UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(mark one) |
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| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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| For the quarterly period ended March 31, 2009 |
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| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission File Number: 1-10499
NORTHWESTERN CORPORATION
Delaware |
| 46-0172280 |
(State or other jurisdiction of |
| (I.R.S. Employer |
3010 W. 69th Street, Sioux Falls, South Dakota |
| 57108 |
(Address of principal executive offices) |
| (Zip Code) |
| Indicate by check mark whether the registrant (1) has 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 registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o | |
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Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o | |
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| Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non- |
accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. | |
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Large Accelerated Filer x Accelerated Filer o Non-accelerated Filer o Smaller Reporting Company o | |
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| Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange |
Act). Yes o No x | |
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| Indicate by check mark whether the registrant has filed all documents and reports required to be filed by |
Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by the court. Yes x No o | |
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| Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest |
practicable date: |
Common Stock, Par Value $.01
35,936,518 shares outstanding at April 17, 2009
NORTHWESTERN CORPORATION
FORM 10-Q
INDEX
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
On one or more occasions, we may make statements in this Quarterly Report on Form 10-Q regarding our assumptions, projections, expectations, targets, intentions or beliefs about future events. All statements other than statements of historical facts, included or incorporated by reference in this Quarterly Report, relating to management's current expectations of future financial performance, continued growth, changes in economic conditions or capital markets and changes in customer usage patterns and preferences are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.
Words or phrases such as “anticipates,” “may,” “will,” “should,” “believes,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” “targets,” “will likely result,” “will continue” or similar expressions identify forward-looking statements. Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. We caution that while we make such statements in good faith and believe such statements are based on reasonable assumptions, including without limitation, management's examination of historical operating trends, data contained in records and other data available from third parties, we cannot assure you that we will achieve our projections. Factors that may cause such differences include, but are not limited to:
| • | potential adverse federal, state, or local legislation or regulation or adverse determinations by regulators could have a material adverse effect on our liquidity, results of operations and financial condition; |
| • | unanticipated changes in availability of trade credit, creditworthiness of counterparties, usage, commodity prices, fuel supply costs or availability due to higher demand, shortages, weather conditions, transportation problems or other developments, may reduce revenues or may increase operating costs, each of which could adversely affect our liquidity and results of operations; |
| • | unscheduled generation outages or forced reductions in output, maintenance or repairs, which may reduce revenues and increase cost of sales or may require additional capital expenditures or other increased operating costs; and |
| • | adverse changes in general economic and competitive conditions in the U.S. financial markets and in our service territories. |
We have attempted to identify, in context, certain of the factors that we believe may cause actual future experience and results to differ materially from our current expectation regarding the relevant matter or subject area. In addition to the items specifically discussed above, our business and results of operations are subject to the uncertainties described under the caption “Risk Factors” which is part of the disclosure included in Part II, Item 1A of this Report.
From time to time, oral or written forward-looking statements are also included in our reports on Forms 10-K and 8-K, Proxy Statements on Schedule 14A, press releases, analyst and investor conference calls, and other communications released to the public. We believe that at the time made, the expectations reflected in all of these forward-looking statements are and will be reasonable. However, any or all of the forward-looking statements in this Quarterly Report on Form 10-Q, our reports on Forms 10-K and 8-K, our Proxy Statements on Schedule 14A and any other public statements that are made by us may prove to be incorrect. This may occur as a result of assumptions, which turn out to be inaccurate, or as a consequence of known or unknown risks and uncertainties. Many factors discussed in this Quarterly Report on Form 10-Q, certain of which are beyond our control, will be important in determining our future performance. Consequently, actual results may differ materially from those that might be anticipated from forward-looking statements. In light of these and other uncertainties, you should not regard the inclusion of any of our forward-looking statements in this Quarterly Report on Form 10-Q or other public communications as a representation by us that our plans and objectives will be achieved, and you should not place undue reliance on such forward-looking statements.
We undertake no obligation, to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. However, your attention is directed to any further disclosures made on related subjects in our subsequent annual and periodic reports filed with the Securities and Exchange Commission (SEC) on Forms 10-K, 10-Q and 8-K and Proxy Statements on Schedule 14A.
Unless the context requires otherwise, references to “we,” “us,” “our,” “NorthWestern Corporation,” “NorthWestern Energy,” and “NorthWestern” refer specifically to NorthWestern Corporation and its subsidiaries.
PART 1. FINANCIAL INFORMATION
ITEM 1. | FINANCIAL STATEMENTS |
NORTHWESTERN CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
(in thousands, except share data)
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| March 31, 2009 | December 31, 2008 | |||||
ASSETS |
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Current Assets: |
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Cash and cash equivalents |
| $ | 83,246 |
| $ | 11,292 |
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Restricted cash |
| 14,948 |
| 14,727 |
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Accounts receivable, net |
| 142,377 |
| 155,672 |
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Inventories |
| 34,929 |
| 70,741 |
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Regulatory assets |
| 57,435 |
| 46,905 |
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Prepaid energy supply |
| 4,019 |
| 2,734 |
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Deferred income taxes |
| 5,561 |
| 685 |
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Other |
| 6,636 |
| 10,661 |
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Total current assets |
| 349,151 |
| 313,417 |
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Property, Plant, and Equipment, Net |
| 1,839,603 |
| 1,839,699 |
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Goodwill |
| 355,128 |
| 355,128 |
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Regulatory assets |
| 226,190 |
| 233,102 |
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Other noncurrent assets |
| 21,777 |
| 20,691 |
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Total assets |
| $ | 2,791,849 |
| $ | 2,762,037 |
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LIABILITIES AND SHAREHOLDERS' EQUITY |
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Current Liabilities: |
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Current maturities of capital leases |
| $ | 1,329 |
| $ | 1,193 |
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Current maturities of long-term debt |
| 20,165 |
| 228,045 |
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Accounts payable |
| 66,289 |
| 94,685 |
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Accrued expenses |
| 239,704 |
| 215,431 |
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Regulatory liabilities |
| 43,692 |
| 49,223 |
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Total current liabilities |
| 371,179 |
| 588,577 |
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Long-term capital leases |
| 36,499 |
| 36,798 |
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Long-term debt |
| 880,464 |
| 634,011 |
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Deferred income taxes |
| 133,634 |
| 114,707 |
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Noncurrent regulatory liabilities |
| 231,924 |
| 222,969 |
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Other noncurrent liabilities |
| 363,639 |
| 401,442 |
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Total liabilities |
| 2,017,339 |
| 1,998,504 |
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Commitments and Contingencies (Note 14) |
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Shareholders' Equity: |
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Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 39,471,783 and 35,936,518, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued |
| 395 |
| 395 |
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Treasury stock at cost |
| (89,536 | ) | (89,487 | ) | |||
Paid-in capital |
| 806,498 |
| 805,900 |
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Retained earnings |
| 45,145 |
| 34,371 |
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Accumulated other comprehensive income |
| 12,008 |
| 12,354 |
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Total shareholders' equity |
| 774,510 |
| 763,533 |
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Total liabilities and shareholders' equity |
| $ | 2,791,849 |
| $ | 2,762,037 |
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See Notes to Condensed Consolidated Financial Statements
NORTHWESTERN CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
(in thousands, except per share amounts)
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| Three Months Ended March 31, |
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| 2009 |
| 2008 |
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Revenues |
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Electric |
| $ | 207,987 |
| $ | 196,619 |
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Gas |
| 158,803 |
| 171,643 |
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Other |
| 4,113 |
| 17,713 |
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Total Revenues |
| 370,903 |
| 385,975 |
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Operating Expenses |
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Cost of sales |
| 208,010 |
| 229,084 |
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Operating, general and administrative |
| 65,419 |
| 60,071 |
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Property and other taxes |
| 24,289 |
| 23,640 |
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Depreciation |
| 22,722 |
| 21,091 |
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Total Operating Expenses |
| 320,440 |
| 333,886 |
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Operating Income |
| 50,463 |
| 52,089 |
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Interest Expense |
| (15,134 | ) | (16,080 | ) | ||
Other Income |
| 591 |
| 662 |
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Income Before Income Taxes |
| 35,920 |
| 36,671 |
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Income Tax Expense |
| (13,107 | ) | (13,220 | ) | ||
Net Income |
| $ | 22,813 |
| $ | 23,451 |
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Average Common Shares Outstanding |
| 35,934 |
| 38,972 |
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Basic Earnings per Average Common Share |
| $ | 0.63 |
| $ | 0.60 |
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Diluted Earnings per Average Common Share |
| $ | 0.63 |
| $ | 0.59 |
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Dividends Declared per Average Common Share |
| $ | 0.335 |
| $ | 0.33 |
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See Notes to Condensed Consolidated Financial Statements
NORTHWESTERN CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(in thousands)
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| Three Months Ended March 31, |
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| 2009 |
| 2008 |
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OPERATING ACTIVITIES: |
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Net Income |
| $ | 22,813 |
| $ | 23,451 |
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Items not affecting cash: |
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Depreciation |
| 22,722 |
| 21,091 |
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Amortization of debt issue costs, discount and deferred hedge gain |
| 462 |
| 594 |
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Amortization of restricted stock |
| 598 |
| 1,194 |
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Equity portion of allowance for funds used during construction |
| (116 | ) | (172 | ) | ||
(Gain) loss on sale of assets |
| (269 | ) | 2 |
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Unrealized loss on derivative instruments |
| — |
| 1,203 |
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Deferred income taxes |
| 14,050 |
| 11,269 |
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Changes in current assets and liabilities: |
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Restricted cash |
| (221 | ) | 578 |
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Accounts receivable |
| 13,295 |
| 1,202 |
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Inventories |
| 35,812 |
| 34,007 |
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Prepaid energy supply costs |
| (1,285 | ) | 200 |
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Other current assets |
| 4,095 |
| 520 |
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Accounts payable |
| (28,620 | ) | (26,032 | ) | ||
Accrued expenses |
| 12,067 |
| 14,466 |
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Regulatory assets |
| 1,683 |
| 3.902 |
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Regulatory liabilities |
| (5,531 | ) | 1,519 |
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Other noncurrent assets |
| 7,671 |
| 5,729 |
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Other noncurrent liabilities |
| (34,096 | ) | (16,768 | ) | ||
Cash provided by operating activities |
| 65,130 |
| 77,955 |
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INVESTING ACTIVITIES: |
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Property, plant, and equipment additions |
| (18,509 | ) | (13,957 | ) | ||
Proceeds from sale of assets |
| 320 |
| 3 |
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Cash used in investing activities |
| (18,189 | ) | (13,954 | ) | ||
FINANCING ACTIVITIES: |
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Dividends on common stock |
| (12,039 | ) | (12,861 | ) | ||
Issuance of long-term debt |
| 250,000 |
| — |
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Repayment of long-term debt |
| (103,309 | ) | (18,047 | ) | ||
Line of credit borrowings |
| 237,000 |
| 14,000 |
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Line of credit repayments |
| (345,000 | ) | (26,000 | ) | ||
Financing costs |
| (1,639 | ) | (111 | ) | ||
Cash provided by (used in) financing activities |
| 25,013 |
| (43,019 | ) | ||
Increase in Cash and Cash Equivalents |
| 71,954 |
| 20,982 |
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Cash and Cash Equivalents, beginning of period |
| 11,292 |
| 12,773 |
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Cash and Cash Equivalents, end of period |
| $ | 83,246 |
| $ | 33,755 |
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Supplemental Cash Flow Information: |
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Cash paid during the period for: |
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Income Taxes |
| — |
| 38 |
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Interest |
| 10,333 |
| 12,088 |
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See Notes to Condensed Consolidated Financial Statements
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Reference is made to Notes to Financial Statements included in NorthWestern Corporation’s Annual Report)
(Unaudited)
(1) Nature of Operations and Basis of Consolidation
NorthWestern Corporation, doing business as NorthWestern Energy, provides electricity and natural gas to approximately 656,000 customers in Montana, South Dakota and Nebraska. We have generated and distributed electricity in South Dakota and distributed natural gas in South Dakota and Nebraska since 1923 and have distributed electricity and natural gas in Montana since 2002.
The Consolidated Financial Statements for the periods included herein have been prepared by NorthWestern Corporation, pursuant to the rules and regulations of the SEC. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (U.S. GAAP) requires management to make estimates and assumptions that may affect the reported amounts of assets, liabilities, revenues and expenses during the reporting period. Actual results could differ from those estimates. The unaudited Consolidated Financial Statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to fairly present our financial position, results of operations and cash flows. The actual results for the interim periods are not necessarily indicative of the operating results to be expected for a full year or for other interim periods. The Condensed Consolidated Financial Statements included herein have been prepared by NorthWestern, without audit, pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with U.S. GAAP have been condensed or omitted pursuant to such rules and regulations; however, management believes that the condensed disclosures provided are adequate to make the information presented not misleading. Management recommends that these unaudited Consolidated Financial Statements be read in conjunction with audited Consolidated Financial Statements and related footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2008.
(2) New Accounting Standards
Accounting Standards Issued
In April 2009, the Financial Accounting Standards Board (FASB) issued three final Staff Positions (FSPs) intended to provide additional application guidance and enhance disclosures regarding fair value measurements and impairments of securities. The FSPs are effective for interim and annual periods ending after June 15, 2009. FSP 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly (FSP 157-4), provides guidelines for making fair value measurements more consistent with the principles presented in FASB Statement No. 157, Fair Value Measurements, and relates to determining fair values when there is no active market or where the price inputs being used represent distressed sales. FSP 115-2 and 124-2, Recognition and Presentation of Other-Than-Temporary Impairments (FSP 115-2 and 124-2), provide additional guidance on presenting impairment losses on securities to bring consistency to the timing of impairment recognition, and provide clarity to investors about the credit and noncredit components of impaired debt securities that are not expected to be sold. The FSP also requires increased and more timely disclosures sought by investors regarding expected cash flows, credit losses, and an aging of securities with unrealized losses. We are still evaluating the impact of FSP 157-4, and FSP 115-2 and 124-2, if any, but do not expect them to have a material impact on our financial position or results of operations.
FSP 107-1, Interim Disclosures about Fair Value of Financial Instruments (FSP 107-1), increases the frequency of fair value disclosures required by Statements of Financial Accounting Standards (SFAS) No. 107, Disclosures About Fair Value of Financial Instruments (SFAS No. 107). FSP 107-1 relates to fair value disclosures for any financial instruments that are not currently reflected on the balance sheet of companies at fair value. Prior to issuing this FSP, fair values for these assets and liabilities were only required to be disclosed once a year. The FSP now requires these disclosures on a quarterly basis, providing qualitative and quantitative information about fair value estimates for all those financial instruments not measured on the balance sheet at fair value. Based on our evaluation of FSP 107-1, we expect to provide the disclosures required in SFAS No. 107 in interim periods beginning in June 2009.
Accounting Standards Adopted
In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (SFAS No. 141R), which replaces SFAS No. 141. SFAS 141R establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non controlling interest in the acquiree and the goodwill acquired. SFAS No. 141R also establishes disclosure requirements, which will enable users to evaluate the nature and financial effects of the business combination. SFAS No. 141R applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008, and interim periods within those fiscal years. SFAS No. 141R was effective beginning January 1, 2009; accordingly, any business combinations we engage in after this date will be recorded and disclosed in accordance with this statement. In addition, if any of our unrecognized tax benefits reverse, they will affect the income tax provision in the period of reversal rather than goodwill. See Note 4, Income Taxes, for further information.
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133 (SFAS No. 161). SFAS No. 161 changes the disclosure requirements for derivative instruments and hedging activities, requiring enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133), and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. The disclosures required by this statement are included in Note 7, Risk Management and Hedging Activities.
(3) Variable Interest Entities
FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, or FIN 46R, requires the consolidation of entities which are determined to be variable interest entities (VIEs) when we are the primary beneficiary of a VIE, which means we have a controlling financial interest. Certain long-term purchase power and tolling contracts may be considered variable interests under FIN 46R. We have various long-term purchase power contracts with other utilities and certain qualifying facility plants. After evaluation of these contracts, we believe one qualifying facility contract may constitute a variable interest entity under the provisions of FIN 46R. We are currently engaged in adversary proceedings with this qualifying facility and, while we have made exhaustive efforts, we have been unable to obtain the information necessary to further analyze this contract under the requirements of FIN 46R. We continue to account for this qualifying facility contract as an executory contract as we have been unable to obtain the necessary information from this qualifying facility in order to determine if it is a VIE and if so, whether we are the primary beneficiary. Based on the current contract terms with this qualifying facility, our estimated gross contractual payments aggregate approximately $487.8 million through 2025, and are included in Contractual Obligations and Other Commitments of Management's Discussion and Analysis.
(4) Income Taxes
We have unrecognized tax benefits of approximately $116.0 million as of March 31, 2009,including approximately $78.3 million, that if recognized, would impact our effective tax rate. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statutes of limitations within the next twelve months.
Our policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. During the three months ended March 31, 2009, we have not recognized expense for interest or penalties, and do not have any amounts accrued at March 31, 2009 and December 31, 2008, respectively, for the payment of interest and penalties.
Our federal tax returns from 2000 forward remain subject to examination by the Internal Revenue Service.
(5) Goodwill
There were no changes in our goodwill during the three months ended March 31, 2009. Goodwill by segment is as follows for both March 31, 2009 and December 31, 2008 (in thousands):
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Regulated electric |
| $ | 241,100 |
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Regulated natural gas |
| 114,028 |
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| $ | 355,128 |
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(6) Other Comprehensive Income
The FASB defines comprehensive income as all changes to the equity of a business enterprise during a period, except for those resulting from transactions with owners. For example, dividend distributions are excepted. Comprehensive income consists of net income and other comprehensive income (OCI). Net income may include such items as income from continuing operations, discontinued operations, extraordinary items, and cumulative effects of changes in accounting principles. OCI may include foreign currency translations, adjustments of minimum pension liability, and unrealized gains and losses on certain investments in debt and equity securities.
Comprehensive income is calculated as follows (in thousands):
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| Three Months Ended |
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| 2009 |
| 2008 |
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Net income |
| $ | 22,813 |
| $ | 23,451 |
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Other comprehensive income, net of tax: |
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Reclassification of net gains on hedging instruments from OCI to net income |
| (297 | ) | (297 | ) | ||
Foreign currency translation |
| (49 | ) | (82 | ) | ||
Comprehensive income |
| $ | 22,467 |
| $ | 23,072 |
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(7) Risk Management and Hedging Activities
Nature of Our Business and Associated Risks
We are exposed to certain risks related to the ongoing operations of our business, including the impact of market fluctuations in the price of electricity and natural gas commodities and changes in interest rates. Commodity price risk is one of our most significant risks due to our lack of ownership of natural gas reserves and minimal ownership of regulated electric generation assets within the Montana market. Several factors influence price levels and volatility. These factors include, but are not limited to, seasonal changes in demand, weather conditions, available generating assets within regions, transportation availability and reliability within and between regions, fuel availability, market liquidity, and the nature and extent of current and potential federal and state regulations.
Objectives and Strategies for Using Derivatives
To manage our exposure to fluctuations in commodity prices we routinely enter into derivative contracts, such as fixed-price forward purchase and sales contracts. The objective of these transactions is to fix the price for a portion of anticipated energy purchases to supply our regulated customers. These types of contracts are included in our electric and natural gas supply portfolios and are used to manage price volatility risk by taking advantage of seasonal fluctuations in market prices. While we may incur gains or losses on individual contracts, the overall portfolio approach is intended to provide price stability for consumers; therefore, these commodity costs are included in our cost tracking mechanisms. We do not maintain a trading portfolio, and do not currently have any derivatives transactions that are not used for risk management purposes. In addition, we may use interest rate swaps to manage our interest rate exposures associated with new debt issuances or to manage our exposure to fluctuations in interest rates on variable rate debt.
Accounting for Derivative Instruments
The accounting requirements for derivative instruments are governed by SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133), as amended, which requires that all derivatives be recognized in the balance sheet, either as assets or liabilities, at fair value, unless they meet the normal purchase and normal sales criteria. The changes in the fair value of recognized derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction.
We evaluate new and existing transactions and agreements to determine whether they are derivatives. Mark-to-market accounting is the default accounting treatment for all derivatives unless they qualify, and we specifically designate them, for one of the other accounting treatments. Derivatives designated for any of the elective accounting treatments must meet specific, restrictive criteria prescribed by SFAS No. 133, both at the time of designation and on an ongoing basis. The permitted accounting treatments include: normal purchase normal sale; cash flow hedge; fair value hedge; and mark-to-market.
We have applied the normal purchases and normal sales scope exception, as provided by SFAS No. 133 and interpreted by Derivatives Implementation Guidance Issue C15, to most of our contracts involving the physical purchase and sale of gas and electricity at fixed prices in future periods. Revenues and expenses from these contracts are reported on a gross basis in the appropriate revenue and expense categories as the commodities are received or delivered.
If we enter contracts to hedge the variability of cash flows related to forecasted transactions that qualify as cash flow hedges, the changes in the fair value of such derivative instruments are reported in other comprehensive income. The relationship between the hedging instrument and the hedged item must be documented to include the risk management objective and strategy and, at inception and on an ongoing basis, the effectiveness of the hedge in offsetting the changes in the cash flows of the item being hedged. Gains or losses accumulated in other comprehensive income are reclassified to earnings in the periods in which earnings are affected by the variability of the cash flows of the related hedged item. Any ineffective portion of all hedges would be recognized in current-period earnings. Cash flows related to these contracts are classified in the same category as the transaction being hedged.
Regulated Utility Commodity Prices
Certain contracts for the physical purchase of natural gas associated with our regulated gas utilities do not qualify for normal purchases under SFAS No. 133. We use the mark-to-market method of accounting for derivative contracts for which we do not elect or do not qualify for hedge accounting. Under the mark-to-market method of accounting, the fair value of these derivatives is recorded as assets and liabilities, with changes reflected in our consolidated statements of income. Since these contracts are for the purchase of energy supply sold to regulated customers, the accounting for these contracts is subject to SFAS No. 71, Accounting for the Effects of Certain Types of Regulations (SFAS No. 71). We record assets or liabilities based on the fair value of these derivatives, with offsetting positions recorded as regulatory liabilities or regulatory assets on the consolidated balance sheets. Upon settlement of these contracts, associated proceeds or costs are refunded to or collected from our customers consistent with regulatory requirements.
The following table discloses unrealized gains and losses on commodity contracts that are reported on the Consolidated Balance Sheets as a regulatory asset or a regulatory liability rather than as a component of accumulated other comprehensive income (AOCI) or in the Consolidated Statement of Income as of March 31, 2009. For more information on the determination of fair value see Note 8.
Mark-to-Market Transactions |
| Balance Sheet Location |
| Fair Value |
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| (in thousands) |
| |
Regulated natural gas net derivative liability |
| Accrued Expenses |
| $ | 41,313 |
|
|
|
|
|
|
|
|
Interest Rate Swaps Designated as Cash Flow Hedges
We have used interest rate swaps designated as cash flow hedges to manage our interest rate exposures associated with new debt issuances. These swaps were designated as cash-flow hedges under SFAS No. 133 with the effective portion of gains and losses, net of associated deferred income tax effects, recorded in AOCI in our Consolidated Balance Sheets. We reclassify these gains from AOCI into interest expense in our Consolidated Statements of Income during the periods in which the hedged interest payments occur. The following table shows the effect of these derivative instruments on the Consolidated Balance Sheet and Statement of Income:
Cash Flow Hedges |
| Amount of Gain Remaining in AOCI as of March 31, 2009 |
| Location of Gain Reclassified from AOCI to Income |
| Amount of Gain Reclassified from AOCI into Income during the three months ended March 31, 2009 |
| |||
|
|
|
|
|
|
|
| |||
Interest rate contracts |
| $ | 11,355 |
|
| Interest Expense |
| $ | 297 |
|
|
|
|
|
|
|
|
|
|
|
|
We expect to reclassify approximately $1.2 million of pre-tax gains on these cash-flow hedges from AOCI into interest expense during the next twelve months. These gains relate to swaps previously terminated, and we have no current interest rate swaps outstanding.
(8) Fair Value Measurements
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (SFAS No. 157), which defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. SFAS No. 157 became effective for most fair value measurements, other than leases and certain nonfinancial assets and liabilities, beginning January 1, 2008. SFAS No. 157 establishes a three-level fair value hierarchy and requires fair value disclosures based upon this hierarchy. In addition, FSP 157-2, which deferred the effective date for certain portions of SFAS No. 157 related to nonrecurring measurements of nonfinancial assets and liabilities was effective beginning with the first quarter of 2009. This FSP had no impact on our disclosures for the first quarter of 2009 and will be applied prospectively as applicable.
The table below disaggregates our net derivative assets and liabilities on a gross contract-by-contract basis as required by SFAS No. 157, and classifies each individual asset or liability within the appropriate level in the fair value hierarchy, regardless of whether a particular contract is eligible for netting against other contracts. These gross balances are intended solely to provide information on sources of inputs to fair value and do not represent our actual credit exposure or net economic exposure. Increases and decreases in the gross components presented in each of the levels in this table also do not indicate changes in the level of derivative activities. Rather, the primary factors affecting the gross amounts are commodity prices. We classify assets and liabilities within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement of each individual asset and liability taken as a whole. Normal purchases and sales transactions, as defined by SFAS No. 133, and certain other long-term power purchase contracts are not included in the fair values by source table as they are not recorded at fair value. See Note 7 for further discussion.
March 31, 2009 |
| Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) |
| Significant Other Observable Inputs (Level 2) |
| Significant Unobservable Inputs (Level 3) |
| Margin Cash Collateral Offset |
| Total Net Fair Value |
| |||||
|
| (in thousands) |
| |||||||||||||
Cash equivalents |
| $ | 70,000 |
| $ | — |
| $ | — |
| $ | — |
| $ | 70,000 |
|
Restricted cash |
|
| 14,948 |
|
| — |
|
| — |
|
| — |
|
| 14,948 |
|
Derivative asset (1) |
|
| — |
|
| 1,512 |
|
| — |
|
| — |
|
| 1,512 |
|
Derivative liability (1) |
|
| — |
|
| (42,825 | ) |
| — |
|
| — |
|
| (42,825 | ) |
Net derivative position |
|
| — |
|
| (41,313 | ) |
| — |
|
| — |
|
| (41,313 | ) |
Total |
| $ | 84,948 |
| $ | (41,313 | ) | $ | — |
| $ | — |
| $ | 43,635 |
|
(1) | The changes in the fair value of these derivatives are deferred as a regulatory asset or liability until the contracts are settled. Upon settlement, associated proceeds or costs are passed through the applicable cost tracking mechanism to customers. |
Cash equivalents and restricted cash represent money market mutual funds. Fair value for the commodity derivatives was determined using internal models based on quoted forward commodity prices. SFAS No. 157 also requires that fair value measurements reflect a credit-spread adjustment based on an entity’s own credit standing. Consideration of our own credit risk did not have a material impact on our fair value measurements. We present our derivative assets and liabilities on a net basis in the Consolidated Balance Sheets.
Certain of these derivative instruments contain provisions that require us to maintain an investment grade credit rating from each of the major credit rating agencies. If our debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position on March 31, 2009, is $38.9 million, for which we have posted collateral of $11 million in the normal course of business. If the credit-risk-related contingent features underlying these agreements were triggered on March 31, 2009, we would be required to post an additional $17.9 million of collateral to our counterparties.
(9) Financing Activities
In March 2009, we issued $250 million of Montana First Mortgage Bonds at a fixed interest rate of 6.34% maturing April 1, 2019. We used the proceeds to redeem our $100 million Colstrip Lease Holdings LLC term loan and repay outstanding borrowings on our revolving credit facility. Remaining funds will be used to repay other outstanding debt obligations related to Colstrip Unit 4, fund a portion of the costs of the proposed Mill Creek generation project if approved, and fund future capital expenditures.
(10) Regulatory Matters
Colstrip Unit 4
In January 2009, as a result of a 2008 Montana Public Service Commission (MPSC) order, we placed our joint ownership interest in Colstrip Unit 4, which had previously been an unregulated asset, into utility rate base at a value of $407 million, and applied the provisions of SFAS No. 71 to our joint ownership interest in Colstrip Unit 4. The order included a capital structure of 50% equity and 50% debt, an authorized return on equity of 10% and cost of debt of 6.5%, which are set for 34 years, based on the estimated useful life of the plant. Our interest in Colstrip Unit 4 is expected to supply approximately 13% of our base-load requirements through 2010 and approximately 25% thereafter (upon expiration of an existing power sale agreement). The generation related costs and return on rate base related to Colstrip Unit 4, including the cost of any replacement power purchased during outages, will be included in our annual electric supply tracker filing for inclusion in customer rates.
Mill Creek Generating Station
In August 2008, we filed a request with the MPSC for advanced approval to construct a 150 MW natural gas fired facility at an estimated cost of $206 million. The Mill Creek Generating Station would provide regulating resources to balance our transmission system in Montana to maintain reliability and enable additional wind power to be integrated onto the network to meet future renewable energy portfolio needs. We have revised our initial capital request included in the filing to $201.6 million, and requested a capital structure of 50% equity and 50% debt and an authorized return on equity of 10.75%. The MPSC conducted hearings during the first quarter of 2009 and we anticipate an MPSC decision during the second quarter of 2009.
Western Electricity Coordination Council Compliance Audit
We have completed our compliance audit under the compliance monitoring and enforcement program of the Western Electricity Coordinating Council (WECC), a regional electric reliability organization. WECC has responsibility for monitoring and enforcing compliance with mandatory reliability standards within the U.S. established by the North American Electric Reliability Corporation (NERC). In connection with the compliance audit, WECC found no violations of the applicable standards. Prior to the audit, we submitted 18 mitigation plans to WECC. We have completed 16 of those mitigation plans, which WECC approved and found to be compliant. One mitigation plan is awaiting final approval from WECC, and completion and approval of the final mitigation plan is pending.
(11) Segment Information
We operate regulated electric and regulated natural gas business units, which are considered reportable business segments under SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information. The remainder of our operations are presented as other. While it is not considered a business unit, other primarily consists of our remaining unregulated natural gas operations, the wind down of our captive insurance subsidiary and our unallocated corporate costs. As discussed in Note 10, the operations of our joint ownership interest in Colstrip Unit 4 were unregulated through December 31, 2008, and are included in regulated operations beginning January 1, 2009, due to an MPSC rate order. We have not revised the 2008 segment presentation due to the nature of the transfer of the asset from unregulated to the regulated business.
We evaluate the performance of these segments based on gross margin. The accounting policies of the operating segments are the same as the parent except that the parent allocates some of its operating expenses to the operating segments according to a methodology designed by management for internal reporting purposes and involves estimates and assumptions. Financial data for the business segments are as follows (in thousands):
Three Months Ended |
| Regulated |
|
|
|
|
|
|
| |||||||
March 31, 2009 |
| Electric |
| Gas |
| Other |
| Eliminations |
| Total |
| |||||
Operating revenues |
| $ | 207,987 |
| $ | 158,803 |
| $ | 4,651 |
| $ | (538 | ) | $ | 370,903 |
|
Cost of sales |
| 94,748 |
| 108,938 |
| 4,324 |
| — |
| 208,010 |
| |||||
Gross margin |
| 113,239 |
| 49,865 |
| 327 |
| (538 | ) | 162,893 |
| |||||
Operating, general and administrative |
| 42,979 |
| 21,815 |
| 1,163 |
| (538 | ) | 65,419 |
| |||||
Property and other taxes |
| 18,017 |
| 6,227 |
| 45 |
| — |
| 24,289 |
| |||||
Depreciation |
| 18,391 |
| 4,323 |
| 8 |
| — |
| 22,722 |
| |||||
Operating income (loss) |
| 33,852 |
| 17,500 |
| (889 | ) | — |
| 50,463 |
| |||||
Interest expense |
| (11,150 | ) | (3,068 | ) | (916 | ) | — |
| (15,134 | ) | |||||
Other income |
| 291 |
| 268 |
| 32 |
| — |
| 591 |
| |||||
Income tax (expense) benefit |
| (8,067 | ) | (5,475 | ) | 435 |
| — |
| (13,107 | ) | |||||
Net Income (loss) |
| $ | 14,926 |
| $ | 9,225 |
| $ | (1,338) |
| $ | — |
|
| 22,813 |
|
Total assets |
| $ | 1,956,083 |
| $ | 824,058 |
| $ | 11,708 |
| $ | — |
| $ | 2,791,849 |
|
Capital expenditures |
| $ | 14,846 |
| $ | 3,663 |
| $ | — |
| $ | — |
| $ | 18,509 |
|
Three months ended, |
| Regulated |
| Unregulated |
|
|
|
|
|
|
| ||||||||
March 31, 2008 |
| Electric |
| Gas |
| Electric |
| Other |
| Eliminations |
| Total |
| ||||||
Operating revenues |
| $ | 196,619 |
| $ | 171,643 |
| $ | 20,404 |
| $ | 7,922 |
| $ | (10,613 | ) | $ | 385,975 |
|
Cost of sales |
| 103,055 |
| 121,308 |
| 7,032 |
| 7,764 |
| (10,075 | ) | 229,084 |
| ||||||
Gross margin |
| 93,564 |
| 50,335 |
| 13,372 |
| 158 |
| (538 | ) | 156,891 |
| ||||||
Operating, general and administrative |
| 35,370 |
| 17,924 |
| 3,677 |
| 3,638 |
| (538 | ) | 60,071 |
| ||||||
Property and other taxes |
| 16,429 |
| 6,328 |
| 879 |
| 4 |
| — |
| 23,640 |
| ||||||
Depreciation |
| 15,395 |
| 3,883 |
| 1,805 |
| 8 |
| — |
| 21,091 |
| ||||||
Operating income (loss) |
| 26,370 |
| 22,200 |
| 7,011 |
| (3,492 | ) | — |
| 52,089 |
| ||||||
Interest expense |
| (9,306 | ) | (3,230 | ) | (3,176 | ) | (368 | ) | — |
| (16,080 | ) | ||||||
Other income |
| 257 |
| 309 |
| 13 |
| 83 |
| — |
| 662 |
| ||||||
Income tax (expense) benefit |
| (5,687 | ) | (7,290 | ) | (1,715 | ) | 1,472 |
| — |
| (13,220 | ) | ||||||
Net income (loss) |
| $ | 11,634 |
| $ | 11,989 |
| $ | 2,133 |
| $ | (2,305 | ) | $ | — |
| $ | 23,451 |
|
Total assets |
| $ | 1,532,317 |
| $ | 748,111 |
| $ | 250,229 |
| $ | 17,649 |
| $ | — |
| $ | 2,548,306 |
|
Capital expenditures |
| $ | 10,738 |
| $ | 2,726 |
| $ | 493 |
| $ | — |
| $ | — |
| $ | 13,957 |
|
(12) Earnings Per Share
Basic earnings per share is computed by dividing earnings applicable to common stock by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution of common stock equivalent shares that could occur if all unvested shares were to vest. Common stock equivalent shares are calculated using the treasury stock method. Performance share awards are included in diluted weighted-average number of shares outstanding based upon what would be issued if the end of the reporting period was the end of the performance period of the award.
The dilutive effect is computed by dividing earnings applicable to common stock by the weighted average number of common shares outstanding plus the effect of the outstanding unvested restricted shares and deferred share units. Average shares used in computing the basic and diluted earnings per share are as follows:
|
| Three Months Ended |
| ||
|
| March 31, 2009 |
| March 31, 2008 |
|
Basic computation |
| 35,933,877 |
| 38,972,507 |
|
Dilutive effect of |
|
|
|
|
|
Nonvested shares, performance share awards and deferred share units |
| 388,296 |
| 445,331 |
|
|
|
|
|
| |
Diluted computation |
| 36,322,173 |
| 39,417,838 |
|
(13) Employee Benefit Plans
Net periodic benefit cost for our pension and other postretirement plans consists of the following (in thousands):
|
| Pension Benefits |
| Other Postretirement Benefits |
| ||||||||
|
| Three Months Ended March 31, |
| ||||||||||
|
| 2009 |
| 2008 |
| 2009 |
| 2008 |
| ||||
Components of Net Periodic Benefit Cost |
|
|
|
|
|
|
|
|
| ||||
Service cost |
| $ | 1,981 |
| $ | 2,170 |
| $ | 133 |
| $ | 150 |
|
Interest cost |
| 6,081 |
| 5,726 |
| 621 |
| 611 |
| ||||
Expected return on plan assets |
| (6,539 | ) | (6,756 | ) | (319 | ) | (289 | ) | ||||
Amortization of prior service cost |
| 61 |
| 60 |
| — |
|
|
| ||||
Recognized actuarial gain |
| — |
| (141 | ) | (154 | ) | (107 | ) | ||||
Net Periodic Benefit Cost |
| $ | 1,584 |
| $ | 1,059 |
| $ | 281 |
| $ | 365 |
|
Pension costs in Montana are included in expense on a pay as you go (cash funding) basis. The MPSC authorized the recognition of pension costs based on an average of the annual funding to be made over an 8-year period for the calendar years 2005 through 2012, therefore our pension expense differs from the net periodic benefit cost. During the first quarter of 2009, we contributed approximately $43.2 million to our pension plans. We experienced losses on plan assets of approximately 6.0% during the first quarter of 2009. If asset returns do not improve during the remainder of 2009, we will likely need to increase our funding estimates.
(14) Commitments and Contingencies
Environmental Liabilities
Our liability for environmental remediation obligations is estimated to range between $22.5 million to $43.8 million. As of March 31, 2009, we have a reserve of approximately $31.9 million. Environmental costs are recorded when it is probable we are liable for the remediation and we can reasonably estimate the liability. Over time, as specific laws are implemented and we gain experience in operating under them, a portion of the costs related to such laws will become determinable, and we may seek authorization to recover such costs in rates or seek insurance reimbursement as applicable; therefore, we do not expect these costs to have a material adverse effect on our consolidated financial position or ongoing operations. There can be no assurance, however, of regulatory recovery.
We maintain insurance coverage for environmental related exposure, and are currently seeking insurance recoveries. We anticipate receiving in excess of $5.0 million during the second quarter of 2009. Approximately 90% of these anticipated recoveries relate to previously incurred Montana generation related environmental remediation costs, while approximately 10% of the anticipated recoveries relate to previously incurred costs and estimated future costs for other Montana matters. If we receive these proceeds, the portion related to previously incurred Montana generation related costs will be recognized as a reduction to operating expenses in the period received and the remaining portion may be returned to customers pending regulatory review.
Manufactured Gas Plants - Approximately $26.8 million of our environmental reserve accrual is related to manufactured gas plants. A formerly operated manufactured gas plant located in Aberdeen, South Dakota, has been identified on the Federal Comprehensive Environmental Response, Compensation, and Liability Information System (CERCLIS) list as contaminated with coal tar residue. We are currently investigating, characterizing, and initiating remedial actions at the Aberdeen site pursuant to work plans approved by the South Dakota Department of Environment and Natural Resources. Our current reserve for remediation costs at this site is approximately $13.3 million, and we estimate that approximately $10 million of this amount will be incurred during the next five years.
We also own sites in North Platte, Kearney and Grand Island, Nebraska on which former manufactured gas facilities were located. During 2005, the Nebraska Department of Environmental Quality (NDEQ) conducted Phase II investigations of soil and groundwater at our Kearney and Grand Island sites. On March 30, 2006 and May 17, 2006, the NDEQ released to us the Phase II Limited Subsurface Assessment performed by the NDEQ's environmental consulting firm for Kearney and Grand Island, respectively. We have conducted limited additional site investigation, assessment and monitoring work at Kearney and Grand Island. At present, we cannot determine with a reasonable degree of certainty the nature and timing of any risk-based remedial action at our Nebraska locations.
In addition, we own or have responsibility for sites in Butte, Missoula and Helena, Montana on which former manufactured gas plants were located. An investigation conducted at the Missoula site did not require entry into the Montana Department of Environmental Quality (MDEQ) voluntary remediation program, but required preparation of a groundwater monitoring plan. The Butte and Helena sites were placed into the MDEQ's voluntary remediation program for cleanup due to excess regulated pollutants in the groundwater. We have conducted additional groundwater monitoring at the Butte and Missoula sites and, at this time, we believe natural attenuation should address the conditions at these sites; however, additional groundwater monitoring will be necessary. In Helena, we continue limited operation of an oxygen delivery system implemented to enhance natural biodegradation of pollutants in the groundwater and we are currently evaluating limited source area treatment/removal options. Monitoring of groundwater at this site is ongoing and will be necessary for an extended time. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of risk-based remedial action at the Helena site or if any additional actions beyond monitored natural attenuation will be required.
Milltown Dam Removal - Our subsidiary, Clark Fork and Blackfoot, LLC (CFB), owns the former Milltown Dam site, and previously operated a three MW hydroelectric generation facility located at the confluence of the Clark Fork and Blackfoot Rivers. Dam removal activities were initiated during the first quarter of 2008 and are expected to be complete in 2009. Our remaining obligation to the State of Montana related to this site is approximately $0.6 million, which will be solely funded through the transfer of land and water rights associated with the former Milltown Dam operations to the State of Montana.
Coal-Fired Plants- We have a joint ownership interest in four electric generating plants, all of which are coal fired and operated by other companies. We have an undivided interest in these facilities and are responsible for our proportionate share of the capital and operating costs while being entitled to our proportionate share of the power generated. In addition, a significant portion of the electric supply we procure in the market is generated by coal-fired plants.
Global Climate Change - There is a growing concern nationally and internationally about global climate change and the contribution of emissions of greenhouse gases including, most significantly, carbon dioxide. This concern has led to increased interest in legislation at the federal level, actions at the state level, as well as litigation relating to greenhouse emissions, including a U.S. Supreme Court decision holding that the EPA relied on improper factors in deciding not to regulate carbon dioxide emissions from motor vehicles under the Clean Air Act. In April 2009, the EPA issued a proposed finding that greenhouse gas emissions endanger the public health and welfare. The EPA’s proposed finding indicated that the current and projected levels of six greenhouse gas emissions – carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulfur hexafluoride contribute to climate change. The proposed findings were not accompanied by proposed regulations, and it is uncertain whether the EPA will finalize the endangerment finding before proposing regulations or whether it will propose regulations more quickly. Increased pressure for carbon dioxide emissions reduction also is coming from investor organizations.
Specifically, coal-fired plants have come under scrutiny due to their emissions of carbon dioxide. There is a gap between proposed emissions reduction levels and the current capabilities of technology, as there is no currently available commercial scale technology that would achieve the proposed reduction levels. Such technology may not be available within a timeframe consistent with the implementation of climate change legislation or at all. To the extent that such technology does become available, we can provide no assurance that it will be suitable for installation at the generation facilities we have a joint interest in, or on a cost effective basis.
The current presidential administration has indicated it will pursue policies to regulate greenhouse gas emissions. While we cannot predict the impact of any legislation until final, if legislation or regulations are passed at the federal or state levels imposing mandatory reductions of carbon dioxide and other greenhouse gases on generation facilities, the cost to us and / or our customers could be significant.
Clean Air Act - The Clean Air Act Amendments of 1990 and subsequent amendments stipulate limitations on sulfur dioxide and nitrogen oxide emissions from coal-fired power plants. We comply with these existing emission requirements through purchase of sub-bituminous coal, and we believe that we are in compliance with all presently applicable environmental protection requirements and regulations with respect to these plants.
In June 2008, the Sierra Club filed a lawsuit in U.S. District Court in South Dakota against NorthWestern and the other joint owners of the Big Stone plant alleging certain violations of the Clean Air Act, which has been dismissed by the Court. For further discussion see the “Legal Proceedings – Sierra Club” section below.
Clean Air Mercury Rule– In March 2005, the EPA issued the Clean Air Mercury Regulations (CAMR) to reduce the emissions of mercury from coal-fired facilities through a market-based cap-and-trade program. Although the U.S. Court of Appeals for the District of Columbia Circuit struck down CAMR, the state of Montana has finalized its own rules more stringent than CAMR's 2018 cap that would require every coal-fired generating plant in the state to achieve reduction levels by 2010. The joint owners of Colstrip Unit 4 currently plan to install chemical injection technologies to meet these requirements. We estimate our share of the capital cost would be approximately $1 million, with ongoing annual operating costs of approximately $3 million. If the Montana rules are maintained in their current form and enhanced chemical injection technologies are not sufficiently developed to meet the Montana levels of reduction by 2010, then adsorption/absorption technology with fabric filters at the Colstrip Unit 4 generation facility would be required, which could represent a material cost. Recent tests have shown that it may be possible to meet the Montana rules with more refined chemical injection technology combined with adjustments to boiler/fireball dynamics at a minimal cost. We are continuing to work with the other Colstrip owners to determine the ultimate financial impact of these rules.
Other
We continue to manage equipment containing polychlorinated biphenyl (PCB) oil in accordance with the EPA's Toxic Substance Control Act regulations. We will continue to use certain PCB-contaminated equipment for its remaining useful life and will, thereafter, dispose of the equipment according to pertinent regulations that govern the use and disposal of such equipment.
We routinely engage the services of a third-party environmental consulting firm to assist in performing a comprehensive evaluation of our environmental reserve. Based upon information available at this time, we believe that the current environmental reserve properly reflects our remediation exposure for the sites currently and previously owned by us. The portion of our environmental reserve applicable to site remediation may be subject to change as a result of the following uncertainties:
| • | We may not know all sites for which we are alleged or will be found to be responsible for remediation; and |
| • | Absent performance of certain testing at sites where we have been identified as responsible for remediation, we cannot estimate with a reasonable degree of certainty the total costs of remediation. |
LEGAL PROCEEDINGS
Bankruptcy Related Litigation
Magten Settlement - In July 2008, the U.S. Bankruptcy Court approved a global settlement agreement between NorthWestern, Magten Asset Management (Magten), Law Debenture Trust Company of New York (Law Debenture) and the Plan Committee that resolves the litigation related to claims of holders of quarterly income preferred securities (QUIPS) in our Chapter 11 bankruptcy case. On July 23, 2008 the Ad Hoc Committee filed an appeal to the global settlement agreement; however, we and the other parties involved waived a closing condition and closed on the settlement on July 24, 2008. Under the approved global settlement agreement Magten, Law Debenture, their lawyers and the holders of the QUIPS, collectively received a cash payment of $23 million to be allocated amongst them in accordance with the terms of the global settlement agreement. The cash payment was funded by our repurchase of 782,059 shares held in the disputed claims reserve established under our confirmed Plan of Reorganization, as discussed below. This settlement resolves the last significant claim from the bankruptcy case. The parties to the appeal have submitted all appellate briefs, and the Ad Hoc Committee has requested oral argument on the appeal. The appeal remains pending before The United States District Court of Delaware, which has not yet decided the request for oral argument.
Disputed Claims Reserve - In July 2008, we obtained bankruptcy court approval for the purchase of the remaining shares in the disputed claims reserve. The motion allowed unsecured creditors and debt holders in Class 7 and Class 9 to elect to receive their surplus distribution in stock or cash. We repurchased 1.1 million shares from the disputed claims reserve for those claimants who elected a cash payment. In October 2008, we filed a motion requesting the Bankruptcy Court to determine the disputed claims reserve is taxable as a grantor trust. The Internal Revenue Service (IRS) filed an objection to the motion; however we have reached an agreement in principle with the IRS and the Plan Committee to settle this matter. If the matter is resolved as contemplated, it would not have a material impact on our financial position, results of operations or cash flows. We anticipate finalizing a settlement agreement and seeking Bankruptcy Court approval by the third quarter of 2009. Upon resolution of this motion, we expect to distribute the remaining cash and shares in the disputed claims reserve to eligible claimants.
McGreevey Litigation
We are one of several defendants in a class action lawsuit entitled McGreevey, et al. v. The Montana Power Company, et al., now pending in U.S. District Court in Montana. The lawsuit, which was filed by former shareholders of The Montana Power Company (most of whom became shareholders of Touch America Holdings, Inc. as a result of a corporate reorganization of The Montana Power Company), contends that the disposition of various generating and energy-related assets by The Montana Power Company are void because of the failure to obtain shareholder approval for the transactions. Plaintiffs thus seek to reverse those transactions, or receive fair value for their stock as of late 2001, when plaintiffs claim shareholder approval should have been sought. NorthWestern is named as a defendant due to the fact that we purchased The Montana Power L.L.C. (now CFB), which plaintiffs claim is a successor to the Montana Power Company.
We were one of the defendants in a second class action lawsuit brought by the McGreevey plaintiffs, also entitled McGreevey, et al. v. The Montana Power Company, et al., pending in U.S. District Court in Montana. This lawsuit sought, among other things, the avoidance of the transfer of assets from CFB to us, declaration that the assets were fraudulently transferred and were not property of our bankruptcy estate, the imposition of constructive trusts over the transferred assets, and the return of such assets to CFB. We were dismissed from this lawsuit by the U.S. District Court in Montana in February 2009.
In June 2006, we and the McGreevey plaintiffs entered into an agreement to settle all claims brought by the McGreevey plaintiffs in all of the actions described above, wherein the McGreevey plaintiffs executed a covenant not to execute against us, and we quit claimed any interest we had in any claims we may or may not have under any applicable directors and officers liability insurance policy, against any insurers for contractual or extracontractual damages, and against certain defendants in the McGreevey lawsuits. In November 2006, this agreement was approved by the Delaware Bankruptcy Court and the claims were discharged. We filed a joint motion with the plaintiffs' attorneys in U.S. District Court in Montana to dismiss the claims against us in the McGreevey lawsuits. On March 16, 2007, the U.S. District Court in Montana denied the motion to dismiss us from the McGreevey
lawsuits, questioning the benefits of the settlement to be received by the class members in the settlement and the authority of the plaintiffs' counsel to have negotiated the settlement without a class having been certified by the court. On January 11, 2008, the U.S. District Court in Montana suggested that the settlement agreement was invalid because the plaintiffs' attorneys had not secured the court's permission to engage in settlement discussions. The District Court enjoined the plaintiffs from taking any further action in any of these matters. The plaintiffs appealed the District Court’s January 11th injunction to the Ninth Circuit U.S. Court of Appeals, where on July 10, 2008, the Ninth Circuit U.S. Court of Appeals heard oral arguments; a determination is pending. We believe that given the scope of the Order confirming the Plan and the injunctions issued by the Delaware Bankruptcy Court which channeled the claims to the D&O Trust, we have limited exposure to the plaintiffs for damages arising from the McGreevey claims. In January 2009, the U.S. District Court in Montana held a status conference and issued a bench ruling asking all parties to submit memorandum discussing the party’s willingness to enter into a global settlement of the matter. We responded noting our position that all matters are resolved against NorthWestern as discussed above and noted that we are willing to work with the other parties and the Court. We will continue to vigorously defend against these claims and explore ways to remove ourselves from the lawsuit.
Ammondson
In April 2005, a group of former employees of the Montana Power Company filed a lawsuit in the state court of Montana against us and certain officers styled Ammondson, et al. v. NorthWestern Corporation, et al. The former employees have alleged that by moving to terminate their supplemental retirement contracts in our bankruptcy proceeding without having listed them as claimants or giving them notice of the disclosure statement and plan of reorganization, that we breached those contracts, and breached a covenant of good faith and fair dealing under Montana law and by virtue of filing a complaint in our bankruptcy case against those employees from seeking to prosecute their state court action against NorthWestern, we had engaged in malicious prosecution and should be subject to punitive damages. In May 2005, the Bankruptcy Court found that it did not have jurisdiction over these contracts, dismissed our action against these former employees, and transferred our motion to terminate the contracts to Montana state court, thereby removing any claim from consideration in the resolution of our bankruptcy case. In February 2007, a jury verdict was rendered against us in Montana state court, which ordered us to pay $17.4 million in compensatory and $4.0 million in punitive damages. Due to the verdict, we recognized a loss of $19.0 million in our 2006 results of operations to increase our recorded liability related to this claim. The Montana state court reviewed the amount of the punitive damages under state law and did not alter the amount. We have appealed the judgment to the Montana Supreme Court and posted a $25.8 million bond. We intend to vigorously pursue the appeal; however, there can be no assurance that we will prevail in our efforts. Interest accrues on the verdict amount during the appeal process.
Sierra Club
On June 10, 2008, Sierra Club filed a complaint in the U.S. District Court for the District of South Dakota (Northern Division) against us and two other co-owners (the Defendants) of Big Stone Generating Station (Big Stone). The complaint alleged certain violations of the (i) Prevention of Significant Deterioration and (ii) New Source Performance Standards (NSPS) provisions of the Clean Air Act and certain violations of the South Dakota State Implementation Plan (South Dakota SIP). The action further alleged that the Defendants modified and operated Big Stone without obtaining the appropriate permits, without meeting certain emissions limits and NSPS requirements and without installing appropriate emission control technology, all allegedly in violation of the Clean Air Act and the South Dakota SIP. Sierra Club alleged that Defendants’ actions have contributed to air pollution and visibility impairment and have increased the risk of adverse health effects and environmental damage. Sierra Club sought both declaratory and injunctive relief to bring the Defendants into compliance with the Clean Air Act and the South Dakota SIP and to require Defendants to remedy the alleged violations. Sierra Club also sought unspecified civil penalties, including a beneficial mitigation project. We believed that these claims were without merit and that Big Stone was and is being operated in compliance with the Clean Air Act and the South Dakota SIP.
The Defendants filed a Motion to Dismiss the Sierra Club complaint on August 12, 2008, based on certain of the claims being barred by statute of limitations and the remaining claims being an impermissible collateral attack on valid Clean Air Permits issued by the state of South Dakota. On September 22, 2008, the Sierra Club filed its response. Additionally on September 22, 2008, the Sierra Club sent a Notice of Intent to Sue for additional violations of the Clean Air Act at Big Stone, which are similar in nature and seek the same remedies as the June
2008 complaint. On March 31, 2009, the U.S. District Court for the District of South Dakota (Northern Division) entered a Memorandum Opinion and Order granting Defendants’ Motion to Dismiss the Sierra Club Complaint. The deadline to appeal the Defendants’ dismissal has not yet expired.
Other Litigation and Contingencies
Colstrip Energy Limited Partnership
In December 2006, the MPSC issued an order finalizing certain qualifying facility rates for the periods July 1, 2003 through June 30, 2006. Colstrip Energy Limited Partnership (CELP) is a qualifying facility with which we have a power purchase agreement through 2025. Under the terms of the power purchase agreement with CELP, energy and capacity rates were fixed through June 30, 2004 (with a small portion to be set by the MPSC's determination of rates in the annual avoided cost filing), and beginning July 1, 2004 through the end of the contract, energy and capacity rates are to be determined each year pursuant to a formula. CELP filed a complaint against NorthWestern and the MPSC in Montana district court on July 6, 2007 which contests the MPSC’s order. CELP is disputing inputs in to the rate-setting formula, used by us and approved by the MPSC on an annual basis, to calculate energy and capacity payments for the contract years 2004, 2005 and 2006. CELP is claiming that NorthWestern breached the power purchase agreement causing damages, which CELP asserts are not presently known but believed to be approximately $22 million for contract years 2004, 2005 and 2006. If the MPSC's order is upheld in its current form, we anticipate reducing our QF liability by approximately $25 to $50 million as our estimate of energy and capacity rates for the remainder of the contract period would be reduced. A temporary restraining order was agreed to by the parties and has been issued restraining us from implementing the rates finalized by the MPSC order pending an ultimate decision on CELP's complaint. On June 30, 2008, the state district court judge granted our motions to enforce the contractual arbitration provision and to stay all discovery and proceedings against us, pending the decision of the required contract arbitration. The state district court, on June 30, 2008, also granted a motion by the MPSC to bifurcate, having the effect of separating the issues between contract/tort claims and the administrative appeal of the MPSC’s orders; which we supported. The order also stayed the appellate decision pending a decision in our arbitration proceedings. Arbitration is scheduled for June 2009. We believe that we will prevail in the arbitration and intend to vigorously defend our positions.
Colstrip Unit 4 Coal Royalties
Relative to our joint ownership in Colstrip Unit 4, the Mineral Management Service of the United States Department of Interior (MMS) issued two orders to Western Energy Company (WECO) in 2002 and 2003 to pay additional royalties concerning coal sold to Colstrip Units 3 and 4 owners. The orders assert that additional royalties are owed as a result of WECO not paying royalties in connection with revenue received by WECO from the Colstrip Units 3 and 4 owners under a coal transportation agreement during the period October 1, 1991 through December 31, 2001. On April 28, 2005, the appeals division of the MMS issued an order that reduced the amount claimed based upon the applicable statute of limitations. Further, on September 28, 2006, the MMS issued an order to pay additional royalties on the basis of an audit of WECO's royalty payments during the three years 2002 to 2004. WECO appealed these orders to the Interior Board of Land Appeals of the United States Department of Interior (IBLA) who affirmed the orders on September 12, 2007. WECO filed a complaint and request for declaratory ruling in the U.S. District Court for the District of Columbia in January 2008 seeking relief from the orders issued by the MMS and affirmed by the IBLA, and we continue to monitor the appeals process. The Colstrip Units 3 and 4 owners and WECO currently dispute the responsibility of the expenses if the MMS position prevails. We believe that the Colstrip Units 3 and 4 owners have reasonable defenses in this matter. However, if the MMS position prevails and WECO succeeds in passing the expense responsibility to the owners, our share of the alleged additional royalties would be 15 percent, or approximately $6.0 million, and we would have ongoing royalty expenses related to coal transportation. The parties have an agreement in principle to resolve this dispute. If the matter is resolved as contemplated, it would not have a material impact on our financial position, results of operations or cash flows. We expect the parties to finalize the agreement during the first half of 2009.
Blue Dot Bankruptcy
During the second quarter of 2008, our subsidiary Blue Dot Services, LLC (Blue Dot) lost an arbitration matter with an insurance carrier and the insurance carrier was awarded $3.5 million plus interest related to a dispute that
originated in 2007. The award was partially satisfied by $2.5 million in letter of credit draws by the insurance carrier and approximately $300,000 in cash. On September 5, 2008, Blue Dot and its subsidiaries filed a petition for protection under Chapter 7 of the Bankruptcy Code in United States Bankruptcy Court for the District of Delaware. We classified Blue Dot as a discontinued operation in 2003. We do not anticipate Blue Dot’s ultimate liquidation will have a material adverse effect, if any, on our financial position, results of operations or cash flows.
Bozeman Explosion
On March 5, 2009, a natural gas explosion occurred in downtown Bozeman, Montana. The explosion resulted in one fatality, the destruction of three buildings (and the several places of business located within the destroyed buildings), and ancillary damage to nearby buildings and vehicles. Our investigation of this incident is ongoing. While litigation has not been commenced with respect to this incident, claims have been made against NorthWestern. We have paid our deductible and tendered the defense of any claims which may arise out of this incident to our insurance carrier. Our total available insurance coverage is approximately $150 million.
McCarthy
On March 16, 2009, Monsignor John F. McCarthy, as the duly appointed personal representative for the estate of Father James C. McCarthy, filed a complaint in the Montana Second Judicial District Court, Butte-Silver Bow County against us, one of our employees and other unknown individuals and entities. The complaint arises out of an April 2007 natural gas explosion and alleges negligence and strict liability with respect to the maintenance and operation of the natural gas distribution system that served Fr. McCarthy’s residence. The explosion destroyed a four-plex residence and nearby properties sustained damages. Fr. McCarthy died in November 2007. The plaintiff seeks unspecified compensatory and punitive damages and other equitable relief, costs and attorney’s fees. The investigation of this incident is ongoing, and while we cannot predict an outcome, we intend to vigorously defend against this complaint. We have filed a notice of removal to remove the case from Montana state court to the Butte Division of the U.S. District Court for the District of Montana. Such removal is pending.
We are also subject to various other legal proceedings, governmental audits and claims that arise in the ordinary course of business. In the opinion of management, the amount of ultimate liability with respect to these other actions will not materially affect our financial position, results of operations, or cash flows.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
NorthWestern Corporation, doing business as Northwestern Energy, provides electricity and natural gas to approximately 656,000 customers in Montana, South Dakota and Nebraska. For a discussion of NorthWestern’s business strategy, see Management’s Discussion and Analysis in our Annual Report on Form 10-K for the year ended December 31, 2008.
HIGHLIGHTS
Highlights for the three months ended March 31, 2009 include:
| • | Improved gross margin of $6.0 million as compared with the first quarter of 2008 primarily due to the transfer of our joint ownership interest in Colstrip Unit 4 to electric utility rate base; |
| • | Upgrade of our senior secured and unsecured credit ratings by Moody’s Investors Service (Moody’s); and |
| • | Issuance of $250 million of 6.34% Montana First Mortgage Bonds due in 2019. |
RESULTS OF OPERATIONS
Our consolidated results include the results of our business units constituting each of our business segments. The overall consolidated discussion is followed by a detailed discussion of gross margin by segment.
Colstrip Unit 4
In January 2009, as a result of a 2008 MPSC order, we placed our joint ownership interest in Colstrip Unit 4, which had previously been an unregulated asset, into utility rate base at a value of $407 million, and applied the provisions of SFAS No. 71. The order included a capital structure of 50% equity and 50% debt, an authorized return on equity of 10% and cost of debt of 6.5%, which are set for 34 years based on the estimated useful life of the plant. Our interest in Colstrip Unit 4 is expected to supply approximately 13% of our base-load requirements through 2010 and approximately 25% thereafter (upon expiration of an existing power sale agreement). The generation related costs and return on rate base related to Colstrip Unit 4 will be included in our annual electric supply tracker filing for inclusion in customer rates. During the first quarter of 2009, gross margin increased by approximately $5.8 million due to the regulated treatment of this asset.
Non-GAAP Financial Measure
The following discussion includes financial information prepared in accordance with generally accepted accounting principles (GAAP), as well as another financial measure, Gross Margin, that is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that exclude (or include) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Gross Margin (Revenues less Cost of Sales) is a non-GAAP financial measure due to the exclusion of depreciation from the measure. The presentation of Gross Margin is intended to supplement investors’ understanding of our operating performance. Gross Margin is used by us to determine whether we are collecting the appropriate amount of energy costs from customers to allow recovery of operating costs. Our Gross Margin measure may not be comparable to other companies’ Gross Margin measure. Furthermore, this measure is not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.
OVERALL CONSOLIDATED RESULTS
Three Months Ended March 31, 2009 Compared with the Three Months Ended March 31, 2008
|
| Three Months Ended March 31, |
| ||||||||||
|
| 2009 |
| 2008 |
| Change |
| % Change |
| ||||
|
| (in millions) |
| ||||||||||
Operating Revenues |
|
|
|
|
|
|
|
|
| ||||
Regulated Electric |
| $ | 208.0 |
| $ | 196.7 |
| $ | 11.3 |
| 5.7 | % | |
Regulated Natural Gas |
| 158.8 |
| 171.6 |
| (12.8 | ) | (7.5 | ) | ||||
Unregulated Electric |
| — |
| 20.4 |
| (20.4 | ) | (100.0 | ) | ||||
Other |
| 4.6 |
| 7.9 |
| (3.3 | ) | (41.8 | ) | ||||
Eliminations |
| (0.5 | ) | (10.6 | ) | 10.1 |
| 95.3 |
| ||||
|
| $ | 370.9 |
| $ | 386.0 |
| $ | (15.1 | ) | (3.9 | )% | |
|
| Three Months Ended March 31, |
| |||||||||||||||||
|
| 2009 |
| 2008 |
| Change |
| % Change |
| |||||||||||
|
| (in millions) |
| |||||||||||||||||
Cost of Sales |
|
|
|
|
|
|
|
|
| |||||||||||
Regulated Electric |
| $ | 94.8 |
| $ | 103.1 |
| $ | (8.3 | ) | (8.1 | )% | ||||||||
Regulated Natural Gas |
| 108.9 |
| 121.3 |
| (12.4 | ) | (10.2 | ) | |||||||||||
Unregulated Electric |
| — |
| 7.0 |
| (7.0 | ) | (100.0 | ) | |||||||||||
Other |
| 4.3 |
| 7.8 |
| (3.5 | ) | (44.9 | ) | |||||||||||
Eliminations |
| — |
| (10.1 | ) | 10.1 |
| 100.0 |
| |||||||||||
|
| $ | 208.0 |
| $ | 229.1 |
| $ | (21.1 | ) | (9.2 | )% | ||||||||
|
| Three Months Ended March 31, |
| |||||||||
|
| 2009 |
| 2008 |
| Change |
| % Change |
| |||
|
| (in millions) |
| |||||||||
Gross Margin |
|
|
|
|
|
|
|
|
| |||
Regulated Electric |
| $ | 113.2 |
| $ | 93.6 |
| $ | 19.6 |
| 20.9 | % |
Regulated Natural Gas |
| 49.9 |
| 50.3 |
| (0.4 | ) | (0.8 | ) | |||
Unregulated Electric |
| — |
| 13.4 |
| (13.4 | ) | (100.0 | ) | |||
Other |
| 0.3 |
| 0.1 |
| 0.2 |
| 200.0 |
| |||
Eliminations |
| (0.5 | ) | (0.5 | ) | — |
| — |
| |||
|
| $ | 162.9 |
| $ | 156.9 |
| $ | 6.0 |
| 3.8 | % |
Consolidated gross margin was $162.9 million for the three months ended March 31, 2009, an increase of $6.0 million, or 3.8%, from gross margin in the same period of 2008.
The improvement in consolidated gross margin was substantially due to the transfer of our interest in Colstrip Unit 4 to Montana utility rate base and represents our return on rate base. Prior to the transfer of Colstrip Unit 4, all of our Montana electric supply costs were based on power purchase agreements, which are passed through to customers at actual cost with no return component. Results of operations of this plant were reflected in our unregulated electric segment through December 31, 2008, which impacts the comparability of our segmented results.
|
| Three Months Ended March 31, |
| ||||||||||
|
| 2009 |
| 2008 |
| Change |
| % Change |
| ||||
|
| (in millions) |
| ||||||||||
Operating Expenses (excluding cost of sales) |
|
|
|
|
|
|
|
|
| ||||
Operating, general and administrative |
| $ | 65.4 |
| $ | 60.1 |
| $ | 5.3 |
| 8.8 | % | |
Property and other taxes |
| 24.3 |
| 23.6 |
| 0.7 |
| 3.0 |
| ||||
Depreciation |
| 22.7 |
| 21.1 |
| 1.6 |
| 7.6 |
| ||||
|
| $ | 112.4 |
| $ | 104.8 |
| $ | 7.6 |
| 7.3 | % | |
Consolidated operating, general and administrative expenses were $65.4 million for the three months ended March 31, 2009 as compared with $60.1 million for the three months ended March 31, 2008. Primary components of this change include the following:
|
| Operating, General & Administrative Expenses |
| |
|
| 2009 vs. 2008 |
| |
|
| (Millions of Dollars) |
| |
Insurance reserves |
| $ | 2.6 |
|
Pension expense |
| 2.1 |
| |
Labor and benefits |
| 1.6 |
| |
Other |
| (1.0 | ) | |
Increase in Operating, General & Administrative Expenses |
| $ | 5.3 |
|
The increase in operating, general and administrative expenses of $5.3 million was primarily due to the following:
| • | Increased insurance reserves; |
| • | Higher pension expense related to our Montana plan, based on our funding projections and a revised MPSC pension accounting order issued during the fourth quarter of 2008; and |
| • | Increased labor and benefit costs primarily due to compensation increases. |
Our Montana pension expense is based on an average of our funding requirements for calendar years 2005 through 2012, which is currently estimated at approximately $30.6 million annually. Our estimate is based on achieving an 8.00% return on assets. While this is a long-term assumption, our funding requirements are determined annually based on many variables, including actual plan asset returns. We experienced losses on plan assets of approximately 6.0% during the first quarter of 2009. If asset returns do not improve during the remainder of 2009, we will likely need to increase our funding estimates, which would result in higher pension expense.
Property and other taxes were $24.3 million for the three months ended March 31, 2009 as compared with $23.6 million in the first quarter of 2008. The increase was due to higher estimated property valuations.
Depreciation expense was $22.7 million for the three months ended March 31, 2009 as compared with $21.1 million in the first quarter of 2008. The increase was primarily due to 2008 plant additions.
Consolidated operating income for the three months ended March 31, 2009 was $50.5 million, as compared with $52.1 million in the first quarter of 2008. The decrease was primarily due to higher operating expenses partly offset by the $6.0 million increase in gross margin discussed above.
Consolidated interest expense for the three months ended March 31, 2009 was $15.1 million, a decrease of $1.0 million, or 6.2%, from the first quarter of 2008. This decrease was primarily related to lower interest rates on our variable rate debt.
Consolidated income tax expense for the three months ended March 31, 2009 was $13.1 million as compared with $13.2 million in the first quarter of 2008. Our effective tax rate for 2009 was 36.4% as compared to 36.0% for 2008.
Consolidated net income for the three months ended March 31, 2009 was $22.8 million as compared with $23.5 million for the first quarter of 2008. The slight decrease was primarily due to lower operating income partly offset by lower interest expense as discussed above.
REGULATED ELECTRIC SEGMENT
Three Months Ended March 31, 2009 Compared with the Three Months Ended March 31, 2008
|
| Results |
| |||||||||||
|
| 2009 |
| 2008 |
| Change |
| % Change |
| |||||
|
| (in millions) |
| |||||||||||
Retail revenue |
| $ | 180.5 |
| $ | 181.3 |
| $ | (0.8 | ) | 0.4 | % | ||
Transmission |
| 11.9 |
| 11.2 |
| 0.7 |
| 6.3 |
| |||||
Wholesale |
| 11.1 |
| 2.1 |
| 9.0 |
| 428.6 |
| |||||
Other |
| 4.5 |
| 2.1 |
| 2.4 |
| 114.3 |
| |||||
Total Revenues |
| 208.0 |
| 196.7 |
| 11.3 |
| 5.7 |
| |||||
Total Cost of Sales |
| 94.8 |
| 103.1 |
| (8.3 | ) | (8.1 | ) | |||||
Gross Margin |
| $ | 113.2 |
| $ | 93.6 |
| $ | 19.6 |
| 20.9 | % | ||
|
| Revenues |
| Volumes MWH |
| Avg. Customer Counts |
| |||||||||
|
| 2009 |
| 2008 |
| 2009 |
| 2008 |
| 2009 |
| 2008 |
| |||
|
| (in thousands) |
|
|
|
|
|
|
|
|
| |||||
Retail Electric |
|
|
|
|
|
|
|
|
|
|
|
|
| |||
Montana |
| $ | 66,094 |
| $ | 67,294 |
| 679 |
| 668 |
| 269,003 |
| 266,104 |
| |
South Dakota |
| 13,547 |
| 12,631 |
| 171 |
| 160 |
| 48,194 |
| 47,908 |
| |||
Residential |
| 79,641 |
| 79,925 |
| 850 |
| 828 |
| 317,197 |
| 314,012 |
| |||
Montana |
| 68,892 |
| 69,852 |
| 796 |
| 799 |
| 60,202 |
| 59,148 |
| |||
South Dakota |
| 16,673 |
| 15,684 |
| 228 |
| 222 |
| 11,475 |
| 11,331 |
| |||
Commercial |
| 85,565 |
| 85,536 |
| 1,024 |
| 1,021 |
| 71,677 |
| 70,479 |
| |||
Industrial |
| 10,947 |
| 11,490 |
| 765 |
| 761 |
| 72 |
| 72 |
| |||
Other |
| 4,311 |
| 4,367 |
| 24 |
| 24 |
| 4,643 |
| 4,653 |
| |||
Total Retail Electric |
| $ | 180,464 |
| $ | 181,318 |
| 2,663 |
| 2,634 |
| 393,589 |
| 389,216 |
| |
Wholesale Electric |
| 11,131 |
| 2,066 |
| 243 |
| 49 |
| N/A |
| N/A |
| |||
The following summarizes the components of the changes in regulated electric margin for the three months ended March 31, 2009 and 2008:
|
| Gross Margin |
| |
|
| 2009 vs. 2008 |
| |
|
| (Millions of Dollars) |
| |
Transfer of interest in Colstrip Unit 4 to regulated electric |
| $ | 19.2 |
|
Other |
| 0.4 |
| |
Improvement in Regulated Electric Gross Margin |
|
| 19.6 |
|
Reduction in Unregulated Electric Gross Margin |
|
| (13.4 | ) |
Net Improvement in Electric Gross Margin |
| $ | 6.2 |
|
This improvement is primarily due to the transfer of Colstrip Unit 4 to the regulated utility, which is reflected as an increase in retail revenue and a reduction to cost of sales. We are continuing to fulfill third party contractual obligations, which are reflected as an increase in wholesale revenues and volumes above. Revenues from the sales of the output of this plant were reflected in our unregulated electric segment through December 31, 2008, which impacts the comparability of the results of our regulated electric segment. Prior to the transfer of Colstrip Unit 4, all of our Montana electric supply costs were based on power purchase agreements, which are passed through to customers at actual cost with no return component. In addition, average electric supply prices decreased resulting in decreased retail revenues and cost of sales in 2009 as compared with 2008, with no impact to gross margin.
REGULATED NATURAL GAS SEGMENT
Three Months Ended March 31, 2009 Compared with the Three Months Ended March 31, 2008
|
| Results |
| |||||||||||
|
| 2009 |
| 2008 |
| Change |
| % Change |
| |||||
|
| (in millions) |
| |||||||||||
Retail revenue |
| $ | 144.4 |
| $ | 151.9 |
| $ | (7.5 | ) | (4.9 | )% | ||
Wholesale and other |
| 14.4 |
| 19.7 |
| (5.3 | ) | 26.9 |
| |||||
Total Revenues |
| 158.8 |
| 171.6 |
| (12.8 | ) | (7.5 | ) | |||||
Total Cost of Sales |
| 108.9 |
| 121.3 |
| (12.4 | ) | (10.2 | ) | |||||
Gross Margin |
| $ | 49.9 |
| $ | 50.3 |
| $ | (0.4 | ) | (0.8 | )% | ||
|
| Revenues |
| Volumes (Dkt) |
| Customer Counts |
| ||||||||
|
| 2009 |
| 2008 |
| 2009 |
| 2008 |
| 2009 |
| 2008 |
| ||
|
| (in thousands) |
|
|
|
|
|
|
|
|
| ||||
Retail Gas |
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Montana |
| $ | 55,524 |
| $ | 60,744 |
| 5,383 |
| 5,568 |
| 157,395 |
| 155,758 |
|
South Dakota |
| 18,690 |
| 18,688 |
| 1,577 |
| 1,607 |
| 37,105 |
| 36,912 |
| ||
Nebraska |
| 15,443 |
| 15,167 |
| 1,316 |
| 1,405 |
| 36,813 |
| 36,888 |
| ||
Residential |
| 89,657 |
| 94,599 |
| 8,276 |
| 8,580 |
| 231,313 |
| 229,558 |
| ||
Montana |
| 28,271 |
| 30,265 |
| 2,735 |
| 2,757 |
| 22,046 |
| 21,685 |
| ||
South Dakota |
| 14,296 |
| 13,934 |
| 1,497 |
| 1,378 |
| 5,887 |
| 5,839 |
| ||
Nebraska |
| 10,942 |
| 11,311 |
| 1,231 |
| 1,284 |
| 4,582 |
| 4,593 |
| ||
Commercial |
| 53,509 |
| 55,510 |
| 5,463 |
| 5,419 |
| 32,515 |
| 32,117 |
| ||
Industrial |
| 803 |
| 1,289 |
| 79 |
| 119 |
| 299 |
| 306 |
| ||
Other |
| 476 |
| 505 |
| 52 |
| 54 |
| 142 |
| 141 |
| ||
Total Retail Gas |
| $ | 144,445 |
| $ | 151,903 |
| 13,870 |
| 14,172 |
| 264,269 |
| 262,122 |
|
|
| 2009 as compared with: |
| ||
Heating Degree-Days |
| 2008 |
| Historic Average |
|
Montana |
| 2% warmer |
| 2% warmer |
|
South Dakota |
| 1% colder |
| 5% colder |
|
Nebraska |
| 8% warmer |
| 4% warmer |
|
The following summarizes the components of the changes in regulated natural gas margin for the three months ended March 31, 2009 and 2008:
|
| Gross Margin |
| |
|
| 2009 vs. 2008 |
| |
|
| (Millions of Dollars) |
| |
Warmer winter weather |
| $ | (0.7 | ) |
Other |
| 0.3 |
| |
Reduction in Gross Margin |
| $ | (0.4 | ) |
The decline in margin and volumes is primarily due to warmer winter weather in Montana and Nebraska. Our wholesale and other revenues are largely gross margin neutral as they are offset by changes in cost of sales.
LIQUIDITY AND CAPITAL RESOURCES
We utilize our revolver availability to manage our cash flows due to the seasonality of our business, and utilize any cash on hand in excess of current operating requirements to invest in our business and reduce borrowings. As of March 31, 2009, our total net liquidity was approximately $260.0 million, including $83.2 million of cash and $176.8 million of revolving credit facility availability. Revolver availability was $176.8 million as of April 17, 2009. A total of nine banks participate in our revolving credit facility, with no one bank providing more than 13% of the total availability. No bank has advised us of its intent to withdraw from the revolving credit facility or notified us that they would be unable to honor their obligations. We plan to enter into a new revolving credit facility with availability between $250 and $300 million during the second quarter of 2009 to replace our existing revolving credit facility maturing in November 2009.
Factors Impacting our Liquidity
Financing Transaction - In March 2009, we issued $250 million of Montana First Mortgage Bonds at a fixed interest rate of 6.34% maturing April 1, 2019, and used the proceeds to redeem our $100 million Colstrip Lease Holdings LLC term loan and repay outstanding borrowings on our revolving credit facility. Remaining funds will be used to repay other outstanding debt obligations related to Colstrip Unit 4, fund a portion of the proposed Mill Creek generation project if approved, and fund future capital expenditures.
Supply Costs - Our operations are subject to seasonal fluctuations in cash flow. During the heating season, which is primarily from November through March, cash receipts from natural gas sales and transportation services typically exceed cash requirements. During the summer months, cash on hand, together with the seasonal increase in cash flows and utilization of our existing revolver, are used to purchase natural gas to place in storage, perform maintenance and make capital improvements.
The effect of this seasonality on our liquidity is also impacted by changes in the market prices of our electric and natural gas supply, which is recovered through various monthly cost tracking mechanisms. These energy supply tracking mechanisms are designed to provide stable and timely recovery of supply costs on a monthly basis during the July to June annual tracking period, with an adjustment in the following annual tracking period to correct for any under or over collection in our monthly trackers. Due to the lag between our purchases of electric and natural gas commodities and revenue receipt from customers, cyclical over and under collection situations arise consistent with the seasonal fluctuations discussed above; therefore we usually under collect in the fall and winter and over collect in the spring. Fluctuations in recoveries under our cost tracking mechanisms can have a significant effect on cash flow from operations and make year-to-year comparisons difficult.
As of March 31, 2009, we are over collected on our current Montana natural gas and electric trackers by approximately $3.5 million, as compared with an under collection of $10.5 million as of December 31, 2008, and an over collection of $12.7 million as of March 31, 2008. In addition, we posted $11 million of letters of credit to counterparties during the first quarter of 2009 as collateral for forward supply contracts, which reduces our revolving credit facility availability.
Pension Plan Contributions – During the first quarter of 2009, we made contributions of $43.2 million to our qualified pension plans. Based on our available liquidity, we anticipate making additional contributions to our qualified pension plans during 2009 ranging between $20 million and $50 million. These additional contributions are not required for 2009, but will improve the funded status of our plans and will reduce 2010 contribution requirements.
Credit Ratings
Fitch Investors Service (Fitch), Moody’s and Standard and Poor’s Rating Group (S&P) are independent credit-rating agencies that rate our debt securities. These ratings indicate the agencies’ assessment of our ability to pay interest and principal when due on our debt. As of April 17, 2009, our current ratings with these agencies are as follows:
|
| Senior Secured Rating |
| Senior Unsecured Rating |
| Outlook |
Fitch |
| BBB+ |
| BBB |
| Stable |
Moody’s (1) |
| Baa1 |
| Baa2 |
| Positive |
S&P |
| A- (MT) BBB+ (SD) |
| BBB |
| Stable |
|
|
|
|
|
|
|
(1) | Moody’s upgraded our senior secured and senior unsecured credit ratings on March 6, 2009, from Baa2 and Baa3, respectively, as reflected above. |
In general, less favorable credit ratings make debt financing more costly and more difficult to obtain on terms that are economically favorable to us and impacts our trade credit availability. A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.
Cash Flows
The following table summarizes our consolidated cash flows (in millions):
|
| Three Months Ended March 31, |
| ||||
|
| 2009 |
| 2008 |
| ||
Operating Activities |
|
|
|
|
| ||
Net income |
| $ | 22.8 |
| $ | 23.5 |
|
Non-cash adjustments to net income |
| 37.4 |
| 35.2 |
| ||
Changes in working capital |
| 31.3 |
| 30.4 |
| ||
Other |
| (26.4 | ) | (11.1 | ) | ||
|
| 65.1 |
| 78.0 |
| ||
|
|
|
|
|
| ||
Investing Activities |
|
|
|
|
| ||
Property, plant and equipment additions |
| (18.5 | ) | (14.0 | ) | ||
Sale of assets |
| 0.3 |
| — |
| ||
|
| (18.2 | ) | (14.0 | ) | ||
|
|
|
|
|
| ||
Financing Activities |
|
|
|
|
| ||
Net borrowing (repayment) of debt |
| 38.7 |
| (30.0 | ) | ||
Dividends on common stock |
| (12.0 | ) | (12.9 | ) | ||
Other |
| (1.7 | ) | (0.1 | ) | ||
|
| 25.0 |
| (43.0 | ) | ||
|
|
|
|
|
| ||
Net Increase in Cash and Cash Equivalents |
| $ | 71.9 |
| $ | 21.0 |
|
Cash and Cash Equivalents, beginning of period |
| $ | 11.3 |
| $ | 12.8 |
|
Cash and Cash Equivalents, end of period |
| $ | 83.2 |
| $ | 33.8 |
|
Cash Provided by Operating Activities
As of March 31, 2009, cash and cash equivalents were $83.2 million as compared with $11.3 million at December 31, 2008 and $33.8 million at March 31, 2008. Cash provided by operating activities totaled $65.1 million for the three months ended March 31, 2009 as compared with $78.0 million during the three months ended March 31, 2008. This decrease in operating cash flows is primarily related to increased pension funding of approximately $21.3 million, offset by improvements associated with the timing of energy supply costs collections in the first quarter of 2009 as compared with 2008, which is discussed above in the “Factors Impacting Our Liquidity” section.
Cash Used in Investing Activities
Cash used in investing activities increased by approximately $4.2 million as compared with the first quarter of 2008 due primarily to increased property, plant and equipment additions.
Cash Provided by (Used in) Financing Activities
Cash provided by financing activities totaled approximately $25.0 million in the first quarter of 2009 as compared with cash used in financing activities of approximately $43.0 million during the three months ended March 31, 2008. During the first quarter of 2009 we issued debt of $250.0 million, made debt repayments of $211.3 million, and paid dividends on common stock of $12.0 million. During the first quarter of 2008 we made debt repayments of $30.0 million and paid dividends on common stock of $12.9 million.
Sources and Uses of Funds
We require liquidity to support and grow our business and use our liquidity for working capital needs, capital expenditures, investments in or acquisitions of assets, to repay debt and, from time to time, to repurchase common stock. We anticipate that our ongoing liquidity requirements will be satisfied through a combination of operating cash flows, borrowings, and as necessary, the issuance of debt or equity securities, consistent with our objective of maintaining a capital structure that will support a strong investment grade credit rating on a long-term basis. The amount of capital expenditures and dividends are subject to certain factors including the use of existing cash, cash equivalents and the receipt of cash from operations. A material adverse change in operations or available financing could impact our ability to fund our current liquidity and capital resource requirements, and we may defer capital expenditures as necessary.
Contractual Obligations and Other Commitments
We have a variety of contractual obligations and other commitments that require payment of cash at certain specified periods. The following table summarizes our contractual cash obligations and commitments as of March 31, 2009. See our Annual Report on Form 10-K for the year ended December 31, 2008 for additional discussion.
|
| Total |
| 2009 |
| 2010 |
| 2011 |
| 2012 |
| 2013 |
| Thereafter | ||||||||
|
| (in thousands) | ||||||||||||||||||||
Long-term Debt |
| $ | 900,629 |
| $ | 16,775 |
| $ | 23,605 |
| $ | 6,578 |
| $ | 3,792 |
| $ | — |
| $ | 849,879 | |
Capital Leases |
| 37,828 |
| 925 |
| 1,358 |
| 1,265 |
| 1,363 |
| 1,468 |
| 31,449 | ||||||||
Future minimum operating lease payments |
| 4,282 |
| 1,239 |
| 1,296 |
| 853 |
| 516 |
| 72 |
| 306 | ||||||||
Estimated Pension and Other Postretirement Obligations (1) |
| 131,350 |
| 2,800 |
| 41,450 |
| 29,600 |
| 27,900 |
| 29,600 |
| N/A | ||||||||
Qualifying Facilities (2) |
| 1,444,039 |
| 46,443 |
| 63,589 |
| 65,323 |
| 67,111 |
| 69,816 |
| 1,131,757 | ||||||||
Supply and Capacity Contracts (3) |
| 1,575,562 |
| 306,306 |
| 336,223 |
| 163,883 |
| 149,184 |
| 132,519 |
| 487,447 | ||||||||
Contractual interest payments on debt (4) |
| 462,336 |
| 39,823 |
| 52,053 |
| 49,902 |
| 49,489 |
| 49,371 |
| 221,698 | ||||||||
Total Commitments (5) |
| $ | 4,556,026 |
| $ | 414,311 |
| $ | 519,574 |
| $ | 317,404 |
| $ | 299,355 |
| $ | 282,846 |
| $ | 2,722,536 | |
(1) We have only estimated cash obligations related to our pension and other postretirement benefit programs for five years, as it is not practicable to estimate thereafter.
(2) The Qualifying Facilities (QFs) require us to purchase minimum amounts of energy at prices ranging from $65 to $138 per megawatt hour through 2032. Our estimated gross contractual obligation related to the QFs is approximately $1.4 billion. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $1.1 billion.
(3) We have entered into various purchase commitments, largely purchased power, coal and natural gas supply and natural gas transportation contracts. These commitments range from one to 19 years.
(4) Contractual interest payments assume no revolver borrowings.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Management’s discussion and analysis of financial condition and results of operations is based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We base our estimates on historical experience and other assumptions that are believed to be proper and reasonable under the circumstances.
As of March 31, 2009, there have been no significant changes with regard to the critical accounting policies disclosed in Management’s Discussion and Analysis in our Annual Report on Form 10-K for the year ended December 31, 2008. The policies disclosed included the accounting for the following: goodwill and long-lived assets, qualifying facilities liability, revenue recognition, regulatory assets and liabilities, pension and postretirement benefit plans, and income taxes. We continually evaluate the appropriateness of our estimates and assumptions. Actual results could differ from those estimates.
ITEM 3. | QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK |
We are exposed to market risks, including, but not limited to, interest rates, energy commodity price volatility, and credit exposure. Management has established comprehensive risk management policies and procedures to manage these market risks.
Interest Rate Risk
We utilize various risk management instruments to reduce our exposure to market interest rate changes. These risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financings. All of our debt has fixed interest rates, with the exception of our revolving credit facility. The revolving credit facility bears interest at the lower of prime or available rates tied to the London Interbank Offered Rate (LIBOR) plus a credit spread, which was 1.25%, or 0.75% over LIBOR as of March 31, 2009. There were no borrowings on our revolving credit facility as of March 31, 2009.
Commodity Price Risk
Commodity price risk is one of our most significant risks due to our lack of ownership of natural gas reserves and minimal ownership of regulated electric generation assets within the Montana market. Several factors influence price levels and volatility. These factors include, but are not limited to, seasonal changes in demand, weather conditions, available generating assets within regions, transportation availability and reliability within and between regions, fuel availability, market liquidity, and the nature and extent of current and potential federal and state regulations.
As part of our overall strategy for fulfilling our regulated electric supply requirements, we employ the use of market purchases, including forward purchase and sales contracts. These types of contracts are included in our electric supply portfolio and are used to manage price volatility risk by taking advantage of seasonal fluctuations in market prices. While we may incur gains or losses on individual contracts, the overall portfolio approach is intended to provide price stability for consumers; therefore, these commodity costs are included in our cost tracking mechanisms.
In our “other” segment, we currently have a capacity contract through 2013 that is primarily used to serve one customer. This customer is currently in bankruptcy and has indicated an intention to reject the natural gas sales contract during the second quarter of 2009. We estimate our maximum exposure related to this capacity contract to be approximately $4.5 million, and we are currently evaluating our alternatives to reduce this exposure.
Counterparty Credit Risk
We are exposed to counterparty credit risk related to the ability of our counterparties to meet their contractual payment obligations, and the potential non-performance of counterparties to deliver contracted commodities or services at the contracted price. We have risk management policies in place to limit our transactions to high quality counterparties, and continue to monitor closely the status of our counterparties, and will take action, as appropriate, to further manage this risk. This includes, but is not limited to, requiring letters of credit or prepayment terms. There can be no assurance, however, that the management tools we employ will eliminate the risk of loss.
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
We have established disclosure controls and procedures designed to ensure that information required to be disclosed in the reports we file or submit under the Securities Exchange Act of 1934 are recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms and accumulated and reported to management, including the principal executive officer and principal financial officer to allow timely decisions regarding required disclosure.
We conducted an evaluation, under the supervision and with the participation of our principal executive officer and principal financial officer of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934). Based on this evaluation, our principal executive officer and principal financial officer have concluded that, as of the end of the period covered by this report, our disclosure controls and procedures are effective.
Changes in Internal Control Over Financial Reporting
There have been no changes in our internal control over financial reporting during the three months ended March 31, 2009 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 1. | LEGAL PROCEEDINGS |
See Note 14, Commitments and Contingencies, to the Consolidated Financial Statements for information about legal proceedings.
ITEM 1A. | RISK FACTORS |
You should carefully consider the risk factors described below, as well as all other information available to you, before making an investment in our common stock or other securities.
Economic conditions and instability in the financial markets could negatively impact our business.
Our operations are impacted by local, national and worldwide economic conditions. The consequences of a prolonged recession may include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets. A lower level of economic activity may result in a decline in energy consumption and an increase in customers’ inability to pay their accounts, which may adversely affect our liquidity, results of operations and future growth.
Access to the capital and credit markets, at a reasonable cost, is necessary for us to fund our operations, including capital requirements. We rely on a revolving credit facility for short-term liquidity needs due to the seasonality of our business, and on capital markets to raise capital for growth projects that are not otherwise provided by operating cash flows. Continued instability in the financial markets may increase the cost of capital, limit our ability to refinance or draw on our credit facility and/or raise capital. If we are unable to obtain the liquidity needed to meet our business requirements on favorable terms, we may defer growth projects and/or capital expenditures.
We are subject to extensive governmental laws and regulations that affect our industry and our operations, which could have a material adverse effect on our liquidity and results of operations.
We are subject to regulation by federal and state governmental entities, including the Federal Energy Regulatory Commission, MPSC, South Dakota Public Utilities Commission and Nebraska Public Service Commission. Regulations can affect allowed rates of return, recovery of costs and operating requirements. Specifically, in our recent proceeding related to Colstrip Unit 4, the MPSC approved a 10% return on equity and 6.5% cost of debt for the expected 34-year life of the plant. In addition, existing regulations may be revised or reinterpreted, new laws, regulations, and interpretations thereof may be adopted or become applicable to us and future changes in laws and regulations may have a detrimental effect on our business.
Our rates are approved by our respective commissions and are effective until new rates are approved. In addition, supply costs are recovered through adjustment charges that are periodically reset to reflect current and projected costs. Inability to recover costs in rates or adjustment clauses could have a material adverse effect on our liquidity and results of operations.
We are also subject to the jurisdiction of NERC with regard to electric system reliability standards. We must comply with the standards and requirements established, which apply to the NERC functions for which we have registered in both the Midwest Reliability Organization for our South Dakota operations and the WECC for our Montana operations. To the extent we are deemed to not be compliant with these standards, we could be subject to fines or penalties.
We are subject to extensive environmental laws and regulations and potential environmental liabilities, which could result in significant costs and liabilities.
We are subject to extensive laws and regulations imposed by federal, state, and local government authorities in the ordinary course of operations with regard to the environment, including environmental laws and regulations relating to air and water quality, solid waste disposal, and other environmental considerations. We believe that we are in substantial compliance with environmental regulatory requirements and that maintaining compliance with
current requirements will not materially affect our financial position or results of operations; however, possible future developments, including the promulgation of more stringent environmental laws and regulations, such as the new mercury emissions rules in Montana, and the timing of future enforcement proceedings that may be taken by environmental authorities could affect the costs and the manner in which we conduct our business and could require us to make substantial additional capital expenditures.
In addition to the requirements related to the mercury emissions rules noted above, there is a growing concern nationally and internationally about global climate change and the contribution of emissions of greenhouse gases including, most significantly, carbon dioxide. This concern has led to increased interest in legislation at the federal level, actions at the state level, as well as litigation relating to greenhouse emissions, including a U.S. Supreme Court decision holding that the EPA relied on improper factors in deciding not to regulate carbon dioxide emissions from motor vehicles under the Clean Air Act. Increased pressure for carbon dioxide emissions reduction also is coming from investor organizations. If legislation or regulations are passed at the federal or state levels imposing mandatory reductions of carbon dioxide and other greenhouse gases on generation facilities, the cost to us of such reductions could be significant.
Many of these environmental laws and regulations create permit and license requirements and provide for substantial civil and criminal fines which, if imposed, could result in material costs or liabilities. We cannot predict with certainty the occurrence of private tort allegations or government claims for damages associated with specific environmental conditions. We may be required to make significant expenditures in connection with the investigation and remediation of alleged or actual spills, personal injury or property damage claims, and the repair, upgrade or expansion of our facilities to meet future requirements and obligations under environmental laws.
To the extent that our environmental liabilities are greater than our reserves or we are unsuccessful in recovering anticipated insurance proceeds under the relevant policies or recovering a material portion of remediation costs in our rates, our results of operations and financial position could be adversely affected.
To the extent our incurred supply costs are deemed imprudent by the applicable state regulatory commissions, we would under recover our costs, which could adversely impact our results of operations and liquidity.
Our wholesale costs for electricity and natural gas are recovered through various pass-through cost tracking mechanisms in each of the states we serve. The rates are established based upon projected market prices or contract obligations. As these variables change, we adjust our rates through our monthly trackers. To the extent our energy supply costs are deemed imprudent by the applicable state regulatory commissions, we would under recover our costs, which could adversely impact our results of operations.
We are required to procure our entire natural gas supply and a large portion of our Montana electric supply pursuant to contracts with third-party suppliers. In light of this reliance on third-party suppliers, we are exposed to certain risks in the event a third-party supplier is unable to satisfy its contractual obligation. If this occurred, then we might be required to purchase gas and/or electricity supply requirements in the energy markets, which may not be on commercially reasonable terms, if at all. If prices were higher in the energy markets, it could result in a temporary material under recovery that would reduce our liquidity.
Poor investment performance of plan assets of our defined benefit pension and post-retirement benefit plans, in addition to other factors impacting these costs, could unfavorably impact our results of operations and liquidity.
We have two defined benefit pension plans that cover substantially all of our employees, and a post-retirement medical plan for our Montana employees. The costs of providing these plans are dependent upon a number of factors, including rate of return on plan assets, discount rates, other actuarial assumptions, and government regulation. While we have complied with the minimum funding requirements, our obligations for these plans exceed the value of plan assets. In addition, the Pension Protection Act of 2006 changed the minimum funding requirements for defined benefit pension plans beginning in 2008. Without sustained growth in the plan assets over time and depending upon the other factors noted above, we could be required to fund our plans with significant amounts of
cash. Such cash funding obligations may change significantly from projections, and could have a material impact on our liquidity and results of operations.
Our plans for future expansion through transmission grid expansion, the construction of power generation facilities and capital improvements to current assets involve substantial risks. Failure to adequately execute and manage significant construction plans, as well as the risk of recovering such costs, could materially impact our results of operations and liquidity.
We have proposed capital investment projects in excess of $1 billion. The completion of these projects, which are primarily investments in electric transmission projects and electric generation projects, are subject to many construction and development risks, including, but not limited to, risks related to financing, regulatory recovery, obtaining and complying with terms of permits, escalating costs of materials and labor, meeting construction budgets and schedules, and environmental compliance. In addition, there are other proposed projects that may result in direct competition to our proposed transmission expansion. Should our efforts be unsuccessful, we could be subject to additional costs, termination payments under committed contracts, and/or the write-off of investments in these projects. We have capitalized approximately $7.6 million of costs associated with these projects as of March 31, 2009.
Our obligation to supply a minimum annual quantity of power to the Montana electric supply could expose us to material commodity price risk if certain Qualifying Facilities (QF) under contract with us do not perform during a time of high commodity prices, as we are required to supply any quantity deficiency.
We perform management of the QF portfolio of resources under the terms and conditions of the QF Tier II Stipulation with the MPSC. This Stipulation may subject us to commodity price risk if the QF portfolio does not perform in a manner to meet the annual minimum energy requirement.
As part of the Stipulation and Settlement with the MPSC and other parties in the Tier II Docket, we agreed to supply the electric supply with a certain minimum amount of power at an agreed upon price per MW. The annual minimum energy requirement is achievable under normal QF operations, including normal periods of planned and forced outages. Furthermore, we will not realize commodity price risk unless any required replacement energy cost is in excess of the total amount recovered under the QF contracts.
However, to the extent the supplied QF power for any year does not reach the minimum quantity set forth in the settlement, we are obligated to secure the quantity deficiency from other sources. The anticipated source for any quantity deficiency is the wholesale market which, in turn, would subject us to commodity price volatility.
Our jointly owned electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased power purchase costs.
Operation of electric generating facilities involves risks, which can adversely affect energy output and efficiency levels. Most of our generating capacity is coal-fired. We rely on a limited number of suppliers of coal for our regulated generation, making us vulnerable to increased prices for fuel as existing contracts expire or in the event of unanticipated interruptions in fuel supply. We are a captive rail shipper of the Burlington Northern Santa Fe Railway for shipments of coal to the Big Stone Plant (our largest source of generation in South Dakota), making us vulnerable to railroad capacity and operational issues and/or increased prices for coal transportation from a sole supplier. Operational risks also include facility shutdowns due to breakdown or failure of equipment or processes, labor disputes, operator error and catastrophic events such as fires, explosions, floods, and intentional acts of destruction or other similar occurrences affecting the electric generating facilities. The loss of a major regulated generating facility would require us to find other sources of supply, if available, and expose us to higher purchased power costs.
Seasonal and quarterly fluctuations of our business could adversely affect our results of operations and liquidity.
Our electric and natural gas utility business is seasonal, and weather patterns can have a material impact on our financial performance. Demand for electricity and natural gas is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand for this product depends heavily upon weather patterns throughout our market areas, and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. In the event that we experience unusually mild winters or cool summers in the future, our results of operations and financial position could be adversely affected. In addition, exceptionally hot summer weather or unusually cold winter weather could add significantly to working capital needs to fund higher than normal supply purchases to meet customer demand for electricity and natural gas.
We must meet certain credit quality standards. If we are unable to maintain investment grade credit ratings, we would be required under certain credit agreements to provide collateral in the form of letters of credit or cash, which may materially adversely affect our liquidity and/or access to capital.
A downgrade of our credit ratings to less than investment grade could adversely affect our liquidity, as counter parties could require us to post collateral. In addition, our ability to raise capital on favorable terms could be hindered, and our borrowing costs could increase.
ITEM 6. | EXHIBITS |
| (a) | Exhibits |
Exhibit 4.1—Twenty-seventh Supplemental Indenture, dated as of March 1, 2009, among NorthWestern Corporation and The Bank of New York Mellon (formerly The Bank of New York) and Ming Ryan, as trustees (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated March 23, 2009, Commission File No. 1-10499).
Exhibit 4.2— Purchase Agreement, dated March 23, 2009, among NorthWestern Corporation and Banc of America Securities LLC and J.P. Morgan Securities Inc., as representatives of several initial purchasers (incorporated by reference to Exhibit 10.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated March 23, 2009, Commission File No. 1-10499).
Exhibit 4.3— Registration Rights Agreement, dated March 26, 2009, among NorthWestern Corporation and Banc of America Securities LLC and J.P. Morgan Securities Inc., as representatives of several initial purchasers (incorporated by reference to Exhibit 10.2 of NorthWestern Corporation’s Current Report on Form 8-K, dated March 23, 2009, Commission File No. 1-10499).
Exhibit 10.1—NorthWestern Energy 2009 Annual Incentive Plan (incorporated by reference to Exhibit 99.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated February 13, 2009, Commission File No. 1-10499).
Exhibit 10.2— Form of NorthWestern Corporation Long-Term Performance Incentive Restricted Stock Award Agreement (incorporated by reference to Exhibit 99.2 of NorthWestern Corporation’s Current Report on Form 8-K, dated February 13, 2009, Commission File No. 1-10499).
Exhibit 31.1—Certification of chief executive officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002.
Exhibit 31.2—Certification of chief financial officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002.
Exhibit 32.1—Certification of chief executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Exhibit 32.2—Certification of chief financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
|
| NORTHWESTERN CORPORATION |
Date: April 23, 2009 | By: | /s/ BRIAN B. BIRD |
|
| Brian B. Bird |
|
| Chief Financial Officer |
|
| Duly Authorized Officer and Principal Financial Officer |
Exhibit |
| Description |
*31.1 |
| Certification of chief executive officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002. |
*31.2 |
| Certification of chief financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
*32.1 |
| Certification of chief executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
*32.2 |
| Certification of chief financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
* | Filed herewith |