10-Q 1 q10_09302009.htm Q3-2009 q10_09302009.htm
 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q

(mark one)
    
x
  
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
     
For the quarterly period ended September 30, 2009
     
OR
     
¨
  
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
incorporation or organization)
  
(I.R.S. Employer
Identification No.)
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
 
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 o No o
 
 
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.
 
Large Accelerated Filer x        Accelerated Filer o        Non-accelerated Filer o        Smaller Reporting Company o
 
 
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
 
 
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
 
 
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
35,983,082 shares outstanding at October 23, 2009

 
 
 
 
 
NORTHWESTERN CORPORATION
 
 
INDEX

 
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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;
·  
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.


 
3
 

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.

 

 
4
 

 
PART 1.    FINANCIAL INFORMATION
 
FINANCIAL STATEMENTS
 
NORTHWESTERN CORPORATION
 
 
(Unaudited)
(in thousands, except share data)
           
   
September 30,
2009
December 31,
2008
ASSETS
          
Current Assets:
          
   Cash and cash equivalents
  
$
6,043
  
$
11,292
  
   Restricted cash
  
13,542
  
14,727
  
   Accounts receivable, net
  
90,458
  
155,672
  
   Inventories
  
62,271
  
70,741
  
   Regulatory assets
  
41,975
  
46,905
  
   Deferred income taxes
  
8,729
  
685
  
   Prepaid and other
  
14,394
  
13,395
  
      Total current assets 
  
237,412
  
313,417
  
Property, plant, and equipment, net
  
1,899,525
  
1,839,699
  
Goodwill
  
355,128
  
355,128
  
Regulatory assets
  
233,525
  
233,102
  
Other noncurrent assets
  
28,888
  
20,691
  
      Total assets 
  
$
2,754,478
  
$
2,762,037
  
LIABILITIES AND SHAREHOLDERS' EQUITY
          
Current Liabilities:
          
   Current maturities of capital leases
  
$
1,187
  
$
1,193
  
   Current maturities of long-term debt
  
6,123
  
228,045
  
   Accounts payable
  
58,511
  
94,685
  
   Accrued expenses
  
224,187
  
215,431
  
   Regulatory liabilities
  
37,051
  
49,223
  
      Total current liabilities 
  
327,059
  
588,577
  
Long-term capital leases
  
35,882
  
36,798
  
Long-term debt
  
884,280
  
634,011
  
Deferred income taxes
  
149,072
  
114,707
  
Noncurrent regulatory liabilities
  
235,881
  
222,969
  
Other noncurrent liabilities
  
346,670
  
401,442
  
      Total liabilities 
  
1,978,844
  
1,998,504
  
Commitments and Contingencies (Note 14)
          
Shareholders' Equity:
          
   Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 39,539,612 and 35,983,082, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued
  
395
  
395
  
   Treasury stock at cost
  
(90,050
)
(89,487
)
   Paid-in capital
  
807,531
  
805,900
  
   Retained earnings
  
46,048
  
34,371
  
   Accumulated other comprehensive income
  
11,710
  
12,354
  
      Total shareholders' equity 
  
775,634
  
763,533
  
      Total liabilities and shareholders' equity
  
$
2,754,478
  
$
2,762,037
    
             

See Notes to Condensed Consolidated Financial Statements

 
 
5
 
 
NORTHWESTERN CORPORATION
 
 
(Unaudited)
 
(in thousands, except per share amounts)
 

   
Three Months Ended
September 30,
  
Nine Months Ended
September 30,
  
   
2009
  
2008
  
2009
  
2008
  
Revenues
                      
   Electric 
  
$
198,416
  
$
207,687
  
$
579,277
  
$
582,687
  
   Gas
  
34,179
  
45,603
  
253,976
  
297,357
  
   Other
  
291
  
18,954
  
6,249
  
54,681
  
     Total Revenues
  
232,886
  
272,244
  
839,502
  
934,725
  
Operating Expenses
                  
   Cost of sales
  
105,183
  
130,503
  
420,033
  
508,941
  
   Operating, general and administrative
  
57,893
  
63,411
  
184,210
  
177,348
  
   Property and other taxes
  
20,866
  
21,718
  
63,401
  
65,898
  
   Depreciation
  
21,977
  
21,292
  
66,959
  
63,608
  
     Total Operating Expenses
  
205,919
  
236,924
  
734,603
  
815,795
  
Operating Income
  
26,967
  
35,320
  
104,899
  
118,930
  
Interest Expense
  
(17,267
)
(15,629
)
(50,403
)
(47,478
)
Other Income
  
403
  
1,218
  
1,192
  
1,640
  
Income Before Income Taxes
  
10,103
  
20,909
  
55,688
  
73,092
  
Income Tax Benefit (Expense)
  
8,797
  
(7,530
)
(7,877
)
(26,759
)
Net Income
  
$
18,900
  
$
13,379
  
$
47,811
  
$
46,333
  
 
Average Common Shares Outstanding
  
35,968
  
38,057
  
35,947
  
38,665
  
Basic Earnings per Average Common Share
  
$
0.53
  
$
0.35
  
$
1.33
  
$
1.20
  
Diluted Earnings per Average Common Share
  
$
0.52
  
$
0.35
  
$
1.32
  
$
1.19
  
Dividends Declared per Average Common Share
  
$
0.335
  
$
0.33
  
$
1.01
  
$
0.99
  


See Notes to Condensed Consolidated Financial Statements
 





 
6
 

NORTHWESTERN CORPORATION
 
(Unaudited)
(in thousands)

   
Nine Months Ended
September 30,
  
   
2009
  
2008
  
OPERATING ACTIVITIES:
          
   Net Income
  
$
47,811
  
$
46,333
  
   Items not affecting cash:
          
      Depreciation
  
66,959
  
63,608
  
      Amortization of debt issue costs, discount and deferred hedge gain
  
1,640
  
1,818
  
      Amortization of restricted stock
  
1,631
  
2,699
  
      Equity portion of allowance for funds used during construction
  
(828
)
(432
)
      Gain on sale of assets
  
(306
)
(154
)
      Unrealized gain on derivative instruments
  
—
  
(3,763
)
      Deferred income taxes
  
26,320
  
28,831
  
   Changes in current assets and liabilities:
          
      Restricted cash
  
1,185
  
(1,684
)
      Accounts receivable
  
65,214
  
35,027
  
      Inventories
  
8,470
  
(27,310
)
      Prepaid energy supply costs
  
(436
)
436
  
      Other current assets
  
(514
)
597
  
      Accounts payable
  
(34,478
)
(20,001
)
      Accrued expenses
  
12,424
  
50,334
  
      Regulatory assets
  
(537
)
7,365
  
      Regulatory liabilities
  
(12,172
)
15,381
  
   Other noncurrent assets
  
3,000
  
902
  
   Other noncurrent liabilities
  
(56,072
)
(23,238
)
Cash provided by operating activities
  
129,311
  
176,749
  
INVESTING ACTIVITIES:
          
   Property, plant, and equipment additions
  
(115,855
)
(81,016
)
   Proceeds from sale of assets
  
326
  
86
  
Cash used in investing activities
  
(115,529
)
(80,930
)
FINANCING ACTIVITIES:
          
   Treasury stock activity
  
(563
)
(78,568
)
   Dividends on common stock
  
(36,134
)
(37,977
)
   Issuance of long-term debt, net of discount
  
249,833
  
55,000
  
   Repayment of long-term debt
  
(137,780
)
(88,953
)
   Line of credit borrowings
  
275,000
  
94,000
  
   Line of credit repayments
  
(359,000
)
(42,000
)
   Financing costs
  
(10,387
)
(1,519
)
Cash used in financing activities
  
(19,031
)
(100,017
)
Decrease in Cash and Cash Equivalents
  
(5,249
)
(4,198
)
Cash and Cash Equivalents, beginning of period
  
11,292
  
12,773
  
Cash and Cash Equivalents, end of period
  
$
6,043
  
$
8,575
  
Supplemental Cash Flow Information:
          
   Cash paid during the period for:
          
      Income taxes
  
$
2
  
$
78
  
      Interest
  
29,506
  
35,112
  
   Significant non-cash transactions:
          
      Capital expenditures included in trade accounts payable
  
3,065
  
3,269
  

See Notes to Condensed Consolidated Financial Statements

 
 
7
 
 
(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 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 generated and distributed electricity and distributed natural gas in Montana since 2002.

The Condensed Consolidated Financial Statements (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 (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 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. Events occurring subsequent to September 30, 2009, have been evaluated as to their potential impact to the Financial Statements through the date of issuance, October 29, 2009.

The 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 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 Financial Statements be read in conjunction with audited Financial Statements and related footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2008.

On July 1, 2009 the Financial Accounting Standards Board (FASB) Accounting Standards Codification (the Codification or ASC) became the single source of authoritative GAAP. Throughout these notes, references to ASC are presented parenthetically along with references to pre-Codification GAAP.

(2)   New Accounting Standards
 
Accounting Standards Issued

In June 2009, the FASB issued Statements of Financial Accounting Standards (SFAS) No. 167 (ASC 810), Amendments to FASB Interpretation No. 46(R) (SFAS No. 167). SFAS No. 167 is a revision to FASB Interpretation No. 46(R) (ASC 810), Consolidation of Variable Interest Entities (FIN 46R), and changes how a company determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar) rights should be consolidated. The determination of whether a company is required to consolidate an entity is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity that most significantly impact the entity’s economic performance. The statement includes the following significant provisions:
·  
requires an entity to qualitatively assess the determination of the primary beneficiary of a variable interest entity (VIE) based on whether the entity (1) has the power to direct matters that most significantly impact the activities of the VIE, and (2) has the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE,
·  
requires an ongoing reconsideration of the primary beneficiary instead of only upon certain triggering events,
·  
amends the events that trigger a reassessment of whether an entity is a VIE, and

 
 
8
 

·  
for an entity that is the primary beneficiary of a VIE, requires separate balance sheet presentation of (1) the assets of the consolidated VIE, if they can be used to only settle specific obligations of the consolidated VIE, and (2) the liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary.

The statement is effective for us beginning January 1, 2010. We are currently evaluating the impact of adoption, if any, on our financial position and results of operations.

Accounting Standards Adopted

In March 2008, the FASB issued SFAS No. 161 (ASC 815), Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133 (SFAS No. 161). This statement requires expanded disclosures about derivative instruments and hedging activities, but does not change the accounting for derivatives. We adopted this statement on January 1, 2009. The disclosures required by this statement are included in Note 7, Risk Management and Hedging Activities.

In April 2009, the FASB issued three Final Staff Positions (FSPs) intended to provide additional application guidance and enhance disclosures regarding fair value measurements and impairments of securities. FSP 157-4 (ASC 820), 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 additional guidance for estimating fair value when the volume and level of activity for the asset or liability have decreased. The FSP also includes guidance on identifying circumstances that indicate a transaction is not orderly. Finally, the FSP expands the disclosure requirements for fair value measurements to include further disaggregation in the tabular disclosures. FSP 115-2 and 124-2 (ASC 820), 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 adopted these FSPs as of June 30, 2009 with no effect on our financial position or results of operations.

FSP 107-1 (ASC 825), Interim Disclosures about Fair Value of Financial Instruments (FSP 107-1), increases the frequency of fair value disclosures required by SFAS No. 107 (ASC 820), Disclosures About Fair Value of Financial Instruments (SFAS No. 107). This FSP requires that companies provide qualitative and quantitative information about fair value estimates for all financial instruments not measured on the balance sheet at fair value in each interim report.  Previously, this was only an annual requirement.  We adopted this FSP as of June 30, 2009. The disclosures required by this statement are included in Note 8, Fair Value Measurements.

In May 2009, the FASB issued SFAS No. 165 (ASC 855), Subsequent Events (SFAS No. 165), which provides guidance to establish general standards of accounting for and disclosures of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. The statement does not result in significant changes in the subsequent events that an entity reports, rather, it requires disclosure of the date through which subsequent events have been evaluated and whether that date represents the date the financial statements were issued or were available to be issued. We adopted this statement as of June 30, 2009. The disclosures required by this statement are included in Note 1, Nature of Operations and Basis of Consolidation.

In June 2009, the FASB issued SFAS No. 168 (ASC 105), FASB Accounting Standards Codification (SFAS No. 168), as the single source of authoritative nongovernmental GAAP. All existing accounting standards are superseded as described in SFAS No. 168, aside from those issued by the SEC. All other accounting literature not included in the Codification is nonauthoritative. We adopted the Codification as of September 30, 2009, which is reflected in our disclosures and references to accounting standards, with no impact to our financial position or results of operations.

(3)  Variable Interest Entities
 
We are required to consolidate VIEs if we are the primary beneficiary, which means we have a controlling financial interest. Certain long-term purchase power and tolling contracts may be considered variable interests. We have various long-term purchase power contracts with other utilities and certain qualifying facility (QF) plants. After evaluation of

 
 
9
 

these contracts, we believe one QF contract may constitute a VIE. We continue to account for this QF contract as an executory contract as we have been unable to obtain the necessary information from this QF 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 QF, our estimated gross contractual payments aggregate approximately $474.9 million through 2025, and are included in Contractual Obligations and Other Commitments of Management's Discussion and Analysis. We will reassess this contract under the new accounting guidance discussed in Note 2 above.

 
In December 2008, we filed a request with the Internal Revenue Service (IRS) to change our tax accounting method related to costs to repair and maintain utility assets. The IRS approved our request in September 2009, which allows us to take a current tax deduction for a significant amount of repair costs that were previously capitalized for tax purposes.

These repair costs are capitalized and depreciated for book purposes. We record a deferred income tax liability as we flow the temporary timing differences between book and tax treatment through to our customers in the form of lower rates. A regulatory asset is established to reflect that future increases in taxes payable will be recovered from customers as the temporary differences reverse. Due to this regulatory treatment, we recorded an income tax benefit of approximately $12.4 million during the third quarter of 2009 to reflect this change in tax accounting method, of which approximately $8.0 million and $4.4 million related to the 2008 and 2009 tax years, respectively. For years prior to 2008, we have not recorded a regulatory asset for the repairs deduction as the benefit was not flowed through to customers. This change in tax accounting method will have the effect of extending our net operating loss carryforwards.

We compute the income tax (benefit) expense for each quarter based on the estimated annual effective tax rate for the year, adjusted for certain discrete items. The effective tax rate was (87.1)% and 14.1% for the three and nine months ended September 30, 2009, respectively, compared to 36.0% and 36.6% for the same periods of 2008. The 2009 rates reflect the impact of the change in tax accounting method for repairs described above and lower estimated 2009 taxable income.

Uncertain Tax Positions

We have unrecognized tax benefits of approximately $117.5 million as of September 30, 2009, including approximately $79.7 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 nine months ended September 30, 2009, we have not recognized expense for interest or penalties, and do not have any amounts accrued at September 30, 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 nine months ended September 30, 2009. Goodwill by segment is as follows for both September 30, 2009 and December 31, 2008 (in thousands):

       
Regulated electric
  
$
241,100
  
Regulated natural gas
  
114,028
  
   
$
355,128
  
 
10
 
 
 
The following table displays the components of Accumulated Other Comprehensive Income (AOCI), which is included in Shareholder’s Equity on the Condensed Consolidated Balance Sheets (in thousands).
 

   
Three Months Ended
September 30,
  
Nine Months Ended
September 30,
  
   
2009
  
2008
  
2009
  
2008
  
Net income
  
$
18,900
    
$
13,379
    
$
47,811
    
$
46,333
    
Other comprehensive income (loss), net of tax:
                                  
Reclassification of net gains on hedging instruments from OCI to net income
    
(297
)
    
(297
)
    
(891
)
    
(891
)
  
Foreign currency translation
    
155
      
(81
)
    
248
      
(143
)
  
Comprehensive income
  
$
18,758
    
$
13,001
    
$
47,168
    
$
45,299
    

(7)   Risk Management and Hedging Activities
 
 
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 a significant risk 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 derivative 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 require that all derivatives be recognized in the balance sheet, either as assets or liabilities, at fair value. 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 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. 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.

Normal Purchases and Normal Sales

We have applied the normal purchase and normal sale scope exception (NPNS) to most of our contracts involving the physical purchase and sale of gas and electricity at fixed prices in future periods. During our normal course of business, we enter into full-requirement energy contracts, power purchase agreements and physical capacity contracts, which

 
 
11
 

qualify for NPNS. All of these contracts are accounted for using the accrual method of accounting; therefore, there were no amounts recorded in the Financial Statements at September 30, 2009 and December 31, 2008. 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.

Mark-to-Market Accounting

Certain contracts for the physical purchase of natural gas associated with our regulated gas utilities do not qualify for NPNS. These are typically forward purchase contracts for natural gas where we lock in a fixed price; however the contracts are settled financially and we do not take physical delivery of the natural gas. We use the mark-to-market method of accounting for these derivative contracts as we do not elect hedge accounting. Upon settlement of these contracts, associated proceeds or costs are refunded to or collected from our customers consistent with regulatory requirements therefore we record a regulatory asset or liability based on changes in market value.

The following table represents the fair value and location of derivative instruments subject to mark-to-market accounting (in thousands). For more information on the determination of fair value see Note 8.

Mark-to-Market Transactions
  
Balance Sheet Location
  
September 30,
2009
  
December 31, 2008
  
               
Regulated natural gas net derivative liability
  
Accrued Expenses
  
$
23,602
  
$
29,156
  

The following table represents the net change in fair value for these derivatives (in thousands):

   
Unrealized gain recognized in
Regulatory Assets
  
Derivatives Subject to Regulatory Deferral
  
Three Months Ended September 30, 2009
  
Nine Months Ended
September 30, 2009
  
             
Natural gas
  
$
8,377
  
$
5,554
  

Credit Risk

We are exposed to credit risk primarily through buying and selling electricity and natural gas to serve customers. Credit risk is the potential loss resulting from counterparty non-performance under an agreement. We manage credit risk with policies and procedures for, among other things, counterparty analysis and exposure measurement, monitoring and mitigation. We may request collateral or other security from our counterparties based on the assessment of creditworthiness and expected credit exposure. It is possible that volatility in commodity prices could cause us to have material credit risk exposures with one or more counterparties.

We enter into commodity master arrangements with our counterparties to mitigate credit exposure, as these agreements reduce the risk of default by allowing us or our counterparty the ability to make net payments. The agreements generally are: Western Systems Power Pool agreements (WSPP) – standardized power sales contracts in the electric industry; (2) International Swaps and Derivatives Association agreements (ISDA) – standardized financial gas and electric contracts; (3) North American Energy Standards Board agreements (NAESB) – standardized physical gas contracts; and (4) Edison Electric Institute Master Purchase and Sale Agreements – standardized power sales contracts in the electric industry.

Many of our forward purchase contracts contain provisions that require us to maintain an investment grade credit rating from each of the major credit rating agencies. If our credit rating were to fall below investment grade, it would be in violation of these provisions, and the counterparties could require immediate payment or demand immediate and ongoing full overnight collateralization on contracts in net liability positions.

The following table presents, as of September 30, 2009, the aggregate fair value of forward purchase contracts that do not qualify as normal purchases in a net liability position with credit risk-related contingent features, collateral posted, and the aggregate amount of additional collateral that we would be required to post with counterparties, if the credit risk-related

 
 
12
 

contingent features underlying these agreements were triggered on September 30, 2009 (in thousands):

Contracts with Contingent Feature
  
Fair Value Liability
  
Posted Collateral
  
Contingent Collateral
  
                 
Credit rating
  
$
24,601
  
$
—
  
$
24,601
  

Interest Rate Swaps Designated as Cash Flow Hedges

If we enter into 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.

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 with the effective portion of gains and losses, net of associated deferred income tax effects, recorded in AOCI. We reclassify these gains from AOCI into interest expense during the periods in which the hedged interest payments occur. The following table shows the effect of these derivative instruments on the Financial Statements:

Cash Flow Hedges
  
Amount of Gain Remaining in AOCI as of September 30, 2009
  
Location of Gain Reclassified from AOCI to Income
  
Amount of Gain Reclassified from AOCI into Income during the Nine Months Ended
September 30, 2009
  
               
Interest rate contracts
  
$
10,761
    
Interest Expense
  
$
891
  
                     

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

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., an exit price). Measuring fair value requires the use of market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, corroborated by market data, or generally unobservable. Valuation techniques are required to maximize the use of observable inputs and minimize the use of unobservable inputs.

A fair value hierarchy that prioritizes the inputs used to measure fair value, and requires fair value measurements to be categorized based on the observability of those inputs has been established by the applicable accounting guidance. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 inputs) and the lowest priority to unobservable inputs (Level 3 inputs). The three levels of the fair value hierarchy are as follows:

·  
Level 1 – Unadjusted quoted prices available in active markets at the measurement date for identical assets or liabilities;

 
 
13
 

·  
Level 2 – Pricing inputs, other than quoted prices included within Level 1, which are either directly or indirectly observable as of the reporting date; and
·  
Level 3 – Significant inputs that are generally not observable from market activity.

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. The table below sets forth by level within the fair value hierarchy the gross components of our assets and liabilities measured at fair value on a recurring basis as of September 30, 2009. Normal purchases and sales transactions are not included in the fair values by source table as they are not recorded at fair value. See Note 7 for further discussion.

September 30, 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)
  
Restricted cash
  
$
12,899
  
$
—
  
$
—
  
$
—
  
$
12,899
  
Derivative asset (1)
    
—
    
1,440
    
—
    
—
    
1,440
  
Derivative liability (1)
    
—
    
(25,042
)
  
—
    
—
    
(25,042
)
Net derivative position
    
—
    
(23,602
)
  
—
    
—
    
(23,602
)
Total
  
$
12,899
  
$
(23,602
)
$
—
  
$
—
  
$
(10,703
)
 
(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.

We present our derivative assets and liabilities on a net basis in the Condensed Consolidated Balance Sheets. The table above disaggregates our net derivative assets and liabilities on a gross contract-by-contract basis as required 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.

Restricted cash represents amounts held in money market mutual funds. Fair value for the commodity derivatives was determined using internal models based on quoted forward commodity prices. We consider nonperformance risk in our valuation of derivative instruments by analyzing the credit standing of our counterparties and considering any counterparty credit enhancements (e.g., collateral). The fair value measurement of liabilities also reflects the nonperformance risk of the reporting entity, as applicable. Therefore, we have factored the impact of our credit standing as well as any potential credit enhancements into the fair value measurement of both derivative assets and derivative liabilities. Consideration of our own credit risk did not have a material impact on our fair value measurements.

Financial Instruments

The estimated fair value of financial instruments is summarized as follows (in thousands):

   
September 30, 2009
  
December 31, 2008
  
   
Carrying Amount
  
Fair Value
  
Carrying Amount
  
Fair Value
  
Liabilities:
                  
  Long-term debt (including current portion)
  
$
890,403
  
$
918,118
  
$
862,056
$
780,023
  

The estimated fair value amounts have been determined using available market information and appropriate valuation methodologies; however, considerable judgment is necessarily required in interpreting market data to develop estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we

 
 
14
 

would realize in a current market exchange.

We used the following methods and assumptions to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:
 
·  
The carrying amounts of cash, cash equivalents, and restricted cash approximate fair value due to the short maturity of the instruments.
 
·  
We determined fair values for debt based on interest rates that are currently available to us for issuance of debt with similar terms and remaining maturities, except for publicly traded debt, for which fair value is based on market prices for the same or similar issues or upon the quoted market prices of U.S. treasury issues having a similar term to maturity, adjusted for our bond issuance rating and the present value of future cash flows.

(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, which were discounted to yield 6.349%. The bonds are secured by our Montana electric and natural gas assets. The bonds were issued in a transaction exempt from registration under the Securities Act of 1933, as amended. We completed an offer to exchange these bonds for a like series of bonds registered under the Securities Act of 1933 during the third quarter of 2009. We used the proceeds to redeem our $100 million Colstrip Lease Holdings LLC term loan, repay outstanding borrowings on our revolving credit facility, repay other outstanding debt obligations of $31.7 million related to Colstrip Unit 4, fund a portion of the costs of the Mill Creek generation project, and fund future capital expenditures.

On June 30, 2009, we amended and restated our unsecured revolving line of credit scheduled to expire on November 1, 2009. The amended facility extends the term to June 30, 2012, and increases the aggregate principal amount available under the facility by $50 million to $250 million. The amended facility does not amortize and borrowings will bear interest based on a credit ratings grid. The ‘spread’ or ‘margin’ ranges from 2.25% to 4.0% over the London Interbank Offered Rate (LIBOR). On the closing date of the agreement, the applicable spread was 3.0%. A total of nine banks participate in the new facility, with no one bank providing more than 14% of the total availability. The amended facility contains covenants substantially similar to the previous facility.

On September 30, 2009, we entered into a purchase agreement under which we agreed to issue $55 million of 5.71% Montana First Mortgage Bonds due October 15, 2039, to certain purchasers. The transaction closed on October 15, 2009. See Note 15 – Subsequent Events for further discussion.

(10)   Regulatory Matters

Colstrip Unit 4

In January 2009, as a result of approval by the Montana Public Service Commission (MPSC), 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. 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 Montana 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 megawatt natural gas fired facility. The Mill Creek Generating Station, estimated to cost approximately $202 million, will provide regulating resources to balance our transmission system in Montana to maintain reliability and enable wind power to be integrated onto the

 
 
15
 

network to meet renewable energy portfolio needs. In May 2009, the MPSC issued an order granting approval to construct the facility, authorizing a return on equity of 10.25% and a preliminary cost of debt of 6.5%, with a capital structure of 50% equity and 50% debt. In addition, the MPSC determined the $81 million cost for the turbines is prudent, with the remainder of the project costs to be submitted to the MPSC for review and approval once construction of the facility is complete. Construction began in June 2009, and the plant is scheduled to be operational by December 31, 2010. As of September 30, 2009, we have capitalized approximately $40.5 million in construction work in process related to this project.

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 additional violations of the applicable standards. Since June 2007, we have identified and self-reported violations of 32 NERC requirements and submitted 19 corresponding mitigation plans to WECC. All but seven of these violations have been dismissed or were subject to expedited dispositions with no penalties. During the third quarter of 2009 we reached a settlement agreement with WECC addressing six of the remaining violations for a total penalty of $80,000, which has been accrued. This settlement is pending formal NERC and Federal Energy Regulatory Commission (FERC) approval. The remaining violation is pending a NERC interpretation of the standard. We anticipate resolving the remaining violation and receiving formal approval of the settlement during the first quarter of 2010.

Mountain States Transmission Intertie (MSTI) and Other Transmission FERC Developments

We have proposed two major transmission projects in Montana – MSTI and the Collector Project - to facilitate development of new generation. MSTI is a proposed 500kV transmission line from southwestern Montana to southeastern Idaho. The Collector Project consists of up to five new transmission lines in Montana that would connect new generation, primarily wind farms, to our existing transmission system and to the proposed MSTI line. Most of the new proposed wind generation that would be served by the Collector Project would be located in Montana. In January 2009, we filed a request with the FERC seeking negotiated rates for the proposed MSTI project and to directly assign the cost of the Collector Project to the generators. The request for negotiated rates for MSTI was not for specific rates rather it was for confirmation from the FERC that MSTI satisfies the FERC’s negotiated rate criteria. As a transmission export project in a region that lacks a regional transmission organization, MSTI has no readily available regional tariff through which to recover costs and thereby mitigate project development risk. The request was based on a rate approach that FERC had approved for similar projects in the region, which would provide us with the flexibility to meet market demand from primarily new renewable generation resources in Montana and to insulate our native load customers from the costs and risks of the project. FERC issued an order in May 2009 denying our request for negotiated rates, and encouraged us to meet our needs by pursuing the MSTI project on a cost-of-service basis by requesting appropriate waivers under our Open Access Transmission Tariff. As to the Collector Project, FERC approved our proposal to directly assign the cost of the project to the generators. This also has the effect of insulating native load customers from the cost of the project. While FERC deferred ruling on our request for tariff waivers, FERC specifically found the proposed Collector Project open season process to be a reasonable means of accommodating a large number of interconnection requests in the queue.

We are planning to conduct open seasons for both MSTI and the Collector Project during the first half of 2010 to identify potential interest for new transmission capacity on this path due to the changing nature of generation projects. The results of the open season will be used to size the projects according to customer demand. The open season process is intended to ensure that the projects have sufficient contracts with credit-worthy shippers to support financing. As of September 30, 2009, we have capitalized approximately $9.6 million of preliminary survey and investigative costs associated with the MSTI project.

(11)   Segment Information
 
Our reportable business segments are primarily engaged in the regulated electric and regulated natural gas business. 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 capacity contract, the wind down of our captive insurance subsidiary and

 
 
16
 

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 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
              
September 30, 2009
  
Electric
  
Gas
  
Other
  
Eliminations
  
Total
  
Operating revenues
  
$
198,689
  
$
34,205
  
$
291
  
$
(299
)
$
232,886
  
Cost of sales
  
92,592
  
12,326
  
265
  
—
  
105,183
  
Gross margin
  
106,097
  
21,879
  
26
  
(299
)
127,703
  
Operating, general and administrative
  
40,834
  
17,701
  
(343
)
(299
)
57,893
  
Property and other taxes
  
15,351
  
5,479
  
36
  
—
  
20,866
  
Depreciation
  
17,772
  
4,197
  
8
  
—
  
21,977
  
Operating income (loss)
  
32,140
  
(5,498
)
325
  
—
  
26,967
  
Interest expense
  
(13,056
)
(3,243
)
(968
)
—
  
(17,267
)
Other income
  
310
  
67
  
26
  
—
  
403
  
Income tax benefit
  
789
  
5,694
  
2,314
  
—
  
8,797
  
Net income (loss)
  
$
20,183
  
$
(2,980
)
$
1,697
  
$
—
  
$
18,900
  
 
Total assets
  
$
1,933,877
  
$
804,365
  
$
16,237
  
$
—
  
$
2,754,478
  
Capital expenditures
  
$
61,697
  
$
7,172
  
$
—
  
$
—
  
$
68,869
  


Three Months Ended
  
Regulated
  
Unregulated
              
September 30, 2008
  
Electric
  
Gas
  
Electric
  
Other
  
Eliminations
  
Total
  
Operating revenues
  
$
208,020
  
$
45,651
  
$
20,091
  
$
7,889
    
(9,407
)
$
272,244
  
Cost of sales
  
113,299
  
22,803
  
(4,184
)
7,611
  
(9,026
)
130,503
  
Gross margin
  
94,721
  
22,848
  
24,275
  
278
  
(381
)
141,741
  
Operating, general and administrative
  
45,882
  
20,058
  
3,563
  
(5,711
)
(381
)
63,411
  
Property and other taxes
  
15,380
  
5,543
  
792
  
3
  
—
  
21,718
  
Depreciation
  
15,416
  
4,041
  
1,827
  
8
  
—
  
21,292
  
Operating income (loss)
  
18,043
  
(6,794
)
18,093
  
5,978
  
—
  
35,320
  
Interest expense
  
(9,679
)
(3,389
)
(2,189
)
(372
)
—
  
(15,629
)
Other income
  
306
  
298
  
1
  
613
  
—
  
1,218
  
Income tax (expense) benefit
  
(3,477
)
3,750
  
(6,303
)
(1,500
)
—
  
(7,530
)
Net income (loss)
  
$
5,193
  
$
(6,135
)
$
9,602
  
$
4,719
  
$
—
  
$
13,379
  
 
Total assets
  
$
1,567,950
  
$
761,863
  
$
247,249
  
$
16,752
  
$
—
  
$
2,593,814
  
Capital expenditures
  
$
26,501
  
$
10,989
  
$
439
  
$
—
  
$
—
  
$
37,929
  


 
17
 


Nine Months Ended
  
Regulated
              
September 30, 2009
  
Electric
  
Gas
  
Other
  
Eliminations
  
Total
  
Operating revenues
  
$
580,139
  
$
254,338
  
$
6,248
  
$
(1,223
)
$
839,502
  
Cost of sales
  
258,964
  
154,105
  
6,964
  
—
  
420,033
  
Gross margin
  
321,175
  
100,233
  
(716
)
(1,223
)
419,469
  
Operating, general and administrative
  
128,575
  
58,806
  
(1,948
)
(1,223
)
184,210
  
Property and other taxes
  
46,433
  
16,857
  
111
  
—
  
63,401
  
Depreciation
  
54,113
  
12,821
  
25
  
—
  
66,959
  
Operating income
  
92,054
  
11,749
  
1,096
  
—
  
104,899
  
Interest expense
  
(37,963
)
(9,629
)
(2,811
)
—
  
(50,403
)
Other income
  
783
  
322
  
87
  
—
  
1,192
  
Income tax (expense) benefit
  
(12,066
)
1,571
  
2,618
  
—
  
(7,877
)
Net income
  
$
42,808
  
$
4,013
  
$
990
  
$
—
    
47,811
  
 
Total assets
  
$
1,933,877
  
$
804,365
  
$
16,236
  
$
—
  
$
2,754,478
  
Capital expenditures
  
$
100,117
  
$
15,738
  
$
—
  
$
—
  
$
115,855
  


Nine Months Ended
  
Regulated
  
Unregulated
              
September 30, 2008
  
Electric
  
Gas
  
Electric
  
Other
  
Eliminations
  
Total
  
Operating revenues
  
$
583,606
  
$
297,825
  
$
57,064
  
$
24,464
  
$
(28,234
)
$
934,725
  
Cost of sales
  
303,550
  
193,996
  
14,472
  
23,770
  
(26,847
)
508,941
  
Gross margin
  
280,056
  
103,829
  
42,592
  
694
  
(1,387
)
425,784
  
Operating, general and administrative
  
115,755
  
53,717
  
10,459
  
(1,196
)
(1,387
)
177,348
  
Property and other taxes
  
46,147
  
17,355
  
2,386
  
10
  
—
  
65,898
  
Depreciation
  
46,203
  
11,925
  
5,455
  
25
  
—
  
63,608
  
Operating income
  
71,951
  
20,832
  
24,292
  
1,855
  
—
  
118,930
  
Interest expense
  
(28,138
)
(9,874
)
(8,358
)
(1,108
)
—
  
(47,478
)
Other income (expense)
  
891
  
857
  
133
  
(241
)
—
  
1,640
  
Income tax expense
  
(15,810
)
(4,413
)
(6,457
)
(79
)
—
  
(26,759
)
Net income
  
$
28,894
  
$
7,402
  
$
9,610
  
$
427
  
$
—
  
$
46,333
  
 
Total assets
  
$
1,567,950
  
$
761,863
  
$
247,249
  
$
16,752
  
$
—
  
$
2,593,814
  
Capital expenditures
  
$
55,982
  
$
23,584
  
$
1,450
  
$
—
  
$
—
  
$
81,016
  

 
 (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.


 
18
 

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:

   
Nine Months Ended
  
Nine Months Ended
  
   
September 30, 2009
  
September 30, 2008
  
Basic computation
  
35,947,378
  
38,665,241
  
   Dilutive effect of
          
   Nonvested shares, performance share awards and deferred share units
  
322,110
  
322,684
  
           
Diluted computation
  
36,269,488
  
38,987,925
  

   
Three Months Ended
  
Three Months Ended
  
   
September 30, 2009
  
September 30, 2008
  
Basic computation
  
35,967,876
  
38,057,346
  
   Dilutive effect of
          
   Nonvested shares, performance share awards and deferred share units
  
322,110
  
322,684
  
           
Diluted computation
  
36,289,986
  
38,380,030
  

 
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 September 30,
  
   
2009
  
2008
  
2009
  
2008
  
Components of Net Periodic Benefit Cost
                  
   Service cost
  
$
2,068
  
$
2,101
  
$
248
  
$
140
  
   Interest cost
  
5,926
  
5,718
  
787
  
591
  
   Expected return on plan assets
  
(5,595
)
(6,803
)
(249
)
(329
)
   Amortization of prior service cost
  
62
  
62
  
—
  
—
  
   Recognized actuarial loss (gain)
  
1,019
  
(205
)
69
  
(149
)
Net Periodic Benefit Cost
  
$
3,480
  
$
873
  
$
855
  
$
253
  

   
Pension Benefits
  
Other Postretirement Benefits
  
   
Nine Months Ended September 30,
  
   
2009
  
2008
  
2009
  
2008
  
Components of Net Periodic Benefit Cost
                  
   Service cost
  
$
6,203
  
$
6,304
  
$
745
  
$
422
  
   Interest cost
  
17,779
  
17,156
  
2,362
  
1,775
  
   Expected return on plan assets
  
(16,787
)
(20,410
)
(746
)
(987
)
   Amortization of prior service cost
  
185
  
185
  
—
  
—
  
   Recognized actuarial loss (gain)
  
3,057
  
(614
)
208
  
(449
)
Net Periodic Benefit Cost
  
$
10,437
  
$
2,621
  
$
2,569
  
$
761
  

Due to the significant decline in equity markets, we experienced plan asset market losses in 2008 in excess of 30%. This decline in plan assets, which has significantly increased our pension expense, is reflected in the increase in net periodic benefit cost above as an actuarial loss due to the use of asset smoothing. This smoothing allows the use of asset averaging, including expected returns, for a 24-month period in the determination of funding requirements. 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

 
 
19
 

2012, therefore our pension expense differs from the net periodic benefit cost for our Montana plan.

During the nine months ended September 30, 2009, we contributed approximately $76.4 million to our pension plans. Our plan funding estimates are based on achieving an 8.0% 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. Our return on plan assets has been approximately 20.0% for the nine months ended September 30, 2009. The overall market has continued to be volatile during 2009, and if asset returns are significantly above or below our assumption of 8.0% for 2009, we will likely need to revise our future 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 September 30, 2009, we have a reserve of approximately $31.3 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 primarily for previously incurred costs. 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. During 2009, we have executed settlements and received approximately $5.3 million of insurance proceeds. The portion related to previously incurred Montana generation related costs has been recognized as a reduction to operating expenses in the second and third quarters of 2009, while 10% of the proceeds has been recorded as a liability that may be returned to customers pending regulatory review.

Manufactured Gas Plants - Approximately $26.2 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 $12.7 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,

 
 
20
 

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 megawatt (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 were completed in the third quarter of 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 gas emissions. Recently, two federal courts of appeal have reinstated nuisance claims against emitters of carbon dioxide, including several utility companies, alleging that such emissions contribute to global warming. 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 or cost-effective for installation at the generation facilities in which we have a joint interest.

Although no federal laws currently limit greenhouse gas emissions, in June 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009, a bill introduced by Rep. Henry Waxman and Rep. Edward Markey and popularly known as the Waxman-Markey bill. The bill would regulate greenhouse gas emissions by instituting a cap-and-trade-system, in which an economy-wide cap on U.S. greenhouse gas emissions would be established starting in 2012 with a cap 3% below the baseline 2005 level. The cap would steeply decline over time until in 2050 it reaches 83% below the baseline level. Emission allowances, which are rights to emit greenhouse gases, would be both allocated for free and auctioned. In addition, the draft legislation contains a renewable energy standard of 25% by the year 2025 and an energy efficiency mandate for electric and natural gas utilities, as well as other requirements. Pending in the U.S. Senate is the Clean Energy Jobs and American Power Act introduced by Sens. John Kerry and Barbara Boxer, known as the Kerry-Boxer bill. The Kerry-Boxer bill also proposes to regulate greenhouse gas emissions by instituting a cap-and-trade-system, with primarily the same target levels proposed by the Waxman-Markey bill; however, the Kerry-Boxer bill is more aggressive in its 2020 target – a reduction to 20% below 2005 levels by 2020 (versus 17% in Waxman-Markey). Although the Waxman-Markey bill is widely viewed as the most probable climate change bill to be enacted into law, the prospects for passage of a similar bill by the U.S. Senate are uncertain.

In addition, the U.S. Supreme Court issued a decision holding that the Environmental Protection Agency (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. In September 2009, the EPA proposed rules to reduce greenhouse gas emissions from light-duty vehicles. Final adoption of the proposed standards for light-duty vehicles is contingent on the EPA first finalizing its proposed endangerment finding for greenhouse gas emissions from motor vehicles. In a related
 
 
21
 

matter, the EPA also proposed rules that would require all new or modified “stationary sources,” such as power plants, that emit 25,000 tons of greenhouse gases per year to obtain operating permits incorporating the “best available control technology” for such emissions.

In addition, in September 2009, the EPA announced the adoption of the first comprehensive national system for reporting emissions of carbon dioxide and other greenhouse gases produced by major sources in the United States. The new reporting requirements will apply to suppliers of fossil fuel and industrial chemicals, manufacturers of motor vehicles and engines, as well as large direct emitters of greenhouse gases with emissions equal to or greater than a threshold of 25,000 metric tons per year, which includes certain of our facilities. The effective date for gathering the data is January 2010 with the first mandatory reporting due in March 2011.

The Montana Governor’s office has joined the Western Regional Climate Initiative (WCI) and is expected to participate in any greenhouse gas emission control regulations that are adopted by the WCI. The WCI, which has a goal of reducing carbon dioxide emissions 15% below the 2005 levels by 2020, currently is developing greenhouse gas emission allocations, offsets, and reporting recommendations. 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. We are proactively involved in analyzing the impacts of current legislative efforts on our customers and shareholders and are participating in public policy forums related to these issues.

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.

Clean Air Mercury Rule - The state of Montana has issued mercury regulation rules that would require every coal-fired generating plant in the state to reduce emissions of mercury by 2010. The joint owners of Colstrip Units 3 & 4 currently plan to install chemical injection technologies to meet these requirements. We estimate our share of the capital cost would be approximately $2 million, with ongoing annual operating costs of approximately $2 million. These ongoing costs will be dependent on the volatility of the cost and amount of chemicals needed to treat the coal before combustion. If these 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 additional cost.

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.


 
22
 

LEGAL PROCEEDINGS

Bankruptcy Related Litigation

Magten Settlement - In July 2008, the U.S. Bankruptcy Court for the District of Delaware (Bankruptcy Court) approved a global settlement agreement between NorthWestern, Magten Asset Management (Magten), Law Debenture Trust Company of New York (Law Debenture) and the committee concerning NorthWestern’s plan of reorganization (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 (Plan), as discussed below in the following paragraph. This settlement resolves the last significant claim from the bankruptcy case. During the third quarter of 2009, the United States District Court of Delaware dismissed the appeal on the grounds of “equitable mootness” in that the parties already had consummated the settlement agreement and affirmed the Bankruptcy Court’s decision on the merits that the global settlement agreement did not violate the Plan. The Ad Hoc Committee did not appeal the dismissal and the appeal period has expired.

Disputed Claims Reserve - In July 2008, we obtained Bankruptcy Court approval for the purchase of the remaining shares in the disputed claims reserve established by the Plan. 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 IRS filed an objection to the motion; however we reached an agreement with the IRS and the Plan Committee to settle this matter. In September 2009, the Bankruptcy Court approved the settlement agreement and authorized a final distribution from the disputed claims reserve. This settlement did not have a material impact on our financial position, results of operations or cash flows. We expect to distribute the remaining cash and shares in the disputed claims reserve to eligible claimants during the fourth quarter of 2009.

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. (Touch America) 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 Company 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. 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.  This agreement was approved by the Bankruptcy Court in November 2006; however on January 11, 2008, the U.S. District Court in Montana suggested that the settlement agreement was invalid and enjoined the plaintiffs from taking any further action in any of these matters. The plaintiffs appealed the District Court’s injunction to the Ninth Circuit U.S. Court of Appeals, where  a determination is pending. In January 2009, the U.S. District Court in Montana asked all parties to submit memorandum discussing the party’s willingness to enter into a global settlement of the matter.
 

 
23
 
 
In October 2009, the parties to the various lawsuits reached a global settlement involving various agreements, which must be approved by the U.S. District Court in Montana and the Delaware Bankruptcy Court. Documentation concerning the settlement must be submitted by November 13, 2009, to the U.S. District Court in Montana for its approval. If the court approves the settlement, we will receive approximately $2.0 million from the Touch America bankruptcy estate and have no remaining liability in the litigation.

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 appealed the judgment to the Montana Supreme Court and posted a $25.8 million bond. Interest accrues on the verdict amount during the appeal process. On October 13, 2009 the Montana Supreme Court issued a decision affirming the jury verdict and the various rulings of the Montana state court before, during and after trial, and remanded the judgment to the Montana state court so that it can be reduced to reflect the payments made to the plaintiffs since the judgment was entered. We are considering our alternatives in light of this decision.

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) (South Dakota Federal District Court) 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 believe these claims are 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 South Dakota Federal District Court entered a Memorandum Opinion and Order granting Defendants’ Motion to Dismiss the Sierra Club Complaint. Sierra Club filed a motion for reconsideration of the dismissal, which was denied in July 2009. On July 30, 2009, Sierra Club appealed the South Dakota Federal District Court’s decision to dismiss the complaint. The briefing schedule adopted by the Eighth Circuit Court of Appeals calls for the appellant to submit its brief by mid-October, for appellees to submit

 
 
24
 

their brief by mid-November and for appellant to submit its reply brief by the end of November. On October 13, 2009, the United States Department of Justice filed a motion seeking a 30-day extension of the time to file an amicus brief in support of the Sierra Club’s position. The Court of Appeals granted this motion, as well as our subsequent joint motion with the Sierra Club, extending the time to file our principal brief and the Sierra Club’s reply brief. We anticipate briefing to be complete by the end of January 2010.

Other Litigation and Contingencies

Colstrip Energy Limited Partnership

In December 2006 and June 2007, the MPSC issued orders relating to certain QF rates for the period July 1, 2003 through June 30, 2006. Colstrip Energy Limited Partnership (CELP) is a QF with which we have a power purchase agreement through June 2024. 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, with the rates to be used in that formula derived from the annual MPSC QF rate review. CELP initially appealed the MPSC’s orders and then, in July 2007, filed a complaint against NorthWestern and the MPSC in Montana district court, which contested the MPSC’s orders. CELP disputed inputs into the underlying rates used in the formula, which initially are calculated by us and reviewed by the MPSC on an annual basis, to calculate energy and capacity payments for the contract years 2004-2005 and 2005-2006. CELP claimed that NorthWestern breached the power purchase agreement causing damages, which CELP asserted to be approximately $23 million for contract years 2004-2005 and 2005-2006. The parties stipulated that NorthWestern would not implement the final derived rates resulting from the MPSC orders, pending an ultimate decision on CELP's complaint. The Montana 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 against us and the administrative appeal of the MPSC’s orders. The order also stayed the appellate decision pending a decision in the arbitration proceedings. Arbitration was held in June 2009 and the arbitration panel entered its interim award in August 2009, holding that although NorthWestern failed to use certain data inputs required by the power purchase agreement, CELP was entitled to neither damages for contract years 2004-2005 or 2005-2006, nor to recalculation of the underlying MPSC filings for those years, effectively finalizing CELP's contract rates for those years. CELP continues to dispute that result. We requested clarification from the arbitration panel as to its intent regarding the applicable rates. We are evaluating the financial impact of the arbitration panel's interim award while we await the final award, which we expect to be issued by the end of 2009. Following issuance of the final award, the matter will return to the Montana district court for confirmation of that award. If the final award is consistent with the interim award, we believe it would reduce our QF liability by approximately $20 to $30 million due to the estimated reduction of energy and capacity rates for the remainder of the contract period.

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. Four lawsuits have been commenced in Montana state court and various claims have been filed against NorthWestern with respect to this incident. 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 for known and potential claims.
 

 
25
 
 
Maryland Street

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 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 (Montana Federal District Court), but the Montana Federal District Court remanded the case to the Montana state court. Subsequently, we filed a motion in the Montana state court seeking to dismiss the amended complaint as to our employee, which is pending.

Gonzales

We are a defendant – along with our predecessor entities the Montana Power Company (MPC) and pre-bankruptcy NorthWestern Corporation (NOR) – in an action (Gonzales Action) pending in the Montana Second Judicial District Court, Butte-Silver Bow County (Montana State Court), alleging fraud, constructive fraud and violations of the Unfair Claim Settlement Practices Act all arising out of the adjustment of workers’ compensation claims. Putnam and Associates, the third party administrator of such workers’ compensation claims, also is a defendant.

The Gonzales Action was first filed on December 18, 1999, against MPC (NOR acquired MPC in 2002) and was stayed due to the chapter 11 bankruptcy filing of NOR. On August 10, 2005, the Bankruptcy Court approved a “Bankruptcy Settlement Stipulation” which permitted the Gonzales Action to proceed, assigned to plaintiffs NOR’s interest in MPC’s insurance policies (to the extent applicable to the allegations made by plaintiffs), released NOR from any and all obligations to the plaintiffs concerning such claims, and preserved plaintiffs’ right to pursue claims arising after November 1, 2004, relating to the adjustment of workers’ compensation claims. To date, no insurance carrier has indicated that coverage is available for any of the claims.

On September 30, 2009 the Montana State Court granted the plaintiffs’ motions to file a sixth amended complaint and partially granted the plaintiff’s motion for class certification. The Montana State Court excluded the fraud claims from its class certification. The new complaint seeks to hold us jointly and severally liable for the acts of MPC and NOR and alleges that we negligently/intentionally sabotaged plaintiffs’ ability to recover under the MPC insurance policies. Plaintiffs seek compensatory and punitive damages from all defendants. Due to the individual nature of the claims, we believe the class certification was improper under Montana law, and we continue to believe that the new complaint violates the bankruptcy stipulation. We have filed an appeal to the Supreme Court of the State of Montana with respect to these issues and intend to continue to defend the lawsuit vigorously.

REC Silicon

REC Advanced Silicon Materials LLC (REC) is a large transmission customer which manufactures polysilicon and silane gas for the photovoltaic and electronics industries. REC purchases services from us pursuant to our Open Access Transmission Tariff. REC brought an action against us in June 2009, in the Montana Second Judicial District Court, Butte-Silver Bow County, which alleges breach of contract and negligence. REC claims we failed to properly maintain a substation, which resulted in an outage for approximately three hours and disrupted REC’s production operations for several days. REC alleges damage claims of approximately $1.25 million. We are still evaluating our potential liability and the extent and validity of REC’s damage claims. We cannot currently predict the impact or resolution of this litigation.

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.


 
26
 

(15)   Subsequent Events
 

Financing Activities

On October 15, 2009 we issued $55 million of Montana First Mortgage Bonds at a fixed interest rate of 5.71% maturing October 15, 2039. The transaction is exempt from the registration requirements of the Securities Act of 1933, as amended. The proceeds will be used to fund a portion of the costs of the Mill Creek generation project and / or future capital expenditures.

Montana Rate Filing

In October 2009, we filed a request with the MPSC for an annual electric transmission and distribution revenue increase of $15.5 million, and an annual natural gas transmission, storage and distribution revenue increase of $2.0 million. The request was based on a return on equity of 10.9%, an equity ratio of 49.45% and rate base of $632.2 million and $256.6 million, respectively. This rate filing does not include electric generation included in rate base. We have requested interim rates and are currently awaiting the establishment of a procedural schedule.
 

 
27
 
 

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.

SUMMARY

Significant achievements during the three months ended September 30, 2009 include:
 
·  
Increased net income of $18.9 million as compared with $13.4 million in the same period of 2008, due primarily to obtaining Internal Revenue Service (IRS) approval of a tax accounting method change to deduct repairs that would have previously been capitalized, resulting in an income tax benefit of $12.4 million during the third quarter of 2009;
 
·  
Upgrade of our senior secured credit ratings by Moody’s Investors Service (Moody’s); and
 
·  
Entered into a purchase agreement on September 30, 2009, under which we agreed to issue $55 million of 5.71% Montana First Mortgage Bonds due October 15, 2039, to certain purchasers.
 

Repairs Tax Deduction

In December 2008, we filed a request with the IRS to change our accounting method related to costs to repair and maintain utility assets. The IRS approved our request in September 2009, which allows us to take a current tax deduction for a significant amount of repair costs that were previously capitalized for tax purposes. For regulatory purposes, we flow these current tax deductions through to our customers. Due to this regulatory treatment, our effective tax rate was (87.1)% and 14.1% for the three and nine months ended September 30, 2009, respectively, compared to 36.0% and 36.6% for the same periods of 2008. The 2009 rates reflect the impact of the change in tax accounting method for repairs and lower estimated 2009 taxable income. We expect the effective tax rate for the year ended December 31, 2009 to be approximately 20%. See Note 4 – Income Taxes, in the Notes to Condensed Consolidated Financial Statements for further discussion.

Colstrip Unit 4

In January 2009, as approved by the MPSC in 2008, 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. The MPSC 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) and will help provide rate stability for our customers. 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. We are currently experiencing an unplanned outage at Colstrip Unit 4 for a rotor repair. We expect the unit to return to service early in the fourth quarter of 2009. We do not expect this to have an impact on our electric margins due to the regulatory treatment of our supply costs; however, we expect operating expenses to increase by approximately $1.3 million for rotor repair costs in the fourth quarter of 2009.

Outlook

The current weak economic conditions have resulted, and we believe likely will continue into 2010 to result in weaker customer demand, among other things. While customer counts increased, retail residential and commercial electric volumes were down 3% and industrial volumes were down 9% for the third quarter of 2009 as compared with the same quarter of 2008. This volume reduction, while due in part to energy efficiency measures and milder weather, is also largely due to weak economic conditions, particularly for commercial and industrial
 
 
 
28
 

customers. Our margins are minimally impacted by changes in industrial demand due to our rate structure. We expect to continue to experience relatively flat residential demand as well as reduced commercial and industrial demand during the remainder of 2009. The weak economy also contributed to a 13% decrease in transmission capacity revenues, which we expect to continue through the end of 2009.

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.

Non-GAAP Financial Measure

The following discussion includes financial information prepared in accordance with 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 September 30, 2009 Compared with the Three Months Ended September 30, 2008
 

   
Three Months Ended September 30,
  
   
2009
  
2008
  
Change
  
% Change
  
   
(in millions)
  
Operating Revenues
                  
Regulated Electric
  
$
198.7
  
$
208.0
  
$
(9.3
)
(4.5
)%
Regulated Natural Gas
  
34.2
  
45.6
  
(11.4
)
(25.0
)
Unregulated Electric
  
—
  
20.1
  
(20.1
)
(100.0
)
Other
  
0.3
  
7.9
  
(7.6
)
(96.2
)
Eliminations
  
(0.3
)
(9.4
)
9.1
  
96.8
  
   
$
232.9
  
$
272.2
  
$
(39.3
)
(14.4
)%

   
Three Months Ended September 30,
  
   
2009
  
2008
  
Change
  
% Change
  
   
(in millions)
  
Cost of Sales
                  
Regulated Electric
  
$
 92.6 $ 113.3   $ (20.7 ) (18.3 )%
Regulated Natural Gas
  
12.3
  
22.8
  
(10.5
)
(46.1
)
Unregulated Electric
  
—
  
(4.2
)
4.2
  
100.0
  
Other
  
0.3
  
7.6
  
(7.3
)
(96.1
)
Eliminations
  
—
  
(9.0
)
9.0
  
100.0
  
   
$
105.2
  
$
130.5
  
$
(25.3
)
(19.4
)%


 
29
 

   
Three Months Ended September 30,
  
   
2009
  
2008
  
Change
  
% Change
  
   
(in millions)
  
Gross Margin
                  
Regulated Electric
  
$
106.1
  
$
94.7
  
$
11.4
  
12.0
%
Regulated Natural Gas
  
21.9
  
22.8
  
(0.9
)
(3.9
)
Unregulated Electric
  
—
  
24.3
  
(24.3
)
(100.0
)
Other
  
—
  
0.3
  
(0.3
)
(100.0
)
Eliminations
  
(0.3
)
(0.4
)
0.1
  
25.0
  
   
$
127.7
  
$
141.7
  
$
(14.0
)
(9.9
)%

Consolidated gross margin was $127.7 million for the three months ended September 30, 2009, a decrease of $14.0 million, or 9.9%, from gross margin in the same period of 2008. Primary components of the change include the following:

   
Gross Margins
  
   
2009 vs. 2008
  
   
(in millions)
  
Transfer of Colstrip Unit 4 to regulated electric
  
$
17.8
  
2008 Unregulated electric
    
(14.1
)
2008 Unregulated electric unrealized gain on forward contract
    
(10.2
)
  Colstrip Unit 4 net decrease to gross margin
    
(6.5
)
Regulated electric retail volumes
  
(2.6
)
Regulated electric transmission
  
(1.7
)
Regulated electric wholesale
  
(0.7
)
Montana property tax tracker
  
(0.8
)
Loss on capacity contract
  
(0.3
)
Other                                                                                                       
    
(1.4
)
Decrease in Consolidated Gross Margin                                                                                                       
  
$
(14.0
)

The transfer of our interest in Colstrip Unit 4 to Montana utility rate base contributed approximately $17.8 million to gross margin. 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. The absence of gross margin from our unregulated electric segment reduced gross margin by approximately $24.3 million as compared to the same period of 2008, which included a $10.2 million unrealized gain on forward contracts. The 2008 unrealized gain was due to changes in forward prices of electricity.

Consolidated margin also decreased due to lower regulated electric retail volumes related to milder weather, lower transmission capacity revenues with less demand to transmit energy for others across our lines, a decrease in wholesale margin due to lower sales and prices, a decrease in property taxes recovered in revenues due to lower valuations, as well as a loss on a capacity contract included in our “other” segment. This capacity contract runs through October 2013 and was primarily used to serve one customer. The customer terminated their supply contract with us during the second quarter of 2009 and we have recorded a loss to reflect the change in the estimate of the market value for the capacity during the remaining term. Our remaining exposure related to this capacity contract is approximately $0.9 million as of September 30, 2009.

 
 
30
 

   
Three Months Ended September 30,
  
   
2009
  
2008
  
Change
  
% Change
  
   
(in millions)
  
Operating Expenses (excluding cost of sales)
                  
Operating, general and administrative
  
$
57.9
  
$
63.4
  
$
  (5.5
)
(8.7
)%
Property and other taxes
  
20.8
  
21.7
  
(0.9
)
(4.1
)
Depreciation 
  
22.0
  
21.3
  
0.7
  
3.3
  
   
$
100.7
  
$
106.4
  
$
(5.7
)
(5.4
)%

Consolidated operating, general and administrative expenses were $57.9 million for the three months ended September 30, 2009 as compared with $63.4 million for the same period of 2008. Primary components of the change include the following:
 
   
Operating, General & Administrative Expenses
  
   
2009 vs. 2008
  
   
(in millions)
  
Pension expense
  
$
(8.9
)
Bad debt expense
  
(1.0
)
Legal and professional fees
  
(0.8
)
Stock-based compensation and short-term incentive
  
(0.8
)
Insurance recoveries and settlements
  
6.3
  
Labor
  
1.0
  
Postretirement health care
  
0.7
  
Colstrip Unit 4 operations
  
0.5
  
Other
  
(2.5
)
Decrease in Operating, General & Administrative Expenses
  
$
(5.5
)

The decrease in operating, general and administrative expenses was primarily due to the following:
 
·  
Lower pension expense as described further below; and
 
·  
Lower bad debt expense based on lower average customer receivable balances and less days outstanding;
 
·  
Decreased legal and professional fees associated with ongoing litigation;
 
·  
Lower stock-based compensation due to reduced equity grants and lower short-term incentive; offset by
 
·  
Net decrease in insurance recoveries and settlements, which includes a $1.4 million insurance recovery in the third quarter of 2009 related to previously incurred Montana generation related environmental remediation costs. In the same period of 2008 we received an insurance reimbursement and a litigation settlement totaling approximately $7.7 million.
 
·  
Increased labor costs due primarily to compensation increases;
 
·  
Higher postretirement health care costs due to plan asset market losses and changes in actuarial assumptions; and
 
·  
Increased plant operations costs at Colstrip Unit 4 due to the outage.
 
Our Montana pension costs are included in expense on a pay as you go (cash funding) basis. Due to plan asset market losses during the third quarter of 2008, we increased our pension funding estimates, which resulted in a significant increase to pension expense in the third quarter of 2008. We received a revised pension accounting order from the MPSC in the fourth quarter of 2008. This revised the expense we recognize to the average of our funding requirements for calendar years 2005 through 2012, which resulted in a reduction to pension expense during the fourth quarter of 2008. Pension expense calculated under this order was approximately $30.6 million for the year ended December 31, 2008, and we currently estimate the same annual expense for 2009. Our estimate is based on achieving an 8.0% 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. Our return on plan assets through the third quarter of 2009 was approximately 20.0%. The overall market has
 

 
31
 

continued to be volatile during 2009, and if asset returns are significantly above or below our assumption of 8.0% for 2009, we will likely need to revise our future funding estimates, which could change our pension expense.

Property and other taxes were $20.8 million for the three months ended September 30, 2009 as compared with $21.7 million in the same period of 2008. The decrease was due to lower assessed property valuations.

Depreciation expense was $22.0 million for the three months ended September 30, 2009 as compared with $21.3 million in the same period of 2008. The increase was primarily due to plant additions.

Consolidated operating income for the three months ended September 30, 2009 was $27.0 million, as compared with $35.3 million in the same period of 2008. The decrease was primarily due to lower gross margin partially offset by lower operating expenses discussed above.

Consolidated interest expense for the three months ended September 30, 2009 was $17.3 million, an increase of $1.7 million, or 10.9%, from the third quarter of 2008. This increase was primarily due to increased debt outstanding.

Consolidated income tax benefit for the three months ended September 30, 2009 was $8.8 million as compared with income tax expense of $7.5 million in the same period of 2008. The effective tax rate for the three months ended September 30, 2009 was (87.1)% as compared with 36.0% for the same period of 2008. These effective tax rates differ from the federal tax rate of 35% primarily due to the effects of tax credits, state income taxes, utility rate-making, and other permanent book-to-tax differences. The third quarter of 2009 effective tax rate was significantly impacted by a change in tax accounting method related to repair costs as discussed above.

Consolidated net income for the three months ended September 30, 2009 was $18.9 million as compared with $13.4 million for the same period of 2008. The increase in net income was primarily due to the income tax benefit, partially offset by lower operating income and higher interest expense as discussed above.

 
 
32
 

Nine Months Ended September 30, 2009 Compared with the Nine Months Ended September 30, 2008

   
Nine Months Ended September 30,
  
   
2009
  
2008
  
Change
  
% Change
  
   
(in millions)
  
Operating Revenues
                  
Regulated Electric
  
$
580.1
  
$
583.6
  
$
(3.5
)
(0.6
)%
Regulated Natural Gas
  
254.3
  
297.8
  
(43.5
)
(14.6
)
Unregulated Electric
  
—
  
57.1
  
(57.1
)
(100.0
)
Other
  
6.3
  
24.4
  
(18.1
)
(74.2
)
Eliminations
  
(1.2
)
(28.2
)
27.0
  
95.7
  
   
$
839.5
  
$
934.7
  
$
(95.2
)
(10.2
)%
 
   
Nine Months Ended September 30,
  
   
2009
  
2008
  
Change
  
% Change
  
   
(in millions)
  
Cost of Sales
                  
Regulated Electric
  
$
258.9
  
$
303.5
  
$
(44.6
)
(14.7
)%
Regulated Natural Gas
  
154.1
  
194.0
  
(39.9
)
(20.6
)
Unregulated Electric
  
—
  
14.5
  
(14.5
)
(100.0
)
Other
  
7.0
  
23.7
  
(16.7
)
(70.5
)
Eliminations
  
—
 
(26.8
)
26.8
  
100.0
  
   
$
420.0
  
$
508.9
  
$
(88.9
)
(17.5
)%
 
   
Nine Months Ended September 30,
  
   
2009
  
2008
  
Change
  
% Change
  
   
(in millions)
  
Gross Margin
                  
Regulated Electric
  
$
321.2
  
$
280.1
  
$
41.1
  
14.7
%
Regulated Natural Gas
  
100.2
  
103.8
  
(3.6
)
(3.5
)
Unregulated Electric
  
—
  
42.6
  
(42.6
)
(100.0
)
Other
  
(0.7
)
0.7
  
(1.4
)
(200.0
)
Eliminations
  
(1.2
)
(1.4
)
0.2
  
(14.3
)
   
$
419.5
  
$
425.8
  
$
(6.3
)
(1.5
)%

Consolidated gross margin was $419.5 million for the nine months ended September 30, 2009, a decrease of $6.3 million, or 1.5%, from gross margin in the same period of 2008. Primary components of the change include the following:

   
Gross Margins
  
   
2009 vs. 2008
  
   
(in millions)
  
Transfer of Colstrip Unit 4 to regulated electric
  
$
52.9
  
2008 Unregulated electric
  
(38.8
)
2008 Unregulated electric unrealized gain on forward contract
  
(3.8
)
  Net Colstrip Unit 4 increase to gross margin
  
10.3
  
Operating costs recovered in supply revenues
  
2.8
  
Regulated electric and gas retail volumes
  
(4.8
)
Regulated electric wholesale
  
(3.5
)
Regulated electric transmission capacity
  
(3.3
)
Montana property tax tracker
  
(2.9
)
Loss on capacity contract
  
(1.5
)
QF supply costs
  
(1.1
)
Other                                                                                                       
    
(2.3
)
Decrease in Consolidated Gross Margin
  
$
(6.3
)
 
 
 
33
 
 
The decrease in gross margin is due to a combination of lower retail revenues as a result of milder weather, lower wholesale pricing and volumes, lower transmission capacity revenues due to decreased demand, a decrease in property taxes recovered in revenues due to lower valuations, a mark-to-market loss on a natural gas capacity contract as discussed above, and higher QF related supply costs based on actual QF pricing and output. These decreases in margin were offset in part by the transfer of our interest in Colstrip Unit 4 to Montana utility rate base as discussed above and higher revenues for operating, general and administrative costs related to our supply function, which are recovered from customers through the supply trackers and therefore have no impact on operating income.
 
   
Nine Months Ended September 30,
  
   
2009
  
2008
  
Change
  
% Change
  
   
(in millions)
  
Operating Expenses (excluding cost of sales)
                  
Operating, general and administrative
  
$
184.2
  
$
177.3
  
$
6.9
  
3.9
%
Property and other taxes
  
63.4
  
66.0
  
(2.6
)
(3.9
)
Depreciation 
  
67.0
  
63.6
  
3.4
  
5.3
  
   
$
314.6
  
$
306.9
  
$
7.7
  
2.5
%

Consolidated operating, general and administrative expenses were $184.2 million for the nine months ended September 30, 2009 as compared with $177.3 million for the nine months ended September 30, 2008. Primary components of the change include the following:
 
   
Operating, General & Administrative Expenses
  
   
2009 vs. 2008
  
   
(in millions)
  
Labor
  
$
4.2
  
Insurance reserves
  
3.7
  
Insurance recoveries and settlements
  
1.7
  
Operating costs recovered in supply tracker
  
2.8
  
Colstrip Unit 4 operations
  
2.4
  
Postretirement health care
  
2.1
  
Pension expense
  
(3.8
)
Legal and professional fees
  
(2.5
)
Stock based compensation and short term incentive
  
(2.2
)
Bad debt expense
  
(0.3
)
Other
  
(1.2
)
Increase in Operating, General & Administrative Expenses
  
$
6.9
  

The increase in operating, general and administrative expenses of $6.9 million was primarily due to the following:
 
·  
Increased labor costs due primarily to compensation increases and severance costs;
 
·  
Increased insurance reserves due primarily to the Bozeman explosion as well as our experience with other general liability and workers compensation matters;
 
·  
Reduced insurance recoveries as compared with the same period of 2008. Insurance recoveries received in 2009 are primarily related to previously incurred Montana generation related environmental remediation costs, which were offset by settlements received in the third quarter of 2008; and
 
·  
Higher operating, general and administrative costs related to our supply function, which are recovered from customers through supply trackers and therefore have no impact on operating income;
 
·  
Increased plant operations costs at Colstrip Unit 4 due to the outage; and
 
·  
Increased postretirement health care costs due to plan asset market losses and changes in actuarial assumptions; partly offset by
 
 
 
34
 
·  
Lower pension expense as discussed above;
 
·  
Decreased legal and professional fees associated with ongoing litigation;
 
·  
Lower stock-based compensation due to reduced equity grants and lower short-term incentive; and
 
·  
Lower bad debt expense based on lower average customer receivable balances and less days outstanding.
 
Property and other taxes were $63.4 million for the nine months ended September 30, 2009 as compared with $66.0 million in the same period of 2008. The decrease was due to lower assessed property valuations.

Depreciation expense was $67.0 million for the nine months ended September 30, 2009 as compared with $63.6 million in the same period of 2008. The increase was primarily due to plant additions.

Consolidated operating income for the nine months ended September 30, 2009 was $104.9 million, as compared with $118.9 million in the same period of 2008. The decrease was primarily due to higher operating expenses and the $6.3 million decrease in gross margin discussed above.

Consolidated interest expense for the nine months ended September 30, 2009 was $50.4 million, an increase of $2.9 million, or 6.1%, from the same period of 2008. This increase was primarily due to increased debt outstanding.

Consolidated income tax expense for the nine months ended September 30, 2009 was $7.9 million as compared with $26.8 million in the same period of 2008. The effective tax rate for the nine months ended September 30, 2009 was 14.1% as compared with 36.6% for the same period of 2008. These effective tax rates differ from the federal tax rate of 35% primarily due to the effects of tax credits, state income taxes, utility rate-making, and other permanent book-to-tax differences. The effective tax rate for the nine months ended September 30, 2009 was significantly impacted by a change in tax accounting method related to repair costs as discussed above. We expect the effective tax rate for the year ended December 31, 2009 to be approximately 20.0%.

Consolidated net income for the nine months ended September 30, 2009 was $47.8 million as compared with $46.3 million for the same period of 2008. The increase was primarily due to lower income tax expense, offset by lower operating income and higher interest expense as discussed above.

 
 
35
 

REGULATED ELECTRIC SEGMENT
 
Three Months Ended September 30, 2009 Compared with the Three Months Ended September 30, 2008

 
   
Results
  
   
2009
  
2008
  
Change
  
% Change
  
   
(in millions)
  
Retail revenue
  
$
163.3
  
$
191.2
  
$
(27.9
)
(14.6
)%
Transmission
  
11.2
  
12.9
  
(1.7
)
(13.2
)
Wholesale
  
11.1
  
2.3
  
8.8
  
382.6
  
Regulatory Amortization and Other
  
13.1
  
1.6
  
11.5
  
718.8
  
Total Revenues
  
198.7
  
208.0
  
(9.3
)
(4.5
)
Total Cost of Sales
  
92.6
  
113.3
  
(20.7
)
(18.3
)
Gross Margin
  
$
106.1
  
$
94.7
  
$
11.4
  
12.0
%

   
Revenues
  
Megawatt Hours (MWH)
  
Avg. Customer Counts
  
   
2009
  
2008
  
2009
  
2008
  
2009
  
2008
  
   
(in thousands)
          
Retail Electric
                          
      Montana
  
$
49,248
  
$
58,008
  
515
  
532
  
267,382
  
265,258
  
      South Dakota
  
10,776
  
11,984
  
122
  
130
  
48,256
  
47,947
  
   Residential 
  
60,024
  
69,992
  
637
  
662
  
315,638
  
313,205
  
      Montana
  
70,030
  
80,770
  
828
  
853
  
60,602
  
59,817
  
      South Dakota
  
16,539
  
18,148
  
230
  
237
  
11,792
  
11,605
  
   Commercial
  
86,569
  
98,918
  
1,058
  
1,090
  
72,394
  
71,422
  
      Industrial
  
8,079
  
11,914
  
717
  
786
  
71
  
71
  
      Other
  
8,592
  
10,411
  
75
  
88
  
7,728
  
7,640
  
Total Retail Electric
  
$
163,264
  
$
191,235
  
2,487
  
2,626
  
395,831
  
392,338
  
Wholesale Electric
                          
      Montana
  
$
9,464
  
$
—
  
126
  
—
  
N/A
  
N/A
  
      South Dakota
  
1,636
  
2,268
  
64
  
71
  
N/A
  
N/A
  
Total Wholesale Electric
  
$
11,100
  
$
2,268
  
190
  
71
  
N/A
  
N/A
  

   
2009 as compared to:
  
Cooling Degree-Days
  
2008
  
Historic Average
  
Montana
  
5% colder
  
10% warmer
  
South Dakota
  
30% colder
  
37% colder
  

The following summarizes the components of the changes in regulated electric margin for the three months ended September 30, 2009 and 2008:

   
Gross Margin
  
 
  
2009 vs. 2008
  
   
(in millions)
  
Transfer of interest in Colstrip Unit 4 to regulated electric
  
$
17.8
  
Retail volumes
  
(2.6
)
Transmission capacity
  
(1.7
)
South Dakota wholesale
  
(0.7
)
QF supply costs
  
(0.7
)
Other
  
(0.7
)
Improvement in Regulated Electric Gross Margin
    
11.4
  
Reduction in Unregulated Electric Gross Margin
    
(24.3
)
Net Decline in Electric Gross Margin
  
$
(12.9
)
 

 
36
 
 
The net decline in gross margin is due to the combination of decreased retail volumes as a result of cooler summer weather and lower usage per customer, lower South Dakota wholesale margin due to lower sales at lower average prices, lower transmission capacity revenues with less demand to transmit energy for others across our lines, and higher QF related supply costs based on actual QF pricing and output. 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. Regulatory amortization increased due to changes in our electric supply and property tax trackers. These amortizations are reflected as reduced rates in retail revenue; therefore they have no impact on gross margin.

This decline in gross margin was offset in part by the transfer of Colstrip Unit 4 to the regulated utility. 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. 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. The absence of gross margin from our unregulated electric segment reduced gross margin by approximately $24.3 million as compared with the same period in 2008, which included a $10.2 million unrealized gain on forward contracts. The 2008 unrealized gain was due to changes in forward prices of electricity. In addition, we are continuing to fulfill a prior third party power purchase agreement, which is reflected as an increase in Montana wholesale revenues and volumes above.

We are currently experiencing an unplanned outage at Colstrip Unit 4 for a rotor repair. We expect Colstrip Unit 4 to return to service early in the fourth quarter of 2009. We do not expect this to have an impact on our electric margin as replacement power is included in our supply tracking mechanism, and the remaining power purchase agreement for the output of this plant is unit-contingent, therefore we are not required to procure supply to fulfill this obligation.

Regulated wholesale electric volumes increased due to the 2009 transfer of Colstrip Unit 4 to the regulated utility discussed above. The increase in regulated wholesale electric volumes was offset in part by a decrease in South Dakota wholesale volumes from lower plant availability related to scheduled maintenance. We expect wholesale volumes for Montana to be reduced into the fourth quarter of 2009 due to the outage at Colstrip Unit 4.


 
37
 

Nine Months Ended September 30, 2009 Compared with the Nine Months Ended September 30, 2008

 
   
Results
  
   
2009
  
2008
  
Change
  
% Change
  
   
(in millions)
  
Retail revenue
  
$
494.8
  
$
538.6
  
$
(43.8
)
(8.1
)%
Transmission
  
33.5
  
36.8
  
(3.3
)
(9.0
)
Wholesale
  
32.8
  
8.1
  
24.7
  
304.9
  
Regulatory Amortization and Other
  
19.0
  
0.1
  
18.9
  
18900.0
  
Total Revenues
  
580.1
  
583.6
  
(3.5
)
(0.6
)
Total Cost of Sales
  
258.9
  
303.5
  
(44.6
)
(14.7
)
Gross Margin
  
$
321.2
  
$
280.1
  
$
41.1
  
14.7
%

   
Revenues
  
MWHs
  
Avg. Customer Counts
  
   
2009
  
2008
  
2009
  
2008
  
2009
  
2008
  
   
(in thousands)
          
Retail Electric
                          
      Montana
  
$
162,708
  
$
178,571
  
1,682
  
1,699
  
268,337
  
265,727
  
      South Dakota
  
33,818
  
34,417
  
402
  
394
  
48,211
  
47,912
  
   Residential 
  
196,526
  
212,988
  
2,084
  
2,093
  
316,548
  
313,639
  
      Montana
  
203,324
  
220,209
  
2,373
  
2,408
  
60,374
  
59,471
  
      South Dakota
  
47,960
  
49,208
  
660
  
658
  
11,656
  
11,486
  
   Commercial
  
251,284
  
269,417
  
3,033
  
3,066
  
72,030
  
70,957
  
      Industrial
  
27,292
  
35,026
  
2,183
  
2,320
  
72
  
71
  
      Other
  
19,743
  
21,129
  
148
  
151
  
6,070
  
5,951
  
Total Retail Electric
  
$
494,845
  
$
538,560
  
7,448
  
7,630
  
394,720
  
390,618
  
Wholesale Electric
                          
      Montana
  
$
28,355
  
$
—
  
426
  
—
  
N/A
  
N/A
  
      South Dakota
  
4,429
  
8,115
  
161
  
202
  
N/A
  
N/A
  
Wholesale Electric
  
$
32,784
  
$
8,115
  
587
  
202
  
N/A
  
N/A
  

   
2009 as compared to:
  
Cooling Degree-Days
  
2008
  
Historic Average
  
Montana
  
6% colder
  
5% colder
  
South Dakota
  
24% colder
  
37% colder
  

The net decline in electric margin and the change in volumes are primarily due to the same reasons discussed above for the three months ended September 30, 2009 and are summarized for the nine months ended September 30, 2009 as compared with 2008 as follows:

   
Gross Margin
  
 
  
2009 vs. 2008
  
   
(in millions)
  
Transfer of interest in Colstrip Unit 4 to regulated electric
  
$
52.9
  
South Dakota wholesale
  
(3.5
)
Transmission capacity
  
(3.3
)
Retail volumes
  
(2.4
)
QF supply costs
  
(1.1
)
Other
  
(1.5
)
Improvement in Regulated Electric Gross Margin
    
41.1
  
Reduction in Unregulated Electric Gross Margin
    
(42.6
)
Net Decline in Electric Gross Margin
  
$
(1.5
)


 
38
 
 
REGULATED NATURAL GAS SEGMENT

Three Months Ended September 30, 2009 Compared with the Three Months Ended September 30, 2008

   
Results
  
   
2009
  
2008
  
Change
  
% Change
  
   
(in millions)
  
Retail revenue
  
$
23.0
  
$
37.5
  
$
(14.5
)
(38.7
)%
Wholesale and other
  
11.2
  
8.1
  
3.1
  
38.3
  
Total Revenues
  
34.2
  
45.6
  
(11.4
)
(25.0
)
Total Cost of Sales
  
12.3
  
22.8
  
(10.5
)
(46.1
)
Gross Margin
  
$
21.9
  
$
22.8
  
$
(0.9
)
(3.9
)%

   
Revenues
  
Dekatherms (Dkt)
  
Customer Counts
  
   
2009
  
2008
  
2009
  
2008
  
2009
  
2008
  
   
(in thousands)
          
Retail Gas
                          
      Montana
  
$
10,259
  
$
16,189
  
822
  
941
  
155,546
  
154,403
  
      South Dakota
  
1,698
  
2,496
  
124
  
126
  
36,353
  
36,169
  
      Nebraska
  
1,973
  
2,922
  
164
  
160
  
36,008
  
35,960
  
   Residential
  
13,930
  
21,607
  
1,110
  
1,227
  
227,907
  
226,532
  
      Montana
  
5,987
  
9,266
  
527
  
571
  
21,780
  
21,601
  
      South Dakota
  
1,357
  
3,156
  
212
  
246
  
5,749
  
5,684
  
      Nebraska
  
1,560
  
3,127
  
297
  
278
  
4,408
  
4,461
  
   Commercial
  
8,904
  
15,549
  
1,036
  
1,095
  
31,937
  
31,746
  
      Industrial
  
134
  
228
  
12
  
15
  
293
  
301
  
      Other
  
58
  
107
  
5
  
7
  
142
  
140
  
Total Retail Gas
  
$
23,026
  
$
37,491
  
2,163
  
2,344
  
260,279
  
258,719
  

   
2009 as compared with:
  
Heating Degree-Days
  
2008
  
Historic Average
  
Montana
  
34% warmer
  
35% warmer
  
South Dakota
  
10% colder
  
4% colder
  
Nebraska
  
2% colder
  
6% colder
  

Gross margin decreased $0.9 million during the three months ended September 30, 2009 as compared with 2008 due to lower average usage per customer. Due to the seasonality of our business, natural gas volumes during the third quarter are impacted to a lesser extent by changes in weather. Heating degree-days reflect activity during the month of September. Our wholesale and other revenues are largely gross margin neutral as they are offset by changes in cost of sales. In addition, average natural gas supply prices decreased, resulting in decreased retail revenues and cost of sales in 2009 as compared with 2008, with no impact to gross margin.


 
39
 

Nine Months Ended September 30, 2009 Compared with the Nine Months Ended September 30, 2008

   
Results
  
   
2009
  
2008
  
Change
  
% Change
  
   
(in millions)
  
Retail revenue
  
$
217.9
  
$
267.9
  
$
(50.0
)
(18.7
)%
Wholesale and other
  
36.4
  
29.9
  
6.5
  
21.7
  
Total Revenues
  
254.3
  
297.8
  
(43.5
)
(14.6
)
Total Cost of Sales
  
154.1
  
194.0
  
(39.9
)
(20.6
)
Gross Margin
  
$
100.2
  
$
103.8
  
$
(3.6
)
(3.5
)%

   
Revenues
  
Dkt
  
Customer Counts
  
   
2009
  
2008
  
2009
  
2008
  
2009
  
2008
  
   
(in thousands)
          
Retail Gas
                          
      Montana
  
$
86.934
  
$
110,886
  
8,338
  
9,033
  
156,662
  
155,236
  
      South Dakota
  
26,132
  
29,284
  
2,251
  
2,322
  
36,676
  
36,527
  
      Nebraska
  
22,432
  
25,068
  
1,981
  
2,091
  
36,360
  
36,397
  
   Residential
  
135,498
  
165,238
  
12,570
  
13,446
  
229,698
  
228,160
  
      Montana
  
44,401
  
56,202
  
4,311
  
4,563
  
21,945
  
21,685
  
      South Dakota
  
19,984
  
23,333
  
2,282
  
2,166
  
5,810
  
5,761
  
      Nebraska
  
16,152
  
20,384
  
2,094
  
2,157
  
4,496
  
4,524
  
   Commercial
  
80,537
  
99,919
  
8,687
  
8,886
  
32,251
  
31,970
  
      Industrial
  
1,149
  
1,765
  
114
  
150
  
296
  
304
  
      Other
  
727
  
950
  
79
  
89
  
142
  
140
  
Total Retail Gas
  
$
217,911
  
$
267,872
  
21,450
  
22,571
  
262,387
  
260,574
  

   
2009 as compared with:
  
Heating Degree-Days
  
2008
  
Historic Average
  
Montana
  
8% warmer
  
5% warmer
  
South Dakota
  
Remained flat
  
5% colder
  
Nebraska
  
7% warmer
  
2% warmer
  

The following summarizes the components of the changes in regulated natural gas margin for the nine months ended September 30, 2009 and 2008:
 
 
   
Gross Margin
  
   
2009 vs. 2008
  
   
(in millions)
  
Warmer winter weather
  
$
(2.4
)
Other
  
(1.2
)
Reduction in Gross Margin
  
$
(3.6
)

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.
 

 
40
 


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 September 30, 2009, our total net liquidity was approximately $226.9 million, including $6.0 million of cash and $220.9 million of revolving credit facility availability. Revolver availability was $246.9 million as of October 23, 2009.

Factors Impacting our Liquidity

Financing Transactions - In March 2009, we received net proceeds of approximately $249.8 million from the issuance 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, repay outstanding borrowings on our revolving credit facility, repay other outstanding debt obligations of $31.7 million related to Colstrip Unit 4, fund a portion of the costs of the Mill Creek generation project, and fund future capital expenditures.

On June 30, 2009, we amended and restated our unsecured revolving line of credit scheduled to expire on November 1, 2009. The amended facility extends the term to June 30, 2012, and increases the aggregate principal amount available under the facility by $50 million to $250 million. The amended facility does not amortize and borrowings will bear interest based on a credit ratings grid. The ‘spread’ or ‘margin’ ranges from 2.25% to 4.0% over the London Interbank Offered Rate (LIBOR). On the closing date of the agreement, the applicable spread was 3.0%. A total of nine banks participate in the new facility, with no one bank providing more than 14.0% of the total availability. The amended facility contains covenants substantially similar to the previous facility.

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 September 30, 2009, we are over collected on our current Montana natural gas and electric trackers by approximately $4.8 million, as compared with an under collection of $10.5 million as of December 31, 2008, and an under collection of $11.3 million as of September 30, 2008. This over collection is primarily due to the volatility of commodity prices.

Pension Plan Contributions – During the nine months ended September 30, 2009, we made contributions of $76.4 million to our qualified pension plans. Based on the expected funded status of our plans and our available liquidity, we anticipate making additional contributions to our qualified pension plans during 2009 of approximately $16.5 million. These contributions are in addition to our minimum funding requirements for 2009, but will improve the funded status of our plans and reduce 2010 contribution requirements.


 
41
 

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 October 23, 2009, our current ratings with these agencies are as follows:
 
   
Senior Secured Rating
  
Senior Unsecured Rating
  
Outlook
Fitch
  
BBB+
  
BBB
  
Stable
Moody’s (1)
  
A3
  
Baa2
  
Positive
S&P
  
A- (MT)
BBB+ (SD)
  
BBB
  
Stable
             
 
(1)
Moody’s upgraded our senior secured credit rating on August 3, 2009, from Baa1, 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):

   
Nine Months Ended September 30,
  
   
2009
  
2008
  
Operating Activities
          
Net income
  
$
47.8
  
$
46.3
  
Non-cash adjustments to net income
  
95.4
  
92.6
  
Changes in working capital
  
39.2
  
60.1
  
Other
  
(53.1
)
(22.3
)
   
129.3
  
176.7
  
           
Investing Activities
          
Property, plant and equipment additions
  
(115.8
)
(81.0
)
Sale of assets
  
0.3
  
0.1
  
   
(115.5
)
(80.9
)
           
Financing Activities
          
Net borrowing of debt
  
28.0
  
18.0
  
Dividends on common stock
  
(36.1
)
(38.0
)
Treasury stock activity
  
(0.6
)
(78.6
)
Other
  
(10.4
)
(1.4
)
   
(19.1
)
(100.0
)
           
Net Decrease in Cash and Cash Equivalents
  
$
(5.3
)
$
(4.2
)
Cash and Cash Equivalents, beginning of period
  
$
11.3
  
$
12.8
  
Cash and Cash Equivalents, end of period
  
$
6.0
  
$
8.6
  


 
42
 

Cash Provided by Operating Activities

As of September 30, 2009, cash and cash equivalents were $6.0 million as compared with $11.3 million at December 31, 2008 and $8.6 million at September 30, 2008. Cash provided by operating activities totaled $129.3 million for the nine months ended September 30, 2009 as compared with $176.7 million during the nine months ended September 30, 2008. This decrease in operating cash flows is primarily related to pension funding of $76.4 million, which was an increase of approximately $54.5 million as compared with the nine months ended September 30, 2008, and a $10.8 million prepayment of a power purchase agreement, offset by lower commodity prices reflected in the change in accounts receivable and accounts payable, as well as decreased cash outflows for natural gas storage injections.

Cash Used in Investing Activities

Cash used in investing activities for the nine months ended September 30, 2009, increased by approximately $34.6 million as compared with the same period in 2008 due to increased property, plant and equipment additions.

Cash Used in Financing Activities

Cash used in financing activities totaled approximately $19.1 million during the nine months ended September 30, 2009 as compared with $100.0 million during the nine months ended September 30, 2008. During the nine months ended September 30, 2009 we received net proceeds from the issuance of debt of $249.8 million, made net debt repayments of $221.8 million, paid deferred financing costs of $10.4 million and paid dividends on common stock of $36.1 million. During the nine months ended September 30, 2008 we had net borrowings of $18.0 million, paid dividends on common stock of $38.0 million and used cash to repurchase shares under a previously approved plan of approximately $77.7 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.

We estimate capital spending for the Mill Creek generating station project under construction will be between $80 and $100 million in 2009. We have capitalized approximately $39.0 million during the nine months ended September 30, 2009. In addition to the financing transactions discussed above, we completed the issuance of $55 million of Montana First Mortgage Bonds in October 2009 to finance a portion of this project and / or other capital expenditures.
 

 
43
 

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 September 30, 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
  
$
890,403
  
$
—
  
$
6,123
  
$
6,578
  
$
27,792
  
$
—
  
$
849,910
Capital Leases
  
37,069
  
293
  
1,203
  
1,284
  
1,372
  
1,468
  
31,449
Future minimum operating lease payments
  
3,887
  
458
  
1,439
  
996
  
614
  
74
  
306
Estimated Pension and Other Postretirement Obligations (1)
  
104,225
  
17,425
  
21,700
  
21,700
  
21,700
  
21,700
  
N/A
Qualifying Facilities (2)
  
1,413,246
  
15,650
  
63,589
  
65,323
  
67,111
  
69,816
  
1,131,757
Supply and Capacity Contracts (3)
  
1,529,007
  
116,452
  
337,037
  
175,917
  
162,302
  
150,244
  
587,055
Contractual interest payments on debt (4)
  
437,645
  
14,929
  
51,076
  
50,689
  
49,882
  
49,371
  
221,698
Total Commitments (5)
  
$
4,415,482
  
$
165,207
  
$
482,167
  
$
322,487
  
$
330,773
  
$
292,673
  
$
2,822,175

(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 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 include an assumed average interest rate of 3.25% on an estimated revolving line of credit balance of $24.0 million through maturity in June 2012.
(5)           Potential tax payments related to uncertain tax positions are not practicable to estimate and have been excluded from this table.

 
 
Management’s discussion and analysis of financial condition and results of operations is based on our condensed 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 September 30, 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, QF 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.


 
44
 

 
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, ranging from 2.25% to 4.0% over LIBOR. As of September 30, 2009, the applicable spread was 3.0%, resulting in a borrowing rate of 3.25%. Based upon amounts outstanding as of September 30, 2009, a 1% increase in the LIBOR would increase our annual interest expense by approximately $0.2 million.

Commodity Price Risk

Commodity price risk is a significant risk 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 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.

Our “other” segment includes a pipeline capacity contract through October 2013 that was primarily used to serve natural gas supply to one customer. During the second quarter of 2009, this customer terminated their natural gas supply contract with us during their bankruptcy proceedings. As a result of the supply contract termination, we have excess capacity. We recognized a $1.5 million loss during the nine months ended September 30, 2009 based on our release of the excess capacity through October 2010 and our estimate of the market value for the excess capacity during the remaining term. Our remaining maximum exposure is approximately $0.9 million related to this contract. We have no other remaining capacity contracts outside of our regulated utility operations.

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.

 
 
45
 

 
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 September 30, 2009 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
 

 
 
46
 

 
 
See Note 14, Commitments and Contingencies, to the Condensed 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 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 a decrease in customers’ ability to pay their accounts, which may adversely affect our liquidity, results of operations and future growth. While our territories have been less impacted than other parts of the country, during 2009 we have experienced declines in electric and natural gas usage per customer and lower electric transmission sales, due in part to the recession.

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 draw on our revolving 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. For example, in our 2008 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. The outcome of our Montana electric and natural gas rate case filed in 2009 could have a significant impact on our liquidity and results of operations. 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 FERC 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.


 
47
 

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 and two federal courts of appeal have reinstated nuisance claims against emitters of carbon dioxide, including several utility companies, alleging that such emissions contribute to global warming. 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.
 

 
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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. During 2008, we experienced plan asset losses in excess of 30%. 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, is 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 projects proposed by other parties 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 $9.7 million of costs associated with these projects as of September 30, 2009.

Our obligation to include a minimum annual quantity of power in our Montana electric supply portfolio at an agreed upon price per MWh 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. In addition, we are subject to price escalation risk with one of our largest QF contracts.

As part of the Stipulation and Settlement with the MPSC and other parties in the Tier II Docket, we agreed to include a minimum annual quantity of power in our Montana electric supply portfolio at an agreed upon price per MWh. 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.

In addition, we are subject to price escalation risk with one of our largest QF contracts due to variable contract terms. In estimating our QF liability, we have estimated an annual escalation rate of 1.9% over the term of the contract (through June 2024). To the extent the annual escalation rate exceeds 1.9%, our results of operations and financial position could be adversely affected.

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
 
 
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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, our liquidity, access to capital and operations could be materially adversely affected.

A downgrade of our credit ratings to less than investment grade could adversely affect our liquidity. Certain of our credit agreements and other credit arrangements with counterparties require us to provide collateral in the form of letters of credit or cash to support our obligations if we fall below investment grade. Also, a downgrade below investment grade could hinder our ability to raise capital on favorable terms and increase our borrowing costs.

Our secured credit ratings are also tied to our ability to invest in unregulated ventures due to an existing stipulation with the MPSC and Montana Consumer Counsel, which establishes diminishing limits for such investment at certain credit rating levels. The stipulation does not limit investment in unregulated ventures so long as we maintain credit ratings on a secured basis of at least BBB+ (S&P) and Baa1 (Moody’s). For a further discussion of how a lack of liquidity and access to adequate capital could affect our operations, please see the Risk Factor above, “Economic conditions and instability in the financial markets could negatively impact our business.”


 
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(a) Exhibits
 
Exhibit 4.1— Twenty-eighth Supplemental Indenture, dated as of October 1, 2009, by and between NorthWestern Corporation and The Bank of New York Mellon, as trustee.
 
Exhibit 10.1— Purchase Agreement, dated September 30, 2009, among NorthWestern Corporation and the initial purchasers named therein (incorporated by reference to Exhibit 10.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated September 30, 2009, Commission File No. 1-10499).
 
Exhibit 10.2— Engineering, Procurement and Construction Agreement, dated July 27, 2009, between NorthWestern Corporation and NewMech Companies, Inc.
 
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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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: October 29, 2009
By:
/s/ BRIAN B. BIRD
   
Brian B. Bird
   
Chief Financial Officer
   
Duly Authorized Officer and Principal Financial Officer


 
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Exhibit
Number
  
Description
*4.1
  
Twenty-eighth Supplemental Indenture, dated as of October 1, 2009, by and between NorthWestern Corporation and The Bank of New York Mellon, as trustee.
10.1
  
Purchase Agreement, dated September 30, 2009, among NorthWestern Corporation and the initial purchasers named therein (incorporated by reference to Exhibit 10.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated September 30, 2009, Commission File No. 1-10499).
*10.2
  
Engineering, Procurement and Construction Agreement, dated July 27, 2009, between NorthWestern Corporation and NewMech Companies, Inc.
*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
 

 
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