UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q
(Mark One)
X |
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES |
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EXCHANGE ACT OF 1934 |
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For the quarterly period ended September 30, 2009 |
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OR |
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES |
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EXCHANGE ACT OF 1934 |
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For the transition period from __________ to __________ |
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Exact name of registrants as specified |
I.R.S. Employer |
|
Commission File |
in their charters, address of principal |
Identification |
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Number |
executive offices, zip code and telephone number |
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, www.idahopower.com |
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None |
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Former name, former address and former fiscal year, if changed since last report. |
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Indicate
by check mark whether the registrants (1) have filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrants were
required to file such reports), and (2) have been subject to such filing
requirements for the past 90 days. Yes X No
___
Indicate by check mark whether
the registrants have submitted electronically and posted on their corporate Web
sites, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for
such shorter period that the registrants were required to submit and post such
files). Yes ___ No ___
Indicate by check mark whether
the registrants are large accelerated filers, accelerated filers, non-accelerated
filers, or smaller reporting companies. See the definitions of large
accelerated filer, accelerated filer and smaller reporting company in Rule
12b-2 of the Exchange Act (check one):
IDACORP, Inc.: |
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Large accelerated filer |
X |
Accelerated filer |
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Non-accelerated filer |
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Smaller reporting company |
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Idaho Power Company: |
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Large accelerated filer |
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Accelerated filer |
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Non-accelerated filer |
X |
Smaller reporting company |
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Indicate by check mark whether
the registrants are shell companies (as defined in Rule 12b-2 of the Exchange
Act).
Yes ___ No X
Number of shares of Common Stock outstanding as of September 30, 2009: |
|
IDACORP, Inc.: |
47,650,036 |
Idaho Power Company: |
39,150,812, all held by IDACORP, Inc. |
This combined Form 10-Q
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
representations as to the information relating to IDACORP, Inc.s other
operations.
Idaho Power Company meets the
conditions set forth in General Instructions H(1)(a) and (b) of Form 10-Q and
is therefore filing this Form with the reduced disclosure format.
COMMONLY USED TERMS
AFUDC |
- |
Allowance for Funds Used During Construction |
APCU |
- |
Annual Power Cost Update |
ASC |
- |
Accounting Standards Codification |
Cal ISO |
- |
California Independent System Operator |
CalPX |
- |
California Power Exchange |
CAMP |
- |
Comprehensive Aquifer Management Plan |
CO2 |
- |
Carbon Dioxide |
EIS |
- |
Environmental impact statement |
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 Ratings, Inc. |
GAAP |
- |
Generally Accepted Accounting Principles in the United States of America |
HCC |
- |
Hells Canyon Complex |
Ida-West |
- |
Ida-West Energy, a subsidiary of IDACORP, Inc. |
IDWR |
- |
Idaho Department of Water Resources |
IE |
- |
IDACORP Energy, a subsidiary of IDACORP, Inc. |
IERCO |
- |
Idaho Energy Resources Co., a subsidiary of Idaho Power Company |
IFS |
- |
IDACORP Financial Services, a subsidiary of IDACORP, Inc. |
IPC |
- |
Idaho Power Company, a subsidiary of IDACORP, Inc. |
IPUC |
- |
Idaho Public Utilities Commission |
IRP |
- |
Integrated Resource Plan |
IWRB |
- |
Idaho Water Resource Board |
kW |
- |
Kilowatt |
LGAR |
- |
Load growth adjustment rate |
maf |
- |
Million acre feet |
MD&A |
- |
Managements Discussion and Analysis of Financial Condition and Results of Operations |
Moodys |
- |
Moodys Investors Service |
MW |
- |
Megawatt |
MWh |
- |
Megawatt-hour |
NOx |
- |
Nitrogen Oxide |
NWRFC |
- |
National Weather Service Northwest River Forecast Center |
O&M |
- |
Operations and Maintenance |
OATT |
- |
Open Access Transmission Tariff |
OPUC |
- |
Oregon Public Utility Commission |
PCA |
- |
Power Cost Adjustment |
PCAM |
- |
Power Cost Adjustment Mechanism |
PURPA |
- |
Public Utility Regulatory Policies Act of 1978 |
REC |
- |
Renewable Energy Certificate |
RH BART |
- |
Regional Haze Best Available Retrofit Technology |
RFP |
- |
Request for Proposal |
S&P |
- |
Standard & Poors Ratings Services |
SFAS |
- |
Statement of Financial Accounting Standards |
- |
Sulfur Dioxide |
|
SRBA |
- |
Snake River Basin Adjudication |
Valmy |
- |
North Valmy Steam Electric Generating Plant |
VIEs |
- |
Variable Interest Entities |
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TABLE OF CONTENTS
Part I. Financial Information: |
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Item 1. Financial Statements (unaudited) |
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IDACORP, Inc.: |
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Condensed Consolidated Statements of Income |
1 |
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Condensed Consolidated Balance Sheets |
2-3 |
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Condensed Consolidated Statements of Cash Flows |
4 |
|
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Condensed Consolidated Statements of Comprehensive Income |
5 |
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Idaho Power Company: |
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|
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Condensed Consolidated Statements of Income |
6 |
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Condensed Consolidated Balance Sheets |
7-8 |
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Condensed Consolidated Statements of Capitalization |
9 |
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Condensed Consolidated Statements of Cash Flows |
10 |
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Condensed Consolidated Statements of Comprehensive Income |
11 |
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Notes to the Condensed Consolidated Financial Statements |
12-41 |
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Reports of Independent Registered Public Accounting Firm |
42-43 |
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Item 2. Managements Discussion and Analysis of Financial Condition and Results of |
44-86 |
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Operations |
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Item 3. Quantitative and Qualitative Disclosures About Market Risk |
86-87 |
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Item 4. Controls and Procedures |
87-88 |
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Part II. Other Information: |
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Item 1. Legal Proceedings |
88 |
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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds |
88-89 |
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Item 6. Exhibits |
89-97 |
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Signatures |
98 |
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Exhibit Index |
99 |
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SAFE HARBOR STATEMENT
This Form 10-Q 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-Q at Part I, Item 2, Managements Discussion and Analysis of
Financial Condition and Results of Operations Forward-Looking Information.
Forward-looking statements are all statements other than statements of
historical fact, including without limitation those that are identified by the
use of the words anticipates, believes, estimates, expects, intends, plans,
predicts, projects, may result, may continue, and similar expressions.
PART I FINANCIAL
INFORMATION
Item 1. Financial Statements
IDACORP, Inc.
Condensed Consolidated Statements of Income
(unaudited)
Three months ended |
Nine months ended |
|||||||||
September 30, |
September 30, |
|||||||||
|
2009 |
2008 |
2009 |
2008 |
||||||
(thousands of dollars except for per share amounts) |
||||||||||
Operating Revenues: |
||||||||||
Electric utility: |
||||||||||
General business |
$ |
277,676 |
$ |
246,639 |
$ |
663,818 |
$ |
602,700 |
||
Off-system sales |
23,691 |
34,637 |
78,888 |
93,640 |
||||||
Other revenues |
21,761 |
16,831 |
50,969 |
43,508 |
||||||
Total electric utility revenues |
323,128 |
298,107 |
793,675 |
739,848 |
||||||
Other |
1,381 |
1,609 |
3,042 |
3,534 |
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Total operating revenues |
324,509 |
299,716 |
796,717 |
743,382 |
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Operating Expenses: |
||||||||||
Electric utility: |
||||||||||
Purchased power |
73,483 |
79,513 |
131,370 |
174,900 |
||||||
Fuel expense |
49,530 |
46,467 |
113,138 |
112,385 |
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Third-party transmission expense |
2,791 |
3,738 |
5,473 |
6,138 |
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Power cost adjustment |
1,614 |
(20,105) |
44,236 |
(38,678) |
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Other operations and maintenance |
68,970 |
71,040 |
212,392 |
213,183 |
||||||
Energy efficiency programs |
12,202 |
5,956 |
24,933 |
13,249 |
||||||
Gain on sale of emission allowances |
- |
(158) |
(289) |
(504) |
||||||
Depreciation |
28,837 |
25,717 |
81,631 |
78,084 |
||||||
Taxes other than income taxes |
5,600 |
4,827 |
15,749 |
14,431 |
||||||
Total electric utility expenses |
243,027 |
216,995 |
628,633 |
573,188 |
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Other expense |
1,879 |
1,144 |
3,374 |
3,331 |
||||||
Total operating expenses |
244,906 |
218,139 |
632,007 |
576,519 |
||||||
Operating Income (Loss): |
||||||||||
Electric utility |
80,101 |
81,112 |
165,042 |
166,660 |
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Other |
(498) |
465 |
(332) |
203 |
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Total operating income |
79,603 |
81,577 |
164,710 |
166,863 |
||||||
Other Income , net |
4,569 |
2,038 |
15,548 |
10,081 |
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Income (Losses) of Unconsolidated Equity-Method |
||||||||||
Investments |
2,866 |
2,642 |
648 |
(4,672) |
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Interest Expense: |
||||||||||
Interest on long-term debt |
18,840 |
17,226 |
53,762 |
49,847 |
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Other interest expense, net of AFUDC |
(239) |
1,310 |
481 |
3,219 |
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Total interest expense |
18,601 |
18,536 |
54,243 |
53,066 |
||||||
Income Before Income Taxes |
68,437 |
67,721 |
126,663 |
119,206 |
||||||
Income Tax Expense |
13,730 |
15,809 |
25,700 |
28,335 |
||||||
Net Income |
54,707 |
51,912 |
100,963 |
90,871 |
||||||
Adjustment for (income) loss attributable to |
||||||||||
|
noncontrolling interests |
(229) |
(173) |
(126) |
98 |
|||||
Net Income Attributable to IDACORP, Inc. |
$ |
54,478 |
$ |
51,739 |
$ |
100,837 |
$ |
90,969 |
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Weighted Average Common Shares Outstanding - Basic (000s) |
47,068 |
45,126 |
46,953 |
45,044 |
||||||
Weighted Average Common Shares Outstanding - Diluted (000s) |
47,141 |
45,246 |
46,999 |
45,149 |
||||||
Earnings Per Share of Common Stock: |
||||||||||
Earnings Attributable to IDACORP Inc.-Basic |
$ |
1.16 |
$ |
1.15 |
$ |
2.15 |
$ |
2.02 |
||
Earnings Attributable to IDACORP Inc.-Diluted |
$ |
1.16 |
$ |
1.14 |
$ |
2.15 |
$ |
2.02 |
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Dividends Paid Per Share of Common Stock |
$ |
0.30 |
$ |
0.30 |
$ |
0.90 |
$ |
0.90 |
||
The accompanying notes are an integral part of these statements. |
||||||||||
1
IDACORP, Inc.
Condensed Consolidated Balance Sheets
(unaudited)
September 30, |
December 31, |
|||
|
2009 |
2008 |
||
Assets |
(thousands of dollars) |
|||
Current Assets: |
||||
Cash and cash equivalents |
$ |
28,869 |
$ |
8,828 |
Receivables: |
||||
Customer |
83,990 |
64,733 |
||
Allowance for uncollectible accounts |
(1,534) |
(1,724) |
||
Other |
12,242 |
10,439 |
||
Taxes receivable |
- |
18,111 |
||
Accrued unbilled revenues |
49,779 |
43,934 |
||
Materials and supplies (at average cost) |
50,599 |
50,121 |
||
Fuel stock (at average cost) |
22,346 |
16,852 |
||
Prepayments |
11,659 |
10,059 |
||
Deferred income taxes |
14,739 |
37,550 |
||
Other |
3,105 |
7,381 |
||
Total current assets |
275,794 |
266,284 |
||
|
||||
Investments |
197,861 |
198,552 |
||
|
||||
Property, Plant and Equipment: |
||||
Utility plant in service |
4,141,054 |
4,030,134 |
||
Accumulated provision for depreciation |
(1,556,226) |
(1,505,120) |
||
Utility plant in service - net |
2,584,828 |
2,525,014 |
||
Construction work in progress |
236,632 |
207,662 |
||
Utility plant held for future use |
6,549 |
6,318 |
||
Other property, net of accumulated depreciation |
19,134 |
19,171 |
||
Property, plant and equipment - net |
2,847,143 |
2,758,165 |
||
|
||||
Other Assets: |
||||
American Falls and Milner water rights |
24,487 |
26,332 |
||
Company-owned life insurance |
27,029 |
29,482 |
||
Regulatory assets |
701,931 |
696,332 |
||
Long-term receivables (net of allowance of $1,684 and $2,478) |
5,212 |
4,012 |
||
Other |
37,835 |
43,686 |
||
Total other assets |
796,494 |
799,844 |
||
Total |
$ |
4,117,292 |
$ |
4,022,845 |
|
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The accompanying notes are an integral part of these statements. |
2
IDACORP, Inc.
Condensed Consolidated Balance Sheets
(unaudited)
September 30, |
December 31, |
|||
|
2009 |
2008 |
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Liabilities and Shareholders Equity |
(thousands of dollars) |
|||
Current Liabilities: |
||||
Current maturities of long-term debt |
$ |
84,064 |
$ |
86,528 |
Notes payable |
36,780 |
151,250 |
||
Accounts payable |
88,136 |
96,785 |
||
Taxes accrued |
20,531 |
- |
||
Interest accrued |
27,680 |
16,727 |
||
Other |
37,761 |
44,378 |
||
Total current liabilities |
294,952 |
395,668 |
||
|
||||
Other Liabilities: |
||||
Deferred income taxes |
528,953 |
515,719 |
||
Regulatory liabilities |
285,695 |
276,266 |
||
Other |
340,003 |
344,870 |
||
Total other liabilities |
1,154,651 |
1,136,855 |
||
|
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Long-Term Debt |
1,282,900 |
1,183,451 |
||
|
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Commitments and Contingencies |
||||
Shareholders Equity: |
||||
IDACORP, Inc. shareholders equity: |
||||
Common stock, no par value (shares authorized 120,000,000; |
||||
47,679,227 and 46,929,203 shares issued, respectively) |
747,402 |
729,576 |
||
Retained earnings |
640,029 |
581,605 |
||
Accumulated other comprehensive loss |
(6,900) |
(8,707) |
||
Treasury stock (29,191 and 9,022 shares at cost, respectively) |
(53) |
(37) |
||
Total IDACORP, Inc. shareholders equity |
1,380,478 |
1,302,437 |
||
Noncontrolling interest |
4,311 |
4,434 |
||
Total shareholders equity |
1,384,789 |
1,306,871 |
||
Total |
$ |
4,117,292 |
$ |
4,022,845 |
The accompanying notes are an integral part of these statements. |
3
IDACORP, Inc.
Condensed Consolidated Statements of Cash Flows
(unaudited)
Nine months ended |
||||
September 30, |
||||
|
2009 |
2008 |
||
Operating Activities: |
(thousands of dollars) |
|||
Net income |
$ |
100,963 |
$ |
90,871 |
Adjustments to reconcile net income to net cash provided by |
||||
operating activities: |
||||
Depreciation and amortization |
86,485 |
83,898 |
||
Deferred income taxes and investment tax credits |
14,797 |
16,075 |
||
Changes in regulatory assets and liabilities |
37,721 |
(50,081) |
||
Non-cash pension expense |
3,076 |
3,009 |
||
(Earnings) losses of equity method investments |
(648) |
4,672 |
||
Distributions from equity method investments |
9,415 |
850 |
||
Gain on sale of assets |
(417) |
(3,369) |
||
Other non-cash adjustments to net income, net |
(764) |
1,770 |
||
Change in: |
||||
Accounts receivable and prepayments |
(22,065) |
(11,819) |
||
Accounts payable and other accrued liabilities |
(24,636) |
(16,782) |
||
Taxes accrued |
38,812 |
6,244 |
||
Other current assets |
(11,817) |
(17,940) |
||
Other current liabilities |
5,850 |
8,971 |
||
Other assets |
678 |
1,126 |
||
Other liabilities |
(14,924) |
(2,090) |
||
Net cash provided by operating activities |
222,526 |
115,405 |
||
Investing Activities: |
||||
Additions to property, plant and equipment |
(155,591) |
(176,475) |
||
Proceeds from the sale of non-utility assets |
2,250 |
5,753 |
||
Investments in affordable housing |
(6,176) |
(8,486) |
||
Proceeds from the sale of emission allowances |
2,382 |
2,959 |
||
Investments in unconsolidated affiliates |
- |
(3,065) |
||
Proceeds from the sale of investments |
8,956 |
- |
||
Purchase of held-to-maturity securities |
- |
(2,885) |
||
Maturity of held-to-maturity securities |
- |
4,610 |
||
Withdrawal of refundable deposit for tax related liabilities |
- |
20,000 |
||
Other |
683 |
(7,932) |
||
Net cash used in investing activities |
(147,496) |
(165,521) |
||
Financing Activities: |
||||
Increase (decrease) in term loans |
(170,000) |
170,000 |
||
Issuance of long-term debt |
100,000 |
120,000 |
||
Remarketing (purchase) of pollution control revenue bonds |
166,100 |
(166,100) |
||
Retirement of long-term debt |
(9,174) |
(7,630) |
||
Dividends on common stock |
(42,414) |
(40,516) |
||
Net change in short-term borrowings |
(110,570) |
13,570 |
||
Issuance of common stock |
16,738 |
12,550 |
||
Acquisition of treasury stock |
(1,441) |
(304) |
||
Other |
(4,228) |
(1,694) |
||
Net cash (used in) provided by financing activities |
(54,989) |
99,876 |
||
Net increase in cash and cash equivalents |
20,041 |
49,760 |
||
Cash and cash equivalents at beginning of the period |
8,828 |
7,966 |
||
Cash and cash equivalents at end of the period |
$ |
28,869 |
$ |
57,726 |
Supplemental Disclosure of Cash Flow Information: |
||||
Cash paid during the period for: |
||||
Income taxes (refunded) paid |
$ |
(21,356) |
$ |
8,762 |
Interest (net of amount capitalized) |
$ |
41,227 |
$ |
40,933 |
Non-cash investing activities: |
||||
Additions to property, plant and equipment in accounts payable |
$ |
19,990 |
$ |
10,527 |
Investments in affordable housing |
$ |
6,000 |
$ |
- |
The accompanying notes are an integral part of these statements. |
4
IDACORP, Inc.
Condensed Consolidated Statements of Comprehensive Income
(unaudited)
Three months ended |
||||
September 30, |
||||
|
2009 |
2008 |
||
(thousands of dollars) |
||||
Net Income |
$ |
54,707 |
$ |
51,912 |
Other Comprehensive Income (Loss): |
||||
Unrealized gains (losses) on securities: |
||||
Net unrealized holding gains (losses) arising during the period, |
||||
net of tax of $734 and ($791) |
1,143 |
(1,232) |
||
Unfunded pension liability adjustment, net of tax |
||||
of $87 and $67 |
136 |
104 |
||
Total Comprehensive Income |
55,986 |
50,784 |
||
Comprehensive income attributable to noncontrolling interests |
(229) |
(173) |
||
Comprehensive Income attributable to IDACORP, Inc. common shareholders |
$ |
55,757 |
$ |
50,611 |
The accompanying notes are an integral part of these statements. |
IDACORP, Inc.
Condensed Consolidated Statements of Comprehensive Income
(unaudited)
Nine months ended |
||||
September 30, |
||||
|
2009 |
2008 |
||
(thousands of dollars) |
||||
Net Income |
$ |
100,963 |
$ |
90,871 |
Other Comprehensive Income (Loss): |
||||
Unrealized gains (losses) on securities: |
||||
Net unrealized holding gains (losses) arising during the period, |
||||
net of tax of $898 and ($1,679) |
1,399 |
(2,616) |
||
Unfunded pension liability adjustment, net of tax |
||||
of $261 and $200 |
408 |
311 |
||
Total Comprehensive Income |
102,770 |
88,566 |
||
Comprehensive (income) loss attributable to noncontrolling interests |
(126) |
98 |
||
Comprehensive Income attributable to IDACORP, Inc. common shareholders |
$ |
102,644 |
$ |
88,664 |
The accompanying notes are an integral part of these statements. |
5
Idaho Power
Company
Condensed Consolidated Statements of Income
(unaudited)
Three months ended |
Nine months ended |
|||||||
September 30, |
September 30, |
|||||||
|
2009 |
2008 |
2009 |
2008 |
||||
(thousands of dollars) |
||||||||
Operating Revenues: |
||||||||
General business |
$ |
277,676 |
$ |
246,639 |
$ |
663,818 |
$ |
602,700 |
Off-system sales |
23,691 |
34,637 |
78,888 |
93,640 |
||||
Other revenues |
21,761 |
16,831 |
50,969 |
43,508 |
||||
Total operating revenues |
323,128 |
298,107 |
793,675 |
739,848 |
||||
Operating Expenses: |
||||||||
Operation: |
||||||||
Purchased power |
73,483 |
79,513 |
131,370 |
174,900 |
||||
Fuel expense |
49,530 |
46,467 |
113,138 |
112,385 |
||||
Third-party transmission expense |
2,791 |
3,738 |
5,473 |
6,138 |
||||
Power cost adjustment |
1,614 |
(20,105) |
44,236 |
(38,678) |
||||
Other |
52,495 |
54,806 |
159,420 |
162,537 |
||||
Energy efficiency programs |
12,202 |
5,956 |
24,933 |
13,249 |
||||
Gain on sale of emission allowances |
- |
(158) |
(289) |
(504) |
||||
Maintenance |
16,475 |
16,234 |
52,972 |
50,646 |
||||
Depreciation |
28,837 |
25,717 |
81,631 |
78,084 |
||||
Taxes other than income taxes |
5,600 |
4,827 |
15,749 |
14,431 |
||||
Total operating expenses |
243,027 |
216,995 |
628,633 |
573,188 |
||||
Income from Operations |
80,101 |
81,112 |
165,042 |
166,660 |
||||
Other Income: |
||||||||
Allowance for equity funds used during construction |
2,131 |
1,265 |
4,629 |
2,394 |
||||
Earnings of unconsolidated equity-method investments |
4,328 |
4,487 |
6,980 |
2,621 |
||||
Other income, net |
1,717 |
825 |
9,662 |
7,425 |
||||
Total other income |
8,176 |
6,577 |
21,271 |
12,440 |
||||
Interest Charges: |
||||||||
Interest on long-term debt |
18,826 |
16,916 |
53,661 |
48,868 |
||||
Other interest |
1,302 |
2,290 |
4,230 |
6,437 |
||||
Allowance for borrowed funds used during construction |
(1,654) |
(1,549) |
(4,439) |
(4,966) |
||||
Total interest charges |
18,474 |
17,657 |
53,452 |
50,339 |
||||
Income Before Income Taxes |
69,803 |
70,032 |
132,861 |
128,761 |
||||
Income Tax Expense |
18,746 |
22,627 |
36,194 |
42,357 |
||||
Net Income |
$ |
51,057 |
$ |
47,405 |
$ |
96,667 |
$ |
86,404 |
The accompanying notes are an integral part of these statements. |
6
Idaho Power
Company
Condensed Consolidated Balance Sheets
(unaudited)
September 30, |
December 31, |
|||
|
2009 |
2008 |
||
Assets |
(thousands of dollars) |
|||
Electric Plant: |
||||
In service (at original cost) |
$ |
4,141,054 |
$ |
4,030,134 |
Accumulated provision for depreciation |
(1,556,226) |
(1,505,120) |
||
In service - net |
2,584,828 |
2,525,014 |
||
Construction work in progress |
236,632 |
207,662 |
||
Held for future use |
6,549 |
6,318 |
||
Electric plant - net |
2,828,009 |
2,738,994 |
||
|
||||
Investments and Other Property |
108,747 |
106,057 |
||
|
||||
Current Assets: |
||||
Cash and cash equivalents |
20,334 |
3,141 |
||
Receivables: |
||||
Customer |
83,990 |
64,433 |
||
Allowance for uncollectible accounts |
(1,499) |
(1,724) |
||
Other |
10,278 |
7,947 |
||
Taxes receivable |
- |
41,363 |
||
Accrued unbilled revenues |
49,779 |
43,934 |
||
Materials and supplies (at average cost) |
50,599 |
50,121 |
||
Fuel stock (at average cost) |
22,346 |
16,852 |
||
Prepayments |
11,489 |
9,865 |
||
Deferred income taxes |
3,922 |
3,852 |
||
Other |
2,269 |
4,968 |
||
Total current assets |
253,507 |
244,752 |
||
Deferred Debits: |
||||
American Falls and Milner water rights |
24,487 |
26,332 |
||
Company-owned life insurance |
27,029 |
29,482 |
||
Regulatory assets |
701,931 |
696,332 |
||
Other |
37,047 |
42,907 |
||
Total deferred debits |
790,494 |
795,053 |
||
Total |
$ |
3,980,757 |
$ |
3,884,856 |
The accompanying notes are an integral part of these statements. |
7
Idaho Power
Company
Condensed Consolidated Balance Sheets
(unaudited)
September 30, |
December 31, |
|||
|
2009 |
2008 |
||
Capitalization and Liabilities |
(thousands of dollars) |
|||
Capitalization: |
||||
Common stock equity: |
||||
Common stock, $2.50 par value (50,000,000 shares |
||||
authorized; 39,150,812 shares outstanding) |
$ |
97,877 |
$ |
97,877 |
Premium on capital stock |
638,758 |
618,758 |
||
Capital stock expense |
(2,097) |
(2,097) |
||
Retained earnings |
536,155 |
482,047 |
||
Accumulated other comprehensive loss |
(6,900) |
(8,707) |
||
Total common stock equity |
1,263,793 |
1,187,878 |
||
Long-term debt |
1,279,900 |
1,180,691 |
||
Total capitalization |
2,543,693 |
2,368,569 |
||
|
||||
Current Liabilities: |
||||
Long-term debt due within one year |
81,064 |
81,064 |
||
Notes payable |
- |
112,850 |
||
Accounts payable |
85,971 |
96,268 |
||
Notes and accounts payable to related parties |
1,265 |
768 |
||
Taxes accrued |
478 |
- |
||
Interest accrued |
27,680 |
16,675 |
||
Other |
36,928 |
43,274 |
||
Total current liabilities |
233,386 |
350,899 |
||
|
||||
Deferred Credits: |
||||
Deferred income taxes |
580,896 |
547,159 |
||
Regulatory liabilities |
285,695 |
276,266 |
||
Other |
337,087 |
341,963 |
||
Total deferred credits |
1,203,678 |
1,165,388 |
||
|
||||
Commitments and Contingencies |
||||
Total |
$ |
3,980,757 |
$ |
3,884,856 |
The accompanying notes are an integral part of these statements. |
8
Idaho Power
Company
Condensed Consolidated Statements of Capitalization
(unaudited)
September 30, |
December 31, |
|||||
|
2009 |
% |
2008 |
% |
||
(thousands of dollars) |
||||||
Common Stock Equity: |
||||||
Common stock |
$ |
97,877 |
$ |
97,877 |
||
Premium on capital stock |
638,758 |
618,758 |
||||
Capital stock expense |
(2,097) |
(2,097) |
||||
Retained earnings |
536,155 |
482,047 |
||||
Accumulated other comprehensive loss |
(6,900) |
|
(8,707) |
|
||
Total common stock equity |
1,263,793 |
50 |
1,187,878 |
50 |
||
Long-Term Debt: |
||||||
First mortgage bonds: |
||||||
7.20% Series due 2009 |
80,000 |
80,000 |
||||
6.60% Series due 2011 |
120,000 |
120,000 |
||||
4.75% Series due 2012 |
100,000 |
100,000 |
||||
4.25% Series due 2013 |
70,000 |
70,000 |
||||
6.025% Series due 2018 |
120,000 |
120,000 |
||||
6.15% Series due 2019 |
100,000 |
- |
||||
6 % Series due 2032 |
100,000 |
100,000 |
||||
5.50% Series due 2033 |
70,000 |
70,000 |
||||
5.50% Series due 2034 |
50,000 |
50,000 |
||||
5.875% Series due 2034 |
55,000 |
55,000 |
||||
5.30% Series due 2035 |
60,000 |
60,000 |
||||
6.30% Series due 2037 |
140,000 |
140,000 |
||||
6.25% Series due 2037 |
100,000 |
|
100,000 |
|
||
Total first mortgage bonds |
1,165,000 |
|
1,065,000 |
|
||
Amount due within one year |
(80,000) |
|
(80,000) |
|
||
Net first mortgage bonds |
1,085,000 |
|
985,000 |
|
||
Pollution control revenue bonds: |
||||||
5.15% Series due 2024 |
49,800 |
49,800 |
||||
5.25% Series due 2026 |
116,300 |
116,300 |
||||
Variable Rate Series 2000 due 2027 |
4,360 |
4,360 |
||||
Total pollution control revenue bonds |
170,460 |
|
170,460 |
|
||
American Falls bond guarantee |
19,885 |
19,885 |
||||
Milner Dam note guarantee |
8,509 |
9,573 |
||||
Note guarantee due within one year |
(1,064) |
(1,064) |
||||
Unamortized premium/discount - net |
(2,890) |
(3,163) |
||||
Term Loan Credit Facility |
- |
166,100 |
||||
Purchase of pollution control revenue bonds |
- |
|
(166,100) |
|
||
Total long-term debt |
1,279,900 |
50 |
1,180,691 |
50 |
||
Total Capitalization |
$ |
2,543,693 |
100 |
$ |
2,368,569 |
100 |
The accompanying notes are an integral part of these statements. |
9
Idaho Power Company
Condensed
Consolidated Statements of Cash Flows
(unaudited)
Nine months ended |
||||
September 30, |
||||
|
2009 |
2008 |
||
(thousands of dollars) |
||||
Operating Activities: |
||||
Net income |
$ |
96,667 |
$ |
86,404 |
Adjustments to reconcile net income to net cash provided by |
|
|||
operating activities: |
||||
Depreciation and amortization |
85,922 |
83,285 |
||
Deferred income taxes and investment tax credits |
12,419 |
15,173 |
||
Changes in regulatory assets and liabilities |
37,721 |
(50,081) |
||
Non-cash pension expense |
3,076 |
3,009 |
||
Earnings of equity method investments |
(6,980) |
(2,621) |
||
Distributions from equity method investments |
8,340 |
- |
||
Gain on sale of assets |
(442) |
(3,383) |
||
Other non-cash adjustments to net income |
(2,516) |
(1,346) |
||
Change in: |
||||
Accounts receivables and prepayments |
(21,940) |
(12,162) |
||
Accounts payable |
(26,283) |
(16,175) |
||
Taxes accrued |
41,996 |
21,636 |
||
Other current assets |
(11,817) |
(17,939) |
||
Other current liabilities |
6,029 |
8,945 |
||
Other assets |
678 |
1,121 |
||
Other liabilities |
(14,983) |
(1,888) |
||
Net cash provided by operating activities |
207,887 |
113,978 |
||
Investing Activities: |
||||
Additions to utility plant |
(155,591) |
(176,475) |
||
Proceeds from the sale of non-utility assets |
2,250 |
5,690 |
||
Proceeds from sale of emission allowances |
2,382 |
2,959 |
||
Investments in unconsolidated affiliates |
- |
(3,065) |
||
Withdrawal of refundable deposit for tax related liabilities |
- |
20,000 |
||
Other |
648 |
(7,550) |
||
Net cash used in investing activities |
(150,311) |
(158,441) |
||
Financing Activities: |
||||
Increase (decrease) in term loans |
(170,000) |
170,000 |
||
Issuance of long-term debt |
100,000 |
120,000 |
||
Remarketing (purchase) of pollution control revenue bonds |
166,100 |
(166,100) |
||
Retirement of long-term debt |
(1,064) |
(1,064) |
||
Dividends on common stock |
(42,560) |
(40,678) |
||
Net change in short term borrowings |
(108,950) |
(5,222) |
||
Capital contribution from parent |
20,000 |
- |
||
Other |
(3,909) |
(1,631) |
||
Net cash (used in) provided by financing activities |
(40,383) |
75,305 |
||
Net increase in cash and cash equivalents |
17,193 |
30,842 |
||
Cash and cash equivalents at beginning of the period |
3,141 |
5,347 |
||
Cash and cash equivalents at end of the period |
$ |
20,334 |
$ |
36,189 |
Supplemental Disclosure of Cash Flow Information: |
||||
Cash paid during the period for: |
||||
Income taxes (received from) paid to parent |
$ |
(11,668) |
$ |
8,331 |
Interest (net of amount capitalized) |
$ |
40,505 |
$ |
38,300 |
Non-cash investing activities: |
||||
Additions to property, plant and equipment in accounts payable |
$ |
19,990 |
$ |
10,527 |
The accompanying notes are an integral part of these statements. |
10
Idaho Power
Company
Condensed Consolidated Statements of Comprehensive Income
(unaudited)
Three months ended |
||||
September 30, |
||||
|
2009 |
2008 |
||
(thousands of dollars) |
||||
Net Income |
$ |
51,057 |
$ |
47,405 |
Other Comprehensive Income (Loss): |
||||
Unrealized gains (losses) on securities: |
||||
Net unrealized holding gains (losses) arising during the period, |
||||
net of tax of $734 and ($791) |
1,143 |
(1,232) |
||
Unfunded pension liability adjustment, net of tax |
||||
of $87 and $67 |
136 |
104 |
||
Total Comprehensive Income |
$ |
52,336 |
$ |
46,277 |
The accompanying notes are an integral part of these statements. |
Idaho Power
Company
Condensed Consolidated Statements of Comprehensive Income
(unaudited)
Nine months ended |
||||
September 30, |
||||
|
2009 |
2008 |
||
(thousands of dollars) |
||||
Net Income |
$ |
96,667 |
$ |
86,404 |
Other Comprehensive Income (Loss): |
||||
Unrealized gains (losses) on securities: |
||||
Net unrealized holding gains (losses) arising during the period, |
||||
net of tax of $898 and ($1,679) |
1,399 |
(2,616) |
||
Unfunded pension liability adjustment, net of tax |
||||
of $261 and $200 |
408 |
311 |
||
Total Comprehensive Income |
$ |
98,474 |
$ |
84,099 |
The accompanying notes are an integral part of these statements. |
11
IDACORP,
INC. AND IDAHO POWER COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
This Quarterly Report on Form 10-Q
is a combined report of IDACORP, Inc. (IDACORP) and Idaho Power Company (IPC).
These Notes to the Condensed Consolidated Financial Statements apply to both
IDACORP and IPC. However, IPC makes no representation as to the information
relating to IDACORPs other operations.
Nature of Business
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.
IDACORPs other subsidiaries
include:
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.
Principles of Consolidation
IDACORPs and IPCs condensed
consolidated financial statements include the accounts of each company, the
subsidiaries that the companies control, and any variable interest entities
(VIEs) for which the companies are the primary beneficiaries. All significant
intercompany balances have been eliminated in consolidation. Investments in
subsidiaries that the companies do not control and investments in VIEs for
which the companies are not the primary beneficiaries, but have the ability to
exercise significant influence over operating and financial policies, are
accounted for using the equity method of accounting.
The entities that IDACORP and IPC
consolidate consist primarily of the wholly-owned subsidiaries discussed
above. In addition, IDACORP consolidates one VIE, Marysville Hydro Partners
(Marysville), which is a joint venture owned 50 percent by Ida-West, and 50
percent by Environmental Energy Company (EEC). Marysville has approximately
$26 million of assets, primarily a small hydroelectric plant, and approximately
$17 million of intercompany long-term debt, which is eliminated in consolidation.
EEC has borrowed amounts from Ida-West to fund a portion of its required
capital contributions to Marysville. The loans are payable from EECs share of
distributions and are secured by the stock of EEC and EECs interest in
Marysville. Ida-West is the primary beneficiary because the ownership of the
intercompany note and the EEC note results in it absorbing a majority of the
expected losses of the entity. Creditors of Marysville have no recourse to the
general credit of IDACORP, and there are no other arrangements that could
require IDACORP to provide financial support to Marysville or expose IDACORP to
losses.
12
Through IFS and Ida-West, IDACORP
also holds variable interests in VIEs for which it is not the primary
beneficiary. These interests are presented as Investments on IDACORPs
condensed consolidated balance sheets. IFS investments in VIEs are affordable
housing and historic rehabilitation developments in which IFS holds limited
partnership interests ranging from five to 99 percent. These investments were
acquired between 1996 and 2009, and are not consolidated because IFS does not
absorb a majority of the expected losses of these entities, either because of
specific provisions in the partnership agreements or due to not owning a
majority interest. IFSs maximum exposure to loss in these developments is
limited to its net carrying value, which was $79 million at September 30,
2009. Ida-West has 50 percent ownership of three other joint ventures that are
not consolidated because Ida-West does not absorb a majority of the expected
losses. Ida-Wests maximum exposure to loss in these joint ventures is limited
to its net carrying value, which was $11 million at September 30, 2009.
Financial Statements
In the opinion of IDACORP and
IPC, the accompanying unaudited condensed consolidated financial statements
contain all adjustments necessary to present fairly their consolidated
financial positions as of September 30, 2009, and consolidated results of
operations for the three and nine months ended September 30, 2009, and 2008,
and consolidated cash flows for the nine months ended September 30, 2009, and
2008. These adjustments are of a normal and recurring nature. These financial
statements do not contain the complete detail or footnote disclosure concerning
accounting policies and other matters that would be included in full-year
financial statements, and should be read in conjunction with the audited
consolidated financial statements included in IDACORPs and IPCs Annual Report
on Form 10-K for the year ended December 31, 2008. The results of operations
for the interim periods are not necessarily indicative of the results to be
expected for the full year.
Subsequent Events
In the preparation of these
financial statements, IDACORP and IPC evaluate all subsequent events that
provide additional evidence about conditions that existed at the date of the
balance sheet. Subsequent events were evaluated through October 29, 2009, up
to the time the financial statements were issued.
Reclassifications
Certain prior year amounts have
been reclassified to conform to the current year presentation. The
reclassifications made to prior year amounts include the following:
Other expense was combined with the other income line in IDACORPs and IPCs condensed consolidated statements of income to present information in a more condensed manner;
Third-party transmission expense was broken out from electric utility other operations and maintenance in IDACORPs condensed consolidated statements of income and from other operation in IPCs condensed consolidated statements of income because third-party transmission costs are now treated as a power supply cost in the power cost adjustment (PCA);
Employee notes current was combined with other current receivables and employee notes long-term was combined with other non-current assets in IDACORPs and IPCs condensed consolidated balance sheets due to the employee notes becoming an immaterial balance; and
Uncertain tax positions was combined with other current liabilities
in IDACORPs and IPCs condensed consolidated balance sheets due to the
uncertain tax positions becoming an immaterial balance.
Revenues
Operating revenues for IPC
related to the sale of energy are generally recorded when service is rendered
or energy is delivered to customers. IPC accrues unbilled revenues for
electric services delivered to customers but not yet billed at period-end. IPC
collects franchise fees and similar taxes related to energy consumption. These
amounts are recorded as liabilities until paid to the taxing authority. None
of these collections are reported on the income statement as revenue or
expense. Beginning in February 2009, IPC is collecting AFUDC in base rates for
a specific capital project, as discussed in Note 6, Regulatory Matters. Cash
collected under this ratemaking mechanism is recorded as a regulatory
liability.
Allowance for Funds Used during Construction (AFUDC)
AFUDC represents the cost of
financing construction projects with borrowed funds and equity funds. With one
exception, cash is not realized currently from such allowance, it is realized
under the rate-making process over the service life of the related property
through increased revenues resulting from a higher rate base and higher
depreciation expense. The component of AFUDC attributable to borrowed funds is
included as a reduction to interest expense, while the equity component is
included in other income.
13
Earnings Per Share (EPS)
In January 2009, IDACORP adopted
accounting guidance that clarified that unvested share-based payment awards
that contain non-forfeitable rights to dividends or dividend equivalents
(whether paid or unpaid) are participating securities and shall be included in
the computation of EPS pursuant to the two-class method. Prior-period
EPS data has been adjusted retrospectively. Adoption of this guidance did not
have a material impact on IDACORPs EPS and had no impact on IPCs condensed
consolidated financial statements. The following table presents the
computation of IDACORPs basic and diluted earnings per share for the three and
nine months ended September 30, 2009 and 2008 (in thousands, except for per
share amounts):
|
Three months ended |
Nine months ended |
|||||||||
|
September 30, |
September 30, |
|||||||||
|
2009 |
2008 |
2009 |
2008 |
|||||||
Numerator: |
|
|
|
|
|
|
|
|
|||
|
Net income attributable to IDACORP, Inc. |
$ |
54,478 |
$ |
51,739 |
$ |
100,837 |
$ |
90,969 |
||
|
|
|
|
|
|
|
|
|
|||
Denominator: |
|
|
|
|
|
|
|
|
|||
|
Weighted-average common shares outstanding - basic |
|
47,068 |
|
45,126 |
|
46,953 |
|
45,044 |
||
|
Effect of dilutive securities: |
|
|
|
|
|
|
|
|
||
|
|
Options |
|
15 |
|
32 |
|
12 |
|
43 |
|
|
|
Restricted Stock |
|
58 |
|
88 |
|
34 |
|
62 |
|
|
|
Weighted-average common shares |
|
|
|
|
|
|
|
|
|
|
|
|
outstanding diluted |
|
47,141 |
|
45,246 |
|
46,999 |
|
45,149 |
|
Basic earnings per share |
$ |
1.16 |
$ |
1.15 |
$ |
2.15 |
$ |
2.02 |
||
|
Diluted earnings per share |
$ |
1.16 |
$ |
1.14 |
$ |
2.15 |
$ |
2.02 |
||
|
|
|
|
|
|
|
|
|
|||
The diluted EPS computation
excluded 548,957 and 640,674 options for the three and nine months ended
September 30, 2009, respectively, because the options exercise prices were
greater than the average market price of the common stock during those
periods. For the same periods last year, 577,585 and 513,862 options were
excluded from the diluted EPS computation for the same reason. In total,
636,753 options were outstanding at September 30, 2009, with expiration dates
between 2010 and 2015.
Adoption of Guidance on Noncontrolling Interests
On January 1, 2009, IDACORP and
IPC adopted guidance related to presentation of noncontrolling interests in
consolidated subsidiaries (previously referred to as minority interests). This
guidance clarified that noncontrolling interests should be reported as equity
on the consolidated financial statements. IDACORP has disclosed in its
financial statements the portion of equity and net income attributable to the
noncontrolling interests in consolidated subsidiaries and has reclassified $4
million of noncontrolling interests from other liabilities to shareholders
equity on the December 31, 2008, balance sheet. IPC does not have any
noncontrolling interests. The adoption of this guidance modifies financial
statement presentation, but does not impact financial statement results.
14
The following table presents a
reconciliation of the carrying amount of shareholders equity (in thousands):
|
|
|
Attributable to |
|
|||
|
|
Attributable to |
noncontrolling |
|
|||
|
|
IDACORP, Inc. |
interests |
Total |
|||
Shareholders equity at January 1, 2009 |
$ |
1,302,437 |
$ |
4,434 |
$ |
1,306,871 |
|
|
Net income |
|
100,837 |
|
126 |
|
100,963 |
|
Common stock dividends |
|
(42,413) |
|
- |
|
(42,413) |
|
Common stock issuances |
|
17,061 |
|
- |
|
17,061 |
|
Common stock acquired |
|
(1,441) |
|
- |
|
(1,441) |
|
Unrealized holding gains on securities |
|
1,399 |
|
- |
|
1,399 |
|
Unfunded pension liability adjustment |
|
408 |
|
- |
|
408 |
|
Other |
|
2,190 |
|
(249) |
|
1,941 |
Shareholders equity at September 30, 2009 |
$ |
1,380,478 |
$ |
4,311 |
$ |
1,384,789 |
|
|
|
|
|
|
|
|
|
Shareholders equity at January 1, 2008 |
$ |
1,207,315 |
$ |
4,478 |
$ |
1,211,793 |
|
|
Net income (loss) |
|
90,969 |
|
(98) |
|
90,871 |
|
Common stock dividends |
|
(40,671) |
|
- |
|
(40,671) |
|
Common stock issuances |
|
12,647 |
|
- |
|
12,647 |
|
Common stock acquired |
|
(304) |
|
- |
|
(304) |
|
Unrealized holding losses on securities |
|
(2,616) |
|
- |
|
(2,616) |
|
Unfunded pension liability adjustment |
|
311 |
|
- |
|
311 |
|
Other |
|
3,009 |
|
(7) |
|
3,002 |
Shareholders equity at September 30, 2008 |
$ |
1,270,660 |
$ |
4,373 |
$ |
1,275,033 |
|
|
|
|
|
|
|
|
|
New and Adopted Accounting Pronouncements
The Financial Accounting Standards Board (FASB) has issued several new accounting pronouncements. IDACORP and IPC have adopted these pronouncements in 2009:
On January 1, 2009, IDACORP and IPC adopted guidance related to business combinations. This guidance establishes principles and requirements for how an acquirer in a business combination: (1) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (2) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and (3) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. In April 2009, the FASB issued guidance further clarifying the application of the standard. The guidance primarily relates to business combinations entered into after December 31, 2009, and has not impacted IDACORPs or IPCs consolidated financial statements.
On January 1, 2009, IDACORP and IPC adopted guidance that changes the disclosure requirements for derivative instruments and hedging activities. Entities are required to provide enhanced disclosures about (1) how and why it uses derivative instruments, (2) how derivative instruments and related hedged items are accounted for under prior guidance, and (3) how derivative instruments and related hedged items affect its financial position, financial performance, and cash flows. The adoption of this guidance is reflected in Note 10, and did not otherwise impact IDACORPs or IPCs consolidated financial statements.
On January 1, 2009, IDACORP and IPC adopted guidance related to goodwill and other intangible assets. This guidance removes the requirement that an entity must consider, when determining the useful life of an acquired intangible asset, whether the intangible asset can be renewed without substantial cost or material modifications to the existing terms and conditions associated with the intangible asset. The guidance now requires that an entity consider its own experience in renewing similar arrangements. If the entity has no relevant experience, it would consider market participant assumptions regarding renewal. The adoption of this guidance did not impact IDACORPs or IPCs consolidated financial statements.
15
In June 2009, IDACORP and IPC adopted guidance on accounting for and disclosures of subsequent events, events that occur after the balance sheet date but before financial statements are issued or are available to be issued. The required new disclosures are made earlier in this note, and this guidance has not otherwise impacted IDACORPs or IPCs consolidated financial statements.
Fair Value Measurements: In the first quarter of 2009, IDACORP and IPC adopted the following fair value guidance:
a. Guidelines for making fair value measurements more consistent by providing guidance related to determining fair values when there is no active market or where the price inputs being used represent distressed sales;
b. Guidance that enhances consistency in financial reporting by increasing the frequency of fair value disclosures by requiring quarterly fair value disclosures for any financial instruments that are not currently reflected on the balance sheet of companies at fair value and requires qualitative and quantitative information about fair value estimates for all such financial instruments; and
c. Guidance on other-than-temporary impairments that brings greater consistency to the timing of impairment recognition, and provides greater clarity to investors about the credit and noncredit components of impaired debt securities that are not expected to be sold. The guidance also requires increased and timelier disclosures sought by investors regarding expected cash flows, credit losses, and the aging of securities with unrealized losses.
The adoption of this guidance did not have a material effect on IDACORPs or IPCs consolidated financial statements.
Effective for financial statements
issued for interim and annual periods ending after September 15, 2009, The
FASB Accounting Standards Codification TM became the source of
authoritative U.S. generally accepted accounting principles recognized by the
FASB to be applied to nongovernmental entities. Rules and interpretive
releases of the SEC under authority of federal securities laws are also sources
of authoritative GAAP to SEC registrants. On the effective date, the
Codification superseded, but did not change, all then-existing non-SEC
accounting and reporting standards, and all other nongrandfathered, non-SEC
accounting literature not included in the codification became
nonauthoritative. Transition to the Codification did not affect IDACORPs or
IPCs results of operations, cash flows or financial positions. This Form 10-Q
reflects the implementation of the Codification.
The FASB has also issued the following accounting guidance that becomes effective in future periods:
In December 2008, the FASB issued guidance on enhanced disclosures about retirement plan assets. This guidance will require companies to provide users of financial statements with an understanding of: (1) how investment allocation decisions are made, including the factors that are pertinent to an understanding of investment policies and strategies; (2) the major categories of plan assets; (3) the inputs and valuation techniques used to measure the fair value of plan assets; (4) the effect of fair value measurements using significant unobservable inputs (Level 3) on changes in plan assets for the period; and (5) significant concentrations of risk within plan assets. This guidance is effective for fiscal years ending after December 15, 2009. IDACORP and IPC do not expect the adoption of this guidance to have a material effect on their consolidated financial statements.
In June 2009, the FASB issued guidance on how the transferor and transferee should separately account for a transfer of a financial asset and a related repurchase financing if certain criteria are met. For IDACORP and IPC, this guidance is effective for financial asset transfers occurring on or after January 1, 2010, and early adoption is prohibited. IDACORP and IPC do not expect the adoption of this guidance to have a material effect on their consolidated financial statements.
16
In June 2009, the FASB issued amendments to prior consolidation guidance. The amendments will significantly affect the overall consolidation analysis of VIEs. The amendments will require IDACORP and IPC to reconsider their previous conclusions relating to the consolidation of VIEs, including (1) whether an entity is a VIE, (2) whether the enterprise is the VIEs primary beneficiary, and (3) what type of financial statement disclosures are required. For IDACORP and IPC, the amendments are effective as of January 1, 2010, and early adoption is prohibited. IDACORP and IPC are currently assessing the impact of the amendments on their consolidated financial statements.
Accounting Standards Updates (ASUs) The FASB has issued several amendments to the Codification in the form of ASUs No. 2009-01 through 2009-15. IDACORP and IPC are evaluating the provisions of these amendments. Several of these ASUs are not applicable to IDACORP and IPC and are not included in the following discussion. IDACORP and IPC expect the following ASU to be relevant, but does not expect it to have a material impact on IDACORPs or IPCs consolidated financial statements:
o ASU 2009-05 provides clarification of measurement techniques to be used in circumstances in which a quoted price in an active market for the identical liability is not available and provides other fair value guidance. This guidance is effective for the first reporting period beginning after issuance. IDACORP and IPC will adopt the guidance in their December 31, 2009, financial statements.
2. INCOME TAXES:
In accordance with interim reporting
requirements, IDACORP and IPC use an estimated annual effective tax rate for
computing their provisions for income taxes. IDACORPs effective tax rate for
the nine months ended September 30, 2009, was 20.3 percent, compared to 23.8
percent for the nine months ended September 30, 2008. IPCs effective tax rate
for the nine months ended September 30, 2009, was 27.2 percent, compared to
32.9 percent for the nine months ended September 30, 2008. The decrease in the
2009 estimated annual effective tax rates from 2008 was primarily due to an
examination settlement, state bonus depreciation, and timing and amount of
other regulatory flow-through tax adjustments at IPC. The decreases were
partially offset by additional income tax expense from greater pre-tax earnings
at IDACORP and IPC, and lower tax credits from IFS.
In April 2009, the State of Idaho
adopted the federal bonus depreciation provisions enacted as part of the
American Recovery and Reinvestment Act of 2009. IPCs regulatory tax
accounting method allows for the flow-through of certain state tax adjustments,
including accelerated depreciation. Due to the application of the bonus
depreciation provision, IPC was able to reduce its income tax expense by $2.2
million for the nine months ended September 30, 2009.
The Internal Revenue Service
(IRS) completed its examination of IDACORPs 2006 tax year in May 2009. The
2006 examination report was submitted for U.S. Congress Joint Committee on
Taxation (JCT) review in June. In July, the JCT completed its review and
accepted the report without change. IDACORP considered all uncertain tax
positions related to its 2006 tax year effectively settled as of the second
quarter, and decreased IPCs liability for unrecognized tax benefits by $1.3
million.
In March 2009, the JCT completed
its review of IDACORPs 2001-2004 uniform capitalization appeals settlement and
2005 IRS examination report. The JCT accepted both items without change.
IDACORP considered these matters effectively settled in 2008 and recorded the
related financial effects in its December 31, 2008, financial statements.
The IRS began its examination of
IDACORPs 2007-2008 tax years in July 2009. In May 2009, IDACORP formally
entered the IRS Compliance Assurance Process (CAP) program for its 2009 tax
year. The CAP program provides for IRS examination throughout the year. The
2007-2009 examinations are expected to be completed in 2010. IDACORP and IPC
are unable to predict the outcome of these examinations.
3. COMMON STOCK AND STOCK-BASED COMPENSATION:
During the nine months ended
September 30, 2009, IDACORP entered into the following transactions involving
its common stock:
In September 2009, 326,307 original issue shares were issued in at-the-market offerings at an average price of $28.63 per share through the continuous equity program (CEP). An additional 163,053 shares sold in September 2009 settled in October 2009 at an average price of $29.10 per share.
17
112,128 original issue shares and 24,948 treasury shares were used for awards granted under the 2000 Long-Term Incentive and Compensation Plan.
28,518 original issue shares and 22,550 treasury shares were used for awards granted under the Restricted Stock Plan.
12,936 treasury shares were used for the annual stock grant to directors under the Non-Employee Directors Stock Compensation Plan.
283,071 original issue shares were issued under the Dividend Reinvestment and Stock Purchase Plan and the Employee Savings Plan.
IDACORP has a Sales Agency
Agreement with BNY Mellon Capital Markets, LLC, as IDACORPs agent, for the
offer and sale of up to 3,000,000 shares of its common stock from time to time
in at-the-market offerings. At September 30, 2009, there were 2,301,871
shares remaining available for sale under the CEP. At October 29, 2009 there
were 2,138,818 shares remaining available.
IDACORP contributed $20 million
in cash as additional equity to IPC in September 2009. No additional shares of
IPC common stock were issued.
IDACORP has three share-based
compensation plans. IDACORPs employee plans are the 2000 Long-Term Incentive
and Compensation Plan (LTICP) and the Restricted Stock Plan (RSP). These plans
are intended to align employee and shareholder objectives related to IDACORPs
long-term growth. IDACORP also has one non-employee plan, the Non-Employee
Directors Stock Compensation Plan (DSP). The purpose of the DSP is to increase
directors stock ownership through stock-based compensation.
The LTICP for officers, key
employees and directors permits the grant of nonqualified stock options,
incentive stock options, stock appreciation rights, restricted stock,
restricted stock units, performance units, performance shares and other
awards. The RSP permits only the grant of restricted stock or performance-based
restricted stock. At September 30, 2009, the maximum number of shares
available under the LTICP and RSP were 1,597,309 and 25,515, respectively.
The following table shows the
compensation cost recognized in income and the tax benefits resulting from
these plans, as well as the amounts allocated to IPC for those costs associated
with IPCs employees (in thousands of dollars). No equity compensation costs
have been capitalized:
|
IDACORP |
IPC |
||||||
|
Nine months ended |
Nine months ended |
||||||
|
September 30, |
September 30, |
||||||
|
2009 |
2008 |
2009 |
2008 |
||||
Compensation cost |
$ |
2,711 |
$ |
3,106 |
$ |
2,570 |
$ |
2,933 |
Income tax benefit |
$ |
1,060 |
$ |
1,214 |
$ |
1,005 |
$ |
1,147 |
|
|
|
|
|
|
|
|
|
Stock awards: Restricted
stock awards have vesting periods of up to three years. Restricted stock
awards entitle the recipients to dividends and voting rights, and unvested
shares are restricted as to disposition and subject to forfeiture under certain
circumstances. The fair value of restricted stock awards is measured based on
the market price of the underlying common stock on the date of grant and is
charged to compensation expense over the vesting period based on the number of
shares expected to vest. The weighted average fair value at date of grant for
restricted stock awards granted during 2009 was $25.48.
Performance-based restricted
stock awards have vesting periods of three years. Performance awards entitle
the recipients to voting rights, and unvested shares are restricted as to
disposition, subject to forfeiture under certain circumstances, and subject to
meeting specific performance conditions. Based on the attainment of the
performance conditions, the ultimate award can range from zero to 150 percent of
the target award. Dividends are accrued during the vesting period and will be
paid out only on shares that eventually vest.
18
The performance goals for these
awards are independent of each other and equally weighted, and are based on two
metrics, cumulative earnings per share (CEPS) and total shareholder return
(TSR) relative to a peer group. The fair value of the CEPS portion is based on
the market value at the date of grant, reduced by the loss in time-value of the
estimated future dividend payments, using an expected quarterly dividend of
$0.30. The fair value of the TSR portion is estimated using a statistical
model that incorporates the probability of meeting performance targets based on
historical returns relative to the peer group. Both performance goals are
measured over the three-year vesting period and are charged to compensation
expense over the vesting period based on the number of shares expected to
vest. The weighted average fair value at date of grant for CEPS and TSR awards
granted during the first nine months of 2009 was $19.50.
Stock option awards are granted
with exercise prices equal to the market value of the stock on the date of
grant. The options have a term of 10 years from the grant date and vest over a
five-year period. The fair value of each option is amortized into compensation
expense using graded-vesting. Stock options are not a significant component of
share-based compensation awards under the LTICP.
4. LONG-TERM DEBT:
Long-Term Financing
As of September 30, 2009, IDACORP
had approximately $579 million remaining on a shelf registration statement that
can be used for the issuance of debt securities or common stock. As of October
29, 2009, IDACORP had approximately $574 remaining available on the shelf
registration statement.
On March 30, 2009, IPC issued
$100 million of 6.15 percent first mortgage bonds, due April 1, 2019. IPC used
the net proceeds to repay a portion of its short-term debt in anticipation of
utilizing short-term debt to repay $80 million of 7.20 percent first mortgage
bonds that mature December 1, 2009. IPC has $130 million remaining on a shelf
registration statement that can be used for the issuance of first mortgage
bonds and unsecured debt.
In February 2009, IFS repaid $7.2
million of debt related to investments in affordable housing. The debt was
scheduled to mature in 2009 and 2010. On May 15, 2009, IFS issued a $6 million
equity funding obligation to finance a portion of its $12 million investment in
affordable housing. The obligation is scheduled to mature in 2010.
Pollution Control Revenue
Refunding Bonds and Term Loan Credit Agreement: On April 3, 2008, IPC made
a mandatory purchase of two series of Pollution Control Revenue Refunding Bonds
issued for the benefit of IPC, the $116.3 million aggregate principal amount of
Pollution Control Revenue Refunding Bonds Series 2006 issued by Sweetwater
County, Wyoming due 2026 and the $49.8 million aggregate principal amount of
Pollution Control Revenue Refunding Bonds Series 2003 issued by Humboldt
County, Nevada due 2024 (together the Pollution Control Bonds). IPC initiated
this transaction in order to adjust the interest rate period of the Pollution
Control Bonds from an auction interest rate period to a weekly interest rate
period, effective April 3, 2008. This change was made to mitigate the higher-than-anticipated
interest costs in the auction mode, which was a result of the financial
guarantors credit ratings deterioration.
On August 20, 2009, J.P. Morgan
Securities Inc. as the Remarketing Agent, purchased the Pollution Control Bonds
from IPC for remarketing to the public. The Humboldt County Bonds carry a 5.15
percent term interest rate and mature on December 1, 2024. The Sweetwater
County Bonds carry a 5.25 percent term interest rate and mature on July 15,
2026. The Pollution Control Bonds are not subject to redemption for 10 years,
except for extraordinary optional and mandatory redemption prior to maturity,
in each case at 100 percent of the principal amount, plus accrued interest if
any to the date of redemption. In connection with the remarketing of the
Pollution Control Bonds, the financial guaranty insurance policies securing the
Pollution Control Bonds were terminated.
On August 25, 2009, IPC used
proceeds from the reoffering of the Pollution Control Bonds and additional
corporate funds to prepay its $170 million loan under a Term Loan Credit
Agreement dated as of February 4, 2009, among JPMorgan Chase Bank, N.A., as
administrative agent and lender, Bank of America, N.A. and Wachovia Bank,
National Association, as lenders.
19
5. NOTES PAYABLE:
Credit Facilities
IDACORP has a $100 million credit
facility and IPC has a $300 million credit facility, both of which expire on
April 25, 2012. Commercial paper may be issued up to the amounts supported by
the bank credit facilities. Under these facilities the companies pay a
facility fee on the commitment, quarterly in arrears, based on its rating for
senior unsecured long-term debt securities without third-party credit
enhancement as provided by Moodys and S&P.
At September 30, 2009, no loans
were outstanding on either IDACORPs facility or IPCs facility. At September
30, 2009, IPC had regulatory authority to incur up to $450 million of short-term
indebtedness.
Balances and interest rates of
short-term borrowings were as follows at September 30, 2009, and December 31,
2008 (in thousands of dollars):
|
|
September 30, 2009 |
December 31, 2008 |
|||||||||||
|
|
IPC |
IDACORP |
Total |
IPC |
IDACORP |
Total |
|||||||
Commercial paper |
|
|
|
|
|
|
|
|
|
|
|
|
||
|
outstanding |
$ |
- |
$ |
36,780 |
$ |
36,780 |
$ |
108,950 |
$ |
13,400 |
$ |
122,350 |
|
Other short-term |
|
|
|
|
|
|
|
|
|
|
|
|
||
|
borrowings |
|
- |
|
- |
|
- |
|
3,900 |
|
25,000 |
|
28,900 |
|
|
|
Total |
$ |
- |
$ |
36,780 |
$ |
36,780 |
$ |
112,850 |
$ |
38,400 |
$ |
151,250 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average. |
|
|
|
|
|
|
|
|
|
|
|
|
||
|
interest rate |
|
0.00% |
|
0.44% |
|
0.44% |
|
4.89% |
|
4.29% |
|
4.74% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6. REGULATORY MATTERS:
Idaho 2008 General Rate Case
The IPUC denied reconsideration
with respect to a refund of $3.3 million of fees recovered by IPC from the
FERC. On April 2, 2009, IPC filed an application with the IPUC for an
accounting order approving amortization of the fees over a five year period
beginning October 2006 when IPC received the FERC credit. The IPUC approved
IPCs requested amortization period in an order issued on April 28, 2009. In
the first quarter of 2009, IPC recorded a charge of approximately $1.7 million
to electric utility other operations expense and a corresponding regulatory
liability for the amount to be refunded from February 1, 2009, through the end
of the amortization period, September 2011. As the regulatory liability is
amortized it will reduce electric utility other operations expense ratably over
the remaining amortization period.
The January 30, 2009 order
authorized approximately $15 million related to increases in base net power
supply costs. It also allowed IPC to include in rates approximately $6.8
million ($10.6 million including income tax gross-up) of 2009 AFUDC relating to
the Hells Canyon Complex relicensing project. Typically, AFUDC is not included
in rates until a project is in use and benefitting customers, but the IPUC
determined that including this amount in current rates is in the public
interest. Because AFUDC is already recorded on an accrual basis, this portion
of the rate increase will improve cash flows but will not have a current impact
on IPCs net income. The amounts collected are being deferred as a regulatory
liability and will be recognized in revenues over the life of the new license
once it has been issued.
20
Deferred Net Power Supply Costs
IPCs deferred net power supply
costs consisted of the following balances, including applicable carrying
charges (in thousands of dollars):
|
|
September 30, |
December 31, |
|||
|
|
2009 |
2008 |
|||
Idaho PCA current year: |
|
|
|
|
||
|
Deferral for the 2009-2010 rate year |
$ |
- |
$ |
93,657 |
|
|
Deferral for the 2010-2011 rate year |
|
26,121 |
|
- |
|
Idaho PCA true-up awaiting recovery: |
|
|
|
|
||
|
Authorized in May 2008 |
|
- |
|
47,164 |
|
|
Authorized in May 2009 |
|
66,716 |
|
- |
|
Oregon deferral: |
|
|
|
|
||
|
2001 Costs |
|
- |
|
1,663 |
|
|
2006 Costs |
|
2,285 |
|
1,215 |
|
|
2007 Costs |
|
6,105 |
|
- |
|
|
2008 Power cost adjustment mechanism |
|
5,725 |
|
5,400 |
|
|
|
Total deferral |
$ |
106,952 |
$ |
149,099 |
|
|
|
|
|
|
|
Idaho: IPC has a PCA
mechanism that provides for annual adjustments to the rates charged to its
Idaho retail customers. The PCA tracks IPCs actual net power supply costs
(fuel, purchased power and third-party transmission expenses less off-system
sales) and compares these amounts to net power supply costs currently being
recovered in retail rates.
The annual adjustments are based
on two components:
A forecast component, based on a forecast of net power supply costs in the coming year as compared to net power supply costs in base rates; and
A true-up component, based on the difference between the previous
years actual net power supply costs and the previous years forecast. This
component also includes a balancing mechanism so that, over time, the actual
collection or refund of authorized true-up dollars matches the amounts
authorized. The true-up component is calculated monthly, and interest is
applied to the balance.
Prior to February 1, 2009, the
PCA mechanism provided that 90 percent of deviations in power supply costs
were to be reflected in IPCs rates for both the forecast and the true-up
components. Effective February 1, 2009, this sharing percentage was changed to
95 percent.
2009-2010 PCA: On May 29,
2009, the IPUC approved the 2009-2010 PCA of $84.3 million or 10.2 percent,
effective June 1, 2009. The 2009-2010 PCA reflects a new methodology discussed
in PCA Workshops below that utilizes IPCs most recent operating plan to
forecast power supply expenses rather than the previous method based on a
forecast of Brownlee Reservoir inflow and a regression formula.
2008-2009 PCA: On May 30,
2008, the IPUC approved IPCs 2008-2009 PCA and an increase to then-existing
revenues of $73.3 million, effective June 1, 2008, which resulted in an average
rate increase to IPCs customers of 10.7 percent. The IPUCs order adopted an
IPUC Staff proposal to use a forecast for power supply costs that equaled the
amounts in current base rates. The revenue increase was net of $16.5 million
of gains from the 2007 sale of excess SO2 emission allowances,
including interest, which the IPUC ordered be applied against the PCA.
PCA Workshops: In its May
30, 2008 order approving IPCs 2008-2009 PCA, the IPUC directed IPC to set up
workshops with the IPUC Staff and several of IPCs largest customers (together,
the Parties) to address PCA-related issues not resolved in the PCA filing.
Workshops were conducted in the fall and a settlement stipulation was filed
with the IPUC and approved on January 9, 2009.
21
The following changes were effective as of February 1, 2009:
PCA sharing ratio the PCA allocates the deviations in net power supply expenses between customers (95 percent) and shareholders (5 percent). The previous sharing ratio was 90/10.
LGAR the LGAR is an element of the PCA formula that is intended to eliminate recovery of power supply expenses associated with load growth resulting from changing weather conditions, a growing customer base, or changing customer use patterns. The 2007 general rate case reset the LGAR from $29.41 to $62.79 per MWh, but applied that rate to only 50 percent of the load growth beginning in March 2008. In the stipulation, the Parties agreed on the formula for calculating the LGAR. Based on the final rates approved by the IPUC in the 2008 general rate case and the supporting data, the current LGAR is $26.63 per MWh, effective February 1, 2009.
Use of IPCs operation plan power supply cost forecast the operation plan forecast may better match current collections with actual net power supply costs in the year they are incurred and result in smaller amounts being included in the following years true-up rate, beginning with the 2009-2010 PCA filing.
Inclusion of third-party transmission expense transmission expenses paid to third parties to facilitate wholesale purchases and sales of energy, including losses, are a necessary component of net power supply costs. Deviation in these costs from levels included in base rates is now reflected in PCA computations.
Adjusted distribution of base net power supply costs base net
power supply costs are distributed throughout the year based upon the monthly
shape of normalized revenues for purposes of the PCA deferral calculation.
Oregon: IPC has a power
cost recovery mechanism in Oregon with two components: the annual power cost
update (APCU) and the power cost adjustment mechanism (PCAM). The combination
of the APCU and the PCAM allows IPC to recover excess net power supply costs in
a more timely fashion than through the previously existing deferral process.
The APCU allows IPC to
reestablish its Oregon base net power supply costs annually, separate from a
general rate case, and to forecast net power supply costs for the upcoming
water year. The APCU has two components: the October Update, where each
October IPC calculates its estimated normalized net power supply expenses for
the following April through March test period, and the March Forecast, where
each March IPC files a forecast of its expected net power supply expenses for the
same test period, updated for a number of variables including the most recent
stream flow data and future wholesale electric prices. On June 1 of each year,
rates are adjusted to reflect costs calculated in the APCU.
The PCAM is a true-up filed
annually in February. The filing calculates the deviation between actual net
power supply expenses incurred for the preceding calendar year and the net
power supply expenses recovered through the APCU for the same period. Under
the PCAM, IPC is subject to a portion of the business risk or benefit
associated with this deviation through application of an asymmetrical deadband
(or range of deviations) within which IPC absorbs cost increases or decreases.
For deviations in actual power supply costs outside of the deadband, the PCAM
provides for 90/10 sharing of costs and benefits between customers and IPC.
However, a collection will occur only to the extent that it results in IPCs
actual return on equity (ROE) for the year being no greater than 100 basis
points below IPCs last authorized ROE. A refund will occur only to the extent
that it results in IPCs actual ROE for that year being no less than 100 basis
points above IPCs last authorized ROE. The PCAM rate is then added to or
subtracted from the APCU rate, subject to certain statutory limitations
discussed below, with new combined rates effective each June 1.
2010 APCU: On October 19,
2009, IPC filed the October Update portion of its 2010 APCU with the OPUC. The
filing reflects that revenues associated with IPCs base net power supply costs
would be increased by $2.6 million over the current APCU, an average 8.2
percent increase. The actual impact of the 2010 APCU will be determined once
the March Forecast portion is filed in March 2010 and combined with the October
Update. Final rates are expected to become effective on June 1, 2010.
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2009 APCU: On October 23,
2008, IPC filed the October Update portion of its 2009 APCU with the OPUC. The
filing, combined with supplemental testimony filed on December 1, 2008,
reflects that revenues associated with IPCs base net power supply costs would
be increased by $1.6 million over the previous October Update, an average 4.6
percent increase.
On March 20, 2009, IPC filed the
March Forecast portion of its 2009 APCU. When combined with the October
Update, the March Forecast resulted in a requested increase to Oregon revenues
of 11.5 percent, or $3.9 million annually. On May 26, 2009, the OPUC approved
the requested rate increase effective June 1, 2009.
2008 APCU: On May 20,
2008, the OPUC approved IPCs 2008 APCU (comprising both the October Update and
the March Forecast) with the new rates effective June 1, 2008. The approved
APCU resulted in a $4.8 million, or 15.7 percent, increase in Oregon revenues.
2008 PCAM: On February
27, 2009, IPC filed the true-up of its net power supply costs for the period
January 1 through December 31, 2008, with the OPUC. The 2008 PCAM filing
reflects a deviation of actual net power supply costs above the forecast for
that period of $7.4 million. After the application of the deadband, the filing
requests that $5.0 million be added to IPCs true-up balancing account and
amortized sequentially after the amounts discussed below under Oregon Excess
Power Cost Deferrals. A pre-hearing conference was held on April 27, 2009, to
discuss the status of the case. A joint workshop and settlement conference was
held July 7, 2009. As a result of the conference, IPC filed supplemental
testimony on October 14, 2009, that reflects agreed upon changes to the
calculation of the deferral. The revised 2008 PCAM filing now reflects a
deviation of actual net power supply costs above the forecast for that period
of $7.7 million and requests that $5.1 million be added to IPCs true-up
balancing account and amortized sequentially.
Oregon Excess Power Cost
Deferrals: 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 of gross Oregon revenue per year
($1.9 million for 2009 based on 2008 revenues). On October 6, 2008, the OPUC
issued an order clarifying that the PCAM is also a deferral under the Oregon
statute. The following deferrals were authorized under processes existing prior
to the establishment of the PCAM.
May-December 2007 Excess Power
Costs: 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 (higher than base) power
supply expenses. In the filing, IPC included a forecast of Oregons
jurisdictional share of excess power supply costs of $5.7 million. Settlement
discussions were held in February 2009. As a result of those discussions, the
parties to the proceeding reached a settlement and a stipulation was filed with
the OPUC on April 8, 2009. In the stipulation, the parties agreed to limit the
calculation of excess net power supply costs in this docket to the eight-month
period from May 1 through December 31, 2007. Based on the methodology adopted
by the parties to the stipulation, it was determined that IPC should be allowed
to defer excess net power supply costs of $6.4 million (including interest
through the date of the order) for that period. The amount to be recovered was
reduced by $0.9 million of emission allowance sales (including interest) during
the same period allocated to Oregon, resulting in an approved deferral balance
of $5.5 million. IPC recorded the $6.4 million deferral in the second quarter
2009 as a reduction to power cost adjustment expense. The emission allowances
sales were previously deferred. The parties also agreed that the excess power
supply costs from the period beginning in 2008 would be deferred pursuant to
the PCAM agreement established as part of the power cost variance filing for
2008 and calculated according to the PCAM. On May 28, 2009, the OPUC issued
its order adopting the stipulation.
2006-2007 Excess Power Costs:
On June 30, 2009, IPC filed an application with the OPUC to begin amortizing
through rates the 2006-2007 deferral of $2.0 million plus $0.4 million of
accrued interest, effective September 1, 2009. The OPUC issued an order approving
IPCs application on September 1, 2009. IPC expects amortization of this
deferral to take approximately 16 months. The May 1 - December 31, 2007
deferral of $6.1 million (net of the emission allowance adjustment and
including accrued interest) and the $5.7 million 2008 PCAM balance (including
accrued interest) will be recovered sequentially following the full recovery of
the 2006-2007 deferral.
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Fixed Cost Adjustment Mechanism (FCA)
On March 12, 2007, the IPUC
approved the implementation of a FCA mechanism pilot program for IPCs
residential and small general service customers. The pilot program began on
January 1, 2007, and runs through 2009. The FCA is a rate mechanism designed
to remove IPCs disincentive to invest in energy efficiency programs by
separating (or decoupling) the recovery of fixed costs from the variable
kilowatt-hour charge and linking it instead to a set amount per customer. In
the FCA, for each customer class, the number of customers is multiplied by a
fixed cost per customer. The cost per customer is based on IPCs revenue
requirement as established in a general rate case. This authorized fixed cost
recovery amount is compared to the amount of fixed costs actually recovered by
IPC. The amount of over- or under-recovery is then returned to or collected
from customers in a subsequent rate adjustment. On October 1, 2009, IPC filed
an application with the IPUC to make the FCA mechanism permanent beginning with
the June 1, 2010 rate change.
On May 29, 2009, the IPUC
approved a rate increase, effective June 1, 2009 through May 31, 2010, to
recover $2.7 million of fixed costs under-recovered during 2008. On May 30,
2008, the IPUC approved a rate reduction, effective June 1, 2008 through May
31, 2009, to return $2.4 million of fixed costs over-recovered in 2007.
IPC deferred fixed costs of $5.0
million related to the FCA during the first nine months of 2009.
Energy Efficiency Matters
Idaho Energy Efficiency Rider
(Rider): IPCs Rider is the chief funding mechanism for IPCs investment
in energy efficiency and demand response programs. On May 29, 2009, the IPUC
approved IPCs application to increase the Rider to 4.75 percent of base
revenues, effective June 1, 2009. Based on 2008 test year revenue, IPC expects
Rider revenues of $27.3 million in 2009 and $33.2 million in each of 2010 and
2011. Effective June 1, 2008, IPC began collecting 2.5 percent of base
revenues, or approximately $17 million annually, under the Rider. Prior to
that date, IPC collected 1.5 percent of base revenues, with funding caps for
residential and irrigation customers.
Energy Efficiency Prudency
Review: In the 2008 general rate case, IPC requested that the IPUC
explicitly find that IPCs expenditures between 2002 and 2007 of $29 million of
funds obtained from the Rider were prudently incurred and would, therefore, no
longer be subject to potential disallowance. The IPUC Staff recommended that
the IPUC defer a prudency determination for these expenditures until IPC was
able to provide a comprehensive evaluation package of its programs and
efforts. IPC contended that sufficient information had already been provided
to the IPUC Staff for review.
On February 18, 2009, IPC filed a
stipulation with the IPUC reflecting an agreement with the IPUC Staff on $14.3
million of the Rider funds. The IPUC Staff agreed that this portion of the
Rider expenditures were prudently incurred. On March 6, 2009, the IPUC
approved the stipulation, identifying $18.3 million as prudent, which included
$14.3 million of Rider funding and $4.0 million of other funds.
On April 1, 2009, IPC filed an
application with the IPUC seeking a prudency determination on the $14.7 million
balance of Rider funds spent during 2002 through 2007. IPC has requested that
this application be processed under modified procedure.
On October 5, 2009, IPC and other
investor-owned electric utilities serving in Idaho engaged in an informal
public workshop with the IPUC Staff to discuss how energy efficiency evaluation
and prudency will be determined on a prospective basis. The IPUC Staff is
expected to propose a process for energy efficiency expenditure approval as a
result of the workshop.
Advanced Metering Infrastructure (AMI)
The AMI project provides the
means to automatically retrieve energy consumption information, eliminating
manual meter reading expense. In the future, the system will support
enhancements to allow for time-variant rates, perform remote connects and
disconnects, and collect system operations data enhancing outage management,
reliability efforts and demand-side management options.
IPC filed AMI evaluation and
deployment reports with the IPUC on May 1 and August 31, 2007, in compliance
with an IPUC order. Consistent with the implementation plan contained in those
reports, IPC entered into a number of contracts for materials and resources
that allowed for the AMI implementation to commence in late 2008. IPC intends
to install this technology for approximately 99 percent of its customers and is
on pace to complete the installations by the end of 2011 as scheduled.
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Idaho: On August 5, 2008,
IPC filed an application with the IPUC requesting a CPCN for the deployment of
AMI technology and approval of accelerated depreciation for the existing
metering equipment. The IPUC approved IPCs application on February 12, 2009.
In its application, IPC estimated the three-year investment in AMI to be $70.9
million. In an April 7, 2009, order, the IPUC clarified that IPC can expect in
the ordinary course of events, to include in rate base the prudent capital
costs of deploying AMI as it is placed in service up to the capital cost
commitment estimate of $70.9 million. The IPUC also clarified, as requested by
IPC, that it does not anticipate that the immediate savings derived from the
implementation of AMI throughout IPCs service territory will eliminate or
wholly offset the increase in IPCs revenue requirement caused by the
authorized depreciation period.
On March 13, 2009, IPC filed an
application with the IPUC for authority to increase its rates due to the
inclusion of AMI investment in rate base. The filing requested inclusion of
the investments already made for the installation of AMI throughout IPCs
service territory, and those investments that would be made during a June 1,
2009, through May 31, 2010 test year. IPC requested a first year revenue
requirement of $11.2 million in the Idaho jurisdiction effective June 1, 2009,
for service provided on or after that date. In its calculations, IPC reflected
the reduction in investment and the accelerated depreciation costs related to
the removal of current metering equipment, as well as changes in operating
expenses that accompany the changes in plant investment.
On May 29, 2009, the IPUC
approved annual recovery of $10.5 million, effective June 1, 2009. The order
was based on IPCs actual investment in AMI to date, annualized through
December 31, 2009, rather than IPCs proposed test year. The IPUC also allowed
IPC to begin three-year accelerated depreciation of the existing metering
equipment on June 1, 2009. The order reflects annualized depreciation expense
relating to AMI of $9.2 million. The actual depreciation expense for fiscal
year 2009 will occur over seven months totaling $6.2 million. IPC has recorded
$3.5 million of this amount through September 30, 2009.
Oregon: On October 3,
2008, IPC filed an application with the OPUC requesting authority to accelerate
the depreciation and recovery of existing meters in the Oregon jurisdiction
over an 18-month period beginning January 2009. The OPUC approved IPCs
request on December 30, 2008. IPCs AMI deployment schedule calls for the
replacement of the Oregon service-territory meters around October 2010. The
existing meters will be fully depreciated prior to their removal from service.
The filing estimated the balance of plant in service at December 31, 2008,
attributable to the existing meters to be $1.4 million. The approval of this
application results in an increase of $0.8 million for 2009 in both rates and
depreciation expense. This increase is partially offset by the reduced
depreciation rates discussed below in Depreciation Filings. Combined, the
two adjustments result in a $0.4 million net increase to annual depreciation
during the period of accelerated recovery.
Depreciation Filings
On September 12, 2008, the IPUC
approved a revision to IPCs depreciation rates, retroactive to August 1,
2008. The new rates are based on a settlement reached by IPC and the IPUC
Staff, and result in an annual reduction of depreciation expense of $8.5
million ($7.9 million allocated to Idaho) based upon December 31, 2006,
depreciable electric plant in service.
On October 3, 2008, IPC filed an
application with the OPUC requesting that the new depreciation rates approved
in IPCs Idaho jurisdiction be authorized for IPCs Oregon jurisdiction as
well. The result for the Oregon jurisdiction would be a decrease in annual
depreciation expense and rates of $0.4 million (excluding the impacts of
accelerated depreciation of existing Oregon meters as discussed above in Advanced
Metering Infrastructure (AMI) - Oregon). On August 18, 2009, the OPUC
approved a stipulation whereby the OPUC Staff agreed not to make adjustments to
the depreciation rates adopted by the IPUC. IPC committed to joint involvement
of OPUC Staff prior to submitting future depreciation rates for approval in IPCs
Idaho jurisdiction.
On December 3, 2009, the FERC
approved IPCs request to use the IPUC- approved depreciation rates in future
FERC rate filings. The new depreciation accrual rates were reflected in IPCs
OATT rates beginning October 1, 2009.
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Idaho Open Access Transmission
Tariff (OATT) Shortfall Filing
For Idaho jurisdictional revenue requirement determinations, revenues from
third parties (non-state jurisdictional) received through the OATT, referred to
as revenue credits, are a direct offset to IPCs overall revenue requirement.
In the last two general rate cases, IPC included an estimate of OATT revenues
from third parties based on the forecasted OATT rate less a reserve. However,
as discussed below in OATT, the FERC order issued on January 15, 2009 had a
significant impact on actual third-party transmission revenues IPC received
from June 2006 to date, resulting in the overstating of the revenue credits in
the Idaho jurisdictional revenue requirement authorized by the IPUC. On July
20, 2009, IPC filed a request with the IPUC for authorization to defer $8.1
million in costs associated with the difference between the revenue credits and
the amount of OATT revenues IPC has received since March 2008 and expects to receive
through May 2010. Included in the filing are $4.3 million for the period March
1, 2008, through January 31, 2009, the effective period of the February 28,
2008, general rate case order and $3.8 million estimated for the period
February 1, 2009, through May 31, 2010, the expected effective period of the
January 30, 2009, general rate case order. IPC requested to amortize the
unrecovered transmission revenues on a straight-line basis over a three-year
period beginning June 1, 2010, and to receive a carrying charge on the balance
until rate recovery begins. The application is proceeding under modified
procedure. IPC has filed a request for rehearing of the FERC order and is
taking additional measures to address the revenue shortfall. If the FERC
issues are resolved in IPCs favor, IPC will reduce the deferral. On September
29, 2009, the IPUC Staff filed comments. Both parties have agreed to reduce
the calculation of the total deferral from $8.1 million to $4.7 million to
reflect transmission rate increases that became effective after IPC filed its
application.
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
financial and operational data IPC is required to file annually with the FERC
in its Form 1. The formula rate request included a rate of return on equity of
11.25 percent. IPCs filing was opposed by several affected parties.
Effective June 1, 2006, the FERC accepted IPCs proposed new rates, subject to
refund pending the outcome of the hearing and settlement process.
On August 8, 2007, the FERC
approved a settlement agreement by the parties on all issues except the
treatment of contracts for transmission service that contain their own terms,
conditions and rates that were in existence before the implementation of OATT
in 1996 (Legacy Agreements). This settlement reduced IPCs proposed new rates
and, as a result, approximately $1.7 million collected in excess of the
settlement rates between June 1, 2006, and July 31, 2007, was refunded with
interest in August 2007. As part of the settlement agreement, the FERC
established an authorized rate of return on equity of 10.7 percent.
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 would
have further reduced the new transmission rates. IPC, as well as the opposing
parties, appealed the Initial Decision to the FERC. If implemented, the
Initial Decision would have required IPC to make additional refunds, of
approximately $5.4 million (including $0.4 million of interest) for the June 1,
2006, through December 31, 2008, period. IPC previously reserved this entire
amount.
On January 15, 2009, the FERC
issued an Order on Initial Decision (FERC Order), which upheld the Initial
Decision of the ALJ in most respects, but modified the Initial Decision in one
respect that is unfavorable to IPC. The decision required IPC to reduce its
transmission service rates to FERC jurisdictional customers. Furthermore, IPC
was required to make refunds to FERC jurisdictional transmission customers in
the total amount of $13.3 million (including $1.1 million in interest) for the
period since the new rates went into effect in June 2006. Based on the FERC
Order IPC reserved an additional $7.9 million (including $0.7 million in
interest) in the fourth quarter of 2008, bringing the total reserve amount to
$13.3 million. Prior to the FERC Order, the FERC jurisdictional transmission
revenues (net of the $5 million reserve) recorded in the last seven months of
2006, all of 2007 and 2008 were $8.1 million, $13.3 million and $15.8 million,
respectively. Under the FERC Order, the transmission revenues would have been
$6.4 million in the last seven months of 2006, $11 million in 2007 and $12.6
million in 2008. Refunds were made on February 25, 2009.
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IPC filed a request for rehearing
with the FERC on February 17, 2009. IPC believes that the treatment of the
Legacy Agreements conflicts with precedent. The rehearing request asserts that
the FERC order is in error by: (1) requiring IPC to include the contract
demands associated with the Legacy Agreements in the OATT formula rate divisor
rather than crediting the revenue from the Legacy Agreements against IPCs
transmission revenue requirement; (2) concluding that IPC must include the
contract demands associated with the Legacy Agreements rather than the customers
coincident peak demands; (3) concluding that the transmission rate contained in
one or more of the Legacy Agreements was not a discounted rate; (4) failing to
consider the non-monetary benefits received by IPC from the Legacy Agreements;
(5) concluding that the services provided under the Legacy Agreements are firm
services and therefore should be handled for rate purposes in the same manner
as firm services under the OATT; and (6) failing to affirm the rate treatment
that has been used for the Legacy Agreements for approximately 30 years. On
March 18, 2009, the FERC issued a tolling order that effectively relieves it
from acting on the request for reconsideration for an indefinite time period. IPC
cannot predict when the FERC will rule on the request for rehearing or the
outcome of this matter.
Amended Legacy Agreements:
Subsequent to the January 15, 2009 FERC Order, IPC has sought to mitigate the
resulting revenue shortfall by revising certain of the Legacy Agreements as
provided for in the agreements.
On April 3, 2009, IPC notified
PacifiCorp that it was terminating its provision of a portion of the services
that it provides under the Restated Transmission Service Agreement (RTSA), a
Legacy Agreement, effective June 12, 2009. IPC made a filing with the FERC on
April 13, 2009 submitting revised rate schedule sheets. The FERC accepted the
revised rate schedule sheets by letter order on May 14, 2009. On June 12, 2009
IPC submitted a filing for the purpose of replacing the terminated contract
services with OATT service, effective June 13, 2009. An amended RTSA between
IPC and PacifiCorp and three long term service agreements were filed to provide
for the OATT service. As calculated in the filings, the estimated net
transmission revenue increase for the period June 13, 2009 through June 12,
2010 is approximately $3.2 million. The FERC accepted IPCs filing, effective
June 13, 2009, by letter order on July 28, 2009.
On June 19, 2009 IPC submitted a
filing to increase rates under the Agreement for Interconnection and
Transmission Services (ITSA) contract, another Legacy Agreement between IPC and
PacifiCorp. The filing requested an increase of rates to the level paid by
OATT customers for Point to Point service and an August 19, 2009 effective
date. As calculated in the filing, the estimated net transmission revenue
increase for the period September 1, 2009 through August 31, 2010 is
approximately $3.9 million. PacifiCorp has intervened in the case and on July
10, 2009 filed a motion to suspend the case for five months and pursue
settlement or go to hearing. On August 18, 2009, the FERC accepted IPCs
filing and suspended it, setting it for settlement judge procedures and hearing.
IPC is collecting the new rates subject to refund and has reserved the entire
increase pending settlement. A settlement conference was held on October 7,
2009, and another is scheduled for November 18, 2009. Settlement discussions
are ongoing.
2009 OATT: On August 28,
2009, IPC filed its informational filing with the FERC that contains the annual
update of the formula rate based on the 2008 test year. The new rate included
in the filing was $15.83 per kW-year, an increase of $2.02 per kW-year, or 14.6
percent. New rates were effective October 1, 2009.
2008 OATT: On August 28,
2008, IPC filed its informational filing with the FERC that contained the
annual update of the formula rate based on the 2007 test year. The rate
included in the filing was $18.88 per kW-year, a decrease of $0.85 per kW-year,
or 4.3 percent. New rates were effective October 1, 2008. IPC subsequently
adjusted its rates to $13.81 per kW-year in compliance with the January 15,
2009 order.
7. COMMITMENTS AND CONTINGENCIES:
Purchase Obligations
The following items are the
material changes to purchase obligations made outside of the ordinary course of
business since December 31, 2008:
IPC entered into a contract to purchase coal from the Black Butte Coal Company for use at the Jim Bridger generating plant, in which IPC holds a one-third ownership. The contract is expected to total $127 million from 2010 to 2014.
In February, 2009, IPC entered into a contract with EnerNOC to implement and operate a demand response program for its commercial and industrial customers. IPC estimates it will spend approximately $12.2 million on the program during the five year term of the contract.
IPC entered into two contracts with Siemens Energy, Inc. to purchase gas and steam turbine equipment and services for the Langley Gulch power plant. IPC estimates it will spend approximately $90 million on the contracts from 2009 through 2012.
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On May 7, 2009, IPC entered into an Engineering, Procurement and Construction Services Agreement (EPC Agreement) with Boise Power Partners Joint Venture, a joint venture consisting of Kiewit Power Engineers Co. and TIC-The Industrial Company for design, engineering, procurement, construction management and construction services for the Langley Gulch power plant. The total contract price to be paid by IPC under the EPC Agreement is approximately one-half of the projected $427 million total project cost for Langley Gulch from 2009 to 2012.
On June 30, 2009, IPC entered into a contract with Cargill Environmental Finance to purchase power from the Bettencourt B6 dairy anaerobic digester located near Jerome, Idaho. IPC expects the contract to total $8 million from 2009 to 2029. This agreement does not have a specified term.
In the third quarter, IPC entered into several purchased power agreements with wind and other alternate energy developers. These agreements are expected to total approximately $313 million from 2010 to 2030.
On August 12, 2009, IPC entered into a multi-year Tribal Water Rental Agreement with the Shoshone-Bannock Tribal Water Supply Bank. The agreement is expected to total approximately $10 million from 2009 to 2013.
On September 1, 2009, IPC entered into a purchased power contract with Idaho Winds, LLC. IPCs energy purchases under the contract are expected to total $105 million from 2012 to 2032.
Guarantees
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 $63 million at September 30,
2009. Bridger Coal Company has a reclamation trust fund set aside specifically
for the purpose of paying these reclamation costs. Bridger Coal Company
continually assesses the adequacy of the reclamation trust fund and recently revised
their estimate of future reclamation costs. In order to ensure that the
reclamation trust fund maintains adequate reserves, Bridger Coal Company will
adjust coal prices by adding a per ton surcharge. As an additional safeguard,
the Bridger Reclamation Trust Investment Committee has authority to compel a
per-ton surcharge to ensure adequate funding levels. Because of the existence
of the fund and the ability to apply a per ton surcharge, the estimated fair
value of this guarantee is minimal.
Legal Proceedings
From time to time IDACORP and IPC
are parties to legal claims, actions and complaints in addition to those
discussed below. Although they will vigorously defend against them, IDACORP
and IPC are unable to predict with certainty whether or not they will
ultimately be successful. However, based on the companies evaluation, they
believe that the resolution of these matters, taking into account existing
reserves, will not have a material adverse effect on IDACORPs or IPCs
consolidated financial positions, results of operations or cash flows.
Reference is made to IDACORPs
and IPCs Annual Report on Form 10-K for the year ended December 31, 2008, and
Quarterly Reports on Form 10-Q for the quarters ended March 31, 2009, and June
30, 2009, for a discussion of all material pending legal proceedings to which
IDACORP and IPC and their subsidiaries are parties. The following discussion
provides a summary of material developments that occurred in those proceedings
during the period covered by this report and of any new material proceedings
instituted during the period covered by this report.
Western Energy Proceedings at the FERC:
Throughout this report, the term western
energy situation is used to refer to the California energy crisis that
occurred during 2000 and 2001, and the energy shortages, high prices and
blackouts in the western United States. High prices for electricity in
California and in western wholesale markets during 2000 and 2001 caused
numerous purchasers of electricity in those markets to initiate proceedings
seeking refunds. Some of these proceedings (the western energy proceedings)
remain pending before the FERC or on appeal to the United States Court of
Appeals for the Ninth Circuit (Ninth Circuit).
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There are pending in the Ninth
Circuit approximately 200 petitions for review of numerous FERC orders
regarding the western energy situation, including the California refund
proceeding and show cause orders with respect to contentions of market
manipulation. Decisions in these appeals may have implications with respect to
other pending cases, including those to which IDACORP, IPC or IE are parties.
IDACORP, IPC and IE intend to vigorously defend their positions in these proceedings,
but are unable to predict the outcome of these matters, except as otherwise
stated below, or estimate the impact they may have on their consolidated
financial positions, results of operations or cash flows.
California Refund: This
proceeding originated with an effort by agencies of the State of California and
investor-owned utilities in California to obtain refunds for a portion of the
spot market sales from sellers of electricity into California markets from
October 2, 2000, through June 20, 2001. In April 2001, the FERC issued an
order stating that it was establishing a price mitigation plan for sales in the
California wholesale electricity market. The FERCs order also included the
potential for directing electricity sellers into California from October 2,
2000, through June 20, 2001, to refund portions of their spot market sales
prices if the FERC determined that those prices were not just and reasonable.
In July 2001, the FERC initiated the California refund proceeding including
evidentiary hearings to determine the scope and methodology for determining
refunds. After evidentiary hearings, the FERC issued an order on refund
liability on March 26, 2003, and later denied the numerous requests for
rehearing. The FERC also required the California Independent System Operator
(Cal ISO) to make a compliance filing calculating refund amounts. That
compliance filing has been delayed on a number of occasions and has not yet
been filed with the FERC.
IE and other parties petitioned
the Ninth Circuit for review of the FERCs orders on California refunds. As
additional FERC orders have been issued, further petitions for review have been
filed by potential refund payors, including IE, potential refund recipients and
governmental agencies. These cases have been consolidated before the Ninth
Circuit. Since the initiation of these cases, the Ninth Circuit has convened a
number of case management proceedings to organize these complex cases, while
identifying and severing discrete cases that can proceed to briefing and
decision and staying action on all of the other consolidated cases.
In its October 2005 decision in
the first of the severed cases, the Ninth Circuit concluded that the FERC
lacked refund authority over wholesale electrical energy sales made by
governmental entities and non-public utilities. In its August 2006 decision in
the second severed case, the Ninth Circuit ruled that all transactions that
occurred within the California Power Exchange (CalPX) and the Cal ISO markets
were proper subjects of the refund proceeding, refused to expand the
proceedings into the bilateral market, approved the refund effective date as
October 2, 2000, required the FERC to consider claims that some market
participants had violated governing tariff obligations at an earlier date than
the refund effective date, and expanded the scope of the refund proceeding to
include transactions within the CalPX and Cal ISO markets outside the limited
24-hour spot market and energy exchange transactions. These latter aspects of
the decision exposed sellers to increased claims for potential refunds. A
number of public entities filed petitions for panel rehearing in June 2007 and
certain marketers filed petitions for rehearing and rehearing en banc in
November 2007. Those requests were denied by the Ninth Circuit on April 6,
2009. The Ninth Circuit issued a mandate on April 15, 2009, thereby officially
returning the cases to the FERC for further action consistent with the courts
decision.
In 2005, the FERC established a
framework for sellers wanting to demonstrate that the generally applicable FERC
refund methodology interfered with the recovery of costs. IE and IPC made such
a cost filing but it was rejected by the FERC in March 2006. IE and IPC
requested rehearing of that rejection, but, consistent with obligations
established in a settlement which is described in the following paragraph, IE
and IPC withdrew that request for rehearing to the extent it pertained to the
disputes about the cost filing between IE and IPC and parties that had joined
the settlement. On June 18, 2009 FERC issued an order with respect to the cost
filings of other sellers and in that order also stated that it was not ruling
on the IE and IPC request for rehearing because it had been withdrawn. On July
8, 2009 IE and IPC sought further rehearing pointing out to the FERC that the
withdrawal pertained only to the parties with whom IE and IPC had settled. On
June 18, 2009, in a separate order, the FERC also ruled that net refund
recipients in the California refund proceeding were responsible for the costs
associated with all cost filings. Most of the parties that joined the IE and
IPC settlement described below were net refund recipients, but until the Cal
ISO completes its refund calculations it is uncertain whether any parties who
opted not to join the settlement are net refund recipients. If there are no
such parties, then the requests for rehearing will be moot. On August 7, 2009
the FERC issued an order extending the time for its consideration of the IE and
IPC request for rehearing. IE and IPC are unable to predict how or when the
FERC might rule on their requests for rehearing, but their effect is confined
to obligations of IE and IPC to the minority of market participants that opted
not to join the settlement described below. Accordingly, IE and IPC believe
this matter will not have a material adverse effect on their consolidated
financial positions, results of operations or cash flows.
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