NWEC Northwestern (MM)

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

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FORM   10-Q

 

 

For the transition period from           to           

 

Commission File Number: 1-10499

 

NORTHWESTERN CORPORATION

 

 

Common Stock, Par Value $.01

38,972,551 shares outstanding at April 18, 2008

 

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NORTHWESTERN CORPORATION

FORM   10-Q

INDEX

 

 

 

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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 herein 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 our projections will be achieved. Factors that may cause such differences include, but are not limited to:

 

 

 

 

 

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, 10-Q and 8-K, Proxy Statements on Schedule 14A, press releases, analyst and investor conference calls, and other communications released to the public. Although we believe that at the time made, the expectations reflected in all of these forward-looking statements are and will be reasonable, 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 a forward-looking statement in this Quarterly Report on Form 10-Q or other public communications that we might make 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 SEC on Forms 10-K, 10-Q and 8-K and Proxy Statements on Schedule 14A.

 

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Unless the context requires otherwise, references to “we," “us," “our," “NorthWestern Corporation," “NorthWestern Energy" and “NorthWestern" refer specifically to NorthWestern Corporation and its subsidiaries.

 

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PART   1.   FINANCIAL INFORMATION

 

NORTHWESTERN CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(in thousands, except share data)

 

 

See Notes to Consolidated Financial Statements

 

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NORTHWESTERN CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

(in thousands, except per share amounts)

 

 

See Notes to Consolidated Financial Statements

 

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NORTHWESTERN CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)

 

 

See Notes to Consolidated Financial Statements

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Reference is made to Notes to Financial Statements

included in NorthWestern Corporation’s Annual Report)

(Unaudited)

NorthWestern Corporation, doing business as NorthWestern Energy, provides electricity and natural gas to approximately 650,000 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 requires management to make estimates and assumptions that may affect the reported amounts of assets, liabilities, revenues and expenses during the reporting period. 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. Although 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, 2007.

 

Accounting Standards Issued

 

In March 2008, the Financial Accounting Standards Board (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. This statement will become effective for our fiscal year beginning January 1, 2009. We are still evaluating the impact of SFAS No. 161, if any, but do not expect the statement to have a material impact on our consolidated financial statements.

 

Accounting Standards Adopted

 

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.

 

The statement establishes a three-level fair value hierarchy and requires fair value disclosures based upon this hierarchy. The statement 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.

 

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The following table presents the method of measuring fair value used in determining the carrying amount of our derivative assets and liabilities, and the maturity, by year, to give an indication of when these amounts will settle and generate cash, as of March 31, 2008 (in thousands):

 

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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.

 

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities-including an amendment of FASB Statement No. 115 (SFAS No. 159), which permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value, with unrealized gains and losses related to these financial instruments reported in earnings at each subsequent reporting date. This option would be applied on an instrument by instrument basis. If elected, unrealized gains and losses on the affected financial instruments would be recognized in earnings at each subsequent reporting date. This Statement is effective beginning January 1, 2008. We have assessed the provisions of the statement and elected not to apply fair value accounting to our eligible financial instruments. As a result, adoption of this statement had no impact on our financial results.

 

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 $513.2 million through 2025, and are included in Contractual Obligations and Other Commitments of Management's Discussion and Analysis.

 

We have unrecognized tax benefits of approximately $112.0 million as of March 31, 2008. If any of our unrecognized tax benefits were recognized, they would have no impact on 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 statute of limitations within the next twelve months.

 

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Our policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. During the three months ended March 31, 2008, we have not recognized expense for interest or penalties, and do not have any amounts accrued at March 31, 2008 and December 31, 2007, respectively, for the payment of interest and penalties.

 

Our federal tax returns from 2000 forward remain subject to examination by the Internal Revenue Service.

 

There were no changes in our goodwill during the three months ended March 31, 2008. Goodwill by segment is as follows for March 31, 2008 and December 31, 2007 (in thousands):

 

 

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):

 

 

We are exposed to market risk, including changes in interest rates and the impact of market fluctuations in the price of electricity and natural gas commodities. In order to manage these risks, we use both derivative and non-derivative contracts that may provide for settlement in cash or by delivery of a commodity, including:

 

 

SFAS No. 133 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 have applied the normal purchases and normal sales scope exception, as provided by SFAS No. 133 and

 

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interpreted by Derivatives Implementation Guidance Issue C15, to certain contracts involving the 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. For certain regulated electric and gas contracts that do not physically deliver, in accordance with EITF 03-11, Reporting Gains and Losses on Derivative Instruments that are Subject to SFAS No.   133 and not “Held for Trading Purposes" as defined in Issue no. 02-3 , revenue is reported net versus gross.

 

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, we record the fair value of these derivatives as assets and liabilities, with changes reflected in our consolidated statement of income. The market prices and quantities used to determine fair value reflect management’s best estimate considering various factors; however, future market prices and actual quantities will vary from those used in recording the derivative asset or liability, and it is possible that such variations could be material.

 

Commodity Prices

 

Unregulated Electric - We use derivatives to optimize the value of our unregulated power generation asset. Changes in the fair value for power purchases and sales are recognized on a net basis in operating revenues or cost of sales in the consolidated income statement unless hedge accounting is applied. While our derivative transactions are entered into for the purpose of managing commodity price risk, hedge accounting is only applied where specific criteria are met and it is practicable to do so. In order to apply hedge accounting, the transaction must be designated as a hedge and it must be highly effective in offsetting the hedged risk. Additionally, for hedges of commodity price risk, physical delivery for forecasted commodity transactions must be probable. Transactions that are financially settled are presented on a net basis.

 

Regulated Utilities - 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. Since these contracts are for the purchase of natural gas sold to regulated gas 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 use derivative financial instruments to reduce the commodity price risk associated with the purchase price of a portion of our future natural gas requirements and minimize fluctuations in gas supply prices to our regulated customers. 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 sheet. Upon settlement of these contracts, associated proceeds or costs are refunded to or collected from our customers consistent with regulatory requirements. At March 31, 2008 we had a derivative asset and offsetting regulatory liability of $14.0 million.

 

Interest Rates

 

During 2006, we issued $170.2 million of Montana Pollution Control Obligations and $150 million of Montana First Mortgage Bonds. In association with these refinancing transactions, we implemented a risk management strategy of utilizing interest rate swaps to manage our interest rate exposures associated with anticipated refinancing transactions. 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 accumulated other comprehensive income (AOCI) in our Consolidated Balance Sheets. We settled $320.2 million of forward starting interest rate swap agreements, and received aggregate settlement payments of approximately $14.6 million in 2006. 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. AOCI includes unrealized pre-tax gains related to these transactions of $12.5 million and $12.8 million at March 31, 2008 and December 31, 2007, respectively. 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. We have no further interest rate swaps outstanding.

 

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(8)   Segment Information

We operate the following business units: (i) regulated electric, (ii) regulated natural gas, (iii) unregulated electric, and (iv) all other, which primarily consists of our remaining unregulated natural gas operations and our unallocated corporate costs.

 

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):

 

 

 

 

 

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(9)   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 restricted shares were to vest. Common stock equivalent shares are calculated using the treasury stock method, as applicable. 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:

 

 

Warrants issued in 2004 were exercisable through the close of business November 1, 2007. A total of 194,468 warrants were exercised during the three months ended March 31, 2007. Warrants outstanding as of March 31, 2007 of 4,312,057 were dilutive and included in the 2007 earnings per share calculation.

Net periodic benefit cost for our pension and other postretirement plans consists of the following (in thousands):

 

 

In January 2008, we contributed approximately $21.9 million to our pension plans.

 

 

Federal Energy Regulatory Commission (FERC) Transmission Rate Case - In October 2006, we filed a request with the FERC for an electric transmission revenue increase. Our requested increase pertains only to FERC jurisdictional wholesale transmission and retail choice customers representing approximately $8.6 million in revenue. In May 2007, we implemented interim rates, which are subject to refund plus interest pending final resolution. We filed settlement documents on February 15, 2008 and are awaiting FERC approval, which is expected during the first half of 2008. This proposed settlement would result in an annualized margin increase of approximately $3.0 million. Regulated electric margin for the three months ended March 31, 2008 includes approximately $0.9 million from the interim rate increase.

 

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Montana Electric and Natural Gas Rate Case - In July 2007, we filed a request with the Montana Public Service Commission (MPSC) for an electric transmission and distribution revenue increase of $31.4 million, and a natural gas transmission, storage and distribution revenue increase of $10.5 million. In December 2007, we and the Montana Consumer Counsel filed a joint stipulation with the MPSC to settle our electric and natural gas rate cases. Specific terms of the Stipulation include:

The MPSC has approved interim rates, subject to refund, beginning January 1, 2008, and we anticipate finalizing the rate case during the second quarter of 2008. Regulated electric and gas margin for the three months ended March 31, 2008 includes approximately $3.4 million from the interim rate increase.

 

Environmental Liabilities

Environmental laws and regulations are continually evolving, and, therefore, the character, scope, cost and availability of the measures we may be required to take to ensure compliance with evolving laws or regulations cannot be accurately predicted. The range of exposure for environmental remediation obligations at present is estimated to range between $19.8 million to $57.0 million. As of March 31, 2008, we have a reserve of approximately $32.2 million. We anticipate that as environmental costs become fixed and reliably determinable, we will seek insurance reimbursement and/or authorization to recover these in rates; therefore, we do not expect these costs to have a material adverse effect on our consolidated financial position, ongoing operations, or cash flows.

 

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.

 

Coal-Fired Plants

 

We are joint owners in Colstrip Unit 4, a coal-fired power plant located in southeastern Montana, and three coal-fired plants used to serve our South Dakota customer supply demands. Citing its authority under the Clean Air Act, the EPA had finalized Clean Air Mercury Regulations (CAMR) that affected coal-fired plants. These regulations established a cap-and-trade program that would have taken effect in two phases beginning January 2010 and January 2018. Under CAMR, each state was allocated a mercury emissions cap and was required to develop regulations to implement the requirements, which could follow the federal requirements or be more restrictive. In February 2008 the EPA’s CAMR were turned down by the U.S. Court of Appeals for the District of Columbia Circuit; however, under this opinion, the EPA must either properly remove mercury from regulation under the hazardous air pollutant provisions of the Clean Air Act or develop standards requiring maximum achievable control technology for mercury emissions.

 

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 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

 

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financial impact of these rules.

 

Manufactured Gas Plants

 

Approximately $25.6 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. In 2007, we completed remediation of sediment in a short segment of Moccasin Creek that had been impacted by the former manufactured gas plant operations. Our current reserve for remediation costs at this site is approximately $11.9 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 initiated additional site investigation and assessment work at these locations. 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 exceedences of 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 problems 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 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.

 

Based upon our investigations to date, our current environmental liability reserves, applicable insurance coverage, and the potential to recover some portion of prudently incurred remediation costs in rates, we do not expect remediation costs at these locations to be materially different from the established reserve.

 

Milltown Dam Removal

 

Our subsidiary, Clark Fork and Blackfoot, LLC (CFB), owns the Milltown Dam, 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 within a year. We have a remaining financial obligation of $1.4 million to the State of Montana, which will be covered solely through a combination of a premium refund upon cancellation of an environmental insurance policy, and the sale or transfer of land and water rights associated with the Milltown Dam operations.

 

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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:

 

 

LEGAL PROCEEDINGS

 

Magten/Law Debenture/QUIPS Litigation

 

Magten and Law Debenture v. NorthWestern Corporation - On April 16, 2004, Magten Asset Management Corporation (Magten) and Law Debenture Trust Company (Law Debenture) initiated an adversary proceeding, which we refer to as the QUIPS Litigation, against NorthWestern seeking among other things, to void the transfer of certain assets and liabilities of CFB to us. In essence, Magten and Law Debenture are asserting that the transfer of the transmission and distribution assets acquired from the Montana Power Company was a fraudulent conveyance because it allegedly left CFB insolvent and unable to pay certain claims. The plaintiffs also assert that they are creditors of CFB as a result of Magten owning a portion of the Series A 8.45% Quarterly Income Preferred Securities (QUIPS) for which Law Debenture serves as the Indenture Trustee. Plaintiffs seek, among other things, the avoidance of the transfer of assets, declaration that the assets were fraudulently transferred and are not NorthWestern’s property, the imposition of constructive trusts over the transferred assets and the return of such assets to CFB. On July 18, 2007, the Delaware District Court extended the discovery schedule and scheduled the trial for March 2008; however, the trial date has been adjourned pending the Delaware Bankruptcy Court’s consideration of a comprehensive settlement, discussed below. The parties have entered into a comprehensive settlement and release agreement, dated March 17, 2008 (the Magten Settlement), which would resolve the QUIPS Litigation and other disputes. A motion to approve the Magten Settlement is scheduled to be heard by the Delaware Bankruptcy Court on May 7, 2008. We have and will continue to vigorously defend against the QUIPS litigation in the event the Magten Settlement does not become effective.

 

Magten v. Certain Current and Former Officers of CFB - On April 19, 2004, Magten filed a complaint against certain former and current officers of CFB in U.S. District Court in Montana, seeking compensatory and punitive damages for alleged breaches of fiduciary duties by such officers in connection with the same transaction described above which is at issue in the QUIPS Litigation, namely the transfer of the transmission and distribution assets acquired from the Montana Power Company to NorthWestern. Those officers have requested CFB to indemnify them for their legal fees and costs in defending against the lawsuit and any settlement and/or judgment in such lawsuit. That lawsuit was transferred to the Federal District Court in Delaware in July 2005 and is consolidated with the QUIPS Litigation for purposes of discovery and pre-trial matters. On July 18, 2007, the Delaware District Court extended the discovery schedule and scheduled the trial for March 2008; however, the trial date has been adjourned pending the Delaware Bankruptcy Court’s consideration of the Magten Settlement

 

Magten v. Bank of New York - In July 2006, Magten served a complaint against The Bank of New York (“BNY”) in an action filed in New York state court, seeking damages for alleged breach of contract, breach of fiduciary duty and negligence in connection with the same transaction described above which is at issue in the QUIPS Litigation. Specifically, Magten alleges that BNY, as the Indenture Trustee at the time of the 2002 transfer of assets from Montana Power Company to NorthWestern, should have taken steps to protect the QUIPS holders' interests by seeking to set aside the transfer and imposing a constructive trust on the assets. The New York State court dismissed

 

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Magten's complaint in May 2007 and Magten has filed a notice of appeal. BNY has asserted a right to indemnification by NorthWestern for legal fees and costs incurred in defending against Magten's claims pursuant to the terms of the Indenture governing the QUIPS under which BNY served as Trustee. NorthWestern’s position is that any such recovery should be payable from the Class 9 Disputed Claim Reserve set aside under NorthWestern's Chapter 11 Plan of Reorganization (the “Plan"). The Plan Committee, acting on behalf of certain creditors of NorthWestern's bankruptcy estate, has objected to NorthWestern’s position in this regard; however, NorthWestern and the Plan Committee have resolved this dispute pursuant to a settlement agreement between them, dated November 27, 2007 (the “Plan Committee Settlement”). The joint motion of NorthWestern and the Plan Committee to approve the Plan Committee Settlement is currently scheduled to be heard by the Delaware Bankruptcy Court on May 7, 2008. The Magten Settlement would settle the underlying claims that Magten has asserted against BNY.

 

Magten and Law Debenture v. NorthWestern Corporation and Certain Individuals - On April 15, 2005, Magten and Law Debenture filed an adversary complaint in the Bankruptcy Court against NorthWestern and certain former and current officers and directors seeking to revoke the Confirmation Order of NorthWestern’s Plan on the grounds that it was procured by fraud as a result of the alleged failure to adequately fund the Class 9 Disputed Claims Reserve with enough shares of new common stock to satisfy a potential full recovery on all disputed claims against NorthWestern's bankruptcy estate which were outstanding at the time the Plan became effective on November 1, 2004. The plaintiffs also alleged breach of fiduciary duty on the part of certain former and current officers in connection with the alleged under-funding of the Disputed Claims Reserve. NorthWestern filed a motion to dismiss or stay the litigation and on July 26, 2005, the Bankruptcy Court ordered a stay of the litigation pending resolution of Magten's appeal of the Order confirming the Plan. The Magten Settlement would resolve this litigation; however, NorthWestern intends to seek dismissal of this action and to the extent such action is not dismissed, NorthWestern intends to vigorously defend this action in the event the Magten Settlement does not become effective.

 

As indicated above, the Magten Settlement would effectuate a “global” resolution of all the currently pending claims and litigation arising out of our bankruptcy proceeding involving Magten, NorthWestern, CFB, the Plan Committee, BNY and other interested persons. If it is approved and becomes effective, the Magten Settlement would be funded using shares from the Class 9 Disputed Claims Reserve and payments from NorthWestern’s former attorneys and insurance proceeds.

 

On April 1, 2008, the Ad Hoc Committee filed an objection to the Magten Settlement. The Ad Hoc Committee is comprised of: Basso Capital Management; Bond Street Capital, LLC; Willow Fund, LLC; Franklin Mutual Advisers, LLC; FrontPoint Partners; and Stonehill Capital Management LLC . Such objection also purports to be a late-filed objection to the Plan Committee Settlement which provides for reimbursement of certain of NorthWestern’s defense costs related to the Magten litigation as well as certain Plan Committee and BNY defense costs related to the Magten litigation. A hearing on the two settlement agreements is currently scheduled for May 7, 2008. We cannot currently predict if the Magten Settlement will be approved and become effective; however, our view is that the plaintiffs' claims with respect to the QUIPs Litigation should be treated as general unsecured, or Class 9, claims which would, in either case, be satisfied, in the event they are allowed, out of the Disputed Claims Reserve established under the Plan.

 

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 are 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, like the Magten litigation described above, seeks, among other things, the avoidance of the transfer of assets from CFB to us, declaration that the assets were fraudulently transferred and are not property of our bankruptcy estate, the imposition of constructive trusts over the transferred assets, and the return of such assets to CFB.

 

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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 11 ^th injunction to the Ninth Circuit U.S. Court of Appeals, where a determination is pending. We do not anticipate a resolution of this litigation before class representatives and class counsel are approved by the U.S. District Court in Montana. However, 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. We will continue to vigorously defend against these claims and explore ways to remove ourselves from the lawsuits.

 

City of Livonia  

 

In November 2005, we and our directors were named as defendants in a shareholder class action and derivative action entitled City of Livonia Employee Retirement System v. Draper, et al., pending in the U.S. District Court for the District of South Dakota. The plaintiff claimed, among other things, that the directors breached their fiduciary duties by not sufficiently negotiating with Montana Public Power Inc. and Black Hills Corporation, two entities that had made public, unsolicited offers to purchase NorthWestern. On April 26, 2006, Livonia amended its complaint to add allegations that our directors had erred in choosing the BBI offer because it was not the most attractive offer they had received for the company. In December 2006, the plaintiffs agreed to dismiss the lawsuit with prejudice on the condition that the federal court would retain jurisdiction over any award of attorneys' fees. Plaintiffs filed a motion for attorneys' fees and costs seeking $9.9 million on the grounds that the Board's acceptance of the BBI offer was attributable to their efforts. On December 13, 2007, the federal court ordered additional simultaneous briefing on the issue of whether, in light of the BBI termination, the Livonia litigation had benefited our shareholders. In March 2008 the district court ruled that the plaintiffs lawyers should receive approximately $1.8 million in fees and costs. We have filed an appeal of the court’s order in the U.S. Court of Appeals for the Eighth Circuit. We have also filed a lawsuit in South Dakota state court against the insurance carrier as the carrier would not provide a definitive decision that any award of attorneys' fees would be reimbursed by insurance proceeds. We recorded a $1.8 million liability during the first quarter of 2008, pending the outcome of the appeal and lawsuit against the insurance carrier.

 

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. , Case No. DV-05-97. 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, 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 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 in a case called Ammondson, et al. v. NorthWestern Corporation, et al . 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 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, and we expect to incur additional legal and court costs related to these proceedings.

 

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Other Litigation and Contingencies

 

During the second quarter of 2007, we voluntarily informed the FERC of several potential regulatory compliance issues related to our natural gas business. The FERC has initiated a nonpublic, informal investigation. We cannot currently predict the outcome of the FERC's investigation.

 

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 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 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 a decision on CELP's request for a preliminary injunction. We believe CELP has no basis for their complaint and intend to vigorously defend this action. On January 24, 2008, we commenced an adversary proceeding against CELP in the Delaware Bankruptcy Court seeking a declaration that no prior order of the Delaware Bankruptcy Court either limited or curtailed the rate setting authority of the MPSC. On February 25, 2008, CELP filed a motion to dismiss the adversary proceeding and on April 7, 2008, NorthWestern timely filed its objection to that motion. A hearing on the motion to dismiss our adversary proceeding at CELP has not yet been scheduled.

 

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. The state of Montana issued a demand to WECO in May 2005 consistent with the MMS position outlined above on these transportation revenues. 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 US 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. While the percentage of our share of the alleged additional royalties is not expected to change, the estimated amount may increase as the MMS updates its assessment to reflect ongoing royalty and interest expenses.

 

We are also subject to various other legal proceedings and claims that arise in the ordinary course of business. In the opinion of management, the amount of ultimate liability with respect to these actions will not materially affect our financial position, results of operations, or cash flows.

 

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Unless the context requires otherwise, references to “we,” “us,” “our” and “NorthWestern” refer specifically to NorthWestern Corporation and its subsidiaries.

 

OVERVIEW

 

NorthWestern Corporation, doing business as Northwestern Energy, provides electricity and natural gas to approximately 650,000 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, 2007.

 

Highlights

 

Highlights for the three months ended March 31, 2008 include:

 

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OVERALL CONSOLIDATED RESULTS

The following is a summary of our results of operations for the three months ended March 31, 2008 and 2007. Our consolidated results include the results of our divisions and subsidiaries constituting each of our business segments. This discussion is followed by a more detailed discussion of operating results by segment.

Three Months Ended March 31, 2008 Compared with the Three Months Ended March 31, 2007

 

 

 

 

 

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Consolidated gross margin was $156.9 million for the three months ended March 31, 2008, an increase of $9.6 million, or 6.5%, from gross margin in the same period of 2007. The following summarizes components of the change:

 

Higher regulated electric and gas margin was due primarily to an increase in volumes from customer growth and colder weather, as well as an increase in rates . These increases were offset in part by a decrease in our unregulated electric margin.

 

 

Consolidated operating, general and administrative expenses were $60.1 million for the three months ended March 31, 2008 as compared to $62.4 million from the first quarter of 2007.

 

The reduction in operating, general and administrative expenses of $2.3 million was primarily due to decreased operating lease expense related to the purchase of our previously leased interest in Colstrip Unit 4 during 2007 (we expect operating lease expense to decrease $14.4 million in 2008). This reduction was partly offset by higher legal and professional fees, which included a $1.8 million judgment related to the City of Livonia shareholder litigation.

 

Property and other taxes were $23.6 million for the three months ended March 31, 2008 as compared to $20.6 million in the first quarter of 2007. Property and other taxes increased by approximately $1.8 million during the first quarter of 2008. In addition, property and other taxes in 2007 are net of approximately $1.2 million collected through our Montana property tax tracker.

 

Depreciation expense was $21.1 million for the three months ended March 31, 2008 as compared with $19.9 million in the first quarter of 2007. The increase was primarily due to the purchase of our previously leased interest in Colstrip Unit 4.

 

Consolidated operating income for the three months ended March 31, 2008 was $52.1 million, as compared with $44.4 million in the first quarter of 2007. This $7.7 million increase was primarily due to the $9.6 million increase in gross margin partly offset by higher operating expenses as discussed above.

 

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Consolidated interest expense for the three months ended March 31, 2008 was $16.1 million, an increase of $2.9 million, or 22.0%, from the first quarter of 2007. This increase was primarily related to the additional debt incurred with the purchase of our previously leased interest in Colstrip Unit 4.

 

Consolidated income tax expense for the three months ended March 31, 2008 was $13.2 million as compared with $12.4 million in the first quarter of 2007. Our effective tax rate for 2008 was 36.0% as compared to 39.2% for 2007. Portions of our professional fees and transaction related costs in 2007 were non-deductible for tax purposes, which increased our projected annual effective tax rate. While we reflect an income tax provision in our financial statements, we expect our cash payments for income taxes will be minimal through at least 2010, based on our anticipated use of net operating losses.

 

Consolidated net income for the three months ended March 31, 2008 was $23.5 million compared with $19.1 million for the first quarter of 2007. This increase was primarily due to higher operating income offset by higher interest and income tax expense as discussed above.

 

REGULATED ELECTRIC MARGIN

Three Months Ended March 31, 2008 Compared with the Three Months Ended March 31, 2007

 

 

 

The following summarizes the components of the changes in regulated electric margin for the three months ended March 31, 2008 and 2007:

 

 

The improvement is primarily due to an interim increase in transmission and distribution rates in Montana and increased volumes from 1.5% customer growth and colder weather. Also contributing to the margin increase was an interim increase in our FERC jurisdiction transmission rates and slightly higher wholesale margin due to increased plant availability.

 

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The following summarizes regulated electric volumes and customer counts for the three months ended March 31, 2008 and 2007:

 

 

 

 

Regulated electric volumes increased due primarily to customer growth and colder weather. Regulated wholesale electric volumes increased due to increased plant availability as compared with 2007.

 

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REGULATED NATURAL GAS MARGIN

 

Three Months Ended March 31, 2008 Compared with the Three Months Ended March 31, 2007

 

 

The following summarizes the components of the changes in regulated natural gas margin for the three months ended March 31, 2008 and 2007:

 

 

The improvement is primarily due to an increase in our transportation and distribution rates and increased volumes due to colder weather and 1.4% customer growth. In addition, $0.7 million of the increase is due to the transfer of certain previously unregulated customers and pipelines into the regulated business and $0.4 million from higher storage utilization.

 

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The following summarizes regulated natural gas volumes, customer counts and heating degree-days for the three months ended March 31, 2008 and 2007:

 

 

 

 

 

Regulated natural gas volumes increased due to customer growth and colder weather.

 

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UNREGULATED ELECTRIC MARGIN

Three Months Ended March 31, 2008 Compared with the Three Months Ended March 31, 2007

Our unregulated electric segment primarily consists of our joint ownership in the Colstrip Unit 4 generation facility, which represents approximately 30%. We sell our Colstrip Unit 4 output, approximately 222 MWs at full load, principally to two unrelated third parties under agreements through December 2010. Under a separate agreement we repurchase 111 MWs through December 2010. These 111 MWs were available for market sales to other third parties through June 2007. Beginning July 1, 2007, 90 MWs of base-load energy from Colstrip Unit 4 are being supplied to the Montana electric supply load (included in our regulated electric segment) for a term of 11.5 years at an average nominal price of $35.80 per MWH. In addition, 21 MWs of base-load energy from Colstrip Unit 4 are being provided on an interim basis to the Montana electric supply load for a term of 76 months beginning in March 2008 at $19 per MWH below the Mid-C index price with a floor of zero, pending approval of the proposed stipulation in Montana.

 

 

 

The following summarizes the components of the changes in unregulated electric margin for the three months ended March 31, 2008 and 2007:

 

 

The decrease in margin was primarily due to lower average contracted prices and higher fuel supply costs. In addition, we recorded an unrealized loss of $1.2 million during the first quarter of 2008 related to forward contracts executed during the period to economically hedge a portion of our Colstrip Unit 4 output through 2009. These contracts do not qualify for hedge accounting and market value adjustments will be included in Cost of Sales on a quarterly basis, however these losses will reverse as the power is delivered. An increase in volumes from higher plant availability partly offset these decreases.

 

The following summarizes unregulated electric volumes for the three months ended March 31, 2008 and 2007:

 

 

The increase in energy available to sell as compared with 2007 was due to increased plant availability.

 

We expect our margin to decrease throughout 2008 under the terms of our Colstrip Unit 4 commitments to Montana electric supply discussed above. In addition, in January 2008, we retained a financial advisor to assist us in evaluating our strategic options with respect to our joint ownership of Colstrip Unit 4.

 

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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 reduce borrowings. As of March 31, 2008, we had cash and cash equivalents of $33.8 million, and revolver availability of $173.9 million. During the three months ended March 31, 2008, we repaid $30.0 million of debt, including $12.0 million on our revolver, paid dividends on common stock of $12.9 million and contributed $21.9 million to our pension plans.

Factors Impacting our Liquidity

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, which do not impact net income, can have a significant effect on cash flow from operations and make year-to-year comparisons difficult.

 

As of March 31, 2008, we are over collected on our current Montana natural gas and electric trackers by approximately $12.7 million, as compared with an over collection of $3.7 million as of March 31, 2007. This over collection is primarily due to increases in our electric supply rates during 2007 based on higher forward contracted prices. This has the effect of phasing in the supply cost increases over two years.

 

Cash Flows

The following table summarizes our consolidated cash flows (in millions):

 

 

 

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Cash Provided By Operating Activities

As of March 31, 2008, cash and cash equivalents were $33.8 million, compared with $12.8 million at December 31, 2007 and $1.5 million at March 31, 2007. Cash provided by operating activities totaled $78.0 million for the three months ended March 31, 2008 as compared with $104.1 million during the three months ended March 31, 2007. This decrease in operating cash flows is primarily related to a change in timing of the funding of our pension plans to the first quarter of 2008 from the second quarter of 2007, and other changes in working capital. The change in working capital was due to lower collections associated with the recovery of energy supply costs in the first quarter of 2008 as compared with 2007, which is discussed above in the “Factors Impacting Our Liquidity” section, and increased purchases of electricity in our South Dakota jurisdiction due to outages in the fourth quarter of 2007 at one of our jointly owned plants, partially offset by the timing of our semi-annual Colstrip Unit 4 lease payment in 2007.

Cash Used in Investing Activities

Cash used in investing activities totaled $14.0 million during the three months ended March 31, 2008, as compared with $60.6 million during the three months ended March 31, 2007. During the first quarter of 2008 we invested $14.0 million in property, plant and equipment additions. In the first quarter of 2007 we used $40.2 million to complete the purchase of the Owner Participant interest in a portion of the Colstrip Unit 4 generating facility, and $20.5 million for property, plant and equipment additions.

Cash Used in Financing Activities

Cash used in financing activities totaled $43.0 million during the three months ended March 31, 2008, as compared with $43.9 million during the three months ended March 31, 2007. During the first quarter of 2008 we made debt repayments of $30.0 million and paid dividends on common stock of $12.9 million, as compared with debt repayments of $37.6 million and dividends on common stock of $11.1 million in the first quarter of 2007.

Sources and Uses of Funds

We believe that our cash on hand, operating cash flows, and borrowing capacity, taken as a whole, provide sufficient resources to fund our ongoing operating requirements, debt maturities, anticipated dividends and estimated future capital expenditures during the next twelve months. As of April 18, 2008, our availability under our revolving line of credit was approximately $174.9 million.

 

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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, 2008. See our Annual Report on Form 10-K for the year ended December 31, 2007 for additional discussion.

 

 

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Credit Ratings

Fitch Investors Service (Fitch), Moody’s Investors Service (Moody’s) and 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 18, 2008, our ratings with these agencies are as follows:

 

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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.

 

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, 2008, 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, 2007. 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.

 

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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 revolver and the Colstrip Lease Holdings LLC (CLH) $100 million loan. The revolving credit facility bears interest at a variable rate (approximately 3.57% as of March 31, 2008) tied to the London Interbank Offered Rate (LIBOR) plus a credit spread. The CLH loan currently bears interest at approximately 3.94%, which is 1.25% over LIBOR. Based upon amounts outstanding as of March 31, 2008, a 1% increase in the LIBOR would increase our annual interest expense by approximately $1.0 million.

 

Commodity Price Risk

 

Commodity price risk is one of our most significant risks due to our lack of ownership of natural gas reserves or regulated electric generation assets within the Montana market, and our unregulated joint ownership interest in Colstrip Unit 4. Several factors influence price levels and volatilities. 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 unregulated electric segment we use forward contracts to manage our exposure to the market price of electricity. We have entered into unit-contingent forward contracts for the sale of a significant portion of the output. In addition, we have economically hedged a portion of our output through 2009. As of March 31, 2008 market prices exceeded our contracted forward sales prices by approximately $1.2 million. These market value adjustments will reverse as the power is delivered.

 

In our all other segment, we currently have a capacity contract through 2013 with a pipeline that gives us basis risk depending on gas prices at two different delivery points. We have sales contracts with certain customers that provide for a selling price based on the index price of gas coming from a delivery point in Ventura, Iowa. The pipeline capacity contract allows us to take delivery of gas from Canada, which has historically been cheaper than gas coming from Ventura, even when including transportation costs. If the Canadian gas plus transportation cost exceeds the index price at Ventura, then we will lose money on these gas sales. The annual capacity payments are approximately $1.8 million, which represents our maximum annual exposure related to this basis risk.

 

Counterparty Credit Risk

 

We have considered a number of risks and costs associated with the future contractual commitments included in our energy portfolio. These risks include credit risks associated with the financial condition of counterparties, product location (basis) differentials and other risks. Declines in the creditworthiness of our counterparties could have a material adverse impact on our overall exposure to credit risk. We maintain credit policies with regard to our counterparties that, in management's view, reduce our overall credit risk. There can be no assurance, however, that the management tools we employ will eliminate the risk of loss.

 

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Evaluation of Disclosure Controls and Procedures

 

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, 2008 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

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PART   II.   OTHER INFORMATION

 

See Note 12, Commitments and Contingencies, to the Consolidated Financial Statements for information about legal proceedings.

 

 

You should carefully consider the risk factors described below, as well as all other information available to you, before making an investment in our shares or other securities.

 

We have incurred, and may continue to incur, significant costs associated with outstanding litigation, which may adversely affect our results of operations and cash flows.

 

These costs, which are being expensed as incurred, have had, and may continue to have, an adverse affect on our results of operations and cash flows. Pending litigation matters are discussed in detail under the Legal Proceedings section in Note 12 to the Consolidated Financial Statements. An adverse result in any of these matters could have an adverse effect on our business.

 

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 condition 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 are subject to extensive governmental laws and regulations that affect our industry and our operations, which could have a material adverse effect on our results of operations and financial condition.

 

We are subject to regulation by federal and state governmental entities, including the FERC, MPSC, South Daktoa Public Utilities Commission and Nebraska Public Service Commission. Regulations can affect allowed rates of return, recovery of costs and operating requirements. 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 results of operations, cash flows and financial position.

 

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

 

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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 recent US Supreme Court decision holding that the EPA has the authority 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 in order to meet future requirements and obligations under environmental laws.

 

Our range of exposure for current environmental remediation obligations is estimated to be $19.8 million to $57.0 million. We had an environmental reserve of $32.2 million at March 31, 2008. This reserve was established in anticipation of future remediation activities at our various environmental sites and does not factor in any exposure to us arising from new regulations, private tort actions or claims for damages allegedly associated with specific environmental conditions. 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 condition 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 do not own any natural gas reserves or regulated electric generation assets to service our Montana operations. As a result, we are required to procure our entire natural gas supply and substantially all of our Montana electricity 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.

 

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 QFs 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. 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

 

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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. Since we own no material generation in Montana, 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 I Plant (our largest source of generation in South Dakota), making us vulnerable to railroad capacity 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, 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.

 

We must meet certain credit quality standards. If we are unable to maintain an investment grade credit rating, we would be required under certain commodity purchase 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 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.

 

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.

 

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SIGNATURES

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.

 

 

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EXHIBIT INDEX

 

 

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