-2007 and the 2007-2008 deferrals will be
amortized sequentially following the full recovery of the 2001 deferral.
Oregon Power Cost
Adjustment Mechanism (PCAM)
On August 17, 2007, IPC filed an application with the OPUC requesting the
approval of a power cost adjustment mechanism similar to the Idaho PCA. If the
application is approved, it will allow IPC to recover excess net power supply
costs or distribute benefits to customers in a more timely fashion than through
the existing deferral process. The proposed mechanism differs from the Idaho
PCA in that is reestablishes the base net power supply costs annually. In
Idaho, the base net power supply costs are set by a general rate case. Settlement
conferences were held and the interested parties reached a verbal agreement. A
stipulation has been drafted by IPC and is being reviewed by the parties to the
settlement.
In connection with this
proceeding, on October 29, 2007, IPC made a filing with the OPUC requesting
that revenues associated with IPC's base net power supply costs be increased by
$4.6 million for Oregon. In isolation, this would be an average 15 percent
increase in rates; however, a yet to be filed forecast of net power supply
costs would also be a component of future PCAM rates. If the OPUC approves the
PCAM, any changes in rates are not expected to be effective until June 2008.
Fixed Cost Adjustment
Mechanism (FCA)
On January 27, 2006, IPC filed with the IPUC for authority to implement a rate
adjustment mechanism that would adjust rates downward or upward to recover
fixed costs independent of the volume of IPC's energy sales. This filing was a
continuation of a 2004 case that was opened to investigate the financial disincentives
to investment in energy efficiency by IPC. This true-up mechanism would be
applicable only to residential and small general service customers. The
accounting for the FCA will be separate from the PCA. IPC proposed a three
percent cap on any rate increase to be applied at the discretion of the IPUC.
IPC and the IPUC Staff agreed in concept to a three-year pilot program beginning
January 1, 2007, and a stipulation was filed on December 18, 2006. The
stipulation called for the implementation of a FCA mechanism pilot program as
proposed by IPC in its original application with additional conditions and
provisions related to customer count and weather normalization methodology,
recording of the FCA deferral amount in reports to the IPUC and detailed
reporting of DSM activities. The IPUC approved the stipulation on March 12,
2007. The pilot program began retroactively on January 1, 2007, and will run
through 2009, with the first rate adjustment to occur on June 1, 2008, and
subsequent rate adjustments to occur on June 1 of each year thereafter during
the term of the pilot program. IPC accrued $2.1 million of FCA expense in
2007.
Pension Expense
In the 2003 Idaho general rate case,
the IPUC disallowed recovery of pension expense because there were no current
contributions being made to the plan. On March 20, 2007, IPC filed a request
with the IPUC to clarify that IPC can consider future contributions made to the
pension plan a recoverable cost of service. On June 1, 2007, the IPUC issued its order authorizing IPC to account
for its defined benefit pension expense on a cash basis, and to defer and
account for accrued pension expense under SFAS 87, "Employers' Accounting
for Pensions," as a regulatory
asset. The IPUC acknowledged that it is appropriate for IPC to seek recovery
in its revenue requirement of reasonable and prudently incurred pension expense
based on actual cash contributions. The order did not determine the method of
recovery. IPC began deferring pension expense to a regulatory asset account to
be matched with revenue when future pension contributions are recovered through
rates. The deferral of pension expense did not begin until $4.1 million of
past contributions still recorded on the balance sheet at December 31, 2006,
were expensed. For 2007, approximately $2.8 million was deferred to a
regulatory asset beginning in the third quarter. IPC did not request a
carrying charge to be applied to the deferral of the accrued SFAS 87 expense.
AMI Report
IPC filed its Advanced Metering
Infrastructure (AMI) Status Report with the IPUC on May 1, 2007, in compliance
with an IPUC order. The report details IPC's resolution of the AMI-related
issues identified in the December 2005 AMI Status Report. On August 31, 2007,
IPC filed a supplemental report detailing its assessment of how it will proceed
with AMI deployment. In the report IPC provided a summary of the financial
analysis, a three-year AMI implementation plan beginning in late 2008, a
discussion of cost recovery and identification of remaining issues.
Federal Regulatory Matters
The Bonneville Power Administration Residential Exchange Program: The Pacific Northwest Electric Power Planning and
Conservation Act of 1980, through the Residential Exchange Program, provides
access to the benefits of low-cost federal hydroelectric power to residential
and small farm customers of the region's investor-owned utilities (IOUs). The
program is administered by the Bonneville Power Administration (BPA). IPC
entered into settlement agreements with the BPA that settled IPC's rights under
the Residential Exchange Program (REP) for the fiscal year 2002-2006 rate
period and for the fiscal year 2007-2011 rate period. Pursuant to these
agreements between the BPA and IPC, benefits from the BPA were passed through
to IPC's Idaho and Oregon residential and small-farm customers in the form of
electricity bill credits.
On May 3, 2007, the U.S.
Court of Appeals for the Ninth Circuit ruled that the settlement agreements
entered into between the BPA and the IOUs (including IPC) are inconsistent with
the Northwest Power Act. On May 21, 2007, the BPA notified IPC and six other IOUs
that it was immediately suspending the REP payments that the utilities pass
through to their residential and small-farm customers in the form of
electricity bill credits. IPC took action with both the IPUC and the OPUC to
reduce the level of credit on its customers' bill to zero, effective June 1,
2007. From October 1, 2001 to June 1, 2007, IPC had passed through to its REP
customers approximately $90 million in benefits pursuant to the settlement
agreements.
Since that time IPC has been
working with the other northwest IOUs, northwest state public utility
commissions, and the BPA to craft an agreement so that residential and small
farm customers of IPC can resume sharing in the benefits of the federal
Columbia River power system. However, the matter has yet to be resolved. The
BPA has initiated several public processes, which ultimately will determine
whether benefits will be restored to IPC customers. The most significant of
these processes is the WP-07 supplemental rate case. IPC will fully
participate in this proceeding, which is expected to be completed prior to
October 1, 2008. At issue is the REP calculation and allocation of benefits to
IOUs, and IPC specifically, and resolution of claims of overpayment in past
periods.
Since these REP benefits were
passed through to IPC's customers, the outcome of this matter is not expected
to have a significant effect on IPC's financial condition or results of
operations.
FERC Investigation: On March 28, 2007, the FERC advised IPC that the FERC
was commencing a preliminary, non-public investigation into the pricing and
availability of transmission capacity into and out of IPC's IPCO point of
delivery and transactions related to that transmission capacity during the
period January 1, 2003, to present. Subsequently, the FERC made two data
requests in connection with this investigation. IPC responded to those data
requests between June and August 2007. At IPC's request, IPC representatives
met with FERC personnel on October 18, 2007, to discuss several data responses
that IPC had previously provided. In follow-up to that meeting, IPC had
further discussions with and submitted additional materials to the FERC staff.
IPC is unable to predict the outcome of this investigation.
FERC Proceedings:
Open Access Transmission Tariff
(OATT): On March 24, 2006, IPC
submitted a revised OATT filing with the FERC requesting an increase in
transmission rates. In the filing IPC proposed to move from a fixed rate to a
formula rate, which allows for transmission rates to be updated each year based
on FERC Form 1 data. The formula rate request included a rate of return on
equity of 11.25 percent. The proposed rates would have produced an annual
revenue increase for the FERC jurisdiction of approximately $13 million based
on 2004 test year data. The FERC accepted IPC's rates, effective June 1, 2006,
subject to adjustment to conform to SFAS 109 tax accounting requirements, which
lowered the estimated annual increase in revenues to approximately $11 million.
On August 8, 2007, the FERC
approved a settlement agreement filed in June 2007 by the parties on all issues
except the treatment of contracts for transmission service that contain their
own terms, conditions and rates and that were in existence before the
implementation of OATT in 1996 (Legacy Agreements). The effect of this
settlement was to reduce the estimated FERC jurisdictional annual revenue increase
from $11 million to approximately $8.2 million based on 2004 test year data.
The settlement agreement required that amounts collected in excess of the new
rates for the June 1, 2006, through July 31, 2007, period be refunded with
interest to customers. These refunds totaled approximately $1.7 million and
were paid in August 2007.
Hearings were held before the
FERC in June 2007 regarding the treatment of the Legacy Agreements. IPC's
position was that the revenue IPC receives under the Legacy Agreements should
be credited against the total transmission revenue requirement attributed to
OATT customers and that the contract demands of the Legacy Agreements should
not be included in the load divisor of the rate formula. The intervenors in
the proceeding took the position that such contract demands should be included
in the load divisor, rather than being revenue credited.
On August 31, 2007, the FERC
Presiding Administrative Law Judge (ALJ) issued an initial decision (Initial
Decision) with respect to the treatment of the Legacy Agreements, which is on
file and publicly available at FERC Docket No. ER06-787. In the Initial
Decision, the ALJ concluded that (i) the Legacy Agreements should be included
in the load divisor of the rate formula and (ii) the revenue IPC receives under
the Legacy Agreements should not be credited against the total transmission
revenue requirement attributed to OATT customers. If the Initial Decision is
implemented, IPC estimates that this ruling will reduce the estimated FERC jurisdictional
annual revenue increase (based on 2004 test year data) to $6.8 million.
IPC has appealed the Initial
Decision to the FERC. However, if the Initial Decision is implemented, IPC
would make additional refunds, including interest, of approximately $2.4
million for the June 1, 2006, through December 31, 2007, period. IPC has
reserved this entire amount. IPC expects to pursue recovery of amounts not
received pursuant to a final order in this proceeding through additional
proceedings at the FERC or through the state ratemaking process. IPC is
awaiting a final FERC order.
FERC
Order 890: In February 2007, the
FERC issued Order No. 890 adopting a final rule designed to strengthen the pro
forma OATT by providing greater consistency and increasing transparency. The
FERC had stated in its Notice of Proposed Rulemaking leading to the final rule
that "as a general matter, the purpose of this rulemaking is to strengthen the
pro forma OATT to ensure that it achieves its original purpose - remedying undue
discrimination - not to create new market structures." The most significant
revisions to the pro forma OATT relate to the development of more consistent
methodologies for calculating available transfer capability, changes to the
transmission planning process, changes to the pricing of certain generator and
energy imbalances to encourage efficient scheduling behavior and to exempt
intermittent generators, and changes regarding long-term point-to-point
transmission service, including the addition of conditional firm long-term
point-to-point transmission service, and generation re-dispatch.
As
a transmission provider with an OATT on file with the FERC, IPC is required to
comply with the requirements of the new rule. A major requirement of the new
rule was to file a revised pro forma OATT on July 13, 2007. IPC also
was required to file a revised Attachment C specifying the methodology to
assess available transfer capability on September 11, 2007, and an Attachment K
which sets forth its coordinated, open and transparent planning process on
December 7, 2007. IPC made the required FERC filings and is currently
operating under the new tariff.
On
December 28, 2007, the FERC issued Order No. 890-A, an order on Rehearing and
Clarification of Order 890. Order No. 890-A primarily affirms and clarifies Order
No. 890. Order No. 890-A will become effective 60 days after its publication
in the Federal Register.
Certain details related to
the rule remain to be determined prospectively, and thus it is difficult to make
a precise determination of the overall effect of this new rule on IPC's
transmission operations or wholesale marketing function. However, at least on
a preliminary basis, the rule is not anticipated to have a significant impact
on IPC's financial results. Nonetheless, the final rule includes a wide range
of provisions addressing the provision of transmission services, and as the new
tariff is implemented there is likely to be an impact on IPC's transmission
operations, planning and wholesale marketing functions.
FERC Order 693: Pursuant to section 215 of the FPA, on March 16,
2007, the FERC issued Order No. 693 in which it approved 83 of the 107
reliability standards proposed by the North American Electric Reliability
Corporation (NERC). Previously, the FERC certified the NERC as the electric
reliability organization responsible for developing and enforcing mandatory
reliability standards. Collectively, the reliability standards define overall
acceptable performance with regard to operation, planning and design of the
North American bulk power system. As the FERC recognized in Order No. 693,
most of these reliability standards were already being adhered to on a
voluntary basis. Compliance with these standards became mandatory and subject
to the FERC's penalty authority in June 2007. Since then, additional
reliability standards have been submitted, and will continue to be submitted,
by the NERC to the FERC for approval. IPC reviewed all requirements,
procedures and documentation to ensure compliance with these standards and
submitted all necessary information by the effective date of June 18, 2007.
IPC certified its compliance with a subset of these standards (the WECC
Actively Monitored Standards) prior to the January 10, 2008 deadline. IPC is subject
to compliance spot-checks beginning in 2008. Order No. 693 substantially
impacts documentation requirements, but is not expected to have a material
impact on operations.
Northern
Tier Transmission Group
IPC, along with four other
transmission-owning entities covering all or parts of the transmission system
in six western states, has formed the Northern Tier Transmission Group (NTTG).
The goal of the group is to improve overall operation and expansion of the high-voltage
transmission network. The group continues to make progress on four major
initiatives: improving generation control performance (the first generation
control became operational in March 2007); compliance with FERC Order 890
through cooperative efforts in developing process and information exchange;
providing improved information on available transmission capacity; and
conducting open, participatory transmission planning processes which will
result in identifying specific transmission projects. Several projects have
been identified for the "fast-track" planning process and work has begun on
engineering analysis. One of these projects is IPC's joint project with
PacifiCorp (MidAmerican) to evaluate building two high voltage transmission
lines as discussed below (Gateway West Project). FERC Order No. 890 required
jurisdictional utilities to establish planning procedures, to which IPC
responded by submitting its Attachment K filing with the FERC on December 7,
2007. To date, the FERC has yet to accept or issue orders regarding any
Attachment K filings, including IPC's. In addition to other activities, the
NTTG fulfills a significant portion of the sub-regional and regional planning
requirements specified in Order 890, including the commencement of the NTTG
biennial planning process with a public stakeholder meeting held in January
2008.
Gateway
West Project
IPC and PacifiCorp are jointly
exploring the Gateway West Project to build two 500-kV lines between the Jim
Bridger plant in Wyoming and Boise. The lines would be designed to increase
electrical transmission capacity across southern Idaho in response to
increasing customer demand and growth. This project has been submitted to the
Western Electricity Coordinating Council (WECC) for the first phases of the
ratings process. A review team has been established from members of the WECC
to analyze the impact of the project on the existing system. When the study is
complete, necessary modifications will be made to the engineering design and
the final rating will be obtained prior to the beginning of construction. Planning
and project management personnel for both companies have begun the initial
phases of this project. IPC and PacifiCorp have a cost sharing agreement for
expenses associated with the analysis work of the initial phases. It is
expected that the majority of the project would be completed between 2012 and
2014 depending on the timing of rights-of-way acquisition, siting and
permitting, and construction sequencing. If the project is constructed, IPC
estimates that its share of project costs would be between $800 million and
$1.2 billion.
Hemingway-Boardman
Line
Consistent with the 2006 IRP and
requirements of other transmission customer requirements, IPC is exploring
alternatives for the construction of a 500-kV line between southwestern Idaho
and the Northwest. If built, this line could be in service as early as 2012.
Several electric utilities, including IPC, have proposed development of a
transmission station near Boardman, Oregon which would serve as the northwest
terminal of the project. The Idaho terminal would be the proposed Hemingway
Station located in the vicinity of Melba and Murphy on the south side of the
Snake River near Boise. IPC and a number of other utilities with proposed
regional transmission projects in the Northwest have signed a letter agreeing
to coordinate technical studies, which have begun. Other planning and project
management activities are underway. IPC has received inquiries about
participating in this project from other parties.
The
proposed Gateway West and Hemingway-Boardman transmission projects will be used
both by wholesale transmission customers and to serve IPC's native load
consistent with our OATT. Therefore these facilities will be subject to both
the FERC and state public utility commission regulation and rate-making
policies.
Public Utility Regulatory
Policies Act of 1978
As mandated by the enactment of PURPA and the adoption of avoided cost rates by
the IPUC and the OPUC, IPC has entered into contracts for the purchase of
energy from a number of private developers. Under these contracts, IPC is
required to purchase all of the output from the facilities located inside the
IPC service territory. For projects located outside the IPC service territory,
IPC is required to purchase the output that IPC has the ability to receive at
the facility's requested point of delivery on the IPC system. The IPUC
jurisdictional portion of the costs associated with CSPP contracts are fully
recovered through base rates and the PCA. For IPUC jurisdictional contracts,
projects that generate up to ten average MW of energy on a monthly basis are
eligible for IPUC Published Avoided Costs for up to a 20-year contract term.
The Published Avoided Cost is a price established by the IPUC and the OPUC to
estimate IPC's cost of developing additional generation resources. As
discussed more fully in "Wind Integration Costs" below, on August 4, 2005, the
IPUC granted a temporary reduction in the eligible project size to 100 kW for
intermittent generation resources only and ordered IPC to study the impacts of
integrating this type of resource.
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.
The OPUC jurisdictional portion of the costs associated with CSPP contracts is
recovered through general rate case filings. The Oregon provisions are
currently being reviewed in an OPUC proceeding. If a PURPA project does not
qualify for Published Avoided Costs, then IPC is required to negotiate the
terms, prices and conditions with the developer of that project. These
negotiations reflect the characteristics of the individual projects (i.e.,
operational flexibility, location and size) and the benefits to the IPC system
and must be consistent with other similar energy alternatives.
Recent activities, including
the extension of the Federal Production Tax Credit and the expansion of the tax
credit eligibility to solar, geothermal and other forms of generation,
resolution of IPUC and OPUC PURPA-related hearings and a December 1, 2004,
order by the IPUC increasing the Published Avoided Costs, create a favorable
climate for PURPA project development, which may require IPC to enter into
additional PURPA agreements. The requirement to enter into additional PURPA
agreements may result in IPC acquiring energy at above wholesale market prices,
thus increasing costs to its customers. It is highly likely that the
requirement to enter into additional PURPA agreements will add to IPC's surplus
during certain times of the year, which could also increase costs to IPC's
customers. As of December 31, 2007, IPC had signed agreements to purchase
energy from 94 CSPP facilities with contracts ranging from one to 30 years. Of
these facilities, 76 were on-line at the end of 2007; the other 18 facilities
under contract are due to come on-line in 2008 and 2009. During 2007, IPC
purchased 777,147 MWh from these projects at a cost of $45 million, resulting
in a blended price of 5.9 cents per kilowatt hour.
Wind Integration Costs: Under PURPA, IPC is required to offer independent
developers a power purchase contract based on a standard avoided cost rate for
a qualifying facility with an output of ten average megawatts (aMW) or less.
Because a large number of wind project developers came to IPC requesting PURPA
contracts in early 2005, IPC requested and the IPUC granted temporary relief
from PURPA requirements until the impact of wind integration could be more
fully studied. The IPUC granted this relief by temporarily reducing the PURPA
cap of 10 aMW to 100 kW for PURPA wind projects.
On February 6, 2007, IPC
filed with the IPUC a wind integration study report along with a petition
requesting removal of the temporary restriction on the size of PURPA wind
projects and adjustment of avoided cost rates to compensate for the increase in
system costs due to wind variability. On March 15, 2007, and June 20, 2007, public
workshops were held to present the results of the study, which were contested
by wind developers and advocates of wind generation resources.
In an attempt to settle the
case, IPC entered into a settlement stipulation with Renewable Northwest
Project and the NW Energy Coalition on October 2, 2007. The settlement stipulation
prescribed, among other things, a methodology for calculating a wind
integration charge that will be applied to PURPA wind projects. The
integration charge will be calculated as a percentage of the current 20-year,
levelized, avoided cost rate, subject to a cap of $6.50/MWh. On February 20, 2008, the IPUC issued an order
approving the settlement stipulation and increasing the PURPA cap back to ten
aMW.
Cassia Wind Farm Complaint: On September 13, 2006, Cassia Gulch Wind Park, LLC
and Cassia Wind Farm, LLC (collectively Cassia) filed a complaint against IPC
with the IPUC requesting the IPUC to determine that the cost responsibility for
specified transmission system upgrades to meet contingency planning conditions
should not be assigned to PURPA qualifying facilities connecting to the system,
but rather should be rolled into IPC's plant-in-service rate base and recovered
through rates to retail and transmission customers. The estimated costs of
transmission system upgrades included in this complaint that relate to
connecting Cassia to IPC's system were $60 million. Comments were filed in
October and November 2006, and oral arguments were held in November 2006. On
June 13, 2007, IPC and Cassia filed a Joint Motion to Dismiss the underlying
complaint and to approve a related settlement stipulation. The IPUC approved
the Joint Motion on August 29, 2007.
The key component of the
stipulation is the concept of "redispatch." IPC's estimated cost of
approximately $60 million to complete necessary transmission network upgrades
was based on the assumption that the requesting projects in the transmission
queue would not be dispatchable. Under the stipulation, Cassia agrees to
install, at its expense, equipment and communication facilities necessary to reduce
its energy output to a predetermined set-point within ten minutes of when IPC
requests the reduction. Based on these provisions, the original estimate of
$60 million decreased to approximately $11 million. Under the stipulation, IPC
would fund 25 percent of any upgrade investment, which would be recoverable
through rates, while the developer would fund 25 percent that is non-recoverable
and 50 percent that is recoverable over time. The stipulation also addresses
responsibility for network upgrade costs, sharing of network upgrade costs,
refunds and interests on refunds and security for payment.
On October 15, 2007, the IPUC
approved the application of this same cost allocation methodology to two PURPA
qualifying projects that were not parties to the Cassia dispute and are in a
different geographic region than the one impacted by the Cassia transmission
upgrades. Although the IPUC did not in the Cassia proceeding approve broad
application of the settlement to other projects, it did, in this case, determine
that the circumstances were similar enough to warrant using the same cost
allocation methodology.
PURPA Avoided Cost Rate
Computation: On September 10, 2007,
IPC filed an application with the IPUC requesting modification to the method of
computing avoided cost rates. These rates are used to set the price IPC pays
to new PURPA projects over the lives of the purchase agreements. Specifically,
IPC requested that the fuel cost component of the computation be revised from a
three-year average natural gas price with a prescribed escalation factor to an
average of the 20-year forecast of median natural gas prices as published by
the Northwest Power and Conservation Council (NWPCC) for 2007. IPC believes that
failing to recognize the non-linear shape of the NWPCC's 2007 forecast would
cause the published rates to be much higher than they otherwise would be. IPC did
not propose to adjust any of the non-fuel assumptions in the avoided cost rate
computation.
Avista
Corporation, Rocky Mountain Power, and the IPUC Staff filed comments supporting
IPC's position but recommending that the fuel cost component be tied to each
year in the NWPCC forecast rather than using an average of the twenty years. The IPUC approved the application including the IPUC
Staff's recommended modification on December 28, 2007.
Integrated Resource Plan
IPC filed its 2006 IRP with the IPUC
in September 2006 and with the OPUC in October 2006. The 2006 IRP previewed
IPC's load and resource situation for the next 20 years, analyzed potential
supply-side and demand-side options and identified near-term and long-term
actions.
The IPUC accepted the 2006
IRP in March 2007. The OPUC acknowledged the 2006 IRP in September 2007 with
the stipulation that IPC not commit to the construction of a 250-MW pulverized
coal resource, identified to come on-line in 2013, until IPC presents an update
of the 2006 IRP to the OPUC no later than June 2008. With its acceptance of
the 2006 IRP, the IPUC requested that IPC align the submittal of its next IRP with
those submitted by other utilities. To comply with this request IPC intends to
provide an update on the status of the 2006 IRP to both the IPUC and OPUC no
later than June 2008 and file a new IRP in June 2009.
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. IPC continues to analyze and evaluate the resource plan and make
periodic adjustments and corrections to reflect changes in technology, economic
conditions, anticipated resource development and regulatory requirements. Each
of the sections below provides an update of items identified in the 2006 IRP.
Peaking Resource: Construction of a new simple cycle combustion turbine
resource at the Danskin plant near Mountain Home, Idaho is expected to be
complete in the first quarter of 2008. The combustion turbine will provide approximately 166 MW of capacity during
summer load peaks and up to 200 MW during winter. IPC received a Certificate
of Public Convenience and Necessity for this project on December 15, 2006, that
included a construction cost commitment estimate of $60 million and approval to
include in rate base the prudent capital costs for construction and operating
fuel. The project is ahead of schedule and under the commitment estimate.
Related transmission interconnection and line requirements are being completed
by IPC at an estimated cost of $24 million.
Wind Agreement: In February 2007, the IPUC approved a power purchase
agreement with Telocaset Wind Power Partners, LLC, a subsidiary of Horizon Wind
Energy, for 101 MW (nameplate) of wind generation from the Elkhorn Valley Wind
Project located in eastern Oregon. The project was constructed during 2007 and
became commercially operational on December 28, 2007.
Geothermal Agreement: An RFP for geothermal-powered generation was
released on June 2, 2006. IPC identified U.S. Geothermal, Inc. as the
successful bidder in March 2007 based on a proposal to supply 45.5 MW of
geothermal energy. On January 9, 2008, the IPUC approved a power purchase agreement
for 13 MW (nameplate generation) from the Raft River Geothermal Power Plant
Unit #1 located in southern Idaho. This project began operating in October
2007. Contract negotiations for the remaining 32.5 MW will take place over the
next several months and will include an additional unit at the Raft River site
(on-line 2009) and two units at the Neal Hot Springs site located in eastern
Oregon (on-line 2010 and 2011).
Coal-fired Resource (Shift
to Natural Gas-fired Resource): The
near-term action plan in the 2006 IRP indicated initial commitments to the
construction of a coal-fired resource would be necessary before the end of 2007
in order for a project to be on-line in 2013. In order to meet this schedule,
IPC screened and evaluated coal-fired resources in 2006 and 2007. This
evaluation concluded in August 2007 and the results indicated construction
costs had escalated substantially since resource cost estimates were prepared
for the 2006 IRP. Due to escalating construction costs and continued
uncertainty surrounding future GHG laws and regulations, IPC decided not to
pursue the development of a coal-based resource at this time. However, IPC
continues to evaluate other coal-fired resource opportunities, including
expansion of its jointly-owned facilities, clean coal technologies and
potential power purchase agreements. In order to meet baseload deficiencies
identified in 2013, IPC has shifted its focus to the development of a combined
cycle natural gas-fired resource located closer to its load center in southern
Idaho.
Additional RFPs: On January 22, 2008, IPC released an RFP for 50 to
100 MW of geothermal energy. While additional geothermal resources were not
included in the 2006 IRP for this time frame, the development of PURPA wind and
combined heat and power projects has been slower than anticipated. If
competitively priced geothermal resources are available, they may help to meet
future resource needs. IPC also anticipates releasing an RFP in 2008 for 50 MW
from one or more combined heat and power projects.
Relicensing of
Hydroelectric Projects
IPC, 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. IPC is
actively pursuing the relicensing of the Hells Canyon Complex and Swan Falls
projects.
Hells Canyon Complex: The most significant ongoing relicensing effort is
the Hells Canyon Complex (HCC), which provides approximately two-thirds of IPC's
hydroelectric generating capacity and 40 percent of its total generating
capacity. The current license for the HCC expired at the end of July 2005.
Until the new multi-year license is issued, IPC operates the project under an
annual license issued by the FERC. The license application was filed in July
2003 and accepted by the FERC for filing in December 2003. The FERC is now
processing the application consistent with the requirements of the FPA, the
National Environmental Policy Act of 1969, as amended (NEPA), the Energy Policy
Act and other applicable federal laws.
Consistent with the
requirements of NEPA, the FERC Staff prepared and 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, the federal and state agencies, Native American tribes and
the public about the environmental effects of IPC's proposed operation of the
HCC. The final EIS also considers reasonable alternatives to that proposed
operation. In this latter context, the FERC Staff reviewed the comments and
alternative proposals submitted by the agencies, tribes and the private
interests and evaluated those alternatives as compared to measures proposed by
IPC. The final EIS also contains a "Staff Alternative," reflecting those
instances where some modification to IPC's proposal is deemed advisable by the
Staff to address environmental impacts or concerns. The FERC will consider the
findings and proposals contained in the final EIS, together with the other
information and material filed in the relicensing proceeding, in the
development of a license order for the HCC. IPC's initial review of the final
EIS indicates that, in large measure, the findings and recommendations (the
Staff Alternative) in the final EIS are consistent with the draft EIS issued by
the FERC in July 2006 and that the final EIS generally accepts the science,
analysis and the proposed measures contained in IPC's license application and
supporting documents. IPC is continuing to review the final EIS and expects to
file comments on the final EIS with the FERC in the first quarter of 2008.
In conjunction with the
issuance of the final EIS, on September 13, 2007, the FERC requested formal
consultation with the National Marine Fisheries Service (NMFS) and the U.S.
Fish and Wildlife Service (USFWS) pursuant to section 7 of the Endangered
Species Act (ESA) with regard to the effect of relicensing the HCC on several
aquatic and terrestrial species listed as threatened under the ESA. In subsequent
correspondence these entities, the USFWS and the NMFS advised the FERC that
outstanding issues remain with regard to the licensing of the HCC and they did
not have sufficient information to complete formal ESA consultation on the
project. The agencies further advised that they were working with IPC and
other state and federal agencies to address these outstanding issues. IPC
continues to cooperate with the USFWS, the NMFS, and the FERC in an effort to
address ESA concerns associated with the relicensing of the HCC. The FERC is
not expected to issue a license order for the HCC until ESA consultation is
completed.
On January 31, 2007, IPC
filed Water Quality Certification Applications, under section 401 of the Clean
Water Act (CWA), with the States of Oregon and Idaho. Because the HCC is
located on the Snake River where it forms the border between Idaho and Oregon,
section 401 of the CWA requires as a prerequisite to the licensing of the
project by the FERC that each state certify that any discharge from the project
complies with applicable state water quality standards. IPC worked with the
ODEQ and the IDEQ through 2007 on proposed water quality measures that would
address water quality issues at the project. However, because the CWA requires
that a state agency act on a pending application within one year of its filing
date, IPC found it necessary to withdraw its pending section 401 applications
on November 2, 2007 and re-file new applications on that same date. IPC filed
supplemental information to the applications on February 1, 2008. IPC
continues to work with the ODEQ and the IDEQ to ensure that state water quality
standards will be met at the HCC so that the project can be appropriately
certified.
At December 31, 2007, $96
million of HCC relicensing costs were included in construction work in
progress. The relicensing costs are recorded and will be held in construction
work in progress until a new multi-year license is issued by the FERC, at which
time the charges will be transferred to electric plant in service. Relicensing
costs and costs related to a new license will be submitted to regulators for
recovery through the ratemaking process.
Swan Falls Project: The license for the Swan Falls hydroelectric project
expires in June 2010. On March 10, 2005, IPC issued a Formal Consultation
Package (FCP) to natural resource agencies, Native American tribes and the
public relating to environmental studies designed to determine project effects
for the relicensing of the Swan Falls project. Based upon the results of those
studies and the consultation with the agencies, tribes and the public, on
September 21, 2007, IPC submitted its draft license application to FERC for
public review and comment. The draft contains project-specific information and
the results of the studies developed in the FCP. Comments were received from
the agencies and one tribe and on February 19, 2008 a joint meeting was held to
address the comments and attempt to resolve areas of disagreement over study
results and proposed mitigation measures. IPC will file a final license
application with the FERC in June 2008.
At December 31, 2007, $3
million of Swan Falls project relicensing costs were included in construction
work in progress. The relicensing costs are recorded and will be held in
construction work in progress until a new multi-year license is issued by the
FERC, at which time the charges will be transferred to electric plant in
service. Relicensing costs and costs related to a new license will be
submitted to regulators for recovery through the ratemaking process.
Shoshone Falls Expansion: On August 17, 2006, IPC filed a license amendment
application with the FERC, which would allow IPC to upgrade the Shoshone Falls
project from 12.5 MW to 62.5 MW. In March 2007, IPC received from the FERC a
draft Environmental Assessment (EA) and Notice of Ready for Environmental
Analysis, which provided for a 60-day comment period for interested entities.
The FERC issued a supplemental EA on December 4, 2007. The license amendment
could be issued in the first quarter 2008.
In conjunction with the
license amendment application, IPC has filed a water rights application which
is currently being reviewed by the IDWR.
FERC Market-Based Rate
Authority
IPC has FERC-approved market-based
rate authority, which permits IPC to sell electric energy at market-based rates
rather than being limited to cost-based rates. Every three years, the FERC
requires a review of the conditions under which this market-based rate
authority is granted to ensure that the rates charged thereunder are just and
reasonable. On April 14, 2004, the FERC issued an order indicating that is was
reconsidering the rules, procedures and methodologies associated with such
"triennial filings." In September 2004, IPC filed a revision to its market
power analysis (based on 2003 historical data), which it supplemented in
September and October 2004. On March 3, 2005, the FERC issued an order
accepting IPC's market power analysis. On June 21, 2007, the FERC issued a
final rule, Order No. 697, revamping its market-based rate program. Under
Order No. 697, IPC's next triennial filing is not due until June 30, 2010.
On December 9, 2005, the FERC
Staff requested that IPC perform a complete generation market power study for
the IPC control area using 2004 historical data. IPC filed a revised study
with the FERC on February 3, 2006. The FERC accepted IPC's notice on June 20,
2006, confirming that IPC passed the market power analysis screens and
maintained market-based rate authority.
Because
IPC's new generating unit at its Danskin plant, which has a capacity greater
than 100 MW, will soon be operational, IPC anticipates filing a "Notice of
Change in Status" with the FERC during the first quarter of 2008.
OTHER MATTERS:
Adopted Accounting
Pronouncements
FIN 48: In 2007, IDACORP and IPC
adopted FASB Interpretation No. 48, "Accounting for Uncertainty in Income
Taxes - an interpretation of FASB Statement No. 109" (FIN 48), which
creates a single model to address accounting for uncertainty in tax positions.
FIN 48 prescribes a minimum recognition threshold that a tax position is
required to meet before being recognized in a company's financial statements
and also provides guidance on derecognition, measurement, classification, interest
and penalties, accounting in interim periods, disclosure, and transition.
The cumulative effect of
adopting FIN 48 was recorded as a $15.1 million increase in the 2007 opening
balance in retained earnings.
New Accounting
Pronouncements
See Note 1 to IDACORP's and IPC's Consolidated Financial Statements for a
discussion of recently issued accounting pronouncements.
Inflation
IDACORP and IPC believe that
inflation has caused and will continue to cause increases in certain operating
expenses and the replacement of assets at higher costs. Inflation affects the
cost of labor, products and services required for operations and maintenance
and capital expenditures. While inflation has not had a significant impact on
IDACORP's or IPC's operations, increases in utility expenses due to inflation
could have an adverse effect on earnings because of the need to obtain
regulatory approval to recover such increased expenses.
ITEM
7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
IDACORP and IPC are exposed
to market risks, including changes in interest rates, changes in commodity
prices, credit risk and equity price risk. The following discussion summarizes
these risks and the financial instruments, derivative instruments and
derivative commodity instruments sensitive to changes in interest rates,
commodity prices and equity prices that were held at December 31, 2007.
Interest Rate Risk
IDACORP and IPC manage interest
expense and short- and long-term liquidity though a combination of fixed rate
and variable rate debt. Generally, the amount of each type of debt is managed
through market issuance, but interest rate swap and cap agreements with highly
rated financial institutions may be used to achieve the desired
combination.
Variable Rate Debt: As of December 31, 2007, IDACORP and IPC had $325
million and $374 million, respectively, in net floating rate debt. Assuming no
change in financial structure for either company, if variable interest rates
were one percentage point higher than the rates in effect on December 31, 2007,
interest rate expense would increase and pre-tax earnings would decrease by
approximately $3.2 million for IDACORP and $3.7 million for IPC.
Fixed Rate Debt: As of December 31, 2007, IDACORP and IPC had
outstanding fixed rate debt of $981 million and $956 million, respectively, and
the fair market value of this debt was $972 million and $946 million,
respectively. These instruments are fixed rate and, therefore, do not expose
the companies to a loss in earnings due to changes in market interest rates.
However, the fair value of these instruments would increase by approximately
$96 million for IDACORP and $95 million for IPC if interest rates were to
decline by one percentage point from their December 31, 2007 levels.
Commodity Price Risk
Utility: IPC's exposure to changes
in commodity price is related to its ongoing utility operations producing
electricity to meet the demand of its retail electric customers. The weather
is a major uncontrollable factor affecting the local and regional demand for
electricity and the availability and price of production. The objective of IPC's
energy purchase and sale activity is to meet the demand of retail electric
customers, maintain appropriate physical reserves to ensure reliability, and make
economic use of temporary surpluses that may develop.
IPC's exposure to commodity
price risk is largely offset by the previously discussed PCA mechanism. IPC
has adopted a risk management program designed to reduce exposure to power
supply cost-related uncertainty, further mitigating commodity price risk. This
program has been reviewed and accepted by the IPUC. IPC's Energy Risk
Management Policy (the Policy) describes a collaborative process with customers
and regulators via a committee called the Customer Advisory Group (CAG). The
Risk Management Committee (RMC), comprised of selected IPC officers and other
senior staff, oversees the risk management program. The RMC is responsible for
communicating the status of risk management activities to the IDACORP Board of
Directors, and to the CAG.
The Policy requires
monitoring monthly volumetric electricity position and total dollar (net power
supply cost) exposure on a rolling 18-month forward view. The Power Supply
business unit produces and evaluates projections of the operating plan and
orders risk mitigating actions dictated by the limits stated in the Policy.
The RMC evaluates the actions initiated by Power Supply for consistency and
compliance with the Policy. IPC representatives meet with the CAG at least
annually to assess effectiveness of the limits. Changes to the limits can be
endorsed by the CAG and referred to the Board of Directors for approval. The
primary tools for risk mitigation are physical forward power transactions and
fueling alternatives for utility-owned generation resources.
Credit Risk
Utility: IPC is subject to credit
risk based on its activity with market counterparties. IPC is exposed to this
risk to the extent that a counterparty may fail to fulfill a contractual obligation
to provide energy, purchase energy or complete financial settlement for market
activities. IPC mitigates this exposure by actively establishing credit
limits, measuring, monitoring, reporting, using appropriate contractual
arrangements and transferring of credit risk through the use of financial
guarantees, cash or letters of credit. A current list of acceptable
counterparties and credit limits is maintained.
Equity Price Risk
IDACORP and IPC are exposed to price
fluctuations in equity markets, primarily through their pension plan assets, a
mine reclamation trust fund owned by an equity-method investment of IPC and
other equity investments at IPC. A hypothetical ten percent decrease in equity
prices would result in an approximate $2 million decrease in the fair value of
financial instruments that are classified as available-for-sale securities.
ITEM 8. FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL
STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
PAGE |
||
Consolidated Financial Statements: |
||
IDACORP, Inc. |
||
Consolidated Statements of Income for the Years Ended December 31, 2007, 2006 and 2005 |
67 |
|
Consolidated Balance Sheets as of December 31, 2007 and 2006 |
68-69 |
|
Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006 and 2005 |
70 |
|
Consolidated Statements of Shareholders' Equity for the Years Ended December 31, 2007, 2006 |
||
and 2005 |
71 |
|
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2007, |
||
2006 and 2005 |
72 |
|
|
||
Idaho Power Company |
||
Consolidated Statements of Income for the Years Ended December 31, 2007, 2006 and 2005 |
73 |
|
Consolidated Balance Sheets as of December 31, 2007 and 2006 |
74-75 |
|
Consolidated Statements of Capitalization as of December 31, 2007 and 2006 |
76 |
|
Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006 and 2005 |
77 |
|
Consolidated Statements of Retained Earnings for the Years Ended December 31, 2007, 2006 |
||
and 2005 |
78 |
|
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2007, |
||
2006 and 2005 |
78 |
|
79-116 |
||
117-118 |
||
|
||
Supplemental Financial Information and Consolidated Financial Statement Schedules |
||
119 |
||
Financial Statement Schedules for the Years Ended December 31, 2007, 2006 and 2005: |
||
Schedule I - Condensed Financial Information of Registrant-IDACORP, Inc. |
136-137 |
|
Schedule II-Consolidated Valuation and Qualifying Accounts-IDACORP, Inc. |
138 |
|
Schedule II-Consolidated Valuation and Qualifying Accounts-Idaho Power Company |
139 |
|
IDACORP, Inc.
Consolidated Statements of Income
|
Year Ended December 31, |
|||||
|
2007 |
2006 |
2005 |
|||
(thousands of dollars except for per |
||||||
Operating Revenues: |
share amounts) |
|||||
Electric utility: |
||||||
General business |
$ |
668,303 |
$ |
636,375 |
$ |
667,270 |
Off-system sales |
154,948 |
260,717 |
142,794 |
|||
Other revenues |
52,150 |
23,381 |
27,619 |
|||
Total electric utility revenues |
875,401 |
920,473 |
837,683 |
|||
Other |
3,993 |
5,818 |
5,181 |
|||
Total operating revenues |
879,394 |
926,291 |
842,864 |
|||
Operating Expenses: |
||||||
Electric utility: |
||||||
Purchased power |
289,484 |
283,440 |
222,310 |
|||
Fuel expense |
134,322 |
115,018 |
103,164 |
|||
Power cost adjustment |
(121,131) |
(29,526) |
(2,995) |
|||
Other operations and maintenance |
286,510 |
264,810 |
242,381 |
|||
Demand-side management |
13,487 |
- |
- |
|||
Gain on sale of emission allowances |
(2,754) |
(8,257) |
(1,172) |
|||
Depreciation |
103,072 |
99,824 |
101,485 |
|||
Taxes other than income taxes |
17,634 |
18,661 |
20,856 |
|||
Total electric utility expenses |
720,624 |
743,970 |
686,029 |
|||
Other expense |
6,692 |
12,617 |
2,182 |
|||
Total operating expenses |
727,316 |
756,587 |
688,211 |
|||
Operating Income (Loss): |
||||||
Electric utility |
154,777 |
176,503 |
151,654 |
|||
Other |
(2,699) |
(6,799) |
2,999 |
|||
Total operating income |
152,078 |
169,704 |
154,653 |
|||
Other Income |
20,524 |
18,195 |
17,121 |
|||
Losses of Unconsolidated Equity-Method Investments |
(4,824) |
(2,913) |
(713) |
|||
Other Expense |
8,434 |
8,559 |
8,006 |
|||
Interest Expense: |
||||||
Interest on long-term debt |
59,961 |
56,402 |
56,930 |
|||
Other interest |
3,380 |
4,573 |
2,799 |
|||
Total interest expense |
63,341 |
60,975 |
59,729 |
|||
Income Before Income Taxes |
96,003 |
115,452 |
103,326 |
|||
Income Tax Expense |
13,731 |
15,377 |
17,610 |
|||
Income from Continuing Operations |
82,272 |
100,075 |
85,716 |
|||
Income (Losses) from Discontinued Operations, net of tax |
67 |
7,328 |
(22,055) |
|||
Net Income |
$ |
82,339 |
$ |
107,403 |
$ |
63,661 |
Weighted Average Common Shares Outstanding - Basic (000's) |
44,151 |
42,713 |
42,279 |
|||
Weighted Average Common Shares Outstanding - Diluted (000's) |
44,291 |
42,874 |
42,362 |
|||
Earnings Per Share of Common Stock: |
||||||
Earnings per share from Continuing Operations-Basic |
$ |
1.86 |
$ |
2.34 |
$ |
2.03 |
Earnings (loss) per share from Discontinued Operations-Basic |
- |
0.17 |
(0.52) |
|||
Earnings Per Share of Common Stock-Basic |
$ |
1.86 |
$ |
2.51 |
$ |
1.51 |
Earnings per share from Continuing Operations-Diluted |
$ |
1.86 |
$ |
2.34 |
$ |
2.02 |
Earnings (loss) per share from Discontinued Operations-Diluted |
- |
0.17 |
(0.52) |
|||
Earnings Per Share of Common Stock-Diluted |
$ |
1.86 |
$ |
2.51 |
$ |
1.50 |
Dividends Paid Per Share of Common Stock |
$ |
1.20 |
$ |
1.20 |
$ |
1.20 |
The accompanying notes are an integral part of these statements. |
IDACORP, Inc.
|
December 31, |
|||
|
2007 |
2006 |
||
Assets |
(thousands of dollars) |
|||
Current Assets: |
||||
Cash and cash equivalents |
$ |
7,966 |
$ |
9,892 |
Receivables: |
||||
Customer |
69,160 |
62,131 |
||
Allowance for uncollectible accounts |
(7,505) |
(7,168) |
||
Employee notes |
2,128 |
2,569 |
||
Other |
10,957 |
11,855 |
||
Energy marketing assets |
- |
12,069 |
||
Accrued unbilled revenues |
36,314 |
31,365 |
||
Materials and supplies (at average cost) |
43,270 |
39,079 |
||
Fuel stock (at average cost) |
17,268 |
15,174 |
||
Prepayments |
9,371 |
9,308 |
||
Deferred income taxes |
25,672 |
28,035 |
||
Refundable income tax deposit |
46,083 |
44,903 |
||
Other |
6,023 |
3,993 |
||
Assets held for sale |
- |
3,326 |
||
Total current assets |
266,707 |
266,531 |
||
Investments |
201,085 |
202,825 |
||
Property, Plant and Equipment: |
||||
Utility plant in service |
3,796,339 |
3,583,694 |
||
Accumulated provision for depreciation |
(1,468,832) |
(1,406,210) |
||
Utility plant in service - net |
2,327,507 |
2,177,484 |
||
Construction work in progress |
257,590 |
210,094 |
||
Utility plant held for future use |
3,366 |
2,810 |
||
Other property, net of accumulated depreciation |
28,089 |
28,692 |
||
Property, plant and equipment - net |
2,616,552 |
2,419,080 |
||
Other Assets: |
||||
American Falls and Milner water rights |
29,501 |
30,543 |
||
Company-owned life insurance |
30,842 |
34,055 |
||
Regulatory assets |
449,668 |
423,548 |
||
Long-term receivables (net of allowance of $1,878) |
3,583 |
3,802 |
||
Employee notes |
2,325 |
2,411 |
||
Other |
53,045 |
41,259 |
||
Assets held for sale |
- |
21,076 |
||
Total other assets |
568,964 |
556,694 |
||
Total |
$ |
3,653,308 |
$ |
3,445,130 |
The accompanying notes are an integral part of these statements. |
IDACORP, Inc.
Consolidated Balance Sheets
|
December 31, |
|||
|
2007 |
2006 |
||
Liabilities and Shareholders' Equity |
(thousands of dollars) |
|||
|
||||
Current Liabilities: |
||||
Current maturities of long-term debt |
$ |
11,456 |
$ |
95,125 |
Notes payable |
186,445 |
129,000 |
||
Accounts payable |
85,116 |
86,440 |
||
Energy marketing liabilities |
- |
13,532 |
||
Taxes accrued |
8,492 |
47,402 |
||
Interest accrued |
18,913 |
12,657 |
||
Uncertain tax positions |
26,764 |
- |
||
Other |
38,129 |
23,572 |
||
Liabilities held for sale |
- |
2,606 |
||
Total current liabilities |
375,315 |
410,334 |
||
Other Liabilities: |
||||
Deferred income taxes |
466,182 |
498,512 |
||
Regulatory liabilities |
274,204 |
294,844 |
||
Other |
173,412 |
179,836 |
||
Liabilities held for sale |
- |
8,773 |
||
Total other liabilities |
913,798 |
981,965 |
||
Long-Term Debt |
1,156,880 |
928,648 |
||
|
||||
Commitments and Contingencies (Note 7) |
||||
|
||||
Shareholders' Equity: |
||||
Common stock, no par value (shares authorized 120,000,000; |
||||
45,063,107 and 43,905,458 shares issued, respectively) |
675,774 |
638,799 |
||
Retained earnings |
537,699 |
493,363 |
||
Accumulated other comprehensive loss |
(6,156) |
(5,737) |
||
Treasury stock (380 and 71,570 shares at cost, respectively) |
(2) |
(2,242) |
||
Total shareholders' equity |
1,207,315 |
1,124,183 |
||
Total |
$ |
3,653,308 |
$ |
3,445,130 |
The accompanying notes are an integral part of these statements. |
IDACORP,
Inc.
Consolidated Statements of Cash Flows
Year Ended December 31, |
||||||||||||
2007 |
2006 |
2005 |
||||||||||
Operating Activities: |
(thousands of dollars) |
|||||||||||
Net income |
$ |
82,339 |
$ |
107,403 |
$ |
63,661 |
||||||
Adjustments to reconcile net income to net cash provided by |
||||||||||||
operating activities: |
||||||||||||
Depreciation and amortization |
120,368 |
122,641 |
124,124 |
|||||||||
Deferred income taxes and investment tax credits |
11,026 |
(17,332) |
(31,769) |
|||||||||
Changes in regulatory assets and liabilities |
(128,089) |
(17,133) |
7,275 |
|||||||||
Non-cash pension expense |
6,868 |
- |
- |
|||||||||
Undistributed earnings of subsidiaries |
(6,273) |
(9,553) |
(16,762) |
|||||||||
Gain on sale of assets |
(4,758) |
(25,658) |
(2,128) |
|||||||||
Impairment of goodwill |
- |
- |
10,270 |
|||||||||
Impairment of long-lived asset |
- |
2,047 |
- |
|||||||||
Other non-cash adjustments to net income |
(2,915) |
(3,395) |
(15,073) |
|||||||||
Excess tax benefit from share-based payment arrangements |
(68) |
(1,411) |
- |
|||||||||
Change in: |
||||||||||||
Accounts receivable and prepayments |
(10,284) |
24,304 |
(6,436) |
|||||||||
Accounts payable and other accrued liabilities |
2,206 |
6,725 |
1,821 |
|||||||||
Taxes accrued |
(9,466) |
(24,099) |
26,412 |
|||||||||
Other current assets |
(11,159) |
(4,829) |
(14,360) |
|||||||||
Other current liabilities |
15,551 |
(3,465) |
794 |
|||||||||
Other assets |
2,157 |
3,334 |
(514) |
|||||||||
Other liabilities |
13,098 |
10,199 |
14,181 |
|||||||||
Net cash provided by operating activities |
80,601 |
169,778 |
161,496 |
|||||||||
Investing Activities: |
||||||||||||
Additions to property, plant and equipment |
(287,751) |
(225,048) |
(193,314) |
|||||||||
Proceeds from the sale of ITI |
- |
21,469 |
- |
|||||||||
Proceeds from the sale of IDACOMM |
7,283 |
- |
- |
|||||||||
Investments in affordable housing |
348 |
(5,059) |
(4,992) |
|||||||||
Proceeds from the sale of emission allowances |
19,846 |
11,323 |
70,757 |
|||||||||
Investments in unconsolidated affiliates |
(8,535) |
(16,030) |
- |
|||||||||
Purchase of available-for-sale securities |
(24,349) |
(17,979) |
(85,334) |
|||||||||
Proceeds from the sale of available-for-sale securities |
26,110 |
20,778 |
120,026 |
|||||||||
Purchase of held-to-maturity securities |
(3,116) |
(2,730) |
(2,181) |
|||||||||
Maturity of held-to-maturity securities |
3,317 |
4,647 |
2,840 |
|||||||||
Refundable deposit for tax related liabilities |
- |
(44,903) |
- |
|||||||||
Other assets |
(263) |
492 |
3,248 |
|||||||||
Net cash used in investing activities |
(267,110) |
(253,040) |
(88,950) |
|||||||||
Financing Activities: |
||||||||||||
Issuance of long-term debt |
240,000 |
116,300 |
64,992 |
|||||||||
Retirement of long-term debt |
(95,033) |
(132,642) |
(83,067) |
|||||||||
Dividends on common stock |
(53,012) |
(51,272) |
(50,690) |
|||||||||
Net change in short-term borrowings |
57,445 |
68,900 |
23,830 |
|||||||||
Issuance of common stock |
37,181 |
41,465 |
6,296 |
|||||||||
Acquisition of treasury stock |
(346) |
(213) |
- |
|||||||||
Excess tax benefit from share-based payment arrangements |
68 |
1,411 |
- |
|||||||||
Other assets |
(337) |
(3,058) |
(4,486) |
|||||||||
Other |
(1,383) |
(93) |
(468) |
|||||||||
Net cash provided by (used in) financing activities |
184,583 |
40,798 |
(43,593) |
|||||||||
Net increase (decrease) in cash and cash equivalents |
(1,926) |
(42,464) |
28,953 |
|||||||||
Cash and cash equivalents at beginning of year |
9,892 |
52,356 |
23,403 |
|||||||||
Cash and cash equivalents at end of year |
$ |
7,966 |
$ |
9,892 |
$ |
52,356 |
||||||
Supplemental Disclosure of Cash Flow Information: |
||||||||||||
Cash paid during the year for: |
||||||||||||
Income taxes |
$ |
3,021 |
$ |
54,522 |
$ |
18,937 |
||||||
Interest (net of amount capitalized) |
$ |
62,031 |
$ |
60,353 |
$ |
57,466 |
||||||
Non-cash investing activities |
||||||||||||
Additions to property, plant and equipment in accounts payable |
$ |
13,210 |
$ |
8,299 |
$ |
8,634 |
||||||
The accompanying notes are an integral part of these statements. |
||||||||||||
IDACORP, Inc.
Consolidated Statements of Shareholders' Equity
|
|
|
Accumulated |
|
|||||||||
|
|
|
|
Other |
|
||||||||
|
|
|
Comprehensive |
|
|||||||||
Common Stock |
Retained |
Income |
Treasury Stock |
Total |
|
||||||||
Shares |
Amount |
Earnings |
(Loss) |
Shares |
Amount |
Amount |
|
||||||
(thousands) |
|
||||||||||||
|
|||||||||||||
Balance at January 1, 2005 |
42,374 |
$ |
589,440 |
$ |
424,312 |
$ |
(888) |
157 |
$ |
(4,578) |
$ |
1,008,286 |
|
|
|||||||||||||
Net Income |
- |
- |
63,661 |
- |
- |
- |
63,661 |
|
|||||
Common stock dividends ($1.20 per share) |
- |
- |
(50,690) |
- |
- |
- |
(50,690) |
|
|||||
Issued |
282 |
8,204 |
- |
- |
(14) |
431 |
8,635 |
|
|||||
Acquired |
- |
- |
- |
- |
75 |
(2,268) |
(2,268) |
|
|||||
Other |
- |
1,062 |
1 |
- |
21 |
(899) |
164 |
|
|||||
Unrealized loss on securities (net of tax) |
- |
- |
- |
(1,812) |
- |
- |
(1,812) |
|
|||||
Minimum pension liability adjustment (net of tax) |
- |
- |
- |
(725) |
- |
- |
(725) |
|
|||||
|
|||||||||||||
Balance at December 31, 2005 |
42,656 |
598,706 |
437,284 |
(3,425) |
239 |
(7,314) |
1,025,251 |
|
|||||
|
|||||||||||||
Net Income |
- |
- |
107,403 |
- |
- |
- |
107,403 |
|
|||||
Common stock dividends ($1.20 per share) |
- |
- |
(51,323) |
- |
- |
- |
(51,323) |
|
|||||
Issued |
1,188 |
41,465 |
- |
- |
(11) |
348 |
41,813 |
|
|||||
Acquired |
- |
- |
- |
- |
6 |
(213) |
(213) |
|
|||||
Other |
61 |
(1,372) |
(1) |
- |
(162) |
4,937 |
3,564 |
|
|||||
Unrealized loss on securities (net of tax) |
- |
- |
- |
(1,414) |
- |
- |
(1,414) |
|
|||||
Minimum pension liability adjustment (net of tax) |
- |
- |
- |
2,118 |
- |
- |
2,118 |
|
|||||
Adjustment upon adoption of SFAS 158 (net of tax) |
- |
- |
- |
(3,016) |
- |
- |
(3,016) |
|
|||||
|
|||||||||||||
Balance at December 31, 2006 |
43,905 |
638,799 |
493,363 |
(5,737) |
72 |
(2,242) |
1,124,183 |
|
|||||
|
|||||||||||||
Net Income |
- |
- |
82,339 |
- |
- |
- |
82,339 |
|
|||||
Common stock dividends ($1.20 per share) |
- |
- |
(53,138) |
- |
- |
- |
(53,138) |
|
|||||
Issued |
1,142 |
37,181 |
- |
- |
(12) |
330 |
37,511 |
|
|||||
Acquired |
- |
- |
- |
- |
10 |
(346) |
(346) |
|
|||||
Other |
16 |
(206) |
(1) |
- |
(70) |
2,256 |
2,049 |
|
|||||
Unrealized loss on securities (net of tax) |
- |
- |
- |
(743) |
- |
- |
(743) |
|
|||||
Unfunded pension liability adjustment (net of tax) |
- |
- |
- |
324 |
- |
- |
324 |
|
|||||
Adjustment upon adoption of FIN 48 |
- |
- |
15,136 |
- |
- |
- |
15,136 |
|
|||||
|
|||||||||||||
Balance at December 31, 2007 |
45,063 |
$ |
675,774 |
$ |
537,699 |
$ |
(6,156) |
- |
$ |
(2) |
$ |
1,207,315 |
|
|
|||||||||||||
The accompanying notes are an integral part of these statements. |
IDACORP, Inc.
Consolidated Statements of Comprehensive Income
Year Ended December 31, |
||||||
2007 |
2006 |
2005 |
||||
(thousands of dollars) |
||||||
Net Income |
$ |
82,339 |
$ |
107,403 |
$ |
63,661 |
Other Comprehensive Income (Loss): |
||||||
Unrealized gains (losses) on securities: |
||||||
Unrealized holding gains (losses) arising during the year, |
||||||
net of tax of $114, $1,471 and ($96) |
179 |
2,355 |
(457) |
|||
Reclassification adjustment for gains included |
||||||
in net income, net of tax of ($592), ($2,250) and ($870) |
(922) |
(3,769) |
(1,355) |
|||
Net unrealized losses |
(743) |
(1,414) |
(1,812) |
|||
Unfunded pension liability adjustment, net of tax |
||||||
of $208, $1,359 and ($465) |
324 |
2,118 |
(725) |
|||
Total Comprehensive Income |
$ |
81,920 |
$ |
108,107 |
$ |
61,124 |
The accompanying notes are an integral part of these statements. |
Idaho Power Company
Consolidated Statements of Income
|
Year Ended December 31, |
|||||
|
2007 |
2006 |
2005 |
|||
|
(thousands of dollars) |
|||||
Operating Revenues: |
||||||
General business |
$ |
668,303 |
$ |
636,375 |
$ |
667,270 |
Off-system sales |
154,948 |
260,717 |
142,794 |
|||
Other revenues |
52,150 |
23,381 |
27,619 |
|||
Total operating revenues |
875,401 |
920,473 |
837,683 |
|||
|
||||||
Operating Expenses: |
||||||
Operation: |
||||||
Purchased power |
289,484 |
283,440 |
222,310 |
|||
Fuel expense |
134,322 |
115,018 |
103,164 |
|||
Power cost adjustment |
(121,131) |
(29,526) |
(2,995) |
|||
Other |
218,347 |
200,090 |
182,842 |
|||
Demand-side management |
13,487 |
- |
- |
|||
Gain on sale of emission allowances |
(2,754) |
(8,257) |
(1,172) |
|||
Maintenance |
68,163 |
64,720 |
59,539 |
|||
Depreciation |
103,072 |
99,824 |
101,485 |
|||
Taxes other than income taxes |
17,634 |
18,661 |
20,856 |
|||
Total operating expenses |
720,624 |
743,970 |
686,029 |
|||
Income from Operations |
154,777 |
176,503 |
151,654 |
|||
|
||||||
Other Income (Expense): |