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 ~~March 31,~~June 30, 2008

Or

o		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 of incorporation)		(I.R.S. Employer Identification No.)

3010 West 69^th 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 ~~past~~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 is a large accelerated filer, an accelerated filer, or a non-
accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule ~~12(b)(2)~~12b-2 of the Exchange Act. ~~(check~~(Check one).

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 ~~Act). Yes~~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 ~~registrant’s~~issuer’s classes of common stock, as of the latest
practicable date:

Common Stock, Par Value $.01

~~38,972,551~~38,190,492 shares outstanding at ~~April 18,~~July 25, 2008

NORTHWESTERN CORPORATION

FORM 10-Q

INDEX

		Page
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS			3
PART I. FINANCIAL INFORMATION			5
Item 1.	Financial Statements (Unaudited)		5
	Consolidated Balance Sheets — ~~March 31,~~June 30, 2008 and December 31, ~~2007~~2007		5
	Consolidated Statements of Income — Three and Six Months Ended ~~March 31,~~June 30, 2008 and ~~2007~~2007		6
	Consolidated Statements of Cash Flows – ~~Three~~Six Months Ended ~~March 31,~~June 30, 2008 and ~~2007~~2007		7
	Notes to Consolidated Financial Statements		8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		2023
Item 3.	Quantitative and Qualitative Disclosure About Market Risk		3242
Item 4.	Controls and Procedures		3343
PART II. OTHER INFORMATION			3444
Item 1.	Legal Proceedings		3444
Item 1A.	Risk Factors		3444
Item 4.	Submission of Matters to a Vote of Security Holders		46
Item 6.	Exhibits		3647
SIGNATURES			3748

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

On one or more occasions, we may make statements in this Quarterly Report on Form 10-Q regarding our assumptions, projections, expectations, targets, intentions or beliefs about future events. All statements other than statements of historical facts, included or incorporated by reference herein relating to management's current expectations of future financial performance, continued growth, changes in economic conditions or capital markets and changes in customer usage patterns and preferences are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.

Words or phrases such as “anticipates," “may," “will," “should," “believes," “estimates," “expects," “intends," “plans," “predicts," “projects," “targets," “will likely result," “will continue" or similar expressions identify forward-looking statements. Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. We caution that while we make such statements in good faith and believe such statements are based on reasonable assumptions, including without limitation, management's examination of historical operating trends, data contained in records and other data available from third parties, we cannot assure you that our projections will be achieved. Factors that may cause such differences include, but are not limited to:

potential additional adverse federal, state, or local legislation or regulation or adverse determinations by regulators could have a material adverse effect on our ~~ability to avoid or mitigate adverse rulings or judgments against us in our pending litigation;~~liquidity, results of operations and financial condition.

unanticipated changes in availability of trade credit, 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 would adversely affect our liquidity;

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 our service ~~territories; and~~territories.

potential additional 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.

We have attempted to identify, in context, certain of the factors that we believe may cause actual future experience and results to differ materially from our current expectation regarding the relevant matter or subject area. In addition to the items specifically discussed above, our business and results of operations are subject to the uncertainties described under the caption “Risk Factors" which is part of the disclosure included in Part II, Item 1A of this Report.

From time to time, oral or written forward-looking statements are also included in our reports on Forms 10-K, 10-Q and 8-K, Proxy Statements on Schedule 14A, press releases, analyst and investor conference calls, and other communications released to the public. Although we believe that at the time made, the expectations reflected in all of these forward-looking statements are and will be reasonable, any or all of the forward-looking statements in this Quarterly Report on Form 10-Q, our reports on Forms 10-K and 8-K, our Proxy Statements on Schedule 14A and any other public statements that are made by us may prove to be incorrect. This may occur as a result of assumptions, which turn out to be inaccurate or as a consequence of known or unknown risks and uncertainties. Many factors discussed in this Quarterly Report on Form 10-Q, certain of which are beyond our control, will be important in determining our future performance. Consequently, actual results may differ materially from those that might be anticipated from forward-looking statements. In light of these and other uncertainties, you should not regard the inclusion of a forward-looking statement in this Quarterly Report on Form 10-Q or other public communications that we might make as a representation by us that our plans and objectives will be achieved, and you should not place undue reliance on such forward-looking statements.

We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. However, your attention is directed to any further disclosures made on related subjects in our subsequent annual and periodic reports filed with the ~~SEC~~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"~~Energy” and ~~“NorthWestern"~~“NorthWestern” refer specifically to NorthWestern Corporation and its subsidiaries.

PART 1. FINANCIAL INFORMATION

ITEM 1.
FINANCIAL STATEMENTS
NORTHWESTERN CORPORATION
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(in thousands, except share data)

June 30,

December 31,

March 31,
2008

December 31,
2007

2008

2007
ASSETS

Current Assets:

Cash and cash equivalents

$
33,755

$
12,773

$
24,242

$
12,773

Restricted cash

13,904

14,482

19,520

14,482

Accounts receivable, net of allowance

142,280

143,482

116,802

143,482

Inventories

29,579

63,586

47,304

63,586

Regulatory assets

23,096

27,049

21,190

27,049

Prepaid energy supply

2,966

3,166

2,791

3,166

Deferred income taxes

6,987

2,987

8,813

2,987

Other

18,570

10,829

43,861

10,829

Total current assets

271,137

278,354

284,523

278,354

Property, plant, and equipment, net

1,785,079

1,770,880

1,798,735

1,770,880

Goodwill

355,128

355,128

355,128

355,128

Regulatory assets

117,616

123,041

113,031

123,041

Other noncurrent assets

19,346

19,977

19,236

19,977

Total assets

$
2,548,306

$
2,547,380

$
2,570,653

$
2,547,380

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current Liabilities:

Current maturities of capital leases

$
2,176

$
2,389

$
1,836

$
2,389

Current maturities of long-term debt

18,860

18,617

19,285

18,617

Accounts payable

65,989

91,588

69,237

91,588

Accrued expenses

184,227

168,610

169,631

168,610

Regulatory liabilities

50,415

40,635

85,297

40,635

Total current liabilities

321,667

321,839

345,286

321,839

Long-term capital leases

37,701

38,002

37,412

38,002

Long-term debt

757,352

787,360

744,432

787,360

Deferred income taxes

89,315

74,046

100,987

74,046

Noncurrent regulatory liabilities

215,383

194,959

218,923

194,959

Other noncurrent liabilities

292,460

308,150

291,648

308,150

Total liabilities

1,713,878

1,724,356

1,738,688

1,724,356

Commitments and Contingencies (Note 12)

Commitments and Contingencies (Note 14)

Shareholders’ Equity:

Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 39,335,958 and 38,972,551, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued

393

393

393

393

Treasury stock at cost

(10,781
)

(10,781
)

(10,781
)

(10,781
)
Paid-in capital

804,254

803,061

805,426

803,061

Retained earnings

27,193

16,603

23,835

16,603

Accumulated other comprehensive income

13,369

13,748

13,092

13,748

Total shareholders’ equity

834,428

823,024

831,965

823,024

Total liabilities and shareholders’ equity

$
2,548,306

$
2,547,380

$
2,570,653

$
2,547,380

See Notes to Consolidated Financial Statements

5
NORTHWESTERN CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
(in thousands, except per share amounts)

Three Months Ended
June 30,

Six Months Ended
June 30,

Three Months Ended
March 31,

2008

2007

2008

2007

2008

2007

OPERATING REVENUES

$
385,975

$
366,565

$
276,506

$
259,608

$
662,481

$
626,173

COST OF SALES

229,084

219,278

149,354

141,255

378,438

360,534

GROSS MARGIN

156,891

147,287

127,152

118,353

284,043

265,639

OPERATING EXPENSES

Operating, general and administrative

60,071

62,448

53,866

58,677

113,937

121,125

Property and other taxes

23,640

20,592

20,540

20,660

44,180

41,252

Depreciation

21,091

19,894

21,225

20,793

42,316

40,687

TOTAL OPERATING EXPENSES

104,802

102,934

95,631

100,130

200,433

203,064

OPERATING INCOME

52,089

44,353

31,521

18,223

83,610

62,575

Interest Expense

(16,080
)

(13,220
)

(15,848
)

(14,527
)

(31,849
)

(27,747
)
Other Income

662

378

Other (Expense) Income

(161
)

359

422

737

Income Before Income Taxes

36,671

31,511

15,512

4,055

52,183

35,565

Income Tax Expense

(13,220
)

(12,369
)

(6,009
)

(1,621
)

(19,229
)

(13,989
)
Net Income

$
23,451

$
19,142

$
9,503

$
2,434

$
32,954

$
21,576

Average Common Shares Outstanding

38,972

35,720

38,973

35,988

38,973

35,855

Basic Earnings per Average Common Share

$
0.60

$
0.54

$
0.24

$
0.07

$
0.85

$
0.60

Diluted Earnings per Average Common Share

$
0.59

$
0.51

$
0.24

$
0.06

$
0.84

$
0.57

Dividends Declared per Average Common Share

$
0.33

$
0.31

$
0.33

$
0.31

$
0.66

$
0.62

See Notes to Consolidated Financial Statements

6
NORTHWESTERN CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(in thousands)

Three Months Ended March 31,

Six Months Ended
June 30,

2008

2007

2008

2007

OPERATING ACTIVITIES:

Net Income

$
23,451

$
19,142

$
32,954

$
21,576

Items not affecting cash:

Depreciation

21,091

19,894

42,316

40,687

Amortization of debt issue costs, discount and deferred hedge gain

594

399

1,202

805

Amortization of restricted stock

1,194

2,177

2,364

4,259

Equity portion of allowance for funds used during construction

(172
)

(68
)

(282
)

(163
)

Loss (Gain) on sale of assets

2

(62
)

Gain on sale of assets

(110
)

—

Unrealized loss on derivative instruments

1,203

—

6,396

—

Deferred income taxes

11,269

11,685

21,115

12,712

Changes in current assets and liabilities:

Restricted cash

578

165

(5,038
)

(824
)

Accounts receivable

1,202

9,764

26,780

46,979

Inventories

34,007

31,632

16,282

3,126

Prepaid energy supply costs

200

(924
)

375

(547
)

Other current assets

520

366

(288
)

(330
)

Accounts payable

(26,032
)

(19,977
)

(23,569
)

(18,314
)

Accrued expenses

14,466

7,038

(5,324
)

3,622

Regulatory assets

3,902

6,554

5,808

5,893

Regulatory liabilities

1,519

11,633

11,933

26,493

Other noncurrent assets

5,729

2,806

12,159

6,822

Other noncurrent liabilities

(16,768
)

1,865

(20,419
)

(16,559
)

Cash provided by operating activities

77,955

104,089

124,654

136,237

INVESTING ACTIVITIES:

Property, plant, and equipment additions

(13,957
)

(20,470
)

(43,087
)

(52,608
)

Colstrip Unit 4 acquisition

—

(40,247
)

—

(40,247
)

Proceeds from sale of assets

3

109

29

592

Cash used in investing activities

(13,954
)

(60,608
)

(43,058
)

(92,263
)

FINANCING ACTIVITIES:

Proceeds from exercise of warrants

—

5,102

—

10,600

Treasury stock activity

—

(1
)

—

(6
)

Dividends on common stock

(12,861
)

(11,112
)

(25,722
)

(22,297
)

Issuance of long-term debt

55,000

—

Repayment of long-term debt

(18,047
)

(3,627
)

(85,939
)

(3,920
)

Line of credit repayments, net

(12,000
)

(34,000
)

(12,000
)

(30,000
)

Financing costs

(111
)

(227
)

(1,466
)

(281
)

Cash used in financing activities

(43,019
)

(43,865
)

(70,127
)

(45,904
)

Increase (Decrease) in Cash and Cash Equivalents

20,982

(384
)

11,469

(1,930
)

Cash and Cash Equivalents, beginning of period

12,773

1,930

12,773

1,930

Cash and Cash Equivalents, end of period

$
33,755

$
1,546

$
24,242

$
—

Supplemental Cash Flow Information:

Cash paid during the period for:

Income Taxes

38

859

Income taxes

43

1,274

Interest

12,088

11,664

24,479

18,993

Significant noncash transactions:

Assumption of debt related to Colstrip Unit 4 acquisition

—

20,438

—

20,438

See Notes to Consolidated Financial Statements

7
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Reference is made to Notes to Financial Statements
included in NorthWestern Corporation’s Annual Report)
(Unaudited)
(1) Nature of Operations and Basis of Consolidation
NorthWestern Corporation, doing business as NorthWestern Energy, provides electricity and natural gas to approximately 650,000 customers in Montana, South Dakota and Nebraska. We have generated and distributed electricity in South Dakota and distributed natural gas in South Dakota and Nebraska since 1923 and have distributed electricity and natural gas in Montana since 2002.

The consolidated financial statements for the periods included herein have been prepared by NorthWestern Corporation, pursuant to the rules and regulations of the SEC. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that may affect the reported amounts of assets, liabilities, revenues and expenses during the reporting period. The unaudited consolidated financial statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to fairly present our financial position, results of operations and cash flows. The actual results for the interim periods are not necessarily indicative of the operating results to be expected for a full year or for other interim periods. Although management believes that the condensed disclosures provided are adequate to make the information presented not misleading, management recommends that these unaudited consolidated financial statements be read in conjunction with audited consolidated financial statements and related footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2007.

(2) New Accounting Standards
Accounting Standards Issued

In ~~March~~May 2008, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 162, The Hierarchy of Generally Accepted Accounting Principles (Statement No. 162). Statement No. 162 supersedes the existing hierarchy contained in the U.S. auditing standards. The existing hierarchy was carried over to Statement No. 162 essentially unchanged. The Statement becomes effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to the auditing literature. The new hierarchy is not expected to change current accounting practice in any area.
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133 (SFAS No. 161). SFAS No. 161 changes the disclosure requirements for derivative instruments and hedging activities, requiring enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133), and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. This statement will become effective for our fiscal year beginning January 1, 2009. We are still evaluating the impact of SFAS No. 161, if any, but do not expect the statement to have a material impact on our consolidated financial statements.

Accounting Standards Adopted

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (SFAS No. 157), which defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. SFAS No. 157 became effective for most fair value measurements, other than leases and certain nonfinancial assets and liabilities, beginning January 1, 2008.

8
The statement establishes a three-level fair value hierarchy and requires fair value disclosures based upon this hierarchy. The statement also requires that fair value measurements reflect a credit-spread adjustment based on an entity’s own credit standing. Consideration of our own credit risk did not have a material impact on our fair value measurements.

The following table ~~presents~~sets forth by level within the ~~method of measuring~~ fair value ~~used in determining the carrying amount of~~hierarchy our ~~derivative~~ assets and liabilities ~~and the maturity, by year, to give an indication of when these amounts will settle and generate cash,~~that were measured at fair value on a recurring basis as of ~~March 31,~~June 30, 2008 (in thousands):

Settlement Term

2008

2009

2010

2011

Fair Value

Prices provided by observable market inputs (level 2) (1)

Regulated gas derivative asset (2)

$
4,270

$
5,546

$
3,295

$
869

$
13,980

Unregulated electric derivative liability

(1,034
)
(169
)
—

—

(1,203
)
Net derivative asset

$
3,236

$
5,377

$
3,295

$
869

$
12,777

At June 30, 2008

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 (1)

Regulated gas derivative asset (2)

$
—

$
38,449

$
—

$
—

$
38,449

Unregulated electric derivative liability

—

(6,396
)
—

—

(6,396
)
Net derivative asset

$
—

$
32,053

$
—

$
—

$
32,053

(1)
Fair value was determined using internal models based on quoted external commodity prices.
(2)
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 classify assets and liabilities within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement of each individual asset and liability taken as a whole. Normal purchases and sales transactions, as defined by SFAS No. 133, and certain other long-term power purchase contracts are not included in the fair values by source table as they are not recorded at fair value. See Note 7 for further discussion.

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

(3) Variable Interest Entities
FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, or FIN 46R, requires the consolidation of entities which are determined to be variable interest entities (VIEs) when we are the primary beneficiary of a VIE, which means we have a controlling financial interest. Certain long-term purchase power and tolling contracts may be considered variable interests under FIN 46R. We have various long-term purchase power contracts with other utilities and certain qualifying facility plants. After evaluation of these contracts, we believe one qualifying facility contract may constitute a variable interest entity under the provisions of FIN 46R. We are currently engaged in adversary proceedings with this qualifying facility and, while we have made exhaustive efforts, we have been unable to obtain the information necessary to further analyze this contract under the requirements of FIN 46R. We continue to account for this qualifying facility contract as an executory contract as we have been unable to obtain the necessary information from this qualifying facility in order to determine if it is a VIE and if so, whether we are the primary beneficiary. Based on the current contract terms with this qualifying facility, our estimated gross contractual payments aggregate approximately ~~$513.2~~$506.9 million through 2025, and are included in Contractual Obligations and Other Commitments of Management's Discussion and Analysis.

9
(4) Income Taxes
We have unrecognized tax benefits of approximately $112.0 million as of ~~March 31,~~June 30, 2008. If any of our unrecognized tax benefits were recognized during 2008, they would have no impact on our effective tax rate. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statute of limitations within the next twelve months.

Our policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. During the ~~three~~six months ended ~~March 31,~~June 30, 2008, we have not recognized expense for interest or penalties, and do not have any amounts accrued at ~~March 31,~~June 30, 2008 and December 31, 2007, respectively, for the payment of interest and penalties.

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

(5) Goodwill
There were no changes in our goodwill during the ~~three~~six months ended ~~March 31,~~June 30, 2008. Goodwill by segment is as follows for ~~March 31,~~June 30, 2008 and December 31, 2007 (in thousands):

Regulated electric
$
241,100

Regulated natural gas

114,028

Unregulated electric

—

$
355,128

(6) Other Comprehensive Income
The FASB defines comprehensive income as all changes to the equity of a business enterprise during a period, except for those resulting from transactions with owners. For example, dividend distributions are excepted. Comprehensive income consists of net income and other comprehensive income (OCI). Net income may include such items as income from continuing operations, discontinued operations, extraordinary items, and cumulative effects of changes in accounting principles. OCI may include foreign currency translations, adjustments of minimum pension liability, and unrealized gains and losses on certain investments in debt and equity securities.
Comprehensive income is calculated as follows (in thousands):

Three Months Ended
March 31,

Three Months Ended
June 30,

Six Months Ended
June 30,

2008

2007

2008

2007

2008

2007

Net income

$
23,451

$
19,142

$
9,503

$
2,434

$
32,954

$
21,576

Other comprehensive income, net of tax:

Other comprehensive income (loss), net of tax:

Reclassification of net gains on hedging instruments from OCI to net income

(297
)

(297
)

(297
)

(297
)

(594
)

(594
)

Foreign currency translation

(82
)

19

20

151

(62
)

170

Comprehensive income

$
23,072

$
18,864

$
9,226

$
2,288

$
32,298

$
21,152

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

Forward contracts, which commit us to purchase or sell energy commodities in the future,
Option contracts, which convey the right to buy or sell a commodity at a predetermined price, and
Swap agreements, which require payments to or from counterparties based upon the differential between two prices for a predetermined contractual (notional) quantity.
10

SFAS No. 133 requires that all derivatives be recognized in the balance sheet, either as assets or liabilities, at fair value, unless they meet the normal purchase and normal sales criteria. The changes in the fair value of recognized derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction.

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

interpreted by Derivatives Implementation Guidance Issue C15, to certain contracts involving the purchase and sale of gas and electricity at fixed prices in future periods. Revenues and expenses from these contracts are reported on a gross basis in the appropriate revenue and expense categories as the commodities are received or delivered. For certain regulated electric and gas contracts that do not physically deliver, in accordance with EITF 03-11, Reporting Gains and Losses on Derivative Instruments that are Subject to SFAS No. 133 and not “Held for Trading Purposes" as defined in Issue no. 02-3, revenue is reported net versus gross.

While most of our derivative transactions are entered into for the purpose of managing commodity price risk, hedge accounting is only applied where specific criteria are met and it is practicable to do so. In order to apply hedge accounting, the transaction must be designated as a hedge and it must be highly effective in offsetting the hedged risk. Additionally, for hedges of commodity price risk, physical delivery for forecasted commodity transactions must be probable. We use the mark-to-market method of accounting for derivative contracts for which we do not elect or do not qualify for hedge accounting. Under the mark-to-market method of accounting, we record the fair value of these derivatives as assets and liabilities, with changes reflected in our consolidated ~~statement~~statements of income. The market prices and quantities used to determine fair value reflect management’s best estimate considering various factors; however, future market prices and actual quantities will vary from those used in recording the derivative asset or liability, and it is possible that such variations could be material.

Commodity Prices

Unregulated Electric - We use derivatives to optimize the value of our unregulated power generation asset. Changes in the fair value for power purchases and sales are recognized on a net basis in operating revenues or cost of sales in the consolidated income statement unless hedge accounting is applied. While our derivative transactions are entered into for the purpose of managing commodity price risk, hedge accounting is only applied where specific criteria are met and it is practicable to do so. In order to apply hedge accounting, the transaction must be designated as a hedge and it must be highly effective in offsetting the hedged risk. Additionally, for hedges of commodity price risk, physical delivery for forecasted commodity transactions must be probable. Transactions that are financially settled are presented on a net basis. For the six months ended June 30, 2008, we recorded unrealized losses in the income statement consistent with the mark-to-market method of accounting discussed above of approximately $6.4 million related to economic hedges where we have locked in forward prices.

Regulated Utilities - Certain contracts for the physical purchase of natural gas associated with our regulated gas utilities do not qualify for normal purchases under SFAS No. 133. Since these contracts are for the purchase of natural gas sold to regulated gas customers, the accounting for these contracts is subject to SFAS No. 71, Accounting for the Effects of Certain Types of Regulations (SFAS No. 71). We use derivative financial instruments to reduce the commodity price risk associated with the purchase price of a portion of our future natural gas requirements and minimize fluctuations in gas supply prices to our regulated customers. We record assets or liabilities based on the fair value of these derivatives, with offsetting positions recorded as regulatory liabilities or regulatory assets on the consolidated balance ~~sheet.~~sheets. Upon settlement of these contracts, associated proceeds or costs are refunded to or collected from our customers consistent with regulatory requirements. At ~~March 31,~~June 30, 2008 we had a derivative asset, included in other current assets in the consolidated balance sheet, and offsetting regulatory liability of ~~$14.0~~$38.4 million.

Interest Rates

During 2006, we issued $170.2 million of Montana Pollution Control Obligations and $150 million of Montana First Mortgage Bonds. In association with these refinancing transactions, we implemented a risk management strategy of utilizing interest rate swaps to manage our interest rate exposures associated with anticipated refinancing transactions. These swaps were designated as cash-flow hedges under SFAS No. 133 with the effective portion of gains and losses, net of associated deferred income tax effects, recorded in accumulated other comprehensive income (AOCI) in our ~~Consolidated Balance Sheets.~~consolidated balance sheets. We settled $320.2 million of forward starting interest rate swap
11
agreements, and received aggregate settlement payments of approximately $14.6 million in 2006. We reclassify these gains from AOCI into interest expense in our ~~Consolidated Statements~~consolidated statements of ~~Income~~income during the periods in which the hedged interest payments occur. AOCI includes unrealized pre-tax gains related to these transactions of ~~$12.5~~$12.2 million and $12.8 million at ~~March 31,~~June 30, 2008 and December 31, 2007, respectively. We expect to reclassify approximately $1.2 million of pre-tax gains on these cash-flow hedges from AOCI into interest expense during the next twelve months. We have no further interest rate swaps outstanding.

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

We evaluate the performance of these segments based on gross margin. The accounting policies of the operating segments are the same as the parent except that the parent allocates some of its operating expenses to the operating segments according to a methodology designed by management for internal reporting purposes and involves estimates and assumptions. Financial data for the business segments, are as follows (in thousands):

Three months ended,

Regulated

Unregulated

Regulated

Unregulated

March 31, 2008

Electric

Gas

Electric

Other

Eliminations

Total

June 30, 2008

Electric

Gas

Electric

Other

Eliminations

Total

Operating revenues

$
196,619

$
171,643

$
20,404

$
7,922

$
(10,613
)
$
385,975

$
178,967

$
80,531

$
16,569

$
8,653

$
(8,214
)
$
276,506

Cost of sales

103,055

121,308

7,032

7,764

(10,075
)
229,084

87,196

49,885

11,624

8,395

(7,746
)
149,354

Gross margin

93,564

50,335

13,372

158

(538
)
156,891

91,771

30,646

4,945

258

(468
)
127,152

Operating, general and administrative

35,370

17,924

3,677

3,638

(538
)
60,071

34,503

15,735

3,219

877

(468
)
53,866

Property and other taxes

16,429

6,328

879

4

—

23,640

14,338

5,484

715

3

—

20,540

Depreciation

15,395

3,883

1,805

8

—

21,091

15,392

4,001

1,823

9

—

21,225

Operating income (loss)

26,370

22,200

7,011

(3,492
)
—

52,089

27,538

5,426

(812
)
(631
)
—

31,521

Interest expense

(9,306
)
(3,230
)
(3,176
)
(368
)
—

(16,080
)

(9,201
)
(3,286
)
(2,993
)
(368
)
—

(15,848
)
Other income

257

309

13

83

—

662

Other income (expense)

376

281

119

(937
)
—

(161
)
Income tax (expense) benefit

(5,687
)
(7,290
)
(1,715
)
1,472

—

(13,220
)

(6,646
)
(873
)
1,561

(51
)
—

(6,009
)
Net income (loss)

$
11,634

$
11,989

$
2,133

$
(2,305
)
$
—

$
23,451

$
12,067

$
1,548

$
(2,125
)
$
(1,987
)
$
—

$
9,503

Total assets

$
1,532,317

$
748,111

$
250,229

$
17,649

$
—

$
2,548,306

$
1,543,185

$
754,213

$
256,036

$
17,219

$
—

$
2,570,653

Capital expenditures

$
10,738

$
2,726

$
493

$
—

$
—

$
13,957

$
18,748

$
9,864

$
518

$
—

$
—

$
29,130

Three months ended,

Regulated

Unregulated

June 30, 2007

Electric

Gas

Electric

Other

Eliminations

Total

Operating revenues

$
170,579

$
62,032

$
14,601

$
16,715

$
(4,319
)
$
259,608

Cost of sales

87,890

36,924

4,205

16,180

(3,944
)
141,255

Gross margin

82,689

25,108

10,396

535

(375
)
118,353

Operating, general and administrative

30,831

16,063

7,536

4,622

(375
)
58,677

Property and other taxes

14,453

5,345

856

6

—

20,660

Depreciation

15,280

4,107

954

452

—

20,793

Operating income (loss)

22,125

(407
)
1,050

(4,545
)
—

18,223

Interest expense

(9,848
)
(3,634
)
(677
)
(368
)
—

(14,527
)
Other income

205

40

6

108

—

359

Income tax (expense) benefit

(4,692
)
1,473

(196
)
1,794

—

(1,621
)
Net income (loss)

$
7,790

$
(2,528
)
$
183

$
(3,011
)
$
—

$
2,434

Total assets

$
1,483,660

$
731,352

$
118,604

$
20,325

$
—

$
2,353,941

Capital expenditures

$
16,156

$
14,681

$
1,301

$
—

$
—

$
32,138

Three months ended,

Regulated

Unregulated

March 31, 2007

Electric

Gas

Electric

Other

Eliminations

Total

Operating revenues

$
178,494

$
158,189

$
22,278

$
16,071

$
(8,467
)
$
366,565

Cost of sales

92,788

115,210

4,236

14,993

(7,949
)
219,278

Gross margin

85,706

42,979

18,042

1,078

(518
)
147,287

Operating, general and administrative

34,508

18,085

8,368

2,005

(518
)
62,448

Property and other taxes

14,191

5,595

779

27

—

20,592

Depreciation

15,378

3,950

416

150

—

19,894

Operating income (loss)

21,629

15,349

8,479

(1,104
)
—

44,353

Interest expense

(9,750
)
(2,852
)
(226
)
(392
)
—

(13,220
)
Other income

176

154

2

46

—

378

Income tax (expense) benefit

(4,465
)
(4,950
)
(3,456
)
502

—

(12,369
)
Net income (loss)

$
7,590

$
7,701

$
4,799

$
(948
)
$
—

$
19,142

Total assets

$
1,475,296

$
726,799

$
118,326

$
20,078

$
—

$
2,340,499

Capital expenditures

$
12,395

$
7,435

$
640

$
—

$
—

$
20,470

12

Six months ended,

Regulated

Unregulated

June 30, 2008

Electric

Gas

Electric

Other

Eliminations

Total

Operating revenues

$
375,586

$
252,174

$
36,973

$
16,575

$
(18,827
)
$
662,481

Cost of sales

190,251

171,193

18,656

16,159

(17,821
)
378,438

Gross margin

185,335

80,981

18,317

416

(1,006
)
284,043

Operating, general and administrative

69,873

33,659

6,896

4,515

(1,006
)
113,937

Property and other taxes

30,767

11,812

1,594

7

—

44,180

Depreciation

30,787

7,884

3,628

17

—

42,316

Operating income (loss)

53,908

27,626

6,199

(4,123
)
—

83,610

Interest expense

(18,459
)
(6,485
)
(6,169
)
(736
)
—

(31,849
)
Other income (expense)

585

559

132

(854
)
—

422

Income tax (expense) benefit

(12,333
)
(8,163
)
(154
)
1,421

—

(19,229
)
Net income (loss)

$
23,701

$
13,537

$
8

$
(4,292
)
$
—

$
32,954

Total assets

$
1,543,185

$
754,213

$
256,036

$
17,219

$
—

$
2,570,653

Capital expenditures

$
29,482

$
12,594

$
1,011

$
—

$
—

$
43,087

Six months ended,

Regulated

Unregulated

June 30, 2007

Electric

Gas

Electric

Other

Eliminations

Total

Operating revenues

$
349,073

$
220,221

$
36,879

$
32,786

$
(12,786
)
$
626,173

Cost of sales

180,679

152,134

8,441

31,173

(11,893
)
360,534

Gross margin

168,394

68,087

28,438

1,613

(893
)
265,639

Operating, general and administrative

65,339

34,148

15,904

6,627

(893
)
121,125

Property and other taxes

28,644

10,941

1,635

32

—

41,252

Depreciation

30,658

8,057

1,370

602

—

40,687

Operating income (loss)

43,753

14,941

9,529

(5,648
)
—

62,575

Interest expense

(19,598
)
(6,486
)
(903
)
(760
)
—

(27,747
)
Other income

381

194

8

154

—

737

Income tax (expense) benefit

(9,156
)
(3,477
)
(3,652
)
2,296

—

(13,989
)
Net income (loss)

$
15,380

$
5,172

$
4,982

$
(3,958
)
$
—

$
21,576

Total assets

$
1,483,660

$
731,352

$
118,604

$
20,325

$
—

$
2,353,941

Capital expenditures

$
28,552

$
22,115

$
1,941

$
—

$
—

$
52,608

13
(9) Earnings Per Share
Basic earnings per share is computed by dividing earnings applicable to common stock by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution of common stock equivalent shares that could occur if all unvested restricted shares were to vest. Common stock equivalent shares are calculated using the treasury stock ~~method, as applicable.~~method. 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:

March 31, 2008

March 31, 2007

Six Months Ended June 30, 2008

Six Months Ended June 30, 2007

Basic computation

38,972,507

35,719,981

38,972,529

35,854,902

Dilutive effect of

Restricted shares

445,331

530,466

448,939

530,655

Stock warrants

—

1,575,428

—

1,469,097

Diluted computation

39,417,838

37,825,875

39,421,468

37,854,654

Three Months Ended June 30, 2008

Three Months Ended
June 30, 2007

Basic computation

38,972,551

35,988,340

Dilutive effect of

Restricted shares

448,939

530,655

Stock warrants

—

1,355,872

Diluted computation

39,421,490

37,874,867

Warrants issued in 2004 were exercisable through the close of business November 1, 2007. A total of ~~194,468~~406,519 warrants were exercised during the ~~three~~six months ended ~~March 31,~~June 30, 2007. Warrants outstanding as of ~~March 31,~~June 30, 2007 of ~~4,312,057~~4,100,006 were dilutive and included in the 2007 earnings per share calculation.
(10) Employee Benefit Plans
Net periodic benefit cost for our pension and other postretirement plans consists of the following for the three and six months ended June 30, 2008 and 2007 (in thousands):

Pension Benefits

Other Postretirement
Benefits

Three Months Ended March 31,

2008

2007

2008

2007

Components of Net Periodic Benefit Cost

Service cost

$
2,170

$
2,289

$
150

$
188

Interest cost

5,726

5,399

611

702

Expected return on plan assets

(6,756
)

(5,823
)

(289
)

(225
)

Amortization of prior service cost

60

60

—

—

Recognized actuarial gain

(141
)

—

(107
)

—

Net Periodic Benefit Cost

$
1,059

$
1,925

$
365

$
665

Pension Benefits

Other Postretirement Benefits

Three Months Ended June 30,

2008

2007

2008

2007

Components of Net Periodic Benefit Cost

Service Cost

$
2,033

$
2,185

$
132

$
102

Interest Cost

5,712

5,501

573

519

Expected return on plan assets

(6,851
)

(6,388
)

(369
)

(310
)

Amortization of prior service cost

63

61

—

—

Recognized actuarial (gain) loss

(268
)

—

(193
)

—

Net Periodic Benefit Cost

$
689

$
1,359

$
143

$
311

14

Pension Benefits

Other Postretirement Benefits

Six Months Ended June 30,

2008

2007

2008

2007

Components of Net Periodic Benefit Cost

Service Cost

$
4,203

$
4,474

$
282

$
290

Interest Cost

11,438

10,900

1,184

1,221

Expected return on plan assets

(13,607
)

(12,211
)

(658
)

(535
)

Amortization of prior service cost

123

121

—

(180
)

Recognized actuarial (gain) loss

(409
)

—

(300
)

—

Net Periodic Benefit Cost

$
1,748

$
3,284

$
508

$
796

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

(11) Regulatory Matters

Federal Energy Regulatory Commission (FERC) Transmission Rate Case - In October 2006, we filed a request with the FERC for an electric transmission revenue increase. Our requested increase pertains only to FERC jurisdictional wholesale transmission and retail choice customers representing approximately $8.6 million in revenue. In May 2007, we implemented interim rates, which are subject to refund plus interest pending final resolution. We filed settlement documents on February 15, 2008 and are awaiting FERC ~~approval, which is expected during the first half of 2008. This proposed settlement would result in an annualized margin~~approval. The interim rate increase ofcontributed approximately ~~$3.0 million. Regulated electric margin~~$0.4 million and $1.1 million for the three and six months ended ~~March 31,~~June 30, 2008, ~~includes approximately $0.9 million from the interim rate increase.~~respectively, to regulated electric margin.

Montana Electric and Natural Gas Rate Case - In July 2007, we filed a request with the Montana Public Service Commission (MPSC) for an electric transmission and distribution revenue increase of $31.4 million, and a natural gas transmission, storage and distribution revenue increase of $10.5 million. In December 2007, we and the Montana Consumer Counsel filed a joint stipulation with the MPSC to settle our electric and natural gas rate cases. Specific terms of the ~~Stipulation~~stipulation include:
An increase in base electric rates of $10 million and base natural gas rates of $5 million;
Interim rates effective January 1, 2008;
Capital investment in our electric and natural gas system totaling $38.8 million to be completed in 2008 and 2009 on which we will not earn a return on, but will recover depreciation expense;
A commitment of 21 MWs of unit contingent power from Colstrip Unit 4 at ~~Mid-C~~Mid-Columbia (Mid-C) Index prices minus $19 per MWH, but not less than zero, to electric supply for a period of 76 months beginning March 1, 2008; and
We will submit a general electric and natural gas rate filing no later than July 31, 2009 based on a 2008 test year.
~~The MPSC has approved interim rates, subject to refund, beginning January~~On July 1, 2008, ~~and we anticipate~~the MPSC approved the stipulated agreement, finalizing the Montana electric and natural gas rate ~~case during~~case.
(12) Financing Activities
During the second quarter of ~~2008. Regulated~~2008, we issued $55 million of South Dakota First Mortgage Bonds at a fixed interest rate of 6.05% maturing May 1, 2018, and used the proceeds to redeem our 7.0%, $55 million South Dakota Mortgage Bonds due August 15, 2023. This transaction will reduce our annual interest expense by approximately $0.5 million.
In addition, we repaid our 5.85%, $7.6 million and 5.9%, $13.8 million South Dakota Pollution Control Bonds maturing in 2023. This transaction will reduce our annual interest expense by approximately $1.3 million.
15
(13) Proposed Colstrip Unit 4 Transaction
In January 2008, we announced that we had retained a financial advisor to assist us in the evaluation of our strategic options related to our 30% ownership interest in Colstrip Unit 4. Options reviewed included selling our ownership through a competitive bid process, putting the asset in rate base in Montana, or retaining the asset and contracting future sales of the plant output. On June 10, 2008, we entered into an agreement to sell our interest in Colstrip Unit 4 for $404 million in cash, subject to certain working capital adjustments. The agreement provides a timeline of 120 days for us to explore the viability of placing this asset into our Montana utility rate base. The agreement also contains certain termination rights for both us and the buyer in which, under specified circumstances, we may be required to pay a termination fee of $6.3 million or the buyer may be required to pay a termination fee of $20 million.
Consistent with these terms, on June 30, 2008, we submitted a filing with MPSC to initiate a review process to determine if it would be in the public interest to place our interest in Colstrip Unit 4 into rate base at an equivalent value to the negotiated selling price including certain adjustments. If the filing with the MPSC is rejected, the electric utility’s regulated supply group will have an option to purchase power at a discount to Mid-C Index prices as existing contracts expire and ~~gas margin~~power becomes available in future years. In addition, the transaction is conditioned upon FERC approval and other customary closing conditions. We expect to complete this process by the end of 2008.
We have evaluated the potential sale of our interest in Colstrip Unit 4 for classification as held for sale under SFAS No. 144, Accounting for the ~~three months ended March 31, 2008 includes approximately $3.4 million from~~Impairment or Disposal of Long-Lived Assets. The held for sale classification only applies to assets where the ~~interim~~sale is subject to terms that are usual and customary for sales of such assets, and the sale of the asset is considered probable. The term probable is used consistent with the meaning associated with it in paragraph 3(a) of SFAS No. 5, Accounting for Contingencies, and refers to a future sale that is "likely to occur." The provisions of the agreement allowing us to explore the rate ~~increase.~~base alternative do not constitute usual and customary terms and the transaction is not considered probable, as defined, due to the uncertainty surrounding this process with the MPSC. We have continued to reflect the assets and results of operations of Colstrip Unit 4 as continuing operations, and will reevaluate our classification as the process progresses.

~~(12)~~ (14) Commitments and Contingencies
Environmental Liabilities
Environmental laws and regulations are continually evolving, and, therefore, the character, scope, cost and availability of the measures we may be required to take to ensure compliance with evolving laws or regulations cannot be accurately predicted. The range of exposure for environmental remediation obligations at present is estimated to range between $19.8 million to $57.0 million. As of ~~March 31,~~June 30, 2008, we have a reserve of approximately ~~$32.2~~$31.2 million. We anticipate that as environmental costs become fixed and reliably determinable, we will seek insurance reimbursement and/or authorization to recover these in rates; therefore, we do not expect these costs to have a material adverse effect on our consolidated financial position, ongoing operations, or cash flows.

The Clean Air Act Amendments of 1990 and subsequent amendments stipulate limitations on sulfur dioxide and nitrogen oxide emissions from coal-fired power plants. We comply with these existing emission requirements through purchase of sub-bituminous coal, and we believe that we are in compliance with all presently applicable environmental protection requirements and regulations with respect to these plants.

Coal-Fired Plants

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

16
Montana has finalized its own rules more stringent than CAMR's 2018 cap that would require every coal-fired generating plant in the state to achieve reduction levels by 2010. The joint owners currently plan to install chemical injection technologies to meet these requirements. We estimate our share of the capital cost would be approximately $1 million, with ongoing annual operating costs of approximately $3 million. If the Montana rules are maintained in their current form and enhanced chemical injection technologies are not sufficiently developed to meet the Montana levels of reduction by 2010, then adsorption/absorption technology with fabric filters at the Colstrip Unit 4 generation facility would be required, which could represent a material cost. Recent tests have shown that it may be possible to meet the Montana rules with more refined chemical injection technology combined with adjustments to boiler/fireball dynamics at a minimal cost. We are continuing to work with the other Colstrip owners to determine the ultimate

financial impact of these rules.
In June 2008 the Sierra Club filed a lawsuit in U.S. District Court in South Dakota against NorthWestern and the other joint owners of the Big Stone plant alleging certain violations of the Clean Air Act. For further discussion see the Litigation – Sierra Club section below.

Manufactured Gas Plants

Approximately ~~$25.6~~$25.4 million of our environmental reserve accrual is related to manufactured gas plants. A formerly operated manufactured gas plant located in Aberdeen, South Dakota, has been identified on the Federal Comprehensive Environmental Response, Compensation, and Liability Information System (CERCLIS) list as contaminated with coal tar residue. We are currently investigating, characterizing, and initiating remedial actions at the Aberdeen site pursuant to work plans approved by the South Dakota Department of Environment and Natural Resources. In 2007, we completed remediation of sediment in a short segment of Moccasin Creek that had been impacted by the former manufactured gas plant operations. Our current reserve for remediation costs at this site is approximately ~~$11.9~~$11.8 million, and we estimate that approximately $10 million of this amount will be incurred during the next five years.

We also own sites in North Platte, Kearney and Grand Island, Nebraska on which former manufactured gas facilities were located. During 2005, the Nebraska Department of Environmental Quality (NDEQ) conducted Phase II investigations of soil and groundwater at our Kearney and Grand Island sites. On March 30, 2006 and May 17, 2006, the NDEQ released to us the Phase II Limited Subsurface Assessment performed by the NDEQ's environmental consulting firm for Kearney and Grand Island, respectively. We have initiated additional site investigation and assessment work at these locations. At present, we cannot determine with a reasonable degree of certainty the nature and timing of any risk-based remedial action at our Nebraska locations.

In addition, we own or have responsibility for sites in Butte, Missoula and Helena, Montana on which former manufactured gas plants were located. An investigation conducted at the Missoula site did not require entry into the Montana Department of Environmental Quality (MDEQ) voluntary remediation program, but required preparation of a groundwater monitoring plan. The Butte and Helena sites were placed into the MDEQ's voluntary remediation program for cleanup due to exceedences of regulated pollutants in the groundwater. We have conducted additional groundwater monitoring at the Butte and Missoula sites and, at this time, we believe natural attenuation should address the problems at these sites; however, additional groundwater monitoring will be necessary. In Helena, we continue limited operation of an oxygen delivery system implemented to enhance natural biodegradation of pollutants in the groundwater and we are currently evaluating limited source area treatment/removal options. Monitoring of groundwater at this site will be necessary for an extended time. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of risk-based remedial action at the Helena site.

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

Milltown Dam Removal

Our subsidiary, Clark Fork and Blackfoot, LLC (CFB), owns the former Milltown Dam site, and previously operated a three MW hydroelectric generation facility located at the confluence of the Clark Fork and Blackfoot Rivers. Dam removal activities were initiated during the first quarter of 2008 and are expected to be complete within a
17
year. ~~We have a~~Our remaining ~~financial~~ obligation ~~of $1.4 million~~ to the State of Montana related to this site is approximately $0.6 million, which will be ~~covered~~ solely funded through ~~a combination of a premium refund upon cancellation of an environmental insurance policy, and~~ the sale or transfer of land and water rights associated with the former Milltown Dam operations.

Other

We continue to manage equipment containing polychlorinated biphenyl (PCB) oil in accordance with the EPA's Toxic Substance Control Act regulations. We will continue to use certain PCB-contaminated equipment for its remaining useful life and will, thereafter, dispose of the equipment according to pertinent regulations that govern the use and disposal of such equipment.

We routinely engage the services of a third-party environmental consulting firm to assist in performing a comprehensive evaluation of our environmental reserve. Based upon information available at this time, we believe that the current environmental reserve properly reflects our remediation exposure for the sites currently and previously owned by us. The portion of our environmental reserve applicable to site remediation may be subject to change as a result of the following uncertainties:

We may not know all sites for which we are alleged or will be found to be responsible for remediation; and
Absent performance of certain testing at sites where we have been identified as responsible for remediation, we cannot estimate with a reasonable degree of certainty the total costs of remediation.

LEGAL PROCEEDINGS

Magten/Law Debenture/QUIPS Litigation

On July 10, 2008 the Delaware Bankruptcy Court approved the global settlement agreement that resolves the Magten and Law Debenture appeals, theMagten v. Certain Current and Former Officers of CFB litigation, the Magten v. Bank of New York litigation and the Magten and Law Debenture v. NorthWestern Corporation and Certain Individuals. 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 (the Plan). In addition, we received a reimbursement of previously incurred legal fees and expenses of $4 million under separate agreements for which no Court approval was requested.
On July 11, 2008, we filed a motion seeking bankruptcy court approval for the purchase of the remaining shares in the disputed claim reserve. The cash from such purchase would be used to make a surplus distribution of all of the remaining assets in the disputed claims reserve to unsecured creditors and debt holders in Class 7 and Class 9 under the Plan, other than the holders of the QUIPS. The motion allows unsecured creditors and debt holders in Class 7 and Class 9 to elect to receive their surplus distribution in stock and accrued dividends or cash. The bankruptcy court approved this motion in July.
Each matter, described below in greater detail, generally related to claims of certain holders of quarterly income preferred securities in our Chapter 11 bankruptcy case.
Magten and Law Debenture v. NorthWestern Corporation - ~~On April 16, 2004,~~ Magten Asset Management Corporation (Magten) and Law Debenture Trust Company (Law Debenture) initiated an adversary proceeding, which we ~~refer~~referred to as the QUIPS Litigation, against NorthWestern seeking among other things, to void the transfer of certain assets and liabilities of CFB to us. In essence, Magten and Law Debenture ~~are asserting~~asserted that the transfer of the transmission and distribution assets acquired from the Montana Power Company was a fraudulent conveyance because it allegedly left CFB insolvent and unable to pay certain claims. The plaintiffs also ~~assert~~asserted that they ~~are~~were creditors of CFB as a result of Magten owning a portion of the Series A 8.45% Quarterly Income Preferred Securities (QUIPS) for which Law Debenture serves as the Indenture Trustee. Plaintiffs ~~seek,~~sought , among other things, the avoidance of the transfer of assets, declaration that the assets were fraudulently transferred and ~~are~~were not NorthWestern’s property, the imposition
18
of constructive trusts over the transferred assets and the return of such assets to CFB. On July 18, 2007, the Delaware District Court extended the discovery schedule and scheduled the trial for March 2008; however, the trial date has been adjourned pending the Delaware Bankruptcy Court’s consideration of a comprehensive settlement, discussed below. The parties have entered into a comprehensive settlement and release agreement, dated March 17, 2008 (the Magten Settlement), which would resolve the QUIPS Litigation and other disputes. A motion to approve the Magten Settlement is scheduled to be heard by the Delaware Bankruptcy Court on May 7, 2008. We have and will continue to vigorously defend against the QUIPS litigation in the event the Magten Settlement does not become effective.

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

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

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

Magten and Law Debenture v. NorthWestern Corporation and Certain Individuals - On April 15, 2005, Magten and Law Debenture filed an adversary complaint in the Bankruptcy Court against NorthWestern and certain former and current officers and directors seeking to revoke the Confirmation Order of NorthWestern’s Plan on the grounds that it was procured by fraud as a result of the alleged failure to adequately fund the Class 9 Disputed Claims Reserve with enough shares of new common stock to satisfy a potential full recovery on all disputed claims against NorthWestern's bankruptcy estate which were outstanding at the time the Plan became effective on November 1, 2004. The plaintiffs also alleged breach of fiduciary duty on the part of certain former and current officers in connection with the alleged under-funding of the Disputed Claims Reserve. NorthWestern filed a motion to dismiss or stay the litigation and on July 26, 2005, the Bankruptcy Court ordered a stay of the litigation pending resolution of Magten's appeal of the Order confirming the Plan. The Magten Settlement would resolve this litigation; however, NorthWestern intends to seek dismissal of this action and to the extent such action is not dismissed, NorthWestern intends to vigorously defend this action in the event the Magten Settlement does not become effective.
As indicated above, the Magten Settlement would effectuate a “global” resolution of all the currently pending claims and litigation arising out of our bankruptcy proceeding involving Magten, NorthWestern, CFB, the Plan Committee, BNY and other interested persons. If it is approved and becomes effective, the Magten Settlement would be funded using shares from the Class 9 Disputed Claims Reserve and payments from NorthWestern’s former attorneys and insurance proceeds.
On April 1, 2008, the Ad Hoc Committee filed an objection to the Magten Settlement. The Ad Hoc Committee is comprised of: Basso Capital Management; Bond Street Capital, LLC; Willow Fund, LLC; Franklin Mutual Advisers, LLC; FrontPoint Partners; and Stonehill Capital Management LLC . Such objection also purports to be a late-filed objection to the Plan Committee Settlement which provides for reimbursement of certain of NorthWestern’s defense costs related to the Magten litigation as well as certain Plan Committee and BNY defense costs related to the Magten litigation. A hearing on the two settlement agreements is currently scheduled for May 7, 2008. We cannot currently predict if the Magten Settlement will be approved and become effective; however, our view is that the plaintiffs' claims with respect to the QUIPs Litigation should be treated as general unsecured, or Class 9, claims which would, in either case, be satisfied, in the event they are allowed, out of the Disputed Claims Reserve established under the Plan.

McGreevey Litigation

We are one of several defendants in a class action lawsuit entitled McGreevey, et al. v. The Montana Power Company, et al, now pending in U.S. District Court in Montana. The lawsuit, which was filed by former shareholders of The Montana Power Company (most of whom became shareholders of Touch America Holdings, Inc. as a result of a corporate reorganization of The Montana Power Company), contends that the disposition of various generating and energy-related assets by The Montana Power Company are void because of the failure to obtain shareholder approval for the transactions. Plaintiffs thus seek to reverse those transactions, or receive fair value for their stock as of late 2001, when plaintiffs claim shareholder approval should have been sought. NorthWestern is named as a defendant due to the fact that we purchased The Montana Power L.L.C. (now CFB), which plaintiffs claim is a successor to the Montana Power Company.

We are one of the defendants in a second class action lawsuit brought by the McGreevey plaintiffs, also entitled McGreevey, et al. v. The Montana Power Company, et al., pending in U.S. District Court in Montana. This lawsuit, like the Magten litigation described above, seeks, among other things, the avoidance of the transfer of assets from CFB to us, declaration that the assets were fraudulently transferred and are not property of our bankruptcy estate, the imposition of constructive trusts over the transferred assets, and the return of such assets to CFB.

In June 2006, we and the McGreevey plaintiffs entered into an agreement to settle all claims brought by the McGreevey plaintiffs in all of the actions described above, wherein the McGreevey plaintiffs executed a covenant not to execute against us, and we quit claimed any interest we had in any claims we may or may not have under any applicable directors and officers liability insurance policy, against any insurers for contractual or extracontractual damages, and against certain defendants in the McGreevey lawsuits. In November 2006, this agreement was approved by the Delaware Bankruptcy Court and the claims were discharged. We filed a joint motion with the plaintiffs' attorneys in U.S. District Court in Montana to dismiss the claims against us in the McGreevey lawsuits. On March 16, 2007, the U.S. District Court in Montana denied the motion to dismiss us from the McGreevey lawsuits, questioning the benefits of the settlement to be received by the class members in the settlement and the authority of the plaintiffs' counsel to have negotiated the settlement without a class having been certified by the court. On January 11, 2008, the U.S. District Court in Montana suggested that the settlement agreement was invalid because the plaintiffs' attorneys had not secured the court's permission to engage in settlement discussions. The District Court enjoined the plaintiffs from taking any further action in any of these matters. The plaintiffs appealed the District Court’s January 11^th
19
injunction to the Ninth Circuit U.S. Court of Appeals, where on July 10, 2008, the Ninth Circuit U.S. Court of Appeals heard oral arguments; a determination is pending. We do not anticipate a resolution of this litigation before class representatives and class counsel are approved by the U.S. District Court in Montana. However, we believe that given the scope of the Order confirming the Plan and the injunctions issued by the Delaware Bankruptcy Court which channeled the claims to the D&O Trust, we have limited exposure to the plaintiffs for damages arising from the McGreevey claims. We will continue to vigorously defend against these claims and explore ways to remove ourselves from the lawsuits.

City of Livonia

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

Ammondson

In April 2005, a group of former employees of the Montana Power Company filed a lawsuit in the state court of Montana against us and certain officers styled Ammondson, et al. v. NorthWestern Corporation, et al., Case No. DV-05-97. The former employees have alleged that by moving to terminate their supplemental retirement contracts in our bankruptcy proceeding without having listed them as claimants or giving them notice of the disclosure statement and Plan, that we breached those contracts, and breached a covenant of good faith and fair dealing under Montana law and by virtue of filing a complaint in our Bankruptcy Case against those employees from seeking to prosecute their state court action against NorthWestern, we had engaged in malicious prosecution and should be subject to punitive damages. In 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 in a case called Ammondson, et al. v. NorthWestern Corporation, et al. Due to the verdict, we recognized a loss of $19.0 million in our 2006 results of operations to increase our recorded liability related to this claim. The Montana state court reviewed the amount of the punitive damages under state law and did not alter the amount. We have appealed the judgment to the Montana Supreme Court and posted a $25.8 million bond. We intend to vigorously pursue the appeal; however, there can be no assurance that we will prevail in our efforts. Interest accrues on the verdict amount during the appeal ~~process, and we expect to incur additional legal and court costs related to these proceedings.~~process.

Sierra Club
On June 10, 2008, Sierra Club filed a complaint in the U.S. District Court for the District of South Dakota (Northern Division) against the Company and two other co-owners (the Defendants) of Big Stone Generating Station (Big Stone). The complaint alleges 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 alleges that the Defendants modified and operated
20
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. Plaintiff alleges that Defendants’ actions have contributed to air pollution and visibility impairment and have increased the risk of adverse health effects and environmental damage. Plaintiff seeks 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. Plaintiff also seeks unspecified civil penalties, including a beneficial mitigation project. We believe that these claims are without merit and that Big Stone has been and is being operated in compliance with the Clean Air Act and the South Dakota SIP. The ultimate outcome of these matters cannot be determined at this time.
Other Litigation and Contingencies
FERC Investigation

During the second quarter of 2007, we voluntarily informed the FERC of several potential regulatory compliance issues related to our natural gas business. The FERC ~~has initiated a nonpublic, informal investigation. We cannot currently predict~~is conducting an ongoing investigation into these matters. Based on our current assessment we do not anticipate the outcome of the ~~FERC's investigation.~~FERC’s investigation will have a material adverse effect on our financial position.
Colstrip Energy Limited Partnership

In December 2006, the MPSC issued an order finalizing certain qualifying facility rates for the periods July 1, 2003 through June 30, 2006. Colstrip Energy Limited Partnership (CELP) is a qualifying facility with which we have a power purchase agreement through 2025. Under the terms of the power purchase agreement with CELP, energy and capacity rates were fixed through June 30, 2004 (with a small portion to be set by the MPSC's determination of rates in the annual avoided cost filing), and beginning July 1, 2004 through the end of the contract, energy and capacity rates are to be determined each year pursuant to a formula. CELP filed a complaint against NorthWestern and the MPSC in Montana district court on July 6, 2007 which contests the MPSC’s order. CELP is disputing inputs in to the rate-setting formula, used by us and approved by the MPSC on an annual basis, to calculate energy and capacity payments for the contract years 2004, 2005 and 2006. CELP is claiming that NorthWestern breached the power purchase agreement causing damages, which CELP asserts are not presently known but believed to be approximately $22 million for contract years 2004, 2005 and 2006. If the MPSC's order is upheld in its current form, we anticipate reducing our QF liability by approximately $25 to $50 million as our estimate of energy and capacity rates for the remainder of the contract period would be reduced. A temporary restraining order was agreed to by the parties and has been issued restraining us from implementing the rates finalized by the MPSC order pending aan ultimate decision on CELP's ~~request for~~complaint. On June 30, 2008, the state district court judge granted our motions to enforce the contractual arbitration provision and to stay all discovery and proceedings against NorthWestern Energy, pending the decision of the required contract arbitration. The state district court, on June 30, 2008, also granted a ~~preliminary injunction.~~motion by the MPSC to bifurcate, having the effect of separating the issues between contract/tort claims and the administrative appeal of the MPSC’s orders; which we supported. The order also stayed the appellate decision pending a decision in our arbitration proceedings. We believe ~~CELP has no basis for their complaint~~that we will prevail in the arbitration and intend to vigorously defend ~~this action. On January 24, 2008, we commenced~~our positions. Concurrently, an adversary proceeding against CELP requesting a declaratory judgment has been sought by us in the Delaware Bankruptcy ~~Court seeking a declaration that no prior order of~~Court. On July 10, 2008, the ~~Delaware~~ Bankruptcy Court ~~either limited or curtailed~~held a hearing and verbally advised the ~~rate setting authority of the MPSC. On February 25,~~parties that they are to settle a scheduling order which provides for briefing and a July 30, 2008 ~~CELP filed a~~hearing on CELP’s motion to ~~dismiss~~stay the ~~adversary proceeding and on April 7, 2008, NorthWestern timely filed its objection to that motion. A hearing on the motion to dismiss our adversary proceeding at CELP has not yet been scheduled.~~proceedings.
Colstrip Unit 4 Coal Royalties

Relative to our joint ownership in Colstrip Unit 4, the Mineral Management Service of the United States Department of Interior (MMS) issued two orders to Western Energy Company (WECO) in 2002 and 2003 to pay additional royalties concerning coal sold to Colstrip Units 3 and 4 owners. The orders assert that additional royalties are owed as a result of WECO not paying royalties in connection with revenue received by WECO from the Colstrip Units 3 and 4 owners under a coal transportation agreement during the period October 1, 1991 through December 31, 2001. On April 28, 2005, the appeals division of the MMS issued an order that reduced the amount claimed based upon the applicable statute of limitations. The ~~state~~State of Montana issued a demand to WECO in May 2005 consistent with the MMS position outlined above on these transportation revenues. Further, on September 28, 2006, the MMS issued an order to pay additional royalties on the basis of an audit of WECO's royalty payments during the three years
21
2002 to 2004. WECO appealed these orders to the Interior Board of Land Appeals of the United States Department of Interior (IBLA) who affirmed the orders on September 12, 2007. WECO filed a complaint and request for declaratory ruling in the US District Court for the District of Columbia in January 2008 seeking relief from the orders issued by the MMS and affirmed by the IBLA, and we continue to monitor the appeals process. The Colstrip Units 3 and 4 owners and WECO currently dispute the responsibility of the expenses if the MMS position prevails. We believe that the Colstrip Units 3 and 4 owners have reasonable defenses in this matter. However, if the MMS position prevails and WECO succeeds in passing the expense responsibility to the owners, our share of the alleged additional royalties would be 15 percent, or approximately $6.0 million, and we would have ongoing royalty expenses related to coal transportation. While the percentage of our share of the alleged additional royalties is not expected to change, the estimated amount may increase as the MMS updates its assessment to reflect ongoing royalty and interest expenses.

Blue Dot Arbitration
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 $3.4 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. Blue Dot has approximately $300,000 in remaining cash and will likely need to liquidate through a bankruptcy filing. 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.
MPSC Investigation
During the first quarter of 2008, the MPSC opened a proceeding to investigate our compliance with a 2004 MPSC order limiting our ability to provide loans, guarantees, advances, equity investments or working capital to subsidiaries or affiliates. This proceeding is in response to an MCC complaint that we violated the MPSC’s order when we purchased our previously leased interests in Colstrip Unit 4. We have provided documentation to the MPSC that we did not violate their order. The investigation is ongoing and we do not anticipate the outcome will have a material adverse effect, if any, on our financial position.
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 actions will not materially affect our financial position, results of operations, or cash flows.

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22
~~ITEM 2.~~
ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

OVERVIEW

NorthWestern Corporation, doing business as Northwestern Energy, provides electricity and natural gas to approximately 650,000 customers in Montana, South Dakota and Nebraska. For a discussion of NorthWestern’s business strategy, see Management’s Discussion and Analysis in our Annual Report on Form 10-K for the year ended December 31, 2007.

Highlights

~~Highlights for the three months ended March 31, 2008~~Recent highlights include:
Improved net income of ~~$4.3~~$7.1 million as compared with the ~~first~~second quarter of 2007 due to higher margins as discussed below;
Began trading on the New York Stock Exchange beginning May 1, 2008;
Announced a share buyback program for approximately 3.1 million shares, equal to the number of shares in our disputed claim reserve;
Concluded our review of strategic options related to our interest in Colstrip Unit 4 by signing a purchase and sale agreement with Bicent (Montana) Power Company LLC (Bicent) for $404 million in cash. The agreement allows us to explore the viability of placing the asset in rate base;
Obtained approval of the stipulated agreement in our Montana electric and natural gas rate case filings by the MPSC;
~~Upgrade~~Secured an upgrade of our senior secured and senior unsecured ~~and long-term corporate~~ credit ratings ~~from~~by Moody’s Investors Service (Moody’s), giving us an investment grade credit rating with each of the three independent credit-rating agencies that rate us, including Fitch Investors Service (Fitch) and Standard and Poor’s Rating Group (S&P)~~, resulting~~; and
Received approval of the settlement with Magten by the Bankruptcy Court, which resolves the last significant claim in our bankruptcy case and provides for reimbursement of previously incurred legal fees and expenses of $4 million.
Proposed Colstrip Unit 4 Transaction
In January 2008, we announced that we had retained a ~~decrease~~financial advisor to assist us in the evaluation of our strategic options related to our 30% ownership interest in Colstrip Unit 4. Options reviewed included selling our ownership through a competitive bid process, putting the asset in rate ~~commitment~~base in Montana, or retaining the asset and contracting future sales of the plant output. On June 10, 2008, we entered into an agreement to sell our interest in Colstrip Unit 4 for $404 million in cash, subject to certain working capital adjustments. The agreement provides a timeline of 120 days for us to explore the viability of placing this asset into our Montana utility rate base. The agreement also contains certain termination rights for both us and the buyer in which, under specified circumstances, we may be required to pay a termination fee of $6.3 million or the buyer may be required to pay a termination fee of $20 million.
Consistent with these terms, on June 30, 2008, we submitted a filing with MPSC to initiate a review process to determine if it would be in the public interest to place our interest in Colstrip Unit 4 into rate base at an equivalent value to the negotiated selling price including certain adjustments. If the filing with the MPSC is rejected, the electric utility’s regulated supply group will have an option to purchase power at a discount to Mid-C Index prices as existing contracts expire and power becomes available in future years. In addition, the transaction is conditioned upon FERC approval and other customary closing conditions. We expect to complete this process by the end of 2008.
Magten Settlement
In July 2008, the US Bankruptcy Court approved a settlement agreement between NorthWestern, Magten Asset
23
Management (Magten), Law Debenture Trust Company of New York (Law Debenture) and the Plan Committee that resolves the litigation related to claims of holders of quarterly income preferred securities (QUIPS) in our Chapter 11 bankruptcy case. On July 23, 2008 the Ad Hoc Committee filed an appeal to the global settlement agreement, however, we and the other parties involved waived a closing condition and closed on the settlement on July 24, 2008. Under the approved global settlement agreement Magten, Law Debenture, their lawyers and the holders of the QUIPS, collectively received a cash payment of $23 million to be allocated amongst them in accordance with the terms of the global settlement agreement. The cash payment was funded by our repurchase of 782,059 shares held in the disputed claims reserve established under our confirmed Plan of Reorganization. This settlement resolves the last significant claim from the bankruptcy case, and also provided for reimbursement of previously incurred legal fees and ~~removal~~expenses of ~~certain covenants associated with our revolver.~~$4 million. See Note 14 – Legal Proceedings for further discussion.

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OVERALL CONSOLIDATED RESULTS
The following is a summary of our results of operations for the three and six months ended ~~March 31,~~June 30, 2008 and 2007. Our consolidated results include the results of our divisions and subsidiaries constituting each of our business segments. This discussion is followed by a more detailed discussion of operating results by segment.
Three Months Ended ~~March 31,~~June 30, 2008 Compared with the Three Months Ended ~~March 31,~~June 30, 2007

Three Months Ended March 31,

Three Months Ended June 30,

2008

2007

Change

% Change

2008

2007

Change

% Change

(in millions)

(in millions)

Operating Revenues

Regulated Electric

$
196.7

$
178.5

$
18.2

10.2

%

$
179.0

$
170.6

$
8.4

4.9

%
Regulated Natural Gas

171.6

158.2

13.4

8.5

80.5

62.0

18.5

29.8

Unregulated Electric

20.4

22.3

(1.9
)
(8.5
)

16.5

14.6

1.9

13.0

Other

7.9

16.1

(8.2
)
(50.9
)

8.7

16.7

(8.0
)
(47.9
)

Eliminations

(10.6
)

(8.5
)

(2.1
)
(24.7
)

(8.2
)

(4.3
)

(3.9
)
(90.7
)

$
386.0

$
366.6

$
19.4

5.3

%

$
276.5

$
259.6

$
16.9

6.5

%

Three Months Ended March 31,

Three Months Ended June 30,

2008

2007

Change

% Change

2008

2007

Change

% Change

(in millions)

(in millions)

Cost of Sales

Regulated Electric

$
103.1

$
92.8

$
10.3

11.1

%

$
87.2

$
87.9

$
(0.7
)
(0.8
)
%
Regulated Natural Gas

121.3

115.2

6.1

5.3

49.9

36.9

13.0

35.2

Unregulated Electric

7.0

4.3

2.7

62.8

11.6

4.2

7.4

176.2

Other

7.8

15.0

(7.2
)
(48.0
)

8.4

16.2

(7.8
)
(48.1
)

Eliminations

(10.1
)

(8.0
)

(2.1
)
(26.3
)

(7.8
)

(4.0
)

(3.8
)
(95.0
)

$
229.1

$
219.3

$
9.8

4.5

%

$
149.3

$
141.2

$
8.1

5.7

%

Three Months Ended March 31,

Three Months Ended June 30,

2008

2007

Change

% Change

2008

2007

Change

% Change

(in millions)

(in millions)

Gross Margin

Regulated Electric

$
93.6

$
85.7

$
7.9

9.2

%

$
91.8

$
82.7

$
9.1

11.0

%
Regulated Natural Gas

50.3

43.0

7.3

17.0

30.6

25.1

5.5

21.9

Unregulated Electric

13.4

18.0

(4.6
)
(25.6
)

4.9

10.4

(5.5
)
(52.9
)

Other

0.1

1.1

(1.0
)
(90.9
)

0.3

0.5

(0.2
)
(40.0
)

Eliminations

(0.5
)

(0.5
)

—

—

(0.4
)

(0.3
)

(0.1
)
(33.3
)

$
156.9

$
147.3

$
9.6

6.5

%

$
127.2

$
118.4

$
8.8

7.4

%

25
Consolidated gross margin ~~was $156.9 million~~ for the three months ended ~~March 31,~~June 30, 2008 was $127.2 million, an increase of ~~$9.6~~$8.8 million, or ~~6.5%~~7.4%, ~~from~~as compared with gross margin of $118.4 million in the ~~same period~~second quarter of 2007. The following summarizes components of the change:

Gross Margin

Gross Margin

2008 vs. 2007

2008 vs. 2007

(Millions of Dollars)

(Millions of Dollars)

Rate increases

$
4.9

Regulated electric and gas volumes

$
6.4

3.0

Montana regulated electric and gas interim rate increase (subject to refund)

3.4

South Dakota and Nebraska regulated gas rate increase

1.7

Transmission volumes and rate increase (subject to refund)

0.9

Regulated electric QF supply costs

3.9

Regulated electric wholesale

2.0

Unregulated electric volumes

2.6

5.2

Unregulated electric pricing and fuel supply costs

(7.2
)

(5.5
)
Unregulated electric unrealized loss on forward contracts

(5.2
)
Other

1.8

0.5

Improvement in Gross Margin

$
9.6

$
8.8

~~Higher~~Improvements in gross margin were due to regulated electric and gas ~~margin was due primarily to an increase~~rate increases, increases in volumes from customer growth and ~~colder weather, as well as~~usage, and lower qualifying facility (QF) supply costs based on actual QF pricing and output. In addition, we had improved electric wholesale margin due to increased plant availability. These improvements were partially offset by an ~~increase in rates~~. ~~These increases were offset in part by a~~overall decrease in our unregulated electric ~~margin.~~margin primarily due to a combination of lower average contracted prices and an increase in unrealized losses on forward contracts due to changes in forward prices of electricity. These forward contracts economically hedge a portion of our Colstrip Unit 4 output through 2009. The unrealized losses will reverse as the power is delivered and the underlying transactions are executed.

Three Months Ended March 31,

Three Months Ended June 30,

2008

2007

Change

% Change

2008

2007

Change

% Change

(in millions)

(in millions)

Operating Expenses

Operating, general and administrative

$
60.1

$
62.4

$
(2.3
)
(3.7
)
%

$
53.9

$
58.7

$
(4.8
)
(8.2
)
%
Property and other taxes

23.6

20.6

3.0

14.6

20.5

20.6

(0.1
)
(0.5
)

Depreciation

21.1

19.9

1.2

6.0

21.2

20.8

0.4

1.9

$
104.8

$
102.9

$
1.9

1.8

%

$
95.6

$
100.1

$
(4.5
)
(4.5
)
%

Consolidated operating, general and administrative expenses were ~~$60.1~~$53.9 million for the three months ended ~~March 31,~~June 30, 2008 as compared ~~to $62.4~~with $58.7 million ~~from~~in the ~~first~~second quarter of 2007.

Operating, General & Administrative Expenses

Operating, General & Administrative Expenses

2008 vs. 2007

2008 vs. 2007

(Millions of Dollars)

(Millions of Dollars)

Operating lease expense

$
(4.9
)

$
(3.6
)
Legal and professional fees

2.8

(4.5
)
Other

(0.2
)

3.3

Reduction in Operating, General & Administrative Expenses

$
(2.3
)

$
(4.8
)

The reduction in operating, general and administrative expenses of ~~$2.3~~$4.8 million was primarily due to decreased operating lease expense related to the purchase of our previously leased interest in Colstrip Unit 4 during 2007 (we expect operating lease expense to decrease $14.4 million in 2008)~~. This reduction was partly offset by higher~~ and lower legal and professional fees, which ~~included a~~includes the reversal of the $1.8 million judgment related to the City of Livonia shareholder ~~litigation.~~litigation that was previously recorded in the first quarter of 2008 due to an insurance recovery. In July 2008, we received a reimbursement of previously incurred legal fees in connection with the Magten settlement discussed above. This
26
receipt will reduce our operating, general and administrative expenses by $4.0 million during the third quarter of 2008.

Property and other taxes ~~were $23.6~~remained flat, with $20.5 million for the three months ended ~~March 31,~~June 30, 2008 as compared to $20.6 million in the ~~first~~second quarter of 2007. Property ~~and other taxes increased by approximately $1.8 million during the first quarter of 2008. In addition, property and other~~ taxes in 2007 are net of approximately ~~$1.2~~$1.7 million collected through our Montana property tax tracker.
Depreciation expense was ~~$21.1~~$21.2 million for the three months ended ~~March 31,~~June 30, 2008 as compared with ~~$19.9~~$20.8 million in the ~~first~~second quarter of 2007. The increase was primarily due to the purchase of our previously leased interest in Colstrip Unit 4.

Consolidated operating income for the three months ended ~~March 31,~~June 30, 2008 was ~~$52.1~~$31.5 million, as compared with ~~$44.4~~$18.2 million in the ~~first~~second quarter of 2007. This ~~$7.7~~$13.3 million increase was ~~primarily~~ due to the ~~$9.6~~$8.8 million increase in gross margin ~~partly offset by higher~~and lower operating expenses as discussed above.

Consolidated interest expense for the three months ended ~~March 31,~~June 30, 2008 was ~~$16.1~~$15.8 million, an increase of ~~$2.9~~$1.3 million, or ~~22.0%~~9.0%, from the ~~first~~second quarter of 2007. This increase was primarily related to the additional debt incurred with the purchase of our previously leased interest in Colstrip Unit 4.

Consolidated income tax expense for the three months ended ~~March 31,~~June 30, 2008 was ~~$13.2~~$6.0 million as compared with ~~$12.4~~$1.6 million in the ~~first~~second quarter of 2007. Our effective tax rate for 2008 was ~~36.0%~~38.7% as compared to ~~39.2%~~39.0% for 2007. ~~Portions of our professional fees and transaction related costs in 2007 were non-deductible for tax purposes, which increased our projected annual effective tax rate.~~ While we reflect an income tax provision in our financial statements, we expect our cash payments for income taxes will be minimal through at least 2010, based on our anticipated use of net operating losses.

Consolidated net income for the three months ended ~~March 31,~~June 30, 2008 was ~~$23.5~~$9.5 million as compared with $2.4 million for the second quarter of 2007. This increase was primarily due to improved margins.
Six Months Ended June 30, 2008 Compared with the Six Months Ended June 30, 2007

Six Months Ended June 30,

2008

2007

Change

% Change

(in millions)

Operating Revenues

Regulated Electric

$
375.6

$
349.1

$
26.5

7.6

%
Regulated Natural Gas

252.2

220.2

32.0

14.5

Unregulated Electric

37.0

36.8

0.2

0.5

Other

16.5

32.8

(16.3
)
(49.7
)

Eliminations

(18.8
)

(12.8
)

(6.0
)
(46.9
)

$
662.5

$
626.1

$
36.4

5.8

%

Six Months Ended June 30,

2008

2007

Change

% Change

(in millions)

Cost of Sales

Regulated Electric

$
190.3

$
180.7

$
9.6

5.3

%
Regulated Natural Gas

171.2

152.1

19.1

12.6

Unregulated Electric

18.7

8.4

10.3

122.6

Other

16.1

31.2

(15.1
)
(48.4
)

Eliminations

(17.8
)

(11.9
)

(5.9
)
(49.6
)

$
378.5

$
360.5

$
18.0

5.0

%
27

Six Months Ended June 30,

2008

2007

Change

% Change

(in millions)

Gross Margin

Regulated Electric

$
185.3

$
168.4

$
16.9

10.0

%
Regulated Natural Gas

81.0

68.1

12.9

18.9

Unregulated Electric

18.3

28.4

(10.1
)
(35.6
)

Other

0.4

1.6

(1.2
)
(75.0
)

Eliminations

(1.0
)

(0.9
)

(0.1
)
(11.1
)

$
284.0

$
265.6

$
18.4

6.9

%
Consolidated gross margin was $284.0 million for the six months ended June 30, 2008, an increase of $18.4 million, or 6.9%, from gross margin in the same period of 2007. The following summarizes components of the change:

Gross Margin

2008 vs. 2007

(Millions of Dollars)

Rate increases

$
10.6

Regulated electric and gas volumes

10.0

Regulated electric QF supply costs

3.5

Regulated electric wholesale

2.6

Unregulated electric volumes

8.1

Unregulated electric pricing and fuel supply costs

(11.8
)
Unregulated electric unrealized loss on forward contracts

(6.4
)
Other

1.8

Improvement in Gross Margin

$
18.4

Improvements in regulated electric and gas margin were due to an increase in rates, an increase in volumes from customer growth and usage, and lower qualifying facility (QF) supply costs based on actual QF pricing and output. In addition, we had improved electric wholesale margin due to increased plant availability. These improvements were partially offset by an overall decrease in our unregulated electric margin primarily due to a combination of lower average contracted prices and an unrealized loss on forward contracts as discussed above.

Six Months Ended June 30,

2008

2007

Change

% Change

(in millions)

Operating Expenses

Operating, general and administrative

$
113.9

$
121.1

$
(7.2
)
(5.9
)
%
Property and other taxes

44.2

41.3

2.9

7.0

Depreciation

42.3

40.7

1.6

3.9

$
200.4

$
203.1

$
(2.7
)
(1.3
)
%
Consolidated operating, general and administrative expenses were $113.9 million for the six months ended June 30, 2008 as compared with $121.1 million in the same period of 2007.

Operating, General & Administrative Expenses

2008 vs. 2007

(Millions of Dollars)

Operating lease expense

$
(8.5
)
Legal and professional fees

(1.7
)
Other

3.0

Reduction in Operating, General & Administrative Expenses

$
(7.2
)
28
The reduction in operating, general and administrative expenses of $7.2 million was primarily due to decreased operating lease expense related to the purchase of our previously leased interest in Colstrip Unit 4 during 2007 (we expect operating lease expense to decrease $14.4 million in 2008) and lower legal and professional fees.
Property and other taxes were $44.2 million for the six months ended June 30, 2008 as compared to $41.3 million in the same period of 2007. Property taxes in 2007 are net of approximately $2.9 million collected through our Montana property tax tracker.
Depreciation expense was $42.3 million for the six months ended June 30, 2008 as compared with $40.7 million in the same period of 2007. The increase was primarily due to the purchase of our previously leased interest in Colstrip Unit 4.
Consolidated operating income for the six months ended June 30, 2008 was $83.6 million, as compared with $62.6 million in the same period of 2007. This $21.0 million increase was due to the $18.4 million increase in gross margin and lower operating expenses as discussed above.
Consolidated interest expense for the six months ended June 30, 2008 was $31.8 million, an increase of $4.1 million, or 14.8%, from the same period of 2007. This increase was primarily related to the additional debt incurred with the purchase of our previously leased interest in Colstrip Unit 4.
Consolidated income tax expense for the six months ended June 30, 2008 was $19.2 million as compared with $14.0 million in the same period of 2007. Our effective tax rate for 2008 was 38.7% as compared to 39.0% for 2007.
Consolidated net income for the six months ended June 30, 2008 was $33.0 million compared with ~~$19.1~~$21.6 million for the ~~first quarter~~same period of 2007. This increase was primarily due to higher operating income offset by higher interest and income tax expense as discussed above.

REGULATED ELECTRIC ~~MARGIN~~SEGMENT
Three Months Ended ~~March 31,~~June 30, 2008 Compared with the Three Months Ended ~~March 31,~~June 30, 2007

Results

2008

2007

Change

% Change

(in millions)

Total Revenues

196.7

178.5

18.2

10.2

Total Cost of Sales

103.1

92.8

10.3

11.1

Gross Margin

$
93.6

$
85.7

$
7.9

9.2

%
% GM/Rev

47.6
%

48.0
%

Results

2008

2007

Change

% Change

(in millions)

Total Revenues

179.0

170.6

8.4

4.9

Total Cost of Sales

87.2

87.9

(0.7
)
(0.8
)

Gross Margin

$
91.8

$
82.7

$
9.1

11.0

%
% GM/Rev

51.3
%

48.5
%

The following summarizes the components of the changes in regulated electric margin for the three months ended ~~March 31,~~June 30, 2008 and 2007:

Gross Margin

2008 vs. 2007

(Millions of Dollars)

Customer growth and colder weather

$
4.0

Montana jurisdiction transmission and distribution interim rate increase (subject to refund)

2.2

FERC jurisdiction transmission interim rate increase (subject to refund)

0.9

Wholesale and other

0.8

Improvement in Gross Margin

$
7.9

Gross Margin

2008 vs. 2007

(Millions of Dollars)

QF supply costs

$
3.9

Montana jurisdiction transmission and distribution rate increase

2.6

Wholesale

2.0

Customer growth and usage

0.5

FERC jurisdiction transmission interim rate increase (subject to refund)

0.4

Transmission volumes

(0.9
)
Other

0.6

Improvement in Gross Margin

$
9.1

~~The~~
29
This improvement is ~~primarily~~ due to ~~an interim increase in transmission~~the annual adjustment of our QF related supply costs to reflect actual QF pricing and ~~distribution rates in Montana and increased volumes from 1.5% customer growth and colder weather. Also contributing to the margin increase~~output, which was ~~an interim increase in~~lower than our ~~FERC jurisdiction transmission rates~~estimate; rate increases; and slightly higher wholesale margin due to increased plant availability. Lower transmission volumes with less demand to transmit energy for others across our lines partly offset these increases.

The following summarizes regulated electric volumes and customer counts for the three months ended ~~March 31,~~June 30, 2008 and 2007:

Volumes MWH

2008

2007

Change

% Change

(in thousands)

Retail Electric

Montana

668

635

33

5.2

%

South Dakota

160

148

12

8.1

Residential

828

783

45

5.7

Montana

799

788

11

1.4

South Dakota

222

203

19

9.4

Commercial

1,021

991

30

3.0

Industrial

761

735

26

3.5

Other

24

24

—

—

Total Retail Electric

2,634

2,533

101

4.0

%

Wholesale Electric

35

32

3

9.4

%

Volumes MWH

2008

2007

Change

% Change

(in thousands)

Retail Electric

Montana

498

461

37

8.0

%

South Dakota

105

103

2

1.9

Residential

603

564

39

6.9

Montana

756

754

2

0.3

South Dakota

200

193

7

3.6

Commercial

956

947

9

1.0

Industrial

773

746

27

3.6

Other

38

45

(7
)
(15.6
)

Total Retail Electric

2,370

2,302

68

3.0

%

Wholesale Electric

82

33

49

148.5

%

Average Customer Counts

2008

2007

Change

% Change

Retail Electric

Montana

265,820

262,209

3,611

1.4

%

South Dakota

47,882

47,603

279

0.6

Residential

313,702

309,812

3,890

1.3

Montana

59,449

58,106

1,343

2.3

South Dakota

11,522

11,373

149

1.3

Commercial

70,971

69,479

1,492

2.1

Industrial

71

70

1

1.4

Other

5,559

5,699

(140
)
(2.5
)

Total Retail Electric

390,303

385,060

5,243

1.4

%

Average Customer Counts

2008

2007

Change

% Change

Retail Electric

Montana

266,104

262,172

3,932

1.5

%

South Dakota

47,908

47,666

242

0.5

Residential

314,012

309,838

4,174

1.3

Montana

59,148

57,719

1,429

2.5

South Dakota

11,331

11,185

146

1.3

Commercial

70,479

68,904

1,575

2.3

Industrial

72

71

1

1.4

Other

4,653

4,593

60

1.3

Total Retail Electric

389,216

383,406

5,810

1.5

%
2008ascomparedto:
CoolingDegree-Days
2007
HistoricAverage
Montana
37% colder
21% colder
South Dakota
84% colder
75% colder

Regulated electric volumes increased due primarily to customer ~~growth and colder weather.~~growth. Regulated wholesale electric volumes increased due to increased plant availability as compared with 2007. Although the weather in our service territories was significantly colder than the prior year, our customer usage is not highly sensitive to these changes during the shoulder months between the heating and cooling seasons.

30
Six Months Ended June 30, 2008 Compared to the Six Months Ended June 30, 2007

Results

2008

2007

Change

% Change

(in millions)

Total Revenues

375.6

349.1

26.5

7.6

Total Cost of Sales

190.3

180.7

9.6

5.3

Gross Margin

$
185.3

$
168.4

$
16.9

10.0

%
% GM/Rev

49.3
%

48.2
%

The following summarizes the components of the changes in regulated electric margin for the six months ended June 30, 2008 and 2007:

Gross Margin

2008 vs. 2007

(Millions of Dollars)

Customer growth, usage and colder weather

$
5.0

Montana jurisdiction transmission and distribution rate increase

4.7

QF supply costs

3.5

Wholesale

2.6

FERC jurisdiction transmission interim rate increase (subject to refund)

1.1

Transmission volumes

(0.9
)
Other

0.9

Improvement in Gross Margin

$
16.9

This improvement is primarily due to rate increases and increased volumes from customer growth, usage and colder weather, lower QF supply costs as discussed above, and improved wholesale margin due to increased plant availability. Lower transmission volumes with less demand to transmit energy for others across our lines partly offset these increases.
The following summarizes regulated electric volumes and customer counts for the six months ended June 30, 2008 and 2007:

Volumes MWH

2008

2007

Change

% Change

(in thousands)

Retail Electric

Montana

1,167

1,096

71

6.5

%

South Dakota

264

251

13

5.2

Residential

1,431

1,347

84

6.2

Montana

1,555

1,542

13

0.8

South Dakota

422

396

26

6.6

Commercial

1,977

1,938

39

2.0

Industrial

1,534

1,480

54

3.6

Other

63

70

(7
)
(10.0
)

Total Retail Electric

5,005

4,835

170

3.5

%

Wholesale Electric

131

65

66

101.5

%
31
Average Customer Counts

2008

2007

Change

% Change

Retail Electric

Montana

265,962

262,191

3,771

1.4

%

South Dakota

47,895

47,634

261

0.5

Residential

313,857

309,825

4,032

1.3

Montana

59,299

57,912

1,387

2.4

South Dakota

11,427

11,279

148

1.3

Commercial

70,726

69,191

1,535

2.2

Industrial

71

71

—

—

Other

5,106

5,146

(40
)
(0.8
)

Total Retail Electric

389,760

384,233

5,527

1.4

%
2008ascomparedto:
CoolingDegree-Days
2007
HistoricAverage
Montana
37% colder
21% colder
South Dakota
84% colder
75% colder
Regulated electric volumes increased due primarily to customer growth, usage and colder weather during the first quarter of 2008. Regulated wholesale electric volumes increased due to increased plant availability as compared with 2007. There are no cooling degree days in the first three months of the year in our service territories; therefore, cooling degree-days are the same for the three and six months ended June 30, 2008.
REGULATED NATURAL GAS ~~MARGIN~~SEGMENT
Three Months Ended ~~March 31,~~June 30, 2008 Compared with the Three Months Ended ~~March 31,~~June 30, 2007

Results

Results

2008

2007

Change

% Change

2008

2007

Change

% Change

(in millions)

(in millions)

Total Revenues
Total Revenues

171.6

158.2

13.4

8.5

Total Revenues

80.5

62.0

18.5

29.8

Total Cost of Sales
Total Cost of Sales

121.3

115.2

6.1

5.3

Total Cost of Sales

49.9

36.9

13.0

35.2

Gross Margin
Gross Margin

$
50.3

$
43.0

$
7.3

17.0

%

Gross Margin

$
30.6

$
25.1

$
5.5

21.9

%

% GM/Rev
% GM/Rev

29.3
%

27.2
%

% GM/Rev

38.0
%

40.5
%

The following summarizes the components of the changes in regulated natural gas margin for the three months ended ~~March 31,~~June 30, 2008 and 2007:

Gross Margin

2008 vs. 2007

(Millions of Dollars)

Colder weather and customer growth

$
2.4

South Dakota and Nebraska jurisdictions transportation and distribution
rate increase

1.7

Montana jurisdiction transportation and distribution interim rate increase
(subject to refund)

1.2

Transfer of previously unregulated customers

0.7

Storage

0.4

Other

0.9

Improvement in Gross Margin

$
7.3

Gross Margin

2008 vs. 2007

(Millions of Dollars)

Colder weather and customer growth

$
3.4

South Dakota and Nebraska jurisdictions transportation and distribution rate increase

1.1

Montana jurisdiction transportation and distribution rate increase

0.8

Storage

0.2

Improvement in Gross Margin

$
5.5

~~The~~This improvement is primarily due to ~~an increase in our transportation and distribution rates and~~ increased volumes due to colder weather and ~~1.4%~~1.3% customer growth. In addition, $0.7 million of the increase is due to the transfer of certain previously unregulated customers and pipelines into the regulated business and $0.4 million from higher storage utilization.growth, along with rate increases.

32
The following summarizes regulated natural gas volumes, customer counts and heating degree-days for the three months ended ~~March 31,~~June 30, 2008 and 2007:

Volumes Dekatherms

2008

2007

Change

% Change

(in thousands)

Retail Gas

Montana

5,568

5,035

533

10.6

%

South Dakota

1,607

1,526

81

5.3

Nebraska

1,405

1,382

23

1.7

Residential

8,580

7,943

637

8.0

Montana

2,757

2,528

229

9.1

South Dakota

1,378

1,181

197

16.7

Nebraska

1,284

1,224

60

4.9

Commercial

5,419

4,933

486

9.9

Industrial

119

73

46

63.0

Other

54

88

(34
)
(38.6
)

Total Retail Gas

14,172

13,037

1,135

8.7

%

Volumes Dekatherms

2008

2007

Change

% Change

(in thousands)

Retail Gas

Montana

2,523

1,955

568

29.1

%

South Dakota

589

466

123

26.4

Nebraska

526

412

114

27.7

Residential

3,638

2,833

805

28.4

Montana

1,234

981

253

25.8

South Dakota

542

434

108

24.9

Nebraska

596

483

113

23.4

Commercial

2,372

1,898

474

25.0

Industrial

16

24

(8
)
(33.3
)

Other

29

20

9

45.0

Total Retail Gas

6,055

4,775

1,280

26.8

%

Average Customer Counts

2008

2007

Change

% Change

Retail Gas

Montana

155,758

152,938

2,820

1.8

%

South Dakota

36,912

36,890

22

0.1

Nebraska

36,888

36,773

115

0.3

Residential

229,558

226,601

2,957

1.3

Montana

21,685

21,185

500

2.4

South Dakota

5,839

5,795

44

0.8

Nebraska

4,593

4,584

9

0.2

Commercial

32,117

31,564

553

1.8

Industrial

306

318

(12
)
(3.8
)

Other

141

139

2

1.4

Total Retail Gas

262,122

258,622

3,500

1.4

%
Average Customer Counts

2008

2007

Change

% Change

Retail Gas

Montana

155,546

152,968

2,578

1.7

%

South Dakota

36,498

36,527

(29
)
(0.1
)

Nebraska

36,344

36,109

235

0.7

Residential

228,388

225,604

2,784

1.2

Montana

21,770

21,308

462

2.2

South Dakota

5,760

5,732

28

0.5

Nebraska

4,519

4,513

6

0.1

Commercial

32,049

31,553

496

1.6

Industrial

305

312

(7
)
(2.2
)

Other

139

141

(2
)
(1.4
)

Total Retail Gas

260,881

257,610

3,271

1.3

%

2008 as compared with:

Heating Degree-Days

2007

Historic Average

Montana

8%25% colder

~~Remained flat~~10% colder

South Dakota

4%36% colder

2%12% colder

Nebraska

4%44% colder
10% colder
Regulated natural gas volumes increased due to colder weather and customer growth.
33
Six Months Ended June 30, 2008 Compared to the Six Months Ended June 30, 2007

Results

2008

2007

Change

% Change

(in millions)

Total Revenues

252.2

220.2

32.0

14.5

Total Cost of Sales

171.2

152.1

19.1

12.6

Gross Margin

$
81.0

$
68.1

$
12.9

18.9

%

% GM/Rev

32.1
%

30.9
%

The following summarizes the components of the changes in regulated natural gas margin for the six months ended June 30, 2008 and 2007:

Gross Margin

2008 vs. 2007

(Millions of Dollars)

Colder weather and customer growth

$
5.9

South Dakota and Nebraska jurisdictions transportation and distribution rate increase

2.8

Montana jurisdiction transportation and distribution rate increase

2.0

Transfer of previously unregulated customers

0.7

Storage

0.6

Other

0.9

Improvement in Gross Margin

$
12.9

This improvement is primarily due to increased volumes due to colder weather and 1.3% customer growth along with rate increases.
34
The following summarizes regulated natural gas volumes, customer counts and heating degree-days for the six months ended June 30, 2008 and 2007:

Volumes Dekatherms

2008

2007

Change

% Change

(in thousands)

Retail Gas

Montana

8,091

6,989

1,102

15.8

%

South Dakota

2,196

1,992

204

10.2

Nebraska

1,931

1,794

137

7.6

Residential

12,218

10,775

1,443

13.4

Montana

3,991

3,510

481

13.7

South Dakota

1,920

1,615

305

18.9

Nebraska

1,880

1,707

173

10.1

Commercial

7,791

6,832

959

14.0

Industrial

136

96

40

41.7

Other

82

108

(26
)
(24.1
)

Total Retail Gas

20,227

17,811

2,416

13.6

%
Average Customer Counts

2008

2007

Change

% Change

Retail Gas

Montana

155,652

152,953

2,699

1.8

%

South Dakota

36,706

36,708

(2
)
—

Nebraska

36,616

36,441

175

0.5

Residential

228,974

226,102

2,872

1.3

Montana

21,728

21,247

481

2.3

South Dakota

5,799

5,764

35

0.6

Nebraska

4,556

4,548

8

0.2

Commercial

32,083

31,559

524

1.7

Industrial

306

315

(9
)
(2.9
)

Other

139

140

(1
)
(0.7
)

Total Retail Gas

261,502

258,116

3,386

1.3

%
2008ascomparedwith:
HeatingDegree-Days
2007
HistoricAverage
Montana
14% colder

3% colder

South Dakota
11% colder
5% colder
Nebraska
12% colder
5% colder

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

35
UNREGULATED ELECTRIC ~~MARGIN~~SEGMENT
Three Months Ended ~~March 31,~~June 30, 2008 Compared with the Three Months Ended ~~March 31,~~June 30, 2007
Our unregulated electric segment primarily consists of our joint ownership in the Colstrip Unit 4 generation facility, which represents approximately 30%. or approximately 222 MWs at full load. We sell our Colstrip Unit 4 output ~~approximately 222 MWs at full load,~~ principally to two unrelated third parties under agreements through December 2010. Under a separate agreement we repurchase 111 MWs through December 2010. These 111 MWs were available for market sales to other third parties through June 2007. Beginning July 1, 2007, 90 MWs of base-load energy from Colstrip Unit 4 are being supplied to the Montana electric supply load (included in our regulated electric segment) for a term of 11.5 years at an average nominal price of $35.80 per MWH. In addition, 21 MWs of base-load energy from Colstrip Unit 4 are being provided ~~on an interim basis~~ to the Montana electric supply load for a term of 76 months beginning in March 2008 at $19 per MWH below the Mid-C ~~index~~Index price with a floor of ~~zero, pending approval of the proposed stipulation in Montana.~~zero.

Results

Results

2008

2007

Change

% Change

2008

2007

Change

% Change

(in millions)

(in millions)

Total Revenues
Total Revenues

20.4

22.3

(1.9
)
(8.5
)

Total Revenues

16.5

14.6

1.9

13.0

Total Cost of Sales
Total Cost of Sales

7.0

4.3

2.7

62.8

Total Cost of Sales

11.6

4.2

7.4

176.2

Gross Margin
Gross Margin

$
13.4

$
18.0

$
(4.6
)
(25.6
)
%

Gross Margin

$
4.9

$
10.4

$
(5.5
)
(52.9
)
%

% GM/Rev

65.7
%

80.7
%

% GM/Rev

29.7
%

71.2
%

The following summarizes the components of the changes in unregulated electric margin for the three months ended ~~March 31,~~June 30, 2008 and 2007:

Gross Margin

Gross Margin

2008 vs. 2007

2008 vs. 2007

(Millions of Dollars)

(Millions of Dollars)

Volumes

$
2.6

$
5.2

Average prices

(5.3
)

(3.2
)
Mark to market loss

(1.2
)
Unrealized loss on forward contracts

(5.2
)
Fuel supply costs

(0.7
)

(2.3
)
Decline in Gross Margin

$
(4.6
)

$
(5.5
)

The decrease in margin was primarily due to lower average contracted prices and higher fuel supply costs. In addition, we recorded an unrealized loss of ~~$1.2~~$5.2 million during the ~~first~~second quarter of 2008 ~~related to~~on forward contracts ~~executed during the period~~due to changes in forward prices of electricity. These contracts economically hedge a portion of our Colstrip Unit 4 output through ~~2009. These contracts~~2009, and do not qualify for hedge accounting, ~~and~~therefore market value adjustments ~~will be~~are included in ~~Cost~~cost of ~~Sales on a quarterly basis, however these~~sales. The unrealized losses will reverse as the power is ~~delivered.~~delivered and the underlying transactions are executed. An increase in volumes from higher plant availability partly offset these decreases.

The following summarizes unregulated electric volumes for the three months ended ~~March 31,~~June 30, 2008 and 2007:

Volumes MWH

2008

2007

Change

% Change

(in thousands)

Wholesale Electric

476

428

48

11.2

%

Volumes MWH

2008

2007

Change

% Change

(in thousands)

Wholesale Electric

416

307

109

35.5

%

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

We expect our margin to decrease throughout 2008 under the terms of our Colstrip Unit 4 commitments to Montana regulated electric supply discussed above. See the Overview section for additional information related to our Colstrip Unit 4 strategic review process.
36
Six Months Ended June 30, 2008 Compared to the Six Months Ended June 30, 2007

Results

2008

2007

Change

% Change

(in millions)

Total Revenues

37.0

36.8

0.2

0.5

Total Cost of Sales

18.7

8.4

10.3

122.6

Gross Margin

$
18.3

$
28.4

$
(10.1
)
(35.6
)
%

% GM/Rev

49.5
%

77.2
%

The following summarizes the components of the changes in unregulated electric margin for the six months ended June 30, 2008 and 2007:

Gross Margin

2008 vs. 2007

(Millions of Dollars)

Volumes

$
8.1

Average prices

(8.8
)
Unrealized loss on forward contracts

(6.4
)
Fuel supply costs

(3.0
)
Decline in Gross Margin

$
(10.1
)
The decrease in margin was primarily due to lower average contracted prices and higher fuel supply costs. In addition, as discussed above, we recorded an unrealized loss of $6.4 million during the first six months of 2008 related to economic hedges due to changes in ~~January 2008, we retained a financial advisor to assist us~~forward prices of electricity. An increase in ~~evaluating our strategic options with respect to our joint ownership of Colstrip Unit 4.~~volumes from higher plant availability partly offset these decreases.

The following summarizes unregulated electric volumes for the six months ended June 30, 2008 and 2007:

Volumes MWH

2008

2007

Change

% Change

(in thousands)

Wholesale Electric

891

735

156

21.2

%
The increase in energy available to sell as compared with 2007 was due to increased plant availability.
37
LIQUIDITY AND CAPITAL RESOURCES
We utilize our revolver availability to manage our cash flows due to the seasonality of our business, and utilize any cash on hand in excess of current operating requirements to reduce borrowings. As of ~~March 31,~~June 30, 2008, we had cash and cash equivalents of ~~$33.8~~$24.2 million, and revolver availability of ~~$173.9~~$178.4 million. During the ~~three~~six months ended ~~March 31,~~June 30, 2008, we ~~repaid $30.0~~used existing cash to repay $42.9 million of debt, ~~including $12.0 million on our revolver,~~ paid dividends on common stock of ~~$12.9~~$25.7 million, property tax payments of $42.8 million and contributed $21.9 million to our pension plans.
Factors Impacting our Liquidity
Our operations are subject to seasonal fluctuations in cash flow. During the heating season, which is primarily from November through March, cash receipts from natural gas sales and transportation services typically exceed cash requirements. During the summer months, cash on hand, together with the seasonal increase in cash flows and utilization of our existing revolver, are used to purchase natural gas to place in storage, perform maintenance and make capital improvements.
The effect of this seasonality on our liquidity is also impacted by changes in the market prices of our electric and natural gas supply, which is recovered through various monthly cost tracking mechanisms. These energy supply tracking mechanisms are designed to provide stable and timely recovery of supply costs on a monthly basis during the July to June annual tracking period, with an adjustment in the following annual tracking period to correct for any under or over collection in our monthly trackers. Due to the lag between our purchases of electric and natural gas commodities and revenue receipt from customers, cyclical over and under collection situations arise consistent with the seasonal fluctuations discussed above; therefore we usually under collect in the fall and winter and over collect in the spring. Fluctuations in recoveries under our cost tracking mechanisms, which do not impact net income, can have a significant effect on cash flow from operations and make year-to-year comparisons difficult.

As of ~~March 31,~~June 30, 2008, we are over collected on our current Montana natural gas and electric trackers by approximately ~~$12.7~~$35.7 million, as compared with an over collection of ~~$3.7~~$20.7 million as of ~~March 31,~~June 30, 2007. This over collection is primarily due to increases in our electric supply rates during 2007 based on higher forward contracted prices. This has the effect of phasing in the supply cost increases over two years.

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

Three Months Ended
March 31,

Six Months Ended
June 30,

2008

2007

2008

2007

Operating Activities

Net income
$
23.5

$
19.1

$
33.0

$
21.6

Noncash adjustments to net income

35.2

34.0

Non-cash adjustments to net income

73.0

58.3

Changes in working capital

30.4

46.2

27.0

66.0

Other

(11.1
)

4.8

(8.4
)

(9.7
)

78.0

104.1

124.6

136.2

Investing Activities

Property, plant and equipment additions

(14.0
)

(20.5
)

(43.1
)

(52.6
)
Sale of assets

—

0.1

—

0.6

Colstrip Unit 4 acquisition

—

(40.2
)

—

(40.2
)

(14.0
)

(60.6
)

(43.1
)

(92.2
)
Financing Activities

Net repayment of debt

(30.0
)

(37.6
)

(42.9
)

(33.9
)
Dividends on common stock

(12.9
)

(11.1
)

(25.7
)

(22.3
)
Other

(0.1
)

4.8

(1.5
)

10.3

(43.0
)

(43.9
)

(70.1
)

(45.9
)

Net Increase (Decrease) in Cash and Cash Equivalents
$
21.0

$
(0.4
)
$
11.4

$
(1.9
)
Cash and Cash Equivalents, beginning of period
$
12.8

$
1.9

$
12.8

$
1.9

Cash and Cash Equivalents, end of period
$
33.8

$
1.5

$
24.2

$
—

38

Cash Provided Byby Operating Activities
As of ~~March 31,~~June 30, 2008, cash and cash equivalents were ~~$33.8~~$24.2 million, as compared with $12.8 million at December 31, 2007 and ~~$1.5 million~~no cash and cash equivalents at ~~March 31,~~June 30, 2007. Cash provided by operating activities totaled ~~$78.0~~$124.6 million for the ~~three~~six months ended ~~March 31,~~June 30, 2008 as compared with ~~$104.1~~$136.2 million during the ~~three~~six months ended ~~March 31,~~June 30, 2007. This decrease in operating cash flows iswas primarily related to ~~a change in~~the timing of ~~the funding of our pension plans to the first quarter of 2008 from the second quarter of 2007, and other changes in working capital. The change in working capital was due to lower~~accounts receivable collections, associated with the recovery of energy supply costs in the first quarter of 2008 as compared with 2007, which is discussed above in the “Factors Impacting Our Liquidity” section, and increased purchases of electricity in our South Dakota jurisdiction due to outages in the fourth quarter of 2007 at one of our jointly owned plants, partially offset by ~~the timing~~decreased purchases of ~~our semi-annual Colstrip Unit 4 lease payment in 2007.~~storage gas and higher net income.
Cash Used in Investing Activities
Cash used in investing activities totaled ~~$14.0~~$43.1 million during the ~~three~~six months ended ~~March 31,~~June 30, 2008, as compared with ~~$60.6~~$92.2 million during the ~~three~~six months ended ~~March 31,~~June 30, 2007. During the ~~first quarter of~~six months ended June 30, 2008 we invested ~~$14.0~~$43.1 million in property, plant and equipment ~~additions.~~additions as compared with $52.6 million in 2007. In ~~the first quarter of~~addition, in 2007 we used $40.2 million to complete the purchase of ~~the Owner Participant interest in~~ a portion of our previously leased interest in the Colstrip Unit 4 generating ~~facility, and $20.5 million for property, plant and equipment additions.~~facility.
Cash Used in Financing Activities
Cash used in financing activities totaled ~~$43.0~~$70.1 million during the ~~three~~six months ended ~~March 31,~~June 30, 2008, as compared with ~~$43.9~~$45.9 million during the ~~three~~six months ended ~~March 31,~~June 30, 2007. During the ~~first quarter of~~six months ended June 30, 2008 we have made net debt repayments of ~~$30.0~~$42.9 million and paid dividends on common stock of ~~$12.9 million, as compared with~~$25.7 million. During the six months ended June 30, 2007 we made debt repayments of ~~$37.6~~$33.9 million and paid dividends on common stock of ~~$11.1 million in the first quarter of 2007.~~$22.3 million.
Sources and Uses of Funds
We believe that our cash on hand, operating cash flows, and borrowing capacity, taken as a whole, provide sufficient resources to fund our ongoing operating requirements, debt maturities, anticipated dividends and estimated future capital expenditures during the next twelve months. As of ~~April 18,~~July 25, 2008, our availability under our revolving line of credit was approximately ~~$174.9~~$180.7 million.
We announced a common stock repurchase program during the second quarter 2008, which allows us to repurchase approximately 3.1 million shares. This amount is equal to the number of shares in the disputed claims reserve established under our Plan of Reorganization that was confirmed by the bankruptcy court in 2004. We anticipate using approximately $75 million to $80 million to repurchase these shares during the remainder of 2008. There were no purchases during the second quarter of 2008.

39
Contractual Obligations and Other Commitments

We have a variety of contractual obligations and other commitments that require payment of cash at certain specified periods. The following table summarizes our contractual cash obligations and commitments as of ~~March 31,~~June 30, 2008. See our Annual Report on Form 10-K for the year ended December 31, 2007 for additional discussion.

Total

2008

2009

2010

2011

2012

Thereafter

Total

2008

2009

2010

2011

2012

Thereafter

(in thousands)

(in thousands)

Long-term Debt

$
776,212

$
15,590

$
120,045

$
23,605

$
6,578

$
3,792

$
606,602

$
763,717

$
9,684

$
120,045

$
23,605

$
6,578

$
3,792

$
600,013

Capital Leases

39,877

1,885

1,273

1,174

1,265

1,363

32,917

39,248

1,282

1,246

1,174

1,265

1,363

32,918

Future Minimum Operating
Lease Payments

4,237

1,292

1,127

727

513

436

142

4,403

860

1,394

992

609

444

104

Estimated Pension and Other Postretirement
Obligations (1)

88,300

3,100

22,200

22,600

21,500

18,900

N/A

87,300

2,100

22,200

22,600

21,500

18,900

N/A

Qualifying Facilities (2)

1,504,073

44,892

61,586

63,589

65,323

67,111

1,201,572

1,489,468

30,287

61,586

63,589

65,323

67,111

1,201,572

Supply and Capacity Contracts (3)

1,901,140

431,679

410,731

322,362

151,787

129,849

454,732

1,887,669

333,081

487,719

343,225

138,632

130,572

454,440

Contractual Interest Payments on Debt (4)

376,102

33,648

42,283

36,949

34,798

34,385

194,039

334,792

22,135

40,602

36,203

34,052

33,639

168,161

Total Commitments(5)

$
4,689,941

$
532,086

$
659,245

$
471,006

$
281,764

$
255,836

$
2,490,004

Total Commitments (5)

$
4,606,597

$
399,429

$
734,792

$
491,388

$
267,959

$
255,821

$
2,457,208

(1)
We have ~~only~~ estimated cash obligations related to our pension and other postretirement benefit programs for five years, as it is not practicable to estimate thereafter.
(2)
The ~~Qualifying Facilities (QFs)~~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 $1.5 billion. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $1.2 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 22 years.
(4)
Contractual interest payments include an assumed average interest rate of 3.9% on the $100 million floating rate nonrecourse loan through maturity in December 2009 and no revolver borrowings.
(5)
Potential tax payments related to uncertain tax positions are not practicable to estimate and have been excluded from this table.

40
Credit Ratings
Fitch, ~~Investors Service (Fitch),~~ Moody’s ~~Investors Service (Moody’s)~~ and S&P are independent credit-rating agencies that rate our debt securities. These ratings indicate the agencies’ assessment of our ability to pay interest and principal when due on our debt. As of ~~April 18,~~July 25, 2008, our current ratings with these agencies are as follows:

Senior Secured
Rating

Senior Unsecured
Rating

Corporate Rating

Outlook

Fitch (1)

BBB

BBB-

BBB-

~~Stable~~Positive

Moody’s ~~(1)~~(2)
Baa2

Baa3
~~Ba2~~

N/A

~~Stable~~Positive

S&P ~~(2)~~(3)

A- (MT)
BBB+ (SD)

BBB-

BBB

Stable

(1)
~~Moody’s has announced we are currently~~Fitch changed our outlook from stable to positive on ~~review for an upgrade.~~June 23, 2008.
(2)
Moody’s upgraded our senior secured and senior unsecured credit ratings on July 9, 2008 from Baa3 and Ba2, respectively, as reflected above.
(3)
S&P upgraded our senior secured, senior unsecured, and corporate credit ratings during the first quarter of 2008 from BBB, BB-, and BB+, respectively, as reflected above.

In general, less favorable credit ratings make debt financing more costly and more difficult to obtain on terms that are economically favorable to us and impacts our trade credit availability.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Management’s discussion and analysis of financial condition and results of operations is based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We base our estimates on historical experience and other assumptions that are believed to be proper and reasonable under the circumstances.
As of ~~March 31,~~June 30, 2008, there have been no significant changes with regard to the critical accounting policies disclosed in Management’s Discussion and Analysis in our Annual Report on Form 10-K for the year ended December 31, 2007. The policies disclosed included the accounting for the following: goodwill and long-lived assets, qualifying facilities liability, revenue recognition, regulatory assets and liabilities, pension and postretirement benefit plans, and income taxes. We continually evaluate the appropriateness of our estimates and assumptions. Actual results could differ from those estimates.
41

ITEM3.
QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
We are exposed to market risks, including, but not limited to, interest rates, energy commodity price volatility, and credit exposure. Management has established comprehensive risk management policies and procedures to manage these market risks.
Interest Rate Risk

We utilize various risk management instruments to reduce our exposure to market interest rate changes. These risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financings. All of our debt has fixed interest rates, with the exception of our revolver and the Colstrip Lease Holdings ~~LLC~~ (CLH) $100 million loan. The revolving credit facility bears interest at a variable rate ~~(approximately 3.57%~~(currently approximately 3.67% as of ~~March 31,~~June 30, 2008) tied to the London Interbank Offered Rate (LIBOR) plus a credit spread. The CLH loan currently bears interest at approximately ~~3.94%~~4.04%, which is 1.25% over LIBOR. Based upon amounts outstanding as of ~~March 31,~~June 30, 2008, a 1% increase in the LIBOR would increase our annual interest expense by approximately $1.0 million.
Commodity Price Risk

Commodity price risk is one of our most significant risks due to our lack of ownership of natural gas reserves or regulated electric generation assets within the Montana market, and our unregulated joint ownership interest in Colstrip Unit 4. Several factors influence price levels and volatilities. These factors include, but are not limited to, seasonal changes in demand, weather conditions, available generating assets within regions, transportation availability and reliability within and between regions, fuel availability, market liquidity, and the nature and extent of current and potential federal and state regulations.

As part of our overall strategy for fulfilling our regulated electric supply requirements, we employ the use of market purchases, including forward purchase and sales contracts. These types of contracts are included in our electric supply portfolio and are used to manage price volatility risk by taking advantage of seasonal fluctuations in market prices. While we may incur gains or losses on individual contracts, the overall portfolio approach is intended to provide price stability for consumers; therefore, these commodity costs are included in our cost tracking mechanisms.

In our unregulated electric segment we use forward contracts to manage our exposure to the market price of electricity. We have entered into unit-contingent forward contracts for the sale of a significant portion of the output. In addition, we have economically hedged a portion of our output through 2009. As of ~~March 31,~~June 30, 2008 market prices exceeded our contracted forward sales prices by approximately ~~$1.2~~$6.4 million. These market value adjustments will reverse as the power is delivered.

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

Counterparty Credit Risk

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

42
ITEM4.
CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures

We conducted an evaluation, under the supervision and with the participation of our principal executive officer and principal financial officer of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934). Based on this evaluation, our principal executive officer and principal financial officer have concluded that, as of the end of the period covered by this report, our disclosure controls and procedures are effective.
Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting during the three months ended ~~March 31,~~June 30, 2008 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

43
PART II. OTHER INFORMATION

ITEM1.
LEGAL PROCEEDINGS
See Note ~~12,~~14, Commitments and Contingencies, to the Consolidated Financial Statements for information about legal proceedings.

ITEM 1A.
RISK FACTORS
You should carefully consider the risk factors described below, as well as all other information available to you, before making an investment in our shares or other securities.
The agreement to sell our interest in Colstrip Unit 4 to Bicent will only be completed if certain conditions are met, including review of the option to place the asset in rate base and various federal regulatory approvals. We may not be able to obtain an equivalent selling price yielding the same economic value if the transaction is not completed.
On June 10, 2008, we entered into an agreement to sell our interest in Colstrip Unit 4 for $404 million in cash, subject to certain working capital adjustments. The agreement provides a timeline of 120 days for us to explore the viability of placing this asset into our Montana utility rate base. Consistent with these terms, on June 30, 2008, we submitted a filing with MPSC to initiate a review process to determine if it would be in the public interest to place our interest in Colstrip Unit 4 into rate base at an equivalent value to the negotiated selling price. If the MPSC does not include the asset in our Montana utility rate base as requested in the filing, we intend to complete the sale of Colstrip 4 pursuant to the terms of the purchase agreement. However, consummation of the sale is subject to significant conditions, and if those conditions are not fulfilled, or if Bicent (Montana) Power Company, the purchaser, does not perform its obligations under the purchase agreement, we may not be able to obtain a selling price equivalent to the current agreement.
We ~~have incurred,~~are subject to extensive governmental laws and ~~may continue to incur, significant costs associated with outstanding litigation, which may adversely~~regulations that affect our ~~results of~~industry and our operations, ~~and cash flows.~~

~~These costs,~~ which ~~are being expensed as incurred,~~could have ~~had, and may continue to have, an~~a material adverse ~~affect~~effect on our results of operations and ~~cash flows. Pending litigation matters~~financial condition.

We are ~~discussed~~subject to regulation by federal and state governmental entities, including the FERC, MPSC, South Dakota Public Utilities Commission and Nebraska Public Service Commission. Regulations can affect allowed rates of return, recovery of costs and operating requirements. In addition, existing regulations may be revised or reinterpreted, new laws, regulations, and interpretations thereof may be adopted or become applicable to us and future changes in ~~detail under the Legal Proceedings section~~laws and regulations may have a detrimental effect on our business.

Our rates are approved by our respective commissions and are effective until new rates are approved. In addition, supply costs are recovered through adjustment charges that are periodically reset to reflect current and projected costs. Inability to recover costs in ~~Note 12 to the Consolidated Financial Statements. An adverse result in any of these matters~~rates or adjustment clauses could have ana material adverse effect on our ~~business.~~cash flow and financial position.

We are subject to extensive environmental laws and regulations and potential environmental liabilities, which could result in significant costs and liabilities.

We are subject to extensive laws and regulations imposed by federal, state and local government authorities in the ordinary course of operations with regard to the environment, including environmental laws and regulations relating to air and water quality, solid waste disposal and other environmental considerations. We believe that we are in substantial compliance with environmental regulatory requirements and that maintaining compliance with current requirements will not materially affect our financial position or results of operations; however, possible future developments, including the promulgation of more stringent environmental laws and regulations, such as the new mercury emissions rules in Montana, and the timing of future enforcement proceedings that may be taken by environmental authorities could affect the costs and the manner in which we conduct our business and could require us to make substantial additional capital expenditures.

In addition to the requirements related to the mercury emissions rules noted above, there is a growing concern nationally and internationally about global climate change and the contribution of emissions of greenhouse gases including, most significantly, carbon dioxide. This concern has led to increased interest in legislation at the federal level, actions at the state level, as well as litigation relating to greenhouse emissions, including a recent US Supreme Court decision holding that the EPA has the authority to regulate carbon dioxide emissions from motor vehicles under the Clean Air Act. Increased pressure for carbon dioxide emissions reduction also is coming from investor

organizations. If legislation or regulations are passed at the federal or state levels imposing mandatory reductions of carbon dioxide and other greenhouse gases on generation facilities, the cost to us of such reductions could be significant.

Many of these environmental laws and regulations create permit and license requirements and provide for substantial civil and criminal fines which, if imposed, could result in material costs or liabilities. We cannot predict with certainty the occurrence of private tort allegations or government claims for damages associated with specific environmental conditions. We may be required to make significant expenditures in connection with the investigation and remediation of alleged or actual spills, personal injury or property damage claims, and the repair, upgrade or expansion of our facilities in order to meet future requirements and obligations under environmental laws.

Our range of exposure for current environmental remediation obligations is estimated to be $19.8 million to $57.0 million. We had an environmental reserve of $31.2 million at June 30, 2008. This reserve was established in anticipation of future remediation activities at our various environmental sites and does not factor in any exposure to us arising from new regulations, private tort actions or claims for damages allegedly associated with specific environmental conditions. To the extent that our environmental liabilities are greater than our reserves or we are unsuccessful in recovering anticipated insurance proceeds under the relevant policies or recovering a material portion of remediation costs in our rates, our results of operations and financial condition could be adversely affected.

To the extent our incurred supply costs are deemed imprudent by the applicable state regulatory commissions, we would under recover our costs, which could adversely impact our results of operations and liquidity.

Our wholesale costs for electricity and natural gas are recovered through various pass-through cost tracking mechanisms in each of the states we serve. The rates are established based upon projected market prices or contract obligations. As these variables change, we adjust our rates through our monthly trackers. To the extent our energy supply costs are deemed imprudent by the applicable state regulatory commissions, we would under recover our costs, which could adversely impact our results of operations.

We do not own any natural gas reserves or regulated electric generation assets to service our Montana operations. As a result, we are required to procure our entire natural gas supply and substantially all of our Montana electricity supply pursuant to contracts with third-party suppliers. In light of this reliance on third-party suppliers, we are exposed to certain risks in the event a third-party supplier is unable to satisfy its contractual obligation. If this occurred, then we might be required to purchase gas and/or electricity supply requirements in the energy markets, which may not be on commercially reasonable terms, if at all. If prices were higher in the energy markets, it could result in a temporary material under recovery that would reduce our liquidity.

Our obligation to supply a minimum annual quantity of power to the Montana electric supply could expose us to material commodity price risk if certain QFs under contract with us do not perform during a time of high commodity prices, as we are required to supply any quantity deficiency.

We perform management of the QF portfolio of resources under the terms and conditions of the QF Tier II Stipulation. This Stipulation may subject us to commodity price risk if the QF portfolio does not perform in a manner to meet the annual minimum energy requirement.

As part of the Stipulation and Settlement with the MPSC and other parties in the Tier II Docket, we agreed to supply the electric supply with a certain minimum amount of power at an agreed upon price per MW. The annual minimum energy requirement is achievable under normal QF operations, including normal periods of planned and forced outages. Furthermore, we will not realize commodity price risk unless any required replacement energy cost is in excess of the total amount recovered under the QF contracts.

However, to the extent the supplied QF power for any year does not reach the minimum quantity set forth in the settlement, we are obligated to secure the quantity deficiency from other sources. Since we own no material generation in Montana, the anticipated source for any quantity deficiency is the wholesale market which, in turn, would subject us to commodity price volatility.

Our jointly owned electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased power purchase costs.

unanticipated interruptions in fuel supply. We are a captive rail shipper of the Burlington Northern Santa Fe Railway for shipments of coal to the Big Stone I Plant (our largest source of generation in South Dakota), making us vulnerable to railroad capacity issues and/or increased prices for coal transportation from a sole supplier. Operational risks also include facility shutdowns due to breakdown or failure of equipment or processes, labor disputes, operator error and catastrophic events such as fires, explosions, floods, intentional acts of destruction or other similar occurrences affecting the electric generating facilities. The loss of a major regulated generating facility would require us to find other sources of supply, if available, and expose us to higher purchased power costs.

Seasonal and quarterly fluctuations of our business could adversely affect our results of operations and liquidity.

Our electric and natural gas utility business is seasonal, and weather patterns can have a material impact on our financial performance. Demand for electricity and natural gas is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand for this product depends heavily upon weather patterns throughout our market areas, and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. In the event that we experience unusually mild winters or cool summers in the future, our results of operations and financial condition could be adversely affected. In addition, exceptionally hot summer weather or unusually cold winter weather could add significantly to working capital needs to fund higher than normal supply purchases to meet customer demand for electricity and natural gas.

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

We are subject to regulation by federal and state governmental entities, including the FERC, MPSC, South Daktoa Public Utilities Commission and Nebraska Public Service Commission. Regulations can affect allowed rates of return, recovery of costs and operating requirements. In addition, existing regulations may be revised or reinterpreted, new laws, regulations, and interpretations thereof may be adopted or become applicable to us and future changes in laws and regulations may have a detrimental effect on our business.

Our rates are approved by our respective commissions and are effective until new rates are approved. In addition, supply costs are recovered through adjustment charges that are periodically reset to reflect current and projected costs. Inability to recover costs in rates or adjustment clauses could have a material adverse effect on our results of operations, cash flows and financial position.

~~We are subject to extensive environmental laws and regulations and potential environmental liabilities, which could result in significant costs and liabilities.~~

~~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.~~

Our range of exposure for current environmental remediation obligations is estimated to be $19.8 million to $57.0 million. We had an environmental reserve of $32.2 million at March 31, 2008. This reserve was established in anticipation of future remediation activities at our various environmental sites and does not factor in any exposure to us arising from new regulations, private tort actions or claims for damages allegedly associated with specific environmental conditions. To the extent that our environmental liabilities are greater than our reserves or we are unsuccessful in recovering anticipated insurance proceeds under the relevant policies or recovering a material portion of remediation costs in our rates, our results of operations and financial condition could be adversely affected.

~~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.~~

Operation of electric generating facilities involves risks which can adversely affect energy output and efficiency levels. Most of our generating capacity is coal-fired. We rely on a limited number of suppliers of coal for our regulated generation, making us vulnerable to increased prices for fuel as existing contracts expire or in the event of unanticipated interruptions in fuel supply. We are a captive rail shipper of the Burlington Northern Santa Fe Railway for shipments of coal to the Big Stone I Plant (our largest source of generation in South Dakota), making us vulnerable to railroad capacity issues and/or increased prices for coal transportation from a sole supplier. Operational risks also include facility shutdowns due to breakdown or failure of equipment or processes, labor disputes, operator error and catastrophic events such as fires, explosions, floods, intentional acts of destruction or other similar occurrences affecting the electric generating facilities. The loss of a major regulated generating facility would require us to find other sources of supply, if available, and expose us to higher purchased power costs.

We must meet certain credit quality standards. If we are unable to maintain an investment grade credit ~~rating,~~ratings, we would be required under certain ~~commodity purchase~~credit agreements to provide collateral in the form of letters of credit or cash, which may materially adversely affect our liquidity and /or access to capital.

A downgrade of our credit ratings could adversely affect our liquidity, as counter parties could require us to post collateral. In addition, our ability to raise capital on favorable terms could be hindered, and our borrowing costs could increase.

ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

On May 21, 2008, we held our annual meeting of shareholders. At that meeting, the following matters were voted upon:

All of the Directors were elected to serve a one-year term as Directors until the 2009 Annual Meeting.

	VOTES FOR:		VOTES WITHHELD:
Stephen P. Adik		28,747,062		489,014
E. Linn Draper		28,746,192		489,884
Jon S. Fossel		28,750,349		485,727
Michael J. Hanson		28,750,272		485,804
Julia L. Johnson		28,751,838		484,238
Philip L. Maslowe		28,759,157		476,919
D. Louis Peoples		28,717,964		518,112

The ratification of Deloitte & Touche, LLP as our independent auditors was approved.

	FOR:	AGAINST:		ABSTAIN:
Votes	28,762,538		473,538		—

ITEM 6.

EXHIBITS

	(a)	Exhibits

Exhibit 4.1—Eighth Supplemental Indenture, dated as of May 1, 2008, by and between NorthWestern Corporation and The Bank of New York, as trustee under the General Mortgage Indenture and Deed of Trust dated as of August 1, 1993.

Exhibit 10.1—Purchase and Sale Agreement, dated June 9, 2008, among Bicent (Montana) Power Company LLC and NorthWestern Corporation.

Exhibit 99.1—Bond Purchase Agreement, dated May 1, 2008, between NorthWestern Corporation and initial purchasers.

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.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	NORTHWESTERN CORPORATION
Date: ~~April 24,~~July 31, 2008	By:	/s/ BRIAN B. BIRD
		Brian B. Bird
		Chief Financial Officer
		Duly Authorized Officer and Principal Financial Officer

EXHIBIT INDEX

Exhibit Number		Description
*4.1		Eighth Supplemental Indenture, dated as of May 1, 2008, by and between NorthWestern Corporation and The Bank of New York, as trustee under the General Mortgage Indenture and Deed of Trust dated as of August 1, 1993.
*10.1		Purchase and Sale Agreement, dated June 9, 2008, among Bicent (Montana) Power Company LLC and NorthWestern Corporation.
*99.1		Bond Purchase Agreement, dated May 1, 2008, between NorthWestern Corporation and initial purchasers.
*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

								June 30,			December 31,
		March 31, 2008			December 31, 2007			2008			2007
ASSETS
Current Assets:
Cash and cash equivalents	$	33,755		$	12,773		$	24,242		$	12,773
Restricted cash		13,904			14,482			19,520			14,482
Accounts receivable, net of allowance		142,280			143,482			116,802			143,482
Inventories		29,579			63,586			47,304			63,586
Regulatory assets		23,096			27,049			21,190			27,049
Prepaid energy supply		2,966			3,166			2,791			3,166
Deferred income taxes		6,987			2,987			8,813			2,987
Other		18,570			10,829			43,861			10,829
Total current assets		271,137			278,354			284,523			278,354
Property, plant, and equipment, net		1,785,079			1,770,880			1,798,735			1,770,880
Goodwill		355,128			355,128			355,128			355,128
Regulatory assets		117,616			123,041			113,031			123,041
Other noncurrent assets		19,346			19,977			19,236			19,977
Total assets	$	2,548,306		$	2,547,380		$	2,570,653		$	2,547,380
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Current maturities of capital leases	$	2,176		$	2,389		$	1,836		$	2,389
Current maturities of long-term debt		18,860			18,617			19,285			18,617
Accounts payable		65,989			91,588			69,237			91,588
Accrued expenses		184,227			168,610			169,631			168,610
Regulatory liabilities		50,415			40,635			85,297			40,635
Total current liabilities		321,667			321,839			345,286			321,839
Long-term capital leases		37,701			38,002			37,412			38,002
Long-term debt		757,352			787,360			744,432			787,360
Deferred income taxes		89,315			74,046			100,987			74,046
Noncurrent regulatory liabilities		215,383			194,959			218,923			194,959
Other noncurrent liabilities		292,460			308,150			291,648			308,150
Total liabilities		1,713,878			1,724,356			1,738,688			1,724,356
Commitments and Contingencies (Note 12)
Commitments and Contingencies (Note 14)
Shareholders’ Equity:
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 39,335,958 and 38,972,551, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued		393			393			393			393
Treasury stock at cost		(10,781	)		(10,781	)		(10,781	)		(10,781	)
Paid-in capital		804,254			803,061			805,426			803,061
Retained earnings		27,193			16,603			23,835			16,603
Accumulated other comprehensive income		13,369			13,748			13,092			13,748
Total shareholders’ equity		834,428			823,024			831,965			823,024
Total liabilities and shareholders’ equity	$	2,548,306		$	2,547,380		$	2,570,653		$	2,547,380

								Three Months Ended June 30,					Six Months Ended June 30,
		Three Months Ended March 31,
		2008			2007			2008			2007			2008			2007
OPERATING REVENUES	$	385,975		$	366,565		$	276,506		$	259,608		$	662,481		$		626,173
COST OF SALES		229,084			219,278			149,354			141,255			378,438				360,534
GROSS MARGIN		156,891			147,287			127,152			118,353			284,043				265,639
OPERATING EXPENSES
Operating, general and administrative		60,071			62,448			53,866			58,677			113,937				121,125
Property and other taxes		23,640			20,592			20,540			20,660			44,180				41,252
Depreciation		21,091			19,894			21,225			20,793			42,316				40,687
TOTAL OPERATING EXPENSES		104,802			102,934			95,631			100,130			200,433				203,064
OPERATING INCOME		52,089			44,353			31,521			18,223			83,610				62,575
Interest Expense		(16,080	)		(13,220	)		(15,848	)		(14,527	)		(31,849	)			(27,747	)
Other Income		662			378
Other (Expense) Income								(161	)		359			422				737
Income Before Income Taxes		36,671			31,511			15,512			4,055			52,183				35,565
Income Tax Expense		(13,220	)		(12,369	)		(6,009	)		(1,621	)		(19,229	)			(13,989	)
Net Income	$	23,451		$	19,142		$	9,503		$	2,434		$	32,954		$		21,576
Average Common Shares Outstanding		38,972			35,720			38,973			35,988			38,973				35,855
Basic Earnings per Average Common Share	$	0.60		$	0.54		$	0.24		$	0.07		$	0.85		$		0.60
Diluted Earnings per Average Common Share	$	0.59		$	0.51		$	0.24		$	0.06		$	0.84		$		0.57
Dividends Declared per Average Common Share	$	0.33		$	0.31		$	0.33		$	0.31		$	0.66		$		0.62

	Three Months Ended March 31,						Six Months Ended June 30,
		2008			2007			2008			2007
OPERATING ACTIVITIES:
Net Income	$	23,451		$	19,142		$	32,954		$	21,576
Items not affecting cash:
Depreciation		21,091			19,894			42,316			40,687
Amortization of debt issue costs, discount and deferred hedge gain		594			399			1,202			805
Amortization of restricted stock		1,194			2,177			2,364			4,259
Equity portion of allowance for funds used during construction		(172	)		(68	)		(282	)		(163	)
Loss (Gain) on sale of assets		2			(62	)
Gain on sale of assets								(110	)		—
Unrealized loss on derivative instruments		1,203			—			6,396			—
Deferred income taxes		11,269			11,685			21,115			12,712
Changes in current assets and liabilities:
Restricted cash		578			165			(5,038	)		(824	)
Accounts receivable		1,202			9,764			26,780			46,979
Inventories		34,007			31,632			16,282			3,126
Prepaid energy supply costs		200			(924	)		375			(547	)
Other current assets		520			366			(288	)		(330	)
Accounts payable		(26,032	)		(19,977	)		(23,569	)		(18,314	)
Accrued expenses		14,466			7,038			(5,324	)		3,622
Regulatory assets		3,902			6,554			5,808			5,893
Regulatory liabilities		1,519			11,633			11,933			26,493
Other noncurrent assets		5,729			2,806			12,159			6,822
Other noncurrent liabilities		(16,768	)		1,865			(20,419	)		(16,559	)
Cash provided by operating activities		77,955			104,089			124,654			136,237
INVESTING ACTIVITIES:
Property, plant, and equipment additions		(13,957	)		(20,470	)		(43,087	)		(52,608	)
Colstrip Unit 4 acquisition		—			(40,247	)		—			(40,247	)
Proceeds from sale of assets		3			109			29			592
Cash used in investing activities		(13,954	)		(60,608	)		(43,058	)		(92,263	)
FINANCING ACTIVITIES:
Proceeds from exercise of warrants		—			5,102			—			10,600
Treasury stock activity		—			(1	)		—			(6	)
Dividends on common stock		(12,861	)		(11,112	)		(25,722	)		(22,297	)
Issuance of long-term debt								55,000			—
Repayment of long-term debt		(18,047	)		(3,627	)		(85,939	)		(3,920	)
Line of credit repayments, net		(12,000	)		(34,000	)		(12,000	)		(30,000	)
Financing costs		(111	)		(227	)		(1,466	)		(281	)
Cash used in financing activities		(43,019	)		(43,865	)		(70,127	)		(45,904	)
Increase (Decrease) in Cash and Cash Equivalents		20,982			(384	)		11,469			(1,930	)
Cash and Cash Equivalents, beginning of period		12,773			1,930			12,773			1,930
Cash and Cash Equivalents, end of period	$	33,755		$	1,546		$	24,242		$	—
Supplemental Cash Flow Information:
Cash paid during the period for:
Income Taxes		38			859
Income taxes								43			1,274
Interest		12,088			11,664			24,479			18,993
Significant noncash transactions:
Assumption of debt related to Colstrip Unit 4 acquisition		—			20,438			—			20,438

	Settlement Term
	2008			2009			2010		2011		Fair Value
Prices provided by observable market inputs (level 2) (1)
Regulated gas derivative asset (2)	$	4,270		$	5,546		$	3,295	$	869	$		13,980
Unregulated electric derivative liability	(1,034		)	(169		)	—		—		(1,203				)
Net derivative asset	$	3,236		$	5,377		$	3,295	$	869		$		12,777

At June 30, 2008	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 (1)

Regulated gas derivative asset (2)	$	—	$	38,449		$	—	$	—	$	38,449
Unregulated electric derivative liability	—		(6,396		)	—		—		(6,396		)
Net derivative asset	$	—	$	32,053		$	—	$	—	$	32,053


Regulated electric	$	241,100
Regulated natural gas		114,028
Unregulated electric		—
	$	355,128

	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007			2008			2007
Net income	$	23,451		$	19,142		$	9,503		$	2,434		$	32,954		$	21,576
Other comprehensive income, net of tax:
Other comprehensive income (loss), net of tax:
Reclassification of net gains on hedging instruments from OCI to net income		(297	)		(297	)		(297	)		(297	)		(594	)		(594	)
Foreign currency translation		(82	)		19			20			151			(62	)		170
Comprehensive income	$	23,072		$	18,864		$	9,226		$	2,288		$	32,298		$	21,152

Three months ended,	Regulated						Unregulated												Regulated						Unregulated
March 31, 2008	Electric			Gas			Electric			Other			Eliminations			Total
June 30, 2008																			Electric			Gas			Electric			Other			Eliminations			Total
Operating revenues	$	196,619		$	171,643		$	20,404		$	7,922		$	(10,613	)	$	385,975		$	178,967		$	80,531		$	16,569		$	8,653		$	(8,214	)	$	276,506
Cost of sales	103,055			121,308			7,032			7,764			(10,075		)	229,084			87,196			49,885			11,624			8,395			(7,746		)	149,354
Gross margin	93,564			50,335			13,372			158			(538		)	156,891			91,771			30,646			4,945			258			(468		)	127,152
Operating, general and administrative	35,370			17,924			3,677			3,638			(538		)	60,071			34,503			15,735			3,219			877			(468		)	53,866
Property and other taxes	16,429			6,328			879			4			—			23,640			14,338			5,484			715			3			—			20,540
Depreciation	15,395			3,883			1,805			8			—			21,091			15,392			4,001			1,823			9			—			21,225
Operating income (loss)	26,370			22,200			7,011			(3,492		)	—			52,089			27,538			5,426			(812		)	(631		)	—			31,521
Interest expense	(9,306		)	(3,230		)	(3,176		)	(368		)	—			(16,080		)	(9,201		)	(3,286		)	(2,993		)	(368		)	—			(15,848		)
Other income	257			309			13			83			—			662
Other income (expense)																			376			281			119			(937		)	—			(161		)
Income tax (expense) benefit	(5,687		)	(7,290		)	(1,715		)	1,472			—			(13,220		)	(6,646		)	(873		)	1,561			(51		)	—			(6,009		)
Net income (loss)	$	11,634		$	11,989		$	2,133		$	(2,305	)	$	—		$	23,451		$	12,067		$	1,548		$	(2,125	)	$	(1,987	)	$	—		$	9,503
Total assets	$	1,532,317		$	748,111		$	250,229		$	17,649		$	—		$	2,548,306		$	1,543,185		$	754,213		$	256,036		$	17,219		$	—		$	2,570,653
Capital expenditures	$	10,738		$	2,726		$	493		$	—		$	—		$	13,957		$	18,748		$	9,864		$	518		$	—		$	—		$	29,130

Three months ended,	Regulated						Unregulated
March 31, 2007	Electric			Gas			Electric			Other			Eliminations			Total
Operating revenues	$	178,494		$	158,189		$	22,278		$	16,071		$	(8,467	)	$	366,565
Cost of sales	92,788			115,210			4,236			14,993			(7,949		)	219,278
Gross margin	85,706			42,979			18,042			1,078			(518		)	147,287
Operating, general and administrative	34,508			18,085			8,368			2,005			(518		)	62,448
Property and other taxes	14,191			5,595			779			27			—			20,592
Depreciation	15,378			3,950			416			150			—			19,894
Operating income (loss)	21,629			15,349			8,479			(1,104		)	—			44,353
Interest expense	(9,750		)	(2,852		)	(226		)	(392		)	—			(13,220		)
Other income	176			154			2			46			—			378
Income tax (expense) benefit	(4,465		)	(4,950		)	(3,456		)	502			—			(12,369		)
Net income (loss)	$	7,590		$	7,701		$	4,799		$	(948	)	$	—		$	19,142
Total assets	$	1,475,296		$	726,799		$	118,326		$	20,078		$	—		$	2,340,499
Capital expenditures	$	12,395		$	7,435		$	640		$	—		$	—		$	20,470

Six months ended,	Regulated						Unregulated
June 30, 2008	Electric			Gas			Electric			Other			Eliminations			Total
Operating revenues	$	375,586		$	252,174		$	36,973		$	16,575		$	(18,827	)	$	662,481
Cost of sales	190,251			171,193			18,656			16,159			(17,821		)	378,438
Gross margin	185,335			80,981			18,317			416			(1,006		)	284,043
Operating, general and administrative	69,873			33,659			6,896			4,515			(1,006		)	113,937
Property and other taxes	30,767			11,812			1,594			7			—			44,180
Depreciation	30,787			7,884			3,628			17			—			42,316
Operating income (loss)	53,908			27,626			6,199			(4,123		)	—			83,610
Interest expense	(18,459		)	(6,485		)	(6,169		)	(736		)	—			(31,849		)
Other income (expense)	585			559			132			(854		)	—			422
Income tax (expense) benefit	(12,333		)	(8,163		)	(154		)	1,421			—			(19,229		)
Net income (loss)	$	23,701		$	13,537		$	8		$	(4,292	)	$	—		$	32,954
Total assets	$	1,543,185		$	754,213		$	256,036		$	17,219		$	—		$	2,570,653
Capital expenditures	$	29,482		$	12,594		$	1,011		$	—		$	—		$	43,087

	March 31, 2008	March 31, 2007	Six Months Ended June 30, 2008	Six Months Ended June 30, 2007
Basic computation	38,972,507	35,719,981	38,972,529	35,854,902
Dilutive effect of
Restricted shares	445,331	530,466	448,939	530,655
Stock warrants	—	1,575,428	—	1,469,097
Diluted computation	39,417,838	37,825,875	39,421,468	37,854,654

	Three Months Ended June 30, 2008	Three Months Ended June 30, 2007
Basic computation	38,972,551	35,988,340
Dilutive effect of
Restricted shares	448,939	530,655
Stock warrants	—	1,355,872
Diluted computation	39,421,490	37,874,867

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended March 31,
	2008			2007			2008			2007
Components of Net Periodic Benefit Cost
Service cost	$	2,170		$	2,289		$	150		$	188
Interest cost		5,726			5,399			611			702
Expected return on plan assets		(6,756	)		(5,823	)		(289	)		(225	)
Amortization of prior service cost		60			60			—			—
Recognized actuarial gain		(141	)		—			(107	)		—
Net Periodic Benefit Cost	$	1,059		$	1,925		$	365		$	665

		Pension Benefits						Other Postretirement Benefits
		Three Months Ended June 30,
			2008			2007			2008			2007
Components of Net Periodic Benefit Cost
	Service Cost	$	2,033		$	2,185		$	132		$	102
	Interest Cost		5,712			5,501			573			519
	Expected return on plan assets		(6,851	)		(6,388	)		(369	)		(310	)
	Amortization of prior service cost		63			61			—			—
	Recognized actuarial (gain) loss		(268	)		—			(193	)		—
Net Periodic Benefit Cost		$	689		$	1,359		$	143		$	311

		Pension Benefits						Other Postretirement Benefits
		Six Months Ended June 30,
			2008			2007			2008			2007
Components of Net Periodic Benefit Cost
	Service Cost	$	4,203		$	4,474		$	282		$	290
	Interest Cost		11,438			10,900			1,184			1,221
	Expected return on plan assets		(13,607	)		(12,211	)		(658	)		(535	)
	Amortization of prior service cost		123			121			—			(180	)
	Recognized actuarial (gain) loss		(409	)		—			(300	)		—
Net Periodic Benefit Cost		$	1,748		$	3,284		$	508		$	796

	Gross Margin			Gross Margin
	2008 vs. 2007			2008 vs. 2007
	(Millions of Dollars)			(Millions of Dollars)
Rate increases				$	4.9
Regulated electric and gas volumes	$	6.4		3.0
Montana regulated electric and gas interim rate increase (subject to refund)	3.4
South Dakota and Nebraska regulated gas rate increase	1.7
Transmission volumes and rate increase (subject to refund)	0.9
Regulated electric QF supply costs				3.9
Regulated electric wholesale				2.0
Unregulated electric volumes	2.6			5.2
Unregulated electric pricing and fuel supply costs	(7.2		)	(5.5		)
Unregulated electric unrealized loss on forward contracts				(5.2		)
Other	1.8			0.5
Improvement in Gross Margin	$	9.6		$	8.8

	Operating, General & Administrative Expenses			Operating, General & Administrative Expenses
	2008 vs. 2007			2008 vs. 2007
	(Millions of Dollars)			(Millions of Dollars)
Operating lease expense	$	(4.9	)	$	(3.6	)
Legal and professional fees	2.8			(4.5		)
Other	(0.2		)	3.3
Reduction in Operating, General & Administrative Expenses	$	(2.3	)	$	(4.8	)

	Volumes MWH
	2008		2007		Change		% Change
	(in thousands)
Retail Electric
Montana		668		635		33		5.2	%
South Dakota		160		148		12		8.1
Residential		828		783		45		5.7
Montana		799		788		11		1.4
South Dakota		222		203		19		9.4
Commercial		1,021		991		30		3.0
Industrial		761		735		26		3.5
Other		24		24		—		—
Total Retail Electric		2,634		2,533		101		4.0	%
Wholesale Electric		35		32		3		9.4	%

Average Customer Counts		2008		2007		Change			% Change
	Retail Electric
	Montana		265,820		262,209		3,611			1.4		%
	South Dakota		47,882		47,603		279			0.6
	Residential		313,702		309,812		3,890			1.3
	Montana		59,449		58,106		1,343			2.3
	South Dakota		11,522		11,373		149			1.3
	Commercial		70,971		69,479		1,492			2.1
	Industrial		71		70		1			1.4
	Other		5,559		5,699		(140	)		(2.5	)
	Total Retail Electric		390,303		385,060		5,243			1.4		%

	2008ascomparedto:
CoolingDegree-Days	2007	HistoricAverage
Montana	37% colder	21% colder
South Dakota	84% colder	75% colder

	Volumes Dekatherms
	2008		2007		Change			% Change
	(in thousands)
Retail Gas
Montana		5,568		5,035		533			10.6		%
South Dakota		1,607		1,526		81			5.3
Nebraska		1,405		1,382		23			1.7
Residential		8,580		7,943		637			8.0
Montana		2,757		2,528		229			9.1
South Dakota		1,378		1,181		197			16.7
Nebraska		1,284		1,224		60			4.9
Commercial		5,419		4,933		486			9.9
Industrial		119		73		46			63.0
Other		54		88		(34	)		(38.6	)
Total Retail Gas		14,172		13,037		1,135			8.7		%

	2008 as compared with:
Heating Degree-Days	2007	Historic Average
Montana	8%25% colder	~~Remained flat~~10% colder
South Dakota	4%36% colder	2%12% colder
Nebraska	4%44% colder	10% colder

	2008ascomparedwith:
HeatingDegree-Days	2007	HistoricAverage
Montana	14% colder	3% colder
South Dakota	11% colder	5% colder
Nebraska	12% colder	5% colder

		Three Months Ended March 31,						Six Months Ended June 30,
		2008			2007			2008			2007
Operating Activities
Net income	$	23.5		$	19.1		$	33.0		$	21.6
Noncash adjustments to net income		35.2			34.0
Non-cash adjustments to net income								73.0			58.3
Changes in working capital		30.4			46.2			27.0			66.0
Other		(11.1	)		4.8			(8.4	)		(9.7	)
		78.0			104.1			124.6			136.2
Investing Activities
Property, plant and equipment additions		(14.0	)		(20.5	)		(43.1	)		(52.6	)
Sale of assets		—			0.1			—			0.6
Colstrip Unit 4 acquisition		—			(40.2	)		—			(40.2	)
		(14.0	)		(60.6	)		(43.1	)		(92.2	)
Financing Activities
Net repayment of debt		(30.0	)		(37.6	)		(42.9	)		(33.9	)
Dividends on common stock		(12.9	)		(11.1	)		(25.7	)		(22.3	)
Other		(0.1	)		4.8			(1.5	)		10.3
		(43.0	)		(43.9	)		(70.1	)		(45.9	)

Net Increase (Decrease) in Cash and Cash Equivalents	$	21.0		$	(0.4	)	$	11.4		$	(1.9	)
Cash and Cash Equivalents, beginning of period	$	12.8		$	1.9		$	12.8		$	1.9
Cash and Cash Equivalents, end of period	$	33.8		$	1.5		$	24.2		$	—

	Senior Secured Rating	Senior Unsecured Rating	Corporate Rating	Outlook
Fitch (1)	BBB	BBB-	BBB-	~~Stable~~Positive
Moody’s ~~(1)~~(2)	Baa2	Baa3	~~Ba2~~	N/A	~~Stable~~Positive
S&P ~~(2)~~(3)	A- (MT) BBB+ (SD)	BBB-	BBB	Stable