Quarterly Report

For the Transition Period from _____________ to ______________

Commission file number 1-3480

MDU Resources Group, Inc.

(Exact name of registrant as specified in its charter)

Delaware		41-0423660
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

Abbreviation or Acronym

2009 Annual Report	Company's Annual Report on Form 10-K for the year ended December 31, 2009
ASC	FASB Accounting Standards Codification
Bbl	Barrel
Bcf	Billion cubic feet
Bcfe	Billion cubic feet equivalent
BER	Montana Board of Environmental Review
Big Stone Station	450-MW coal-fired electric generating facility located near Big Stone City, South Dakota (22.7 percent ownership)
Big Stone Station II	Formerly proposed coal-fired electric generating facility located near Big Stone City, South Dakota (the Company had anticipated ownership of at least 116 MW)
Bitter Creek	Bitter Creek Pipelines, LLC, an indirect wholly owned subsidiary of WBI Holdings
Brazilian Transmission Lines	Company’s equity method investment in the company owning ECTE, ENTE and ERTE
Btu	British thermal unit
Cascade	Cascade Natural Gas Corporation, an indirect wholly owned subsidiary of MDU Energy Capital
CBNG	Coalbed natural gas
CEM	Colorado Energy Management, LLC, a former direct wholly owned subsidiary of Centennial Resources (sold in the third quarter of 2007)
Centennial	Centennial Energy Holdings, Inc., a direct wholly owned subsidiary of the Company
Centennial Capital	Centennial Holdings Capital LLC, a direct wholly owned subsidiary of Centennial
Centennial Resources	Centennial Energy Resources LLC, a direct wholly owned subsidiary of Centennial
Clean Air Act	Federal Clean Air Act
Clean Water Act	Federal Clean Water Act
Colorado State District Court	Colorado Thirteenth Judicial District Court, Yuma County
Company	MDU Resources Group, Inc.
dk	Decatherm
Dodd-Frank Act	Dodd-Frank Wall Street Reform and Consumer Protection Act
ECTE	Empresa Catarinense de Transmissão de Energia S.A.
EIS	Environmental Impact Statement
ENTE	Empresa Norte de Transmissão de Energia S.A.
EPA	U.S. Environmental Protection Agency
ERTE	Empresa Regional de Transmissão de Energia S.A.
Exchange Act	Securities Exchange Act of 1934, as amended
FASB	Financial Accounting Standards Board

North Dakota District Court	North Dakota South Central Judicial District Court for Burleigh County
NPRC	Northern Plains Resource Council
NSPS	New Source Performance Standards
Oil	Includes crude oil, condensate and natural gas liquids
OPUC	Oregon Public Utility Commission
Oregon DEQ	Oregon State Department of Environmental Quality
Prairielands	Prairielands Energy Marketing, Inc., an indirect wholly owned subsidiary of WBI Holdings
PRP	Potentially Responsible Party
PSD	Prevention of Significant Deterioration
RCRA	Resource Conservation and Recovery Act
ROD	Record of Decision
SDPUC	South Dakota Public Utilities Commission
SEC	U.S. Securities and Exchange Commission
SEC Defined Prices	The average price of natural gas and oil during the applicable 12-month period, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions
Securities Act	Securities Act of 1933, as amended
South Dakota Federal District Court	U.S. District Court for the District of South Dakota
South Dakota SIP	South Dakota State Implementation Plan
TRWUA	Tongue River Water Users’ Association
WBI Holdings	WBI Holdings, Inc., a direct wholly owned subsidiary of Centennial
Williston Basin	Williston Basin Interstate Pipeline Company, an indirect wholly owned subsidiary of WBI Holdings
WUTC	Washington Utilities and Transportation Commission
Wygen III	100-MW coal-fired electric generating facility located near Gillette, Wyoming (25 percent ownership)
WYPSC	Wyoming Public Service Commission

Part I -- Financial Information	Page
Consolidated Statements of Income --
Three and Nine Months Ended September 30, 2010 and 2009	7
Consolidated Balance Sheets --
September 30, 2010 and 2009, and December 31, 2009	8
Consolidated Statements of Cash Flows --
Nine Months Ended September 30, 2010 and 2009	9
Notes to Consolidated Financial Statements	10
Management's Discussion and Analysis of Financial Condition and Results of Operations	37
Quantitative and Qualitative Disclosures About Market Risk	59
Controls and Procedures	61
Part II -- Other Information
Legal Proceedings	61
Risk Factors	62
Unregistered Sales of Equity Securities and Use of Proceeds	64
Other Information	65
Exhibits	66
Signatures	67
Exhibit Index	68
Exhibits

 

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PART I -- FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

MDU RESOURCES GROUP, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

		Three Months Ended September 30,								Nine Months Ended September 30,
		2010				2009				2010				2009
		(In thousands, except per share amounts)
Operating revenues:
Electric, natural gas distribution and pipeline and energy services		$	223,602			$	206,867			$	956,025			$	1,065,061
Construction services, natural gas and oil production, construction materials and contracting, and other			902,321				901,060				1,911,119				2,094,911
Total operating revenues			1,125,923				1,107,927				2,867,144				3,159,972
Operating expenses:
Fuel and purchased power			15,283				15,188				45,300				49,085
Purchased natural gas sold			51,243				57,598				382,376				520,495
Operation and maintenance:
Electric, natural gas distribution and pipeline and energy services			95,367				59,459				226,788				193,394
Construction services, natural gas and oil production, construction materials and contracting, and other			732,998				698,386				1,563,640				1,675,088
Depreciation, depletion and amortization			84,841				79,547				245,066				253,241
Taxes, other than income			37,229				37,476				123,421				129,250
Write-down of natural gas and oil properties			—				—				—				620,000
Total operating expenses			1,016,961				947,654				2,586,591				3,440,553
Operating income (loss)			108,962				160,273				280,553				(280,581	)
Earnings from equity method investments			2,528				2,290				6,970				6,154
Other income			1,740				2,923				6,929				7,076
Interest expense			20,944				20,945				61,950				62,700
Income (loss) before income taxes			92,286				144,541				232,502				(330,051	)
Income taxes			31,276				51,957				80,783				(134,143	)
Net income (loss)			61,010				92,584				151,719				(195,908	)
Dividends on preferred stocks			172				171				513				514
Earnings (loss) on common stock		$	60,838			$	92,413			$	151,206			$	(196,422	)
Earnings (loss) per common share -- basic		$	.32			$	.50			$	.80			$	(1.07	)
Earnings (loss) per common share -- diluted		$	.32			$	.50			$	.80			$	(1.07	)
Dividends per common share		$	.1575			$	.1550			$	.4725			$	.4650
Weighted average common shares outstanding -- basic			188,170				185,160				188,088				184,309
Weighted average common shares outstanding -- diluted			188,338				185,425				188,268				184,309

The accompanying notes are an integral part of these consolidated financial statements.

 

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MDU RESOURCES GROUP, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

		September 30, 2010				September 30, 2009				December 31, 2009
(In thousands, except shares and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents		$	36,285			$	61,449			$	175,114
Receivables, net			585,487				519,572				531,980
Inventories			261,680				268,677				249,804
Deferred income taxes			25,552				13,050				28,145
Short-term investments			250				1,644				2,833
Commodity derivative instruments			26,803				28,421				7,761
Prepayments and other current assets			99,466				77,736				66,021
Total current assets			1,035,523				970,549				1,061,658
Investments			152,577				137,340				145,416
Property, plant and equipment			7,163,515				6,698,227				6,766,582
Less accumulated depreciation, depletion and amortization			3,056,127				2,823,396				2,872,465
Net property, plant and equipment			4,107,388				3,874,831				3,894,117
Deferred charges and other assets:
Goodwill			634,633				629,036				629,463
Other intangible assets, net			26,112				30,184				28,977
Other			260,722				230,632				231,321
Total deferred charges and other assets			921,467				889,852				889,761
Total assets		$	6,216,955			$	5,872,572			$	5,990,952
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Short-term borrowings		$	4,700			$	—			$	10,300
Long-term debt due within one year			73,417				27,790				12,629
Accounts payable			299,094				267,320				281,906
Taxes payable			46,928				64,656				55,540
Dividends payable			29,810				29,012				29,749
Accrued compensation			41,648				49,082				47,425
Commodity derivative instruments			25,803				44,903				36,907
Other accrued liabilities			205,777				162,200				192,729
Total current liabilities			727,177				644,963				667,185
Long-term debt			1,437,171				1,471,833				1,486,677
Deferred credits and other liabilities:
Deferred income taxes			672,155				547,538				590,968
Other liabilities			718,331				691,961				674,475
Total deferred credits and other liabilities			1,390,486				1,239,499				1,265,443
Commitments and contingencies
Stockholders’ equity :
Preferred stocks			15,000				15,000				15,000
Common stockholders’ equity:
Common stock
Shares issued -- $1.00 par value, 188,732,200 at September 30, 2010, 187,673,037 at September 30, 2009 and 188,389,265 at December 31, 2009			188,732				187,673				188,389
Other paid-in capital			1,022,469				1,001,313				1,015,678
Retained earnings			1,439,050				1,334,255				1,377,039
Accumulated other comprehensive income (loss)			496				(18,338	)			(20,833	)
Treasury stock at cost – 538,921 shares			(3,626	)			(3,626	)			(3,626	)
Total common stockholders’ equity			2,647,121				2,501,277				2,556,647
Total stockholders’ equity			2,662,121				2,516,277				2,571,647
Total liabilities and stockholders’ equity		$	6,216,955			$	5,872,572			$	5,990,952

The accompanying notes are an integral part of these consolidated financial statements.

 

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MDU RESOURCES GROUP, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

		Nine Months Ended September 30,
		2010				2009
		(In thousands)
Operating activities:
Net income (loss)		$	151,719			$	(195,908	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization			245,066				253,241
Earnings, net of distributions, from equity method investments			(2,502	)			(2,110	)
Deferred income taxes			71,322				(200,240	)
Write-down of natural gas and oil properties			—				620,000
Changes in current assets and liabilities, net of acquisitions:
Receivables			(57,074	)			141,147
Inventories			(12,565	)			(7,832	)
Other current assets			(32,122	)			67,143
Accounts payable			19,782				(73,984	)
Other current liabilities			(147	)			34,188
Other noncurrent changes			(11,959	)			(6,423	)
Net cash provided by operating activities			371,520				629,222
Investing activities:
Capital expenditures			(340,221	)			(344,779	)
Acquisitions, net of cash acquired			(106,548	)			(6,452	)
Net proceeds from sale or disposition of property			16,496				18,821
Investments			1,106				(560	)
Net cash used in investing activities			(429,167	)			(332,970	)
Financing activities:
Issuance of short-term borrowings			4,700				—
Repayment of short-term borrowings			(10,300	)			(105,100	)
Issuance of long-term debt			17,799				105,000
Repayment of long-term debt			(7,545	)			(252,696	)
Proceeds from issuance of common stock			2,735				51,440
Dividends paid			(89,347	)			(86,011	)
Tax benefit on stock-based compensation			721				195
Net cash used in financing activities			(81,237	)			(287,172	)
Effect of exchange rate changes on cash and cash equivalents			55				655
Increase (decrease) in cash and cash equivalents			(138,829	)			9,735
Cash and cash equivalents -- beginning of year			175,114				51,714
Cash and cash equivalents -- end of period		$	36,285			$	61,449

The accompanying notes are an integral part of these consolidated financial statements.

 

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MDU RESOURCES GROUP, INC.

NOTES TO CONSOLIDATED

FINANCIAL STATEMENTS

September 30, 2010 and 2009

(Unaudited)

1.	Basis of presentation

The accompanying consolidated interim financial statements were prepared in conformity with the basis of presentation reflected in the consolidated financial statements included in the Company's 2009 Annual Report, and the standards of accounting measurement set forth in the interim reporting guidance in the ASC and any amendments thereto adopted by the FASB. Interim financial statements do not include all disclosures provided in annual financial statements and, accordingly, these financial statements should be read in conjunction with those appearing in the 2009 Annual Report. The information is unaudited but includes all adjustments that are, in the opinion of management, necessary for a fair presentation of the accompanying consolidated interim financial statements and are of a normal recurring nature. Depreciation, depletion and amortization expense is reported separately on the Consolidated Statements of Income and therefore is excluded from the other line items within operating expenses. Management has also evaluated the impact of events occurring after September 30, 2010, up to the date of issuance of these consolidated interim financial statements.

2.	Seasonality of operations

Some of the Company's operations are highly seasonal and revenues from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Accordingly, the interim results for particular businesses, and for the Company as a whole, may not be indicative of results for the full fiscal year.

3.	Allowance for doubtful accounts

The Company's allowance for doubtful accounts as of September 30, 2010 and 2009, and December 31, 2009, was $15.9 million, $16.7 million and $16.6 million, respectively.

 

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4.	Inventories and natural gas in storage

Inventories, other than natural gas in storage for the Company’s regulated operations, were stated at the lower of average cost or market value. Natural gas in storage for the Company’s regulated operations is generally carried at average cost, or cost using the last-in, first-out method. The portion of the cost of natural gas in storage expected to be used within one year was included in inventories. Inventories consisted of:

 

		September 30, 2010				September 30, 2009				December 31, 2009
		(In thousands)
Aggregates held for resale		$	82,622			$	88,087			$	80,087
Materials and supplies			62,273				61,580				58,095
Natural gas in storage (current)			40,133				48,517				35,619
Asphalt oil			24,341				21,228				22,989
Other			52,311				49,265				53,014
Total		$	261,680			$	268,677			$	249,804

The remainder of natural gas in storage, which largely represents the cost of gas required to maintain pressure levels for normal operating purposes, was included in other assets and was $59.3 million, $45.6 million, and $59.6 million at September 30, 2010 and 2009, and December 31, 2009, respectively.

5.	Natural gas and oil properties

The Company uses the full-cost method of accounting for its natural gas and oil production activities. Under this method, all costs incurred in the acquisition, exploration and development of natural gas and oil properties are capitalized and amortized on the units-of-production method based on total proved reserves. Any conveyances of properties, including gains or losses on abandonments of properties, are treated as adjustments to the cost of the properties with no gain or loss recognized.

Capitalized costs are subject to a “ceiling test” that limits such costs to the aggregate of the present value of future net cash flows from proved reserves discounted at 10 percent, as mandated under the rules of the SEC, plus the cost of unproved properties less applicable income taxes. Future net revenue was estimated based on end-of-quarter spot market prices adjusted for contracted price changes prior to the fourth quarter of 2009. Effective December 31, 2009, the Modernization of Oil and Gas Reporting rules issued by the SEC changed the pricing used to estimate reserves and associated future cash flows to SEC Defined Prices. Prior to that date, if capitalized costs exceeded the full-cost ceiling at the end of any quarter, a permanent noncash write-down was required to be charged to earnings in that quarter unless subsequent price changes eliminated or reduced an indicated write-down. Effective December 31, 2009, if capitalized costs exceed the full-cost ceiling at the end of any quarter, a permanent noncash write-down is required to be charged to earnings in that quarter regardless of subsequent price changes.

Due to low natural gas and oil prices that existed on March 31, 2009, the Company's capitalized costs under the full-cost method of accounting exceeded the full-cost ceiling at March 31, 2009. Accordingly, the Company was required to write down its natural gas and

 

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oil producing properties. The noncash write-down amounted to $620.0 million ($384.4 million after tax) for the three months ended March 31, 2009.

The Company hedges a portion of its natural gas and oil production and the effects of the cash flow hedges were used in determining the full-cost ceiling. The Company would have recognized an additional write-down of its natural gas and oil properties of $107.9 million ($66.9 million after tax) at March 31, 2009, if the effects of cash flow hedges had not been considered in calculating the full-cost ceiling. For more information on the Company's cash flow hedges, see Note 12.

At September 30, 2010, the Company’s full-cost ceiling exceeded the Company’s capitalized cost. However, sustained downward movements in natural gas and oil prices subsequent to September 30, 2010, could result in a future write-down of the Company’s natural gas and oil properties.

6.	Earnings (loss) per common share

Basic earnings (loss) per common share were computed by dividing earnings (loss) on common stock by the weighted average number of shares of common stock outstanding during the applicable period. Diluted earnings per common share were computed by dividing earnings on common stock by the total of the weighted average number of shares of common stock outstanding during the applicable period, plus the effect of outstanding stock options, restricted stock grants and performance share awards. For the three months ended September 30, 2010 and 2009, and the nine months ended September 30, 2010, there were no shares excluded from the calculation of diluted earnings per share. Diluted loss per common share for the nine months ended September 30, 2009, was computed by dividing the loss on common stock by the weighted average number of shares of common stock outstanding during the applicable period. Due to the loss on common stock for the nine months ended September 30, 2009, the effect of outstanding stock options, restricted stock grants and performance share awards was excluded from the computation of diluted loss per common share as their effect was antidilutive. Common stock outstanding includes issued shares less shares held in treasury.

7.	Cash flow information

Cash expenditures for interest and income taxes were as follows:

		Nine Months Ended September 30,
		2010				2009
		(In thousands)
Interest, net of amount capitalized		$	65,712			$	65,421
Income taxes		$	36,962			$	29,540

8.	New accounting standards

Improving Disclosure About Fair Value Measurements In January 2010, the FASB issued guidance related to improving disclosures about fair value measurements. The guidance requires separate disclosures of the amounts of transfers in and out of Level 1 and Level 2 fair value measurements and a description of the reason for such transfers. In the reconciliation for Level 3 fair value measurements using significant unobservable inputs,

 

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information about purchases, sales, issuances and settlements shall be presented separately. These disclosures are required for interim and annual reporting periods and were effective for the Company on January 1, 2010, except for the disclosures related to the purchases, sales, issuances and settlements in the roll forward activity of Level 3 fair value measurements, which are effective on January 1, 2011. The guidance requires additional disclosures but does not impact the Company’s financial position or results of operations.

9.	Comprehensive income (loss)

Comprehensive income (loss) is the sum of net income (loss) as reported and other comprehensive income (loss). The Company's other comprehensive income (loss) resulted from gains (losses) on derivative instruments qualifying as hedges and foreign currency translation adjustments. For more information on derivative instruments, see Note 12.

Comprehensive income (loss), and the components of other comprehensive income (loss) and related tax effects, were as follows:

		Three Months Ended September 30,
		2010				2009
		(In thousands)
Net income		$	61,010			$	92,584
Other comprehensive income (loss):
Net unrealized loss on derivative instruments qualifying as hedges:
Net unrealized gain (loss) on derivative instruments arising during the period, net of tax of $2,177 and $(4,632) in 2010 and 2009, respectively			3,628				(7,557	)
Less: Reclassification adjustment for gain on derivative instruments included in net income, net of tax of $3,209 and $10,022 in 2010 and 2009, respectively			5,348				16,352
Net unrealized loss on derivative instruments qualifying as hedges			(1,720	)			(23,909	)
Foreign currency translation adjustment, net of tax of $1,730 and $2,538 in 2010 and 2009, respectively			2,679				3,902
			959				(20,007	)
Comprehensive income		$	61,969			$	72,577

 

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		Nine Months Ended September 30,
		2010				2009
		(In thousands)
Net income (loss)		$	151,719			$	(195,908	)
Other comprehensive income (loss):
Net unrealized gain (loss) on derivative instruments qualifying as hedges:
Net unrealized gain (loss) on derivative instruments arising during the period, net of tax of $10,351 and $(1,758) in 2010 and 2009, respectively			17,266				(2,869	)
Less: Reclassification adjustment for gain (loss) on derivative instruments included in net income (loss), net of tax of $(1,745) and $21,908 in 2010 and 2009, respectively			(2,797	)			35,743
Net unrealized gain (loss) on derivative instruments qualifying as hedges			20,063				(38,612	)
Foreign currency translation adjustment, net of tax of $801 and $6,414 in 2010 and 2009, respectively			1,266				9,909
			21,329				(28,703	)
Comprehensive income (loss)		$	173,048			$	(224,611	)

10.	Equity method investments

Investments in companies in which the Company has the ability to exercise significant influence over operating and financial policies are accounted for using the equity method. The Company's equity method investments at September 30, 2010, include the Brazilian Transmission Lines.

In August 2006, MDU Brasil acquired ownership interests in companies owning the Brazilian Transmission Lines. The interests involve the ENTE (13.3-percent ownership interest), ERTE (13.3-percent ownership interest) and ECTE (25-percent ownership interest) electric transmission lines, which are primarily in northeastern and southern Brazil.

In the fourth quarter of 2009, multiple sales agreements were signed with three separate parties for the Company to sell its ownership interests in the Brazilian Transmission Lines. Regulatory approval for the sale has been received. The financial closing of the sale is anticipated to occur this year. One of the parties will purchase 15.6 percent of the Company’s ownership interests over a four-year period. The other parties will purchase 84.4 percent of the Company’s ownership interests at the financial close of the transaction.

At September 30, 2010 and 2009, and December 31, 2009, the Company's equity method investments had total assets of $390.4 million, $379.4 million and $387.0 million, respectively, and long-term debt of $152.6 million, $180.9 million and $176.7 million, respectively. The Company's investment in its equity method investments was approximately $64.4 million, $60.2 million and $62.4 million, including undistributed earnings of $11.6 million, $8.7 million and $9.3 million, at September 30, 2010 and 2009, and December 31, 2009, respectively.

 

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11.	Goodwill and other intangible assets

The changes in the carrying amount of goodwill were as follows:

Nine Months Ended September 30, 2010		Balance as of January 1, 2010*				Goodwill Acquired During the Year**				Balance as of September 30, 2010*
		(In thousands)
Electric		$	—			$	—			$	—
Natural gas distribution			345,736				—				345,736
Construction services			100,127				2,743				102,870
Pipeline and energy services			7,857				1,880				9,737
Natural gas and oil production			—				—				—
Construction materials and contracting			175,743				547				176,290
Other			—				—				—
Total		$	629,463			$	5,170			$	634,633
* Balance is presented net of accumulated impairment of $12.3 million at the pipeline and energy services segment. **Includes purchase price adjustments that were not material related to acquisitions in a prior period.

 

Nine Months Ended September 30, 2009		Balance as of January 1, 2009*				Goodwill Acquired During the Year**				Balance as of September 30, 2009*
		(In thousands)
Electric		$	—			$	—			$	—
Natural gas distribution			344,952				784				345,736
Construction services			95,619				4,184				99,803
Pipeline and energy services			1,159				6,595				7,754
Natural gas and oil production			—				—				—
Construction materials and contracting			174,005				1,738				175,743
Other			—				—				—
Total		$	615,735			$	13,301			$	629,036
* Balance is presented net of accumulated impairment of $12.3 million at the pipeline and energy services segment. **Includes purchase price adjustments that were not material related to acquisitions in a prior period.

 

 

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Year Ended December 31, 2009		Balance as of January 1, 2009*				Goodwill Acquired During the Year**				Balance as of December 31, 2009*
		(In thousands)
Electric		$	—			$	—			$	—
Natural gas distribution			344,952				784				345,736
Construction services			95,619				4,508				100,127
Pipeline and energy services			1,159				6,698				7,857
Natural gas and oil production			—				—				—
Construction materials and contracting			174,005				1,738				175,743
Other			—				—				—
Total		$	615,735			$	13,728			$	629,463
* Balance is presented net of accumulated impairment of $12.3 million at the pipeline and energy services segment. **Includes purchase price adjustments that were not material related to acquisitions in a prior period.

Other intangible assets were as follows:

		September 30, 2010				September 30, 2009				December 31, 2009
		(In thousands)
Customer relationships		$	24,942			$	24,606			$	24,942
Accumulated amortization			(11,273	)			(8,754	)			(9,500	)
			13,669				15,852				15,442
Noncompete agreements			9,405				12,227				12,377
Accumulated amortization			(6,231	)			(6,281	)			(6,675	)
			3,174				5,946				5,702
Other			13,217				11,478				10,859
Accumulated amortization			(3,948	)			(3,092	)			(3,026	)
			9,269				8,386				7,833
Total		$	26,112			$	30,184			$	28,977

Amortization expense for amortizable intangible assets for the three and nine months ended September 30, 2010, was $1.3 million and $3.4 million, respectively. Amortization expense for the three and nine months ended September 30, 2009, was $1.3 million and $3.9 million, respectively. Estimated amortization expense for amortizable intangible assets is $4.4 million in 2010, $4.1 million in 2011, $4.0 million in 2012, $3.6 million in 2013, $3.2 million in 2014 and $10.2 million thereafter.

12.	Derivative instruments

The Company's policy allows the use of derivative instruments as part of an overall energy price, foreign currency and interest rate risk management program to efficiently manage and minimize commodity price, foreign currency and interest rate risk. As of September 30, 2010, the Company had no outstanding foreign currency or interest rate hedges. The

 

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following information should be read in conjunction with Notes 1 and 7 in the Company's Notes to Consolidated Financial Statements in the 2009 Annual Report.

Cascade and Intermountain

At September 30, 2010, Cascade and Intermountain held natural gas swap agreements and a natural gas collar agreement, with total forward notional volumes of 8.2 million MMBtu, which were not designated as hedges. Cascade and Intermountain utilize natural gas swap and collar agreements to manage a portion of their regulated natural gas supply portfolios in order to manage fluctuations in the price of natural gas related to core customers in accordance with authority granted by the IPUC, WUTC and OPUC. Core customers consist of residential, commercial and smaller industrial customers. The fair value of the derivative instrument must be estimated as of the end of each reporting period and is recorded on the Consolidated Balance Sheets as an asset or a liability. Cascade and Intermountain record periodic changes in the fair market value of the derivative instruments on the Consolidated Balance Sheets as a regulatory asset or a regulatory liability, and settlements of these arrangements are expected to be recovered through the purchased gas cost adjustment mechanism. Gains and losses on the settlements of these derivative instruments are recorded as a component of purchased natural gas sold on the Consolidated Statements of Income as they are recovered through the purchased gas cost adjustment mechanism. Under the terms of these arrangements, Cascade and Intermountain will either pay or receive settlement payments based on the difference between the fixed strike price and the monthly index price applicable to each contract. For the three months ended September 30, 2010, Cascade and Intermountain recorded the change in the fair market value of the derivative instruments of $2.7 million as an increase to regulatory assets. For the nine months ended September 30, 2010, Cascade and Intermountain recorded the change in the fair market value of the derivative instruments of $6.3 million as a decrease to regulatory assets.

Certain of Cascade's derivative instruments contain credit-risk-related contingent features that permit the counterparties to require collateralization if Cascade's derivative liability positions exceed certain dollar thresholds. The dollar thresholds in certain of Cascade's agreements are determined and may fluctuate based on Cascade's credit rating on its debt. In addition, Cascade's and Intermountain's derivative instruments contain cross-default provisions that state if the entity fails to make payment with respect to certain of its indebtedness, in excess of specified amounts, the counterparties could require early settlement or termination of such entity's derivative instruments in liability positions. The aggregate fair value of Cascade and Intermountain's derivative instruments with credit-risk-related contingent features that are in a liability position at September 30, 2010, was $21.6 million. The aggregate fair value of assets that would have been needed to settle the instruments immediately if the credit-risk-related contingent features were triggered on September 30, 2010, was $21.6 million.

Fidelity

At September 30, 2010, Fidelity held natural gas swaps and collar agreements with total forward notional volumes of 19.7 million MMBtu, natural gas basis swaps with total forward notional volumes of 16.3 million MMBtu, and oil swap and collar agreements with total forward notional volumes of 2.4 million Bbl, which were designated as cash flow hedging instruments. Fidelity utilizes these derivative instruments to manage a portion of the

 

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market risk associated with fluctuations in the price of natural gas and oil and basis differentials on its forecasted sales of natural gas and oil production.

The fair value of the derivative instruments must be estimated as of the end of each reporting period and is recorded on the Consolidated Balance Sheets as an asset or liability. Changes in the fair value attributable to the effective portion of hedging instruments, net of tax, are recorded in stockholders' equity as a component of accumulated other comprehensive income (loss). At the date the natural gas and oil quantities are settled, the amounts accumulated in other comprehensive income (loss) are reported in the Consolidated Statements of Income. To the extent that the hedges are not effective, the ineffective portion of the changes in fair market value is recorded directly in earnings. The proceeds received for natural gas and oil production are generally based on market prices.

For the three and nine months ended September 30, 2010, and 2009, the amount of hedge ineffectiveness was immaterial, and there were no components of the derivative instruments’ gain or loss excluded from the assessment of hedge effectiveness. Gains and losses must be reclassified into earnings as a result of the discontinuance of cash flow hedges if it is probable that the original forecasted transactions will not occur. There were no such reclassifications into earnings as a result of the discontinuance of hedges.

Gains and losses on derivative instruments that are reclassified from accumulated other comprehensive income (loss) to current-period earnings are included in operating revenues on the Consolidated Statements of Income. For further information regarding the gains and losses on derivative instruments qualifying as cash flow hedges that were recognized in other comprehensive income (loss) and the gains and losses reclassified from accumulated other comprehensive income (loss) into earnings, see Note 9.

As of September 30, 2010, the maximum term of the swap and collar agreements, in which the exposure to the variability in future cash flows for forecasted transactions is being hedged, is 27 months. The Company estimates that over the next 12 months net gains of approximately $13.8 million (after tax) will be reclassified from accumulated other comprehensive income (loss) into earnings, subject to changes in natural gas and oil market prices, as the hedged transactions affect earnings.

Certain of Fidelity's derivative instruments contain cross-default provisions that state if Fidelity fails to make payment with respect to certain indebtedness, in excess of specified amounts, the counterparties could require early settlement or termination of derivative instruments in liability positions. The aggregate fair value of Fidelity's derivative instruments with credit-risk-related contingent features that are in a liability position at September 30, 2010, was $6.5 million. The aggregate fair value of assets that would have been needed to settle the instruments immediately if the credit-risk-related contingent features were triggered on September 30, 2010, was $6.5 million.

 

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The location and fair value of all of the Company’s derivative instruments in the Consolidated Balance Sheets were as follows:

Asset Derivatives	Location on Consolidated Balance Sheets		Fair Value at September 30, 2010				Fair Value at September 30, 2009				Fair Value at December 31, 2009
			(In thousands)
Designated as hedges	Commodity derivative instruments		$	26,803			$	28,421			$	7,761
	Other assets – noncurrent			8,423				2,894				2,734
				35,226				31,315				10,495
Not designated as hedges	Commodity derivative instruments			—				—				—
	Other assets – noncurrent			—				—				—
				—				—				—
Total asset derivatives			$	35,226			$	31,315			$	10,495

Liability Derivatives	Location on Consolidated Balance Sheets		Fair Value at September 30, 2010				Fair Value at September 30, 2009				Fair Value at December 31, 2009
			(In thousands)
Designated as hedges	Commodity derivative instruments		$	4,649			$	10,962			$	13,763
	Other liabilities – noncurrent			1,845				2,639				114
				6,494				13,601				13,877
Not designated as hedges	Commodity derivative instruments			21,154				33,941				23,144
	Other liabilities – noncurrent			418				7,718				4,756
				21,572				41,659				27,900
Total liability derivatives			$	28,066			$	55,260			$	41,777
Note: The fair value of the commodity derivative instruments not designated as hedges is presented net of collateral provided to the counterparties by Cascade of $4.4 million at September 30, 2009.

13.	Fair value measurements

The Company elected to measure its investments in certain fixed-income and equity securities at fair value with changes in fair value recognized in income. The Company anticipates using these investments to satisfy its obligations under its unfunded, nonqualified benefit plans for executive officers and certain key management employees, and invests in these fixed-income and equity securities for the purpose of earning investment returns and capital appreciation. These investments, which totaled $35.9 million, $33.6 million and

 

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$34.8 million, as of September 30, 2010 and 2009, and December 31, 2009, respectively, are classified as Investments on the Consolidated Balance Sheets. The increase in the fair value of these investments for the three and nine months ended September 30, 2010, was $3.2 million (before tax) and $2.2 million (before tax), respectively. The increase in the fair value of these investments for the three and nine months ended September 30, 2009, was $4.1 million (before tax) and $5.9 million (before tax), respectively. The change in fair value, which is considered part of the cost of the plan, is classified in operation and maintenance expense on the Consolidated Statements of Income. The Company did not elect the fair value option for its remaining available-for-sale securities, which are auction rate securities. The Company’s auction rate securities, which totaled $11.4 million at September 30, 2010 and 2009, and December 31, 2009, are accounted for as available-for-sale and are recorded at fair value. The fair value of the auction rate securities approximate cost and, as a result, there are no accumulated unrealized gains or losses recorded in accumulated other comprehensive income (loss) on the Consolidated Balance Sheets related to these investments.

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. The ASC establishes a hierarchy for grouping assets and liabilities, based on the significance of inputs. The Company’s assets and liabilities measured at fair value on a recurring basis are as follows:

		Fair Value Measurements at September 30, 2010, Using
		Quoted Prices in Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Collateral Provided to Counterparties				Balance at September 30, 2010
		(In thousands)
Assets:
Money market funds		$	2,835			$	—			$	—			$	—			$	2,835
Available-for-sale securities:
Fixed-income securities			—				11,400				—				—				11,400
Insurance contract*			—				35,902				—				—				35,902
Commodity derivative instruments - current			—				26,803				—				—				26,803
Commodity derivative instruments - noncurrent			—				8,423				—				—				8,423
Total assets measured at fair value		$	2,835			$	82,528			$	—			$	—			$	85,363
Liabilities:
Commodity derivative instruments - current		$	—			$	25,803			$	—			$	—			$	25,803
Commodity derivative instruments - noncurrent			—				2,263				—				—				2,263
Total liabilities measured at fair value		$	—			$	28,066			$	—			$	—			$	28,066
* Invested in mutual funds.

 

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		Fair Value Measurements at September 30, 2009, Using
		Quoted Prices in Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Collateral Provided to Counterparties				Balance at September 30, 2009
		(In thousands)
Assets:
Money market funds		$	50,608			$	—			$	—			$	—			$	50,608
Available-for-sale securities			33,587				11,400				—				—				44,987
Commodity derivative instruments - current			—				28,421				—				—				28,421
Commodity derivative instruments - noncurrent			—				2,894				—				—				2,894
Total assets measured at fair value		$	84,195			$	42,715			$	—			$	—			$	126,910
Liabilities:
Commodity derivative instruments - current		$	—			$	49,308			$	—			$	4,405			$	44,903
Commodity derivative instruments - noncurrent			—				10,357				—				—				10,357
Total liabilities measured at fair value		$	—			$	59,665			$	—			$	4,405			$	55,260

		Fair Value Measurements at December 31, 2009, Using
		Quoted Prices in Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Collateral Provided to Counterparties				Balance at December 31, 2009
		(In thousands)
Assets:
Money market funds		$	9,124			$	151,000			$	—			$	—			$	160,124
Available-for-sale securities			9,078				37,141				—				—				46,219
Commodity derivative instruments - current			—				7,761				—				—				7,761
Commodity derivative instruments - noncurrent			—				2,734				—				—				2,734
Total assets measured at fair value		$	18,202			$	198,636			$	—			$	—			$	216,838
Liabilities:
Commodity derivative instruments - current		$	—			$	36,907			$	—			$	—			$	36,907
Commodity derivative instruments - noncurrent			—				4,870				—				—				4,870
Total liabilities measured at fair value		$	—			$	41,777			$	—			$	—			$	41,777

 

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The estimated fair value of the Company’s Level 1 money market funds is determined using the market approach and is valued at the net asset value of shares held by the Company, based on published market quotations in active markets.

The estimated fair value of the Company’s Level 1 available-for-sale securities is determined using the market approach and is based on quoted market prices in active markets for identical equity and fixed-income securities.

The estimated fair value of the Company’s Level 2 money market funds and available-for-sale securities is determined using the market approach. The Level 2 money market funds consist of investments in short-term unsecured promissory notes and the value is based on comparable market transactions taking into consideration the credit quality of the issuer. The estimated fair value of the Company’s Level 2 available-for-sale securities is based on comparable market transactions.

The estimated fair value of the Company’s Level 2 commodity derivative instruments is based upon futures prices, volatility and time to maturity, among other things. Counterparty statements are utilized to determine the value of the commodity derivative instruments and are reviewed and corroborated using various methodologies and significant observable inputs. The nonperformance risk of the counterparties in addition to the Company’s nonperformance risk is also evaluated.

Though the Company believes the methods used to estimate fair value are consistent with those used by other market participants, the use of other methods or assumptions could result in a different estimate of fair value.

The Company’s long-term debt is not measured at fair value on the Consolidated Balance Sheets and the fair value is being provided for disclosure purposes only. The estimated fair value of the Company’s long-term debt was based on quoted market prices of the same or similar issues. The estimated fair value of the Company's long-term debt was as follows:

		Carrying Amount				Fair Value
		(In thousands)
Long-term debt at September 30, 2010		$	1,510,588			$	1,679,979
Long-term debt at September 30, 2009		$	1,499,623			$	1,540,656
Long-term debt at December 31, 2009		$	1,499,306			$	1,566,331

The carrying amounts of the Company's remaining financial instruments included in current assets and current liabilities approximate their fair values.

14.	Business segment data

The Company’s reportable segments are those that are based on the Company’s method of internal reporting, which generally segregates the strategic business units due to differences in products, services and regulation. The vast majority of the Company’s operations are located within the United States. The Company also has investments in foreign countries, which largely consist of Centennial Resources’ equity method investment in the Brazilian Transmission Lines.

 

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The electric segment generates, transmits and distributes electricity in Montana, North Dakota, South Dakota and Wyoming. The natural gas distribution segment distributes natural gas in those states as well as in Idaho, Minnesota, Oregon and Washington. These operations also supply related value-added products and services.

The construction services segment specializes in constructing and maintaining electric and communication lines, gas pipelines, fire suppression systems, and external lighting and traffic signalization equipment. This segment also provides utility excavation services and inside electrical wiring, cabling and mechanical services, sells and distributes electrical materials, and manufactures and distributes specialty equipment.

The pipeline and energy services segment provides natural gas transportation, underground storage and gathering services through regulated and nonregulated pipeline systems primarily in the Rocky Mountain and northern Great Plains regions of the United States. This segment also provides cathodic protection and other energy-related services.

The natural gas and oil production segment is engaged in natural gas and oil acquisition, exploration, development and production activities in the Rocky Mountain and Mid-Continent regions of the United States and in and around the Gulf of Mexico.

The construction materials and contracting segment mines aggregates and markets crushed stone, sand, gravel and related construction materials, including ready-mixed concrete, cement, asphalt, liquid asphalt and other value-added products. It also performs integrated contracting services. This segment operates in the central, southern and western United States and Alaska and Hawaii.

The Other category includes the activities of Centennial Capital, which insures various types of risks as a captive insurer for certain of the Company’s subsidiaries. The function of the captive insurer is to fund the deductible layers of the insured companies’ general liability and automobile liability coverages. Centennial Capital also owns certain real and personal property. The Other category also includes Centennial Resources' equity method investment in the Brazilian Transmission Lines.

 

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The information below follows the same accounting policies as described in Note 1 of the Company’s Notes to Consolidated Financial Statements in the 2009 Annual Report. Information on the Company's businesses was as follows:

Three Months Ended September 30, 2010		External Operating Revenues				Inter- segment Operating Revenues				Earnings on Common Stock
		(In thousands)
Electric		$	59,966			$	—			$	11,259
Natural gas distribution			94,336				—				(10,054	)
Pipeline and energy services			69,300				11,940				(7,370	)
			223,602				11,940				(6,165	)
Construction services			210,362				137				5,990
Natural gas and oil production			79,276				27,739				18,717
Construction materials and contracting			612,654				—				40,257
Other			29				2,263				2,039
			902,321				30,139				67,003
Intersegment eliminations			—				(42,079	)			—
Total		$	1,125,923			$	—			$	60,838

						Inter-
		External				segment				Earnings
Three Months		Operating				Operating				on Common
Ended September 30, 2009		Revenues				Revenues				Stock
		(In thousands)
Electric		$	51,922			$	—			$	10,148
Natural gas distribution			97,443				—				(9,299	)
Pipeline and energy services			57,502				11,163				10,619
			206,867				11,163				11,468
Construction services			186,404				17				7,305
Natural gas and oil production			92,675				16,752				24,363
Construction materials and contracting			621,981				—				47,502
Other			—				2,677				1,775
			901,060				19,446				80,945
Intersegment eliminations			—				(30,609	)			—
Total		$	1,107,927			$	—			$	92,413

 

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Nine Months Ended September 30, 2010		External Operating Revenues				Inter- segment Operating Revenues				Earnings on Common Stock
		(In thousands)
Electric		$	155,345			$	—			$	22,091
Natural gas distribution			603,499				—				13,362
Pipeline and energy services			197,181				53,168				10,963
			956,025				53,168				46,416
Construction services			551,608				170				9,041
Natural gas and oil production			235,342				90,066				64,963
Construction materials and contracting			1,124,086				—				25,779
Other			83				6,714				5,007
			1,911,119				96,950				104,790
Intersegment eliminations			—				(150,118	)			—
Total		$	2,867,144			$	—			$	151,206

						Inter-				Earnings
		External				segment				(Loss)
Nine Months		Operating				Operating				on Common
Ended September 30, 2009		Revenues				Revenues				Stock
		(In thousands)
Electric		$	147,677			$	—			$	18,477
Natural gas distribution			744,758				—				9,815
Pipeline and energy services			172,626				49,135				27,879
			1,065,061				49,135				56,171
Construction services			651,897				59				22,870
Natural gas and oil production			248,125				72,203				(328,174	)
Construction materials and contracting