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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
Form 10-Q
 
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
 
EXCHANGE ACT OF 1934
 
For the quarterly period ended March 31, 2011.
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 001-31303
 
Black Hills Corporation
Incorporated in South Dakota
IRS Identification Number 46-0458824
625 Ninth Street
Rapid City, South Dakota 57701
 
 
Registrant's telephone number (605) 721-1700
 
 
Former name, former address, and former fiscal year if changed since last report
NONE
 
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
 
Yes x
 
No o
 
 
Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files).
 
Yes x
 
No o
 
 
Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as defined in Rule 12b-2 of the Exchange Act).
 
Large accelerated filer x
 
Accelerated filer o
 
 
Non-accelerated filer o
 
Smaller reporting company o
 
 
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
 
Yes o
 
No x
 
 
Indicate the number of shares outstanding of each of the issuer's classes of common stock as of the latest practicable date.
Class
Outstanding as of
 
April 29, 2011
 
 
 
Common stock, $1.00 par value
39,409,489
 
shares
 

 

 
TABLE OF CONTENTS
 
 
 
Page
 
Glossary of Terms and Abbreviations and Accounting Standards
 
 
 
 
 
PART I.
FINANCIAL INFORMATION
 
 
 
 
 
Item 1.
Financial Statements
 
 
 
 
 
 
Condensed Consolidated Statements of Income - unaudited
 
 
 
   Three Months Ended March 31, 2011 and 2010
 
 
 
 
 
 
Condensed Consolidated Balance Sheets - unaudited
 
 
 
   March 31, 2011, December 31, 2010 and March 31, 2010
 
 
 
 
 
 
Condensed Consolidated Statements of Cash Flows - unaudited
 
 
 
   Three Months Ended March 31, 2011 and 2010
 
 
 
 
 
 
Notes to Condensed Consolidated Financial Statements - unaudited
 
 
 
 
 
Item 2.
Management's Discussion and Analysis of Financial Condition and Results of Operations
 
 
 
 
 
Item 3.
Quantitative and Qualitative Disclosures about Market Risk
 
 
 
 
 
Item 4.
Controls and Procedures
 
 
 
 
 
PART II.
OTHER INFORMATION
 
 
 
 
 
Item 1.
Legal Proceedings
 
 
 
 
 
Item 1A.
Risk Factors
 
 
 
 
 
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
 
 
 
 
 
Item 5.
Other Information
 
 
 
 
 
Item 6.
Exhibits
 
 
 
 
 
 
Signatures
 
 
 
 
 
 
Exhibit Index
 
 
 

2

 

GLOSSARY OF TERMS AND ABBREVIATIONS
AND ACCOUNTING STANDARDS
 
The following terms and abbreviations and accounting standards appear in the text of this report and have the definitions described below:
AFUDC
Allowance for Funds Used During Construction
AOCI
Accumulated Other Comprehensive Income (Loss)
Aquila
Aquila, Inc.
ASC
Accounting Standards Codification
ASC 820
ASC 820, "Fair Value Measurements and Disclosures"
Bbl
Barrel
Bcf
Billion cubic feet
Bcfe
Billion cubic feet equivalent
BHC
Black Hills Corporation
BHCRPP
Black Hills Corporation Risk Policies and Procedures
BHEP
Black Hills Exploration and Production, Inc., representing our Oil and Gas segment, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
Black Hills Electric Generation
Black Hills Electric Generation, LLC, representing our Power Generation segment, a direct wholly-owned subsidiary of Black Hills Non-regulated Holdings
Black Hills Energy
The name used to conduct the business activities of Black Hills Utility Holdings
Black Hills Non-regulated Holdings
Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of the Company that was formerly known as Black Hills Energy, Inc.
Black Hills Power
Black Hills Power, Inc., a direct, wholly-owned subsidiary of the Company
Black Hills Service Company
Black Hills Service Company, a direct wholly-owned subsidiary of the Company
Black Hills Utility Holdings
Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of the Company
Black Hills Wyoming
Black Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Generation
Btu
British thermal unit
CFTC
Commodities Futures and Trading Commission
Cheyenne Light
Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of the Company
Colorado Electric
Black Hills Colorado Electric Utility Company, LP, (doing business as Black Hills Energy), an indirect, wholly-owned subsidiary of Black Hills Utility Holdings
Colorado Gas
Black Hills Colorado Gas Utility Company, LP, (doing business as Black Hills Energy), an indirect, wholly-owned subsidiary of Black Hills Utility Holdings
Colorado IPP
Black Hills Colorado IPP, a direct wholly-owned subsidiary of Black Hills Electric Generation
CPCN
Certificate of Public Convenience and Necessity
CPUC
Colorado Public Utilities Commission
De-designated interest rate swaps
The $250.0 million notional amount interest rate swaps that were originally designated as cash flow hedges under accounting for derivatives and hedges but subsequently de-designated in December 2008
Dodd-Frank
Dodd-Frank Wall Street Reform and Consumer Protection Act
 
 

3

 

 
Dth
Dekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu)
Enserco
Enserco Energy Inc., representing our Energy Marketing segment, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
FASB
Financial Accounting Standards Board
FERC
Federal Energy Regulatory Commission
Forward Agreement
Equity Forward Agreement with J. P. Morgan connected to a public offering of 4,000,000 million shares of Black Hills Corporation common stock
GAAP
Generally Accepted Accounting Principles
Global Settlement
Global settlement with the utilities commission where the dollar figure is agreed upon, but the specific adjustments used by each party to arrive at the figure are not specified in public rate orders
Iowa Gas
Black Hills Iowa Gas Utility Company, LLC, (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
IPP
Independent Power Producer
IRS
Internal Revenue Service
IUB
Iowa Utilities Board
Kansas Gas
Black Hills Kansas Gas Utility Company, LLC, (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
LIBOR
London Interbank Offered Rate
LOE
Lease Operating Expense
Mcf
One thousand standard cubic feet
Mcfe
One thousand standard cubic feet equivalent
MDU
MDU Resources Group, Inc.
MEAN
Municipal Energy Agency of Nebraska
MMBtu
One million British thermal units
MSHA
Mine Safety and Health Administration
MW
Megawatt
MWh
Megawatt-hour
Nebraska Gas
Black Hills Nebraska Gas Utility Company, LLC, (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
NPSC
Nebraska Public Service Commission
NYMEX
New York Mercantile Exchange
OCA
Office of Consumer Advocate
PGA
Purchase Gas Adjustment
PPA
Power Purchase Agreement
PPACA
Patient Protection and Affordability Care Act
PSCo
Public Service Company of Colorado
Revolving Credit Facility
Our $500 million three-year revolving credit facility which commenced on April 15, 2010 and expires on April 14, 2013
SDPUC
South Dakota Public Utilities Commission
SEC
United States Securities and Exchange Commission
WPSC
Wyoming Public Service Commission
WRDC
Wyodak Resources Development Corp., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
 

4

 

 
 
 

BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
 
Three Months Ended March 31,
 
 
 
2011
2010
 
 
 
(in thousands, except per share amounts)
 
 
Operating revenues:
 
 
 
 
Utilities
$
374,696
 
$
388,666
 
 
 
Non-regulated energy
28,604
 
37,834
 
 
 
Total operating revenues
403,300
 
426,500
 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
Utilities -
 
 
 
 
Fuel, purchased power and cost of gas sold
210,511
 
236,314
 
 
 
Operations and maintenance
67,409
 
65,034
 
 
 
Gain on sale of operating assets
 
(2,683
)
 
 
Non-regulated energy operations and maintenance
29,211
 
22,960
 
 
 
Depreciation, depletion and amortization
31,987
 
28,395
 
 
 
Taxes - property, production and severance
8,218
 
6,477
 
 
 
Other operating expenses
251
 
301
 
 
 
Total operating expenses
347,587
 
356,798
 
 
 
 
 
 
 
 
Operating income
55,713
 
69,702
 
 
 
 
 
 
 
 
Other income (expense):
 
 
 
 
Interest charges -
 
 
 
 
Interest expense (including amortization of debt issuance costs, premium and discount, realized settlements on interest rate swaps)
(29,735
)
(25,120
)
 
 
Allowance for funds used during construction - borrowed
3,363
 
3,148
 
 
 
Capitalized interest
2,434
 
206
 
 
 
Interest rate swaps - unrealized (loss) gain
5,465
 
(3,035
)
 
 
Interest income
560
 
246
 
 
 
Allowance for funds used during construction - equity
295
 
2,028
 
 
 
Other income, net
731
 
418
 
 
 
Total other income (expense)
(16,887
)
(22,109
)
 
 
 
 
 
 
 
Income (loss) from continuing operations before equity in earnings (loss) of unconsolidated subsidiaries and income taxes
38,826
 
47,593
 
 
 
Equity in earnings (loss) of unconsolidated subsidiaries
993
 
317
 
 
 
Income tax benefit (expense)
(12,909
)
(16,476
)
 
 
 
 
 
 
 
Net income (loss)
$
26,910
 
$
31,434
 
 
 
 
 
 
 
 
Weighted average common shares outstanding:
 
 
 
 
Basic
39,059
 
38,848
 
 
 
Diluted
39,761
 
39,009
 
 
 
 
 
 
 
 
Total earnings (loss) per share - basic
$
0.69
 
$
0.81
 
 
 
 
 
 
 
 
Total earnings (loss) per share - diluted
$
0.68
 
$
0.81
 
 
 
 
 
 
 
 
Dividends paid per share of common stock
$
0.365
 
$
0.360
 
 
 
 
The accompanying notes to condensed consolidated financial statements are an integral part of these condensed consolidated financial statements.

5

 

BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
 
 
March 31,
2011
 
December 31,
2010
 
March 31,
2010
 
(in thousands)
ASSETS
 
 
 
 
 
Current assets:
 
 
 
 
 
Cash and cash equivalents
$
44,016
 
 
$
32,438
 
 
$
136,023
 
Restricted cash
3,406
 
 
4,260
 
 
27,215
 
Accounts receivable, net
306,070
 
 
328,811
 
 
242,189
 
Materials, supplies and fuel
69,341
 
 
139,677
 
 
91,111
 
Derivative assets, current
49,295
 
 
56,572
 
 
54,773
 
Income tax receivable, net
23,665
 
 
 
 
 
Deferred income tax assets, current
18,362
 
 
17,113
 
 
5,610
 
Regulatory assets, current
36,834
 
 
66,429
 
 
42,876
 
Other current assets
60,804
 
 
25,571
 
 
26,189
 
Total current assets
611,793
 
 
670,871
 
 
625,986
 
 
 
 
 
 
 
Investments
17,088
 
 
17,780
 
 
18,466
 
 
 
 
 
 
 
Property, plant and equipment
3,461,559
 
 
3,359,762
 
 
3,045,126
 
Less accumulated depreciation and depletion
(889,031
)
 
(864,329
)
 
(830,423
)
Total property, plant and equipment, net
2,572,528
 
 
2,495,433
 
 
2,214,703
 
 
 
 
 
 
 
Other assets:
 
 
 
 
 
Goodwill
354,831
 
 
354,831
 
 
353,734
 
Intangible assets, net
4,011
 
 
4,069
 
 
4,248
 
Derivative assets, non-current
5,135
 
 
9,260
 
 
5,877
 
Regulatory assets, non-current
140,735
 
 
138,405
 
 
117,561
 
Other assets, non-current
20,907
 
 
20,860
 
 
18,064
 
Total other assets
525,619
 
 
527,425
 
 
499,484
 
 
 
 
 
 
 
TOTAL ASSETS
$
3,727,028
 
 
$
3,711,509
 
 
$
3,358,639
 
 
The accompanying notes to condensed consolidated financial statements are an integral part of these condensed consolidated financial statements.
 
 

6

 

 
BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Continued)
(unaudited)
 
 
March 31,
2011
 
December 31,
2010
 
March 31,
2010
 
(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDERS' EQUITY
 
 
 
 
 
Current liabilities:
 
 
 
 
 
Accounts payable
$
217,559
 
 
$
279,069
 
 
$
194,342
 
Accrued liabilities
141,184
 
 
170,301
 
 
140,939
 
Derivative liabilities, current
91,139
 
 
79,167
 
 
68,834
 
Accrued income taxes, net
 
 
779
 
 
10,568
 
Regulatory liabilities, current
15,004
 
 
3,943
 
 
9,850
 
Notes payable
287,000
 
 
249,000
 
 
223,000
 
Current maturities of long-term debt
4,254
 
 
5,181
 
 
24,426
 
Total current liabilities
756,140
 
 
787,440
 
 
671,959
 
 
 
 
 
 
 
Long-term debt, net of current maturities
1,184,830
 
 
1,186,050
 
 
993,514
 
 
 
 
 
 
 
Deferred credits and other liabilities:
 
 
 
 
 
Deferred income tax liability, non-current
303,647
 
 
277,136
 
 
270,079
 
Derivative liabilities, non-current
15,554
 
 
21,361
 
 
12,081
 
Regulatory liabilities, non-current
90,923
 
 
84,611
 
 
44,788
 
Benefit plan liabilities
128,170
 
 
124,709
 
 
144,199
 
Other deferred credits and other liabilities
134,617
 
 
129,932
 
 
114,021
 
Total deferred credits and other liabilities
672,911
 
 
637,749
 
 
585,168
 
 
 
 
 
 
 
Stockholders' equity:
 
 
 
 
 
Common stockholders' equity —
 
 
 
 
 
Common stock $1 par value; 100,000,000 shares authorized; Issued 39,434,304; 39,280,048 and 39,178,067 shares, respectively
39,434
 
 
39,280
 
 
39,178
 
Additional paid-in capital
601,021
 
 
598,805
 
 
593,589
 
Retained earnings
498,614
 
 
486,075
 
 
491,202
 
Treasury stock at cost – 26,075; 10,962 and 4,284 shares, respectively
(762
)
 
(309
)
 
(112
)
Accumulated other comprehensive loss
(25,160
)
 
(23,581
)
 
(15,859
)
Total stockholders' equity
1,113,147
 
 
1,100,270
 
 
1,107,998
 
 
 
 
 
 
 
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY
$
3,727,028
 
 
$
3,711,509
 
 
$
3,358,639
 
 
The accompanying notes to condensed consolidated financial statements are an integral part of these condensed consolidated financial statements.

7

 

BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
 
Three Months Ended March 31,
 
2011
 
2010
Operating activities:
(in thousands)
 
 
 
 
Net income (loss)
$
26,910
 
 
$
31,434
 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation, depletion and amortization
31,987
 
 
28,395
 
Derivative fair value adjustments
9,662
 
 
(1,579
)
Gain on sale of operating assets
 
 
(2,683
)
Stock compensation
2,370
 
 
989
 
Unrealized mark-to-market loss (gain) on interest rate swaps
(5,465
)
 
3,035
 
Deferred income taxes
25,679
 
 
3,492
 
Equity in (earnings) loss of unconsolidated subsidiaries
(993
)
 
(317
)
Allowance for funds used during construction - equity
(295
)
 
(2,028
)
Employee benefit plans
3,642
 
 
3,940
 
Other adjustments
(1,599
)
 
2,382
 
 
 
 
 
Change in operating assets and liabilities:
 
 
 
Materials, supplies and fuel
79,717
 
 
21,755
 
Accounts receivable and other current assets
(35,605
)
 
24,044
 
Accounts payable and other current liabilities
(73,302
)
 
(24,716
)
Regulatory assets
33,966
 
 
3,277
 
Regulatory liabilities
9,984
 
 
2,834
 
 
 
 
 
Other operating activities
4,613
 
 
(5,335
)
Net cash provided by operating activities
111,271
 
 
88,919
 
 
 
 
 
Investing activities:
 
 
 
Property, plant and equipment additions
(122,544
)
 
(81,290
)
Proceeds from sale of ownership interest in operating assets
 
 
6,105
 
Other investing activities
786
 
 
(2,865
)
Net cash used in investing activities
(121,758
)
 
(78,050
)
 
 
 
 
Financing activities:
 
 
 
Dividends paid
(14,371
)
 
(14,089
)
Common stock issued
605
 
 
1,522
 
Short-term borrowings - issuances
210,000
 
 
108,500
 
Short-term borrowings - repayments
(172,000
)
 
(50,000
)
Long-term debt - repayments
(2,155
)
 
(33,217
)
Other financing activities
(14
)
 
(463
)
Net cash provided by (used in) financing activities
22,065
 
 
12,253
 
 
 
 
 
Net change in cash and cash equivalents
11,578
 
 
23,122
 
 
 
 
 
Cash and cash equivalents beginning of period
32,438
 
 
112,901
 
Cash and cash equivalents end of period
$
44,016
 
 
$
136,023
 
 
The accompanying notes to condensed consolidated financial statements are an integral part of these condensed consolidated financial statements.

8

 

BLACK HILLS CORPORATION
 
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Reference is made to Notes to Consolidated Financial Statements
included in the Company's 2010 Annual Report on Form 10-K)
 
 

 
(1)     MANAGEMENT'S STATEMENT
 
The condensed consolidated financial statements included herein have been prepared by Black Hills Corporation (the "Company," "us," "we," or "our") without audit, pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to such rules and regulations; however, we believe that the footnotes adequately disclose the information presented. These condensed quarterly financial statements should be read in conjunction with the financial statements and the notes thereto, included in our 2010 Annual Report on Form 10-K filed with the SEC.
 
Accounting methods historically employed require certain estimates as of interim dates. The information furnished in the accompanying condensed quarterly financial statements reflects all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the March 31, 2011, December 31, 2010 and March 31, 2010 financial information and are of a normal recurring nature. Certain industries in which we operate are highly seasonal and revenues from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements, as well as changes in market price. In particular, the normal peak usage season for gas utilities is November through March and significant earnings variances can be expected between the Gas Utilities segment's peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three months ended March 31, 2011 and our financial condition as of March 31, 2011, December 31, 2010, and March 31, 2010 are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted.
 
Certain prior year data presented in the financial statements have been reclassified to conform to the current year presentation. Specifically, (a) the Company has reclassified revenue into two categories:  utilities revenue and non-regulated revenues, (b) the categories of Fuel, purchased power and cost of gas sales and Operations and maintenance included in our Operating expenses have also been reclassified into utilities and non-regulated, and (c) the Taxes - property, production and severance line has been reclassified to show only those taxes. Any taxes other than income are now included in the respective utility or non-regulated operations and maintenance lines. These reclassifications had no effect on total assets, net income, cash flows or earnings per share.
 
Restatement - Subsequent to the issuance of the Company's 2010 financial statements, the Company's management determined that certain intercompany transactions with our rate regulated operations had not been properly eliminated in consolidation, resulting in an overstatement of Utility and Non-regulated revenue and Fuel, purchased power and cost of gas sold of $15.8 million, in aggregate for the three months ended March 31, 2010, respectively.  As such, the condensed consolidated financial statements have been restated for the correction of this error.  The error did not have an impact on our gross margin, net income, total assets or cash flows.
 
 
 

9

 

(2)    RECENTLY ADOPTED AND RECENTLY ISSUED ACCOUNTING STANDARDS AND LEGISLATION
 
Recently Adopted Accounting Standards
 
Fair Value Measurements, ASC 820
 
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, disclosure of inputs and techniques used in valuation and a description of the reason for such transfers. In the reconciliation for Level 3 fair value measurements using significant unobservable inputs, information about purchases, sales, issuances and settlements are required to be presented separately. These disclosures are required for interim and annual reporting periods and were effective for us 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 were effective on January 1, 2011. The guidance requires additional disclosures, but did not impact our financial position, results of operations or cash flows. The additional disclosures are included in Note 13.
 
Recently Issued Accounting Standards and Legislation
 
Patient Protection and Affordable Care Act
 
In March 2010, the President of the United States signed into law comprehensive healthcare reform legislation under the PPACA as amended by the Healthcare and Education Reconciliation Act. The potential impact on the Company, if any, cannot be determined until regulations are promulgated under the PPACA.  Included among the provisions of the PPACA is a change in the tax treatment of the Medicare Part D subsidy (the "subsidy") which affects our Non-Pension Postretirement Benefit Plan. Internal Revenue Code Section 139A has been amended to eliminate the deduction of the subsidy in reducing income for years beginning after December 31, 2012. The impact of this change in the tax treatment of the subsidy had an immaterial effect on our financial position, results of operations and cash flows. The Company will continue to assess the accounting implications of the PPACA as related regulations and interpretations become available.
 
Dodd-Frank Wall Street Reform and Consumer Protection Act
 
In July 2010, the President of the United States signed into law comprehensive financial reform legislation under Dodd-Frank. Title VII of Dodd-Frank effectively regulates many derivative transactions in the United States that were previously unregulated, including swap transactions in the over-the-counter market. Among other things, Dodd-Frank (i) mandates the clearing of some swaps through regulated central clearing organizations and the trading of clearing swaps through regulated exchanges or swap execution facilities, in each case subject to certain key exemptions, and (ii) authorizes regulators to establish collateral and margin requirements for certain swap transactions that are not cleared. Dodd-Frank provides for a potential exception from these clearing and cash collateral requirements for commercial end-users, potentially including utilities, and it includes a number of defined terms that will be used in determining how this exception applies to particular derivative transactions and the parties to those transactions. Significant rule-making by numerous governmental agencies, particularly the CFTC with respect to non-security commodities, will be required over the next several months to implement the restrictions, limitations, and requirements contemplated by Dodd-Frank, and we will continue to evaluate the impact as these rules become available.
 
(3)    SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
 
 
Three Months Ended
 
March 31,
2011
 
March 31,
2010
 
(in thousands)
Non-cash investing activities—
 
 
 
Property, plant and equipment acquired with accrued liabilities
$
32,419
 
 
$
23,473
 
Cash (paid) refunded during the period for—
 
 
 
Interest (net of amounts capitalized)
$
(11,817
)
 
$
(10,182
)
Income taxes, net
$
(24
)
 
$
44
 
 

10

 

(4)    MATERIALS, SUPPLIES AND FUEL
 
The amounts of materials, supplies and fuel included on the accompanying Condensed Consolidated Balance Sheets, by major classification, were as follows (in thousands):
 
 
 
March 31,
2011
 
December 31,
2010
 
March 31,
2010
Materials and supplies
 
$
34,341
 
 
$
31,749
 
 
$
32,200
 
Fuel - Electric Utilities
 
9,307
 
 
9,687
 
 
9,028
 
Natural gas in storage — Gas Utilities
 
2,199
 
 
21,691
 
 
4,868
 
Gas and oil held by Energy Marketing*
 
23,494
 
 
76,550
 
 
45,015
 
Total materials, supplies and fuel
 
$
69,341
 
 
$
139,677
 
 
$
91,111
 
_____________
* As of March 31, 2011, December 31, 2010 and March 31, 2010, market adjustments related to natural gas held by Energy Marketing and recorded in inventory as part of fair value hedge transactions were $0.3 million, $(9.1) million and $(11.0) million, respectively (see Note 12 for further discussion of Energy Marketing trading activities).
 
(5)    ACCOUNTS RECEIVABLE
 
Trade Accounts Receivable
 
Our Accounts receivable represents primarily customer trade accounts at our Electric Utilities, Gas Utilities and counterparty trade accounts at our Energy Marketing segment. This balance fluctuates primarily due to the seasonality of our Gas Utilities and volumes and commodity prices at our Energy Marketing segment. We maintain an allowance for doubtful accounts which reflects our best estimate of potentially uncollectible trade accounts receivables. We regularly review our trade receivable allowances by considering such factors as historical experience, credit-worthiness, the age of the accounts receivable balances and current economic conditions that may affect our ability to collect.
 
Following is a summary of receivables (in thousands):
 
March 31, 2011
Accounts Receivable, Trade
Unbilled Revenues
Total Accounts Receivable
Less Allowance for Doubtful Accounts
Accounts Receivable, net
Electric
$
46,077
 
$
16,196
 
$
62,273
 
$
(728
)
$
61,545
 
Gas
58,665
 
21,620
 
80,285
 
(1,763
)
78,522
 
Oil and Gas
7,503
 
 
7,503
 
(161
)
7,342
 
Coal Mining
982
 
 
982
 
 
982
 
Energy Marketing
154,660
 
 
154,660
 
(114
)
154,546
 
Power Generation
2,050
 
 
2,050
 
 
2,050
 
Corporate
1,083
 
 
1,083
 
 
1,083
 
Total
$
271,020
 
$
37,816
 
$
308,836
 
$
(2,766
)
$
306,070
 
 
December 31, 2010
Accounts Receivable, Trade
Unbilled Revenues
Total Accounts Receivable
Less Allowance for Doubtful Accounts
Accounts Receivable, net
Electric
$
51,005
 
$
19,572
 
$
70,577
 
$
(708
)
$
69,869
 
Gas
41,970
 
40,376
 
82,346
 
(1,425
)
80,921
 
Oil and Gas
6,213
 
 
6,213
 
(161
)
6,052
 
Coal Mining
2,420
 
 
2,420
 
 
2,420
 
Energy Marketing
157,064
 
 
157,064
 
(69
)
156,995
 
Power Generation
307
 
 
307
 
 
307
 
Corporate
12,247
 
 
12,247
 
 
12,247
 
Total
$
271,226
 
$
59,948
 
$
331,174
 
$
(2,363
)
$
328,811
 
 
March 31, 2010
Accounts Receivable, Trade
Unbilled Revenues
Total Accounts Receivable
Less Allowance for Doubtful Accounts
Accounts Receivable, net
Electric
$
45,466
 
$
13,415
 
$
58,881
 
$
(1,346
)
$
57,535
 
Gas
60,076
 
19,977
 
80,053
 
(2,877
)
77,176
 
Oil and Gas
6,144
 
 
6,144
 
 
6,144
 
Coal Mining
1,698
 
 
1,698
 
 
1,698
 
Energy Marketing
99,738
 
 
99,738
 
(1,008
)
98,730
 
Power Generation
569
 
 
569
 
 
569
 
Corporate
337
 
 
337
 
 
337
 
Total
$
214,028
 
$
33,392
 
$
247,420
 
$
(5,231
)
$
242,189
 
 
Income Tax Receivable
 
Income tax receivable is primarily comprised of the refund (including an estimate of after-tax interest income) to be received as a result of the settlement reached with IRS in mid-2010 and finalized in early 2011 and estimated payments made at the federal, state, and foreign levels. With respect to the estimated payments, they relate to multiple prior tax years and were included in taxes payable at both March 31, 2010 and December 31, 2010. 
  
 
(6)    NOTES PAYABLE
 
Our credit facilities and debt securities contain certain restrictive covenants including, among others, recourse leverage ratios and consolidated net worth covenants. As of March 31, 2011, we were in compliance with these covenants. None of our facilities or debt securities contain default provisions pertaining to our credit ratings.
 
Revolving Credit Facility
 
In April 2010, we entered into a new $500.0 million Revolving Credit Facility expiring April 14, 2013. The facility contains an accordion feature which allows us to, with the consent of the administrative agent, increase the capacity of the facility to $600.0 million. This facility can be used for the issuance of letters of credit, to fund working capital needs and for other corporate purposes. Borrowings are available under a base rate option or a Eurodollar option. The cost of borrowings or letters of credit is determined based upon our credit ratings. At current ratings levels, the margins for base rate borrowings, Eurodollar borrowings and letters of credit are 1.75%, 2.75% and 2.75%, respectively at March 31, 2011. The facility contains a commitment fee to be charged on the unused amount of the facility. Based upon current credit ratings, the fee is 0.5%.
 
Deferred financing costs of $4.7 million are being amortized over the term of the facility and the amortization expense is included in Interest expense on the accompanying Condensed Consolidated Statements of Income as follows (in thousands):
 
 
Three Months Ended March 31,
 
 
 
2011
2010
 
 
Amortization Expense
$
473
 
$
 
 
 
 
The Revolving Credit Facility includes the following covenants that we must comply with at the end of each quarter (dollars, in thousands). We were in compliance with these covenants as of March 31, 2011.
 
 
 
Actual
 
Covenant Requirement
Consolidated Net Worth
 
$
1,113
 
 
$
873
 
Recourse leverage ratio
 
57.8
%
 
65.0
%
 

11

 

Enserco Credit Facility
 
In May 2010, Enserco entered into an agreement for a two-year $250.0 million committed credit facility. The facility contains an accordion feature which allows Enserco, with the consent of the administrative agent, to increase commitments under the facility to $350.0 million. Maximum borrowings under the facility are subject to a sub-limit of $50 million. Borrowings under this facility are available under a base rate option or a Eurodollar option. Margins for base rate borrowings are 1.75% and for Eurodollar borrowings are 2.50%. The facility covenants include tangible net worth, net working capital and realized net working capital requirements. Enserco was in compliance with the covenants of this facility as of March 31, 2011.
 
At March 31, 2011, $147.1 million of letters of credit were issued and outstanding under this facility and there were no cash borrowings outstanding.
 
Deferred financing costs of $2.1 million were recorded for the Enserco Credit Facility and are being amortized over the term of the facility. Amortization of deferred financing costs included in Interest expense on the accompanying Condensed Consolidated Statements of Income was as follows (in thousands):
 
 
Three Months Ended March 31,
 
 
 
2011
2010
 
 
Amortization expense
$
268
 
$
533
 
 
 
 
Corporate Term Loan
 
In December 2010, we entered into a one-year $100.0 million term loan (the "Loan") with J.P. Morgan and Union Bank due in December 2011. The cost of borrowing under the Loan was based on a spread of 137.5 basis points over LIBOR (1.69% at March 31, 2011). The covenants are substantially the same as those which are included in the Revolving Credit Facility. We were in compliance with these covenants as of March 31, 2011.
 

12

 

(7)    EARNINGS PER SHARE
 
Basic earnings per share are computed by dividing net income by the weighted-average number of common shares outstanding during the period. Diluted earnings per share are computed by using all dilutive common shares potentially outstanding during a period. A reconciliation of Net income and basic and diluted share amounts, used to compute earnings per share, is as follows (in thousands, except per share amounts):
 
Period Ended March 31, 2011
 
Three Months
 
 
 
 
Income
 
Average Shares
 
 
 
 
Net income
 
$
26,910
 
 
39,059
 
 
 
 
 
Dilutive effect of:
 
 
 
 
 
 
 
 
Restricted stock
 
 
 
132
 
 
 
 
 
Options
 
 
 
17
 
 
 
 
 
Forward Equity Issuance
 
 
 
460
 
 
 
 
 
Other
 
 
 
93
 
 
 
 
 
Diluted earnings
 
$
26,910
 
 
39,761
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Diluted earnings per share
 
$
0.68
 
 
 
 
 
 
 
 

13

 

Period Ended March 31, 2010
 
Three Months
 
 
 
 
Income
 
Average Shares
 
 
 
 
Net income
 
$
31,434
 
 
38,848
 
 
 
 
 
Dilutive effect of:
 
 
 
 
 
 
 
 
Restricted stock
 
 
 
89
 
 
 
 
 
Options
 
 
 
 
 
 
 
 
Other
 
 
 
72
 
 
 
 
 
Diluted earnings
 
$
31,434
 
 
39,009
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Diluted earnings per share
 
$
0.81
 
 
 
 
 
 
 
 
The following outstanding securities were not included in the computation of diluted earnings per share as their effect would have been anti-dilutive (in thousands):
 
 
Three Months Ended March 31,
 
 
 
2011
 
2010
 
 
 
 
Options to purchase common stock
83
 
 
264
 
 
 
 
 
Restricted stock
7
 
 
 
 
 
 
 
 
90
 
 
264
 
 
 
 
 
 
(8)    COMPREHENSIVE INCOME (LOSS)
 
The following table presents the components of our other comprehensive income (loss) (in thousands):
 
 
Three Months Ended March 31, 2011
Net income
 
 
$
26,910
 
Other comprehensive income (loss), net of tax:
 
 
 
Fair value adjustment on derivatives designated as cash flow hedges
$
(3,785
)
 
 
Taxes
1,637
 
 
 
Fair value adjustment on derivatives designated as cash flow hedges, net of tax
 
 
(2,148
)
 
 
 
 
Reclassification adjustments on cash flow hedges settled and included in net income (loss)
$
861
 
 
 
Taxes
(292
)
 
 
Reclassification adjustments on cash flow hedges settled and included in net income (loss), net of tax
 
 
569
 
 
 
 
 
Comprehensive income
 
 
$
25,331
 
 
 

14

 

 
Three Months Ended March 31, 2010
Net income
 
 
$
31,434
 
Other comprehensive income (loss), net of tax:
 
 
 
Minimum pension liability adjustments
$
19
 
 
 
Taxes
(7
)
 
 
Minimum pension liability adjustments, net of tax
 
 
12
 
 
 
 
 
Fair value adjustment on derivatives designated as cash flow hedges
$
2,007
 
 
 
Taxes
(591
)
 
 
Fair value adjustment on derivatives designated as cash flow hedges, net of tax
 
 
1,416
 
 
 
 
 
Reclassification adjustments on cash flow hedges settled and included in net income (loss)
$
2,938
 
 
 
Taxes
(1,061
)
 
 
Reclassification adjustments on cash flow hedges settled and included in net income (loss), net of tax
 
 
1,877
 
 
 
 
 
Comprehensive income
 
 
$
34,739
 
 
Balances by classification included within Accumulated other comprehensive loss on the accompanying Condensed Consolidated Balance Sheets are as follows (in thousands):
 
 
March 31,
2011
December 31,
2010
March 31,
2010
Derivatives designated as cash flow hedges
$
(14,016
)
$
(12,437
)
$
(6,182
)
Employee benefit plans
(11,142
)
(11,142
)
(9,624
)
Amount from equity-method investees
(2
)
(2
)
(53
)
Total
$
(25,160
)
$
(23,581
)
$
(15,859
)
 
(9)     COMMON STOCK
 
Other than the following transactions, we had no material changes in our common stock during the first three months of 2011 from the amount reported in Note 11 of the Notes to Consolidated Financial Statements in our 2010 Annual Report on Form 10-K.
 
Equity Compensation Plans
 
We granted 67,389 target performance shares to certain officers and business unit leaders for the January 1, 2011 through December 31, 2013 performance period. Actual shares are not issued until the end of the performance plan period (December 31, 2013). Performance shares are awarded based on our total stockholder return over the designated performance period as measured against a selected peer group and can range from 0% to 175% of target. In addition, certain stock price performance must be achieved for a payout to occur. The final value of the performance shares will vary according to the number of shares of common stock that are ultimately granted based upon the actual level of attainment of the performance criteria. The performance awards are paid 50% in the form of cash and 50% in shares of common stock. The grant date fair value was $25.91 per share.
 
We issued 14,111 shares of common stock under the 2010 short-term incentive compensation plan during the three months ended March 31, 2011. Pre-tax compensation cost related to the awards was approximately $0.4 million, which was accrued for in 2010.

15

 

 
We granted 125,963 restricted common shares during the three months ended March 31, 2011. The pre-tax compensation cost related to the awards of restricted stock and restricted stock units of approximately $3.8 million will be recognized over the three-year vesting period.
 
2,500 stock options were exercised during the three months ended March 31, 2011 at a weighted-average exercise price of $30.81 per share which provided $0.1 million of proceeds.
 
Total compensation expense recognized for all equity compensation plans for the three months ended March 31, 2011 and 2010 was $2.4 million and $1.8 million, respectively.
 
As of March 31, 2011, total unrecognized compensation expense related to non-vested stock awards was $11.0 million and is expected to be recognized over a weighted-average period of 2.2 years.
 
Dividend Reinvestment and Stock Purchase Plan
 
We have a Dividend Reinvestment and Stock Purchase Plan ("DRIP") under which stockholders may purchase additional shares of common stock through dividend reinvestment and/or optional cash payments at 100% of the recent average market price. We have the option of issuing new shares or purchasing the shares on the open market. We issued 25,026 new shares at a weighted-average price of $31.07 during the three months ended March 31, 2011. At March 31, 2011, 164,667 shares of unissued common stock were available for future offering under the DRIP Plan.
 
Dividend Restrictions
 
Our Revolving Credit Facility contains restrictions on the payment of cash dividends upon a default or event of default. An event of default would be deemed to have occurred if we did not meet certain financial covenants. The most restrictive financial covenants include the following: a recourse leverage ratio not to exceed 0.65 to 1.00 and a minimum consolidated net worth of $625 million plus 50% of aggregate consolidated net income, if positive, since January 1, 2005. As of March 31, 2011, we were in compliance with the above covenants.
 
Due to our holding company structure, substantially all of our operating cash flows are provided by dividends paid or distributions made by our subsidiaries. The cash to pay dividends to our shareholders is derived from these cash flows. As a result, certain statutory limitations or regulatory or financing agreements could affect the levels of distributions allowed to be made by our subsidiaries. The following restrictions on distributions from our subsidiaries existed as of March 31, 2011:
 
Our utility subsidiaries are generally limited to the amount of dividends allowed by state regulatory authorities to be paid to us as a utility holding company and also may be subject to further restrictions under the Federal Power Act. As of March 31, 2011, the restricted net assets at our Utilities Group were approximately $193.7 million.
 
Our Enserco Credit Facility is a borrowing base credit facility, the structure of which requires certain levels of tangible net worth and net working capital to be maintained for a given borrowing base election level. In order to maintain a borrowing base election level, Enserco may be restricted from making dividend payments to its parent company. Enserco's restricted net assets at March 31, 2011 were $86.2 million.
 
Pursuant to a covenant in the Black Hills Wyoming project financing, Black Hills Non-regulated Holdings has restricted assets of $100.0 million. Black Hills Non-regulated Holdings is the parent of Black Hills Electric Generation which is the parent of Black Hills Wyoming.
 

16

 

Forward Equity Issuance
 
In November 2010, we entered into a Forward Agreement with J.P. Morgan in connection with a public offering of 4,000,000 shares of Black Hills Corporation common stock. Under the Forward Agreement on November 10, 2010, we agreed to issue to J.P. Morgan 4,000,000 shares of our common stock at an initial forward price of $28.70875 per share. On December 7, 2010, the underwriters exercised the over-allotment option to purchase an additional 413,519 shares under the same terms as the original Forward Agreement (together with the Forward Agreement, the "Forward Agreements").
 
Based on the closing Black Hills Corporation common stock price of $33.44 on March 31, 2011, and the forward price on the date for the initial equity forward of $27.95 and over-allotment shares of $27.95, the fair value net cash settlement of the 4,000,000 equity forward instrument and 413,519 over-allotment shares was approximately $24.2 million. The Forward Agreements require a 60-day notice prior to settlement for cash or net share settlements. Forward prices and volume-weighted average market prices for the period between when notice is provided and settlement are used to calculate cash and net share settlement amounts.
 
We may settle the equity forward instrument at any time up to the maturity date of November 10, 2011. We may also unilaterally elect to cash or net share settle on any date up to maturity, for all or a portion of the equity forward shares. It is our intent to settle the equity forward with the physical delivery of shares in the fourth quarter of 2011.
 
At March 31, 2011, the equity forward instrument could have been settled with physical delivery of 4,413,519 shares to J.P. Morgan in exchange for cash of $123.4 million. Assuming required notices were given and actions taken, the forward instruments could have also been net settled at March 31, 2011 with delivery of cash of approximately $23.5 million or approximately 706,000 shares of common stock to J.P. Morgan.
 
(10)     EMPLOYEE BENEFIT PLANS
 
Defined Benefit Pension Plans
 
We have three non-contributory defined benefit pension plans (the "Pension Plans"). One Pension Plan covers certain eligible employees of the following subsidiaries: Black Hills Service Company, Black Hills Power, WRDC and BHEP; one Pension Plan covers certain eligible employees of our subsidiary, Cheyenne Light, and the remaining Pension Plan covers certain eligible employees of Black Hills Energy. The Pension Plan benefits are based on years of service and compensation levels.
 
The components of net periodic benefit cost for the three Plans were as follows (in thousands):
 
 
Three Months Ended March 31,
 
 
 
2011
 
2010
 
 
 
 
Service cost
$
1,355
 
 
$
1,533
 
 
 
 
 
Interest cost
3,732
 
 
3,773
 
 
 
 
 
Expected return on plan assets
(4,239
)
 
(3,623
)
 
 
 
 
Prior service cost
25
 
 
305
 
 
 
 
 
Net loss
1,135
 
 
500
 
 
 
 
 
 
 
 
 
 
 
 
 
Net periodic benefit cost
$
2,008
 
 
$
2,488
 
 
 
 
 
 
Non-pension Defined Benefit Postretirement Healthcare Plans
 
We sponsor three retiree healthcare plans (the "Healthcare Plans"): the Black Hills Corporation Postretirement Healthcare Plan, the Healthcare Plan for Retirees of Cheyenne Light, and the Black Hills Energy Postretirement Healthcare Plan. Employees who participate in the Healthcare Plans and who retire on or after meeting certain eligibility requirements are entitled to postretirement healthcare benefits.
 

17

 

The components of net periodic benefit cost for the Healthcare Plans were as follows (in thousands):
 
 
Three Months Ended March 31,
 
 
 
2011
 
2010
 
 
 
 
Service cost
$
375
 
 
$
377
 
 
 
 
 
Interest cost
542
 
 
611
 
 
 
 
 
Expected return on plan assets
(41
)
 
(52
)
 
 
 
 
Prior service cost (benefit)
(120
)
 
(77
)
 
 
 
 
Net loss (gain)
169
 
 
159
 
 
 
 
 
 
 
 
 
 
 
 
 
Net periodic benefit cost
$
925
 
 
$
1,018
 
 
 
 
 
 
It has been determined that our post-65 retiree drug prescription plans are actuarially equivalent and qualify for the Medicare Part D subsidy.
    
Supplemental Non-qualified Defined Benefit Plans
 
Additionally, we have various supplemental retirement plans for key executives (the "Supplemental Plans"). The Supplemental Plans are non-qualified defined benefit plans.
 
The components of net periodic benefit cost for the Supplemental Plans were as follows (in thousands):
 
 
Three Months Ended March 31,
 
 
 
2011
 
2010
 
 
 
 
Service cost
$
257
 
 
$
171
 
 
 
 
 
Interest cost
324
 
 
321
 
 
 
 
 
Prior service cost
1
 
 
1
 
 
 
 
 
Net loss
127
 
 
71
 
 
 
 
 
 
 
 
 
 
 
 
 
Net periodic benefit cost
$
709
 
 
$
564
 
 
 
 
 
 
Contributions
 
We anticipate that we will make contributions to each of the benefit plans during 2011 and 2012. Contributions to the Healthcare Plans and the Supplemental Plans are expected to be made in the form of benefit payments. Contributions are as follows (in thousands):
 
 
Contributions Made
Anticipated
Anticipated
 
Three Months Ended March 31, 2011
Contributions Remaining for 2011
Contributions for 2012
Defined Benefit Pension Plans
$
 
$
550
 
$
13,431
 
Non-Pension Defined Benefit Postretirement Healthcare Plans
$
882
 
$
2,647
 
$
3,765
 
Supplemental Non-Qualified Defined Benefit Plans
$
235
 
$
707
 
$
896
 
 
 
(11)     SUMMARY OF INFORMATION RELATING TO SEGMENTS OF OUR BUSINESS
 
Our reportable segments are based on our method of internal reporting, which generally segregates the strategic business groups due to differences in products, services and regulation. As of March 31, 2011, substantially all of our operations and assets were located within the United States.

18

 

 
We conduct our operations through the following six reportable segments:
 
Utilities Group —
 
Electric Utilities, which supply electric utility service to areas in South Dakota, Wyoming, Colorado and Montana and natural gas utility service to Cheyenne, Wyoming and vicinity; and
 
Gas Utilities, which supply natural gas utility service in Colorado, Iowa, Kansas and Nebraska.
 
Non-regulated Energy Group —
 
Oil and Gas, which produces, explores and operates oil and natural gas interests located in the Rocky Mountain region and other states;
 
Power Generation, which produces and sells power and capacity to wholesale customers from power plants located in Wyoming. Additionally, in 2009 our Power Generation segment entered into a 20-year PPA to supply Colorado Electric with 200 MW of capacity and energy from power plants under construction in Colorado, which are expected to be placed into service by December 31, 2011. In January 2011, we sold our ownership interest in the partnership which owned the Idaho facilities;
 
Coal Mining, which engages in the mining and sale of coal from our mine near Gillette, Wyoming; and
 
Energy Marketing, which provides natural gas, crude oil, coal, power and environmental marketing and related services in the United States and Canada.
 
Segment information follows the accounting policies described in Note 1 of the Notes to Consolidated Financial Statements in our 2010 Annual Report on Form 10-K.
 
Segment information included in the accompanying Condensed Consolidated Statements of Income and Balance Sheets was as follows (in thousands):
 
Three Months Ended March 31, 2011
 
External
Operating
Revenues
 
Intercompany
Operating
Revenues
 
Net Income (Loss)
Utilities:
 
 
 
 
 
 
   Electric
 
$
144,430
 
 
$
3,839
 
 
$
10,249
 
   Gas
 
230,266
 
 
 
 
19,263
 
Non-regulated Energy:
 
 
 
 
 
 
   Oil and Gas
 
17,906
 
 
 
 
(715
)
   Power Generation
 
687
 
 
6,933
 
 
1,186
 
   Coal Mining
 
7,614
 
 
7,881
 
 
(1,298
)
   Energy Marketing
 
2,397
 
 
68
 
 
(2,641
)
Corporate (a)
 
 
 
 
 
934
 
Intercompany eliminations
 
 
 
(18,721
)
 
(68
)
Total
 
$
403,300
 
 
$
 
 
$
26,910
 
    
 
 

19

 

Three Months Ended March 31, 2010
 
External
Operating
Revenues
 
Intercompany
Operating
Revenues (b)
 
Net Income (Loss)
Utilities:
 
 
 
 
 
 
   Electric
 
$
144,387
 
 
$
4,422
 
 
$
9,852
 
   Gas (c)
 
243,170
 
 
 
 
19,498
 
Non-regulated Energy:
 
 
 
 
 
 
   Oil and Gas  
 
19,743
 
 
 
 
2,348
 
   Power Generation
 
1,334
 
 
6,734
 
 
1,080
 
   Coal Mining
 
6,882
 
 
7,098
 
 
1,346
 
   Energy Marketing
 
9,856
 
 
(84
)
 
2,193
 
Corporate (a)
 
 
 
 
 
(4,967
)
Intercompany eliminations
 
 
 
(17,042
)
 
84
 
Total
 
$
425,372
 
 
$
1,128
 
 
$
31,434
 
    
____________
(a)    Net income (loss) includes a $3.6 million net after-tax mark-to-market gain on interest rate swaps for the three months ended March 31, 2011 and a $2.0 million net after-tax mark-to-market loss on these same interest rate swaps for the three months ended March 31, 2010.
(b)     Total Revenues have been restated to reflect elimination of intercompany activities previously not eliminated. See Note 1 for further discussion.
(c)    Net income (loss) includes a $1.7 million after-tax gain on the sale of operating assets as a result of annexation proceedings by the City of Omaha, Nebraska.
 
Total assets
March 31,
2011
 
December 31,
2010
 
March 31,
2010
Utilities:
 
 
 
 
 
   Electric
$
1,868,600
 
 
$
1,834,019
 
 
$
1,701,329
 
   Gas
683,927
 
 
722,287
 
 
644,734
 
Non-regulated Energy:
 
 
 
 
 
   Oil and Gas
355,357
 
 
349,991
 
 
348,156
 
   Power Generation
336,827
 
 
293,334
 
 
185,856
 
   Coal Mining
94,416
 
 
96,962
 
 
82,776
 
   Energy Marketing
293,544
 
 
314,930
 
 
324,478
 
Corporate
94,357
 
 
99,986
 
 
71,310
 
Total
$
3,727,028
 
 
$
3,711,509
 
 
$
3,358,639
 
 
(12)     RISK MANAGEMENT ACTIVITIES
 
Our activities in the regulated and non-regulated energy sector expose us to a number of risks in the normal operation of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and counterparty risk. We have developed policies, processes, systems, and controls to manage and mitigate these risks.
 
Market risk is the potential loss that might occur as a result of an adverse change in market price or rate. We are exposed to the following market risks:
 
Commodity price risk associated with our marketing businesses, our natural long position with crude oil, natural gas and coal reserves and production, fuel procurement for certain of our gas-fired generation assets and variability in revenue due to changes in gas usage at our Gas Utilities segment and from commodity price changes;
 
Interest rate risk associated with variable rate credit facilities and changes in forward interest rates used to determine the mark-to-market adjustment on our interest rate swaps; and
 
Foreign currency exchange risk associated with marketing transactions in Canadian dollars.
 

20

 

Our exposure to these market risks is affected by a number of factors including the size, duration, and composition of our energy portfolio, the absolute and relative levels of interest rates, currency exchange rates and commodity prices, the volatility of these prices and rates, and the liquidity of the related interest rate and commodity markets.
 
We actively manage our exposure to certain market risks as described in Note 3 of the Notes to our Consolidated Financial Statements in our 2010 Annual Report on Form 10-K. Our derivative and hedging activities included in the accompanying Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Income are detailed in this Note along with Note 13.
 
Trading Activities
 
Energy Marketing
 
We have a natural gas, crude oil, coal, power and environmental marketing business specializing in producer services, end-use origination and wholesale marketing that conducts business in the United States and Canada.
 
Contracts and other activities at our Energy Marketing operations are accounted for under accounting standards for energy trading contracts. As such, all of the contracts and other activities at our marketing operations that meet the definition of a derivative are accounted for at fair value. The fair values are recorded as either Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets. The net gains or losses are recorded as Operating revenues in the accompanying Condensed Consolidated Statements of Income. Accounting for energy trading contracts precludes mark-to-market accounting for energy trading contracts that are not defined as derivatives pursuant to accounting standards for derivatives. As part of our marketing operations, we often employ strategies that include derivative contracts along with inventory, storage and transportation positions to accomplish the objectives of our producer services, end-use origination and wholesale marketing groups. Except in limited circumstances when we are able to designate transportation, storage or inventory positions as part of a fair value hedge, accounting for derivatives and hedging generally does not allow us to mark inventory, transportation or storage positions to market. The result is that while a significant majority of our natural gas, crude oil and coal marketing positions are economically hedged, we are required to mark some parts of our overall strategies (the derivatives) to market value, but are generally precluded from marking the rest of our economic hedges (transportation, inventory or storage) to market. Volatility in reported earnings and derivative positions results from these accounting requirements.
 
To effectively manage our portfolios, we enter into forward physical commodity contracts, financial derivative instruments including over-the-counter swaps and options, and storage and transportation agreements. The business activities of our Energy Marketing segment are conducted within the parameters as defined and allowed in the BHCRPP and further delineated in the Energy Marketing Risk Management Policies and Procedures as approved by our Executive Risk Committee. Our trading contracts do not include credit risk-related contingent features that require us to maintain a specific credit rating.
 
We use a number of quantitative tools to measure, monitor and limit our exposure to market risk in our marketing portfolio. We limit and monitor our market risk through established limits on the nominal size of positions based on type of trade, location and duration. Such limits include those on fixed price, basis, index, storage, transportation and foreign exchange positions.
 
Daily risk management activities include reviewing positions in relation to established position limits, assessing changes in daily mark-to-market and other non-statistical risk management techniques.
 
The contract or notional amounts and terms of our marketing activities and derivative commodity instruments were as follows:
 
 
Outstanding at
 
Outstanding at
 
Outstanding at
 
March 31, 2011
 
December 31, 2010
 
March 31, 2010
 
Notional
Amounts
 
Latest
Expiration
(months)
 
Notional
Amounts
 
Latest
Expiration
(months)
 
Notional
Amounts
 
Latest
Expiration
(months)
(in thousands of MMBtus)
 
 
 
 
 
 
 
 
 
 
 
Natural gas basis swaps purchased
649,523
 
 
19
 
 
399,128
 
 
22
 
 
240,400
 
 
19
 
Natural gas basis swaps sold
671,468
 
 
19
 
 
426,903
 
 
22
 
 
245,790
 
 
19
 
Natural gas fixed-for-float swaps purchased
199,897
 
 
30
 
 
135,005
 
 
33
 
 
87,161
 
 
20
 
Natural gas fixed-for-float swaps sold
196,305
 
 
19
 
 
150,803
 
 
22
 
 
99,233
 
 
22
 
Natural gas physical purchases
147,699
 
 
33
 
 
144,948
 
 
36
 
 
125,570
 
 
24
 
Natural gas physical sales
134,202
 
 
33
 
 
143,021
 
 
36
 
 
123,620
 
 
24
 
Natural gas futures purchased
13,570
 
 
13
 
 
 
 
 
 
 
 
 
Natural gas futures sold
12,050
 
 
2
 
 
 
 
 
 
 
 
 
 
 
Outstanding at
 
Outstanding at
 
Outstanding at
 
March 31, 2011
 
December 31, 2010
 
March 31, 2010
 
Notional
Amounts
 
Latest
Expiration
(months)
 
Notional
Amounts
 
Latest
Expiration
(months)
 
Notional
Amounts
 
Latest
Expiration
(months)
(in thousands of Bbls)
 
 
 
 
 
 
 
 
 
 
 
Crude oil physical purchases
6,779
 
 
13
 
 
5,628
 
 
16
 
 
5,296
 
 
9
 
Crude oil physical sales
6,783
 
 
13
 
 
6,921
 
 
16
 
 
5,647
 
 
9
 
Crude oil swaps purchased
65
 
 
4
 
 
20
 
 
3
 
 
 
 
 
Crude oil swaps sold
275
 
 
4
 
 
240
 
 
4
 
 
94
 
 
2
 
 
 
Outstanding at
 
Outstanding at
 
March 31, 2011
 
December 31, 2010
 
Notional
Amounts
 
Latest
Expiration
(months)
 
Notional
Amounts
 
Latest
Expiration
(months)
(in thousands of tons)
 
 
 
 
 
 
 
Coal fixed-for-float swaps purchased
5,330
 
 
33
 
 
4,060
 
 
36
 
Coal fixed-for-float swaps sold
6,140
 
 
33
 
 
3,720
 
 
36
 
Coal physical purchases
25,575
 
 
45
 
 
24,634
 
 
48
 
Coal physical sales
11,065
 
 
33
 
 
9,046
 
 
36
 
Coal options purchased
2,970
 
 
45
 
 
2,835
 
 
48
 
Coal options sold
552
 
 
9
 
 
270
 
 
12
 
 
 
 
Outstanding at
Outstanding at
 
March 31, 2011
December 31, 2010
 
Notional Amounts
Latest expiration (months)
Notional Amounts
Latest expiration (months) 
(in thousands of MWh):
 
 
 
 
Power fixed-for-float swaps purchased
3,009
 
33
 
902
 
11
 
Power fixed-for-float swaps sold
3,008
 
33
 
902
 
11
 
 

21

 

Derivatives and certain other marketing activities were marked to fair value and the related gains and/or losses recognized in earnings. The amounts included in the accompanying Condensed Consolidated Balance Sheets and Condensed Statements of Income were as follows (in thousands):
 
 
March 31,
2011
 
December 31,
2010
 
March 31,
2010
Derivative assets, current
$
41,482
 
 
$
43,862
 
 
$
40,541
 
Derivative assets, non-current
$
3,951
 
 
$
6,635
 
 
$
2,409
 
Derivative liabilities, current
$
31,167
 
 
$
14,550
 
 
$
17,733
 
Derivative liabilities, non-current
$
(236
)
 
$
3,464
 
 
$
(588
)
Cash collateral receivable (payable) included in derivative assets/liabilities
$
2,984
 
 
$
3,958
 
 
$
171
 
Unrealized gain
$
11,518
 
 
$
28,525
 
 
$
25,634
 
 
In addition, certain volumes of natural gas inventory have been designated as the underlying hedged item in fair value hedge transactions. These volumes include market adjustments based on published industry quotations. Market adjustments are recorded in Materials, supplies and fuel on the accompanying Condensed Consolidated Balance Sheets and the related unrealized gain/loss on the Condensed Consolidated Statements of Income, effectively offsetting the earnings impact of the unrealized gain/loss recognized on the associated derivative asset or liability described above. As of March 31, 2011, December 31, 2010 and March 31, 2010, the market adjustments recorded in Materials, supplies and fuel were $0.3 million, $(9.1) million and $(11.0) million, respectively.
 
Activities Other Than Trading
 
Oil and Gas Exploration and Production
 
We produce natural gas and crude oil through our exploration and production activities. Our natural "long" positions, or unhedged open positions, result in commodity price risk and variability to our cash flows. We employ risk management methods to mitigate this commodity price risk and preserve our cash flows and we have adopted guidelines covering hedging for our natural gas and crude oil production. These guidelines have been approved by our Executive Risk Committee, and are routinely reviewed by our Board of Directors.
 
We held a portfolio of swaps and options to hedge portions of our crude oil and natural gas production. We elect hedge accounting on those over-the-counter swaps and options. These transactions were designated at inception as cash flow hedges, documented under accounting for derivatives and hedging, and initially met prospective effectiveness testing. Effectiveness of our hedging position is evaluated at least quarterly.
 
The derivatives were marked to fair value and are recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets. The effective portion of the gain or loss on these derivatives is reported in Accumulated other comprehensive income (loss) and the ineffective portion is reported in earnings.
 

22

 

We held the following derivatives and related balances (dollars in thousands):
 
 
March 31, 2011
 
December 31, 2010
 
March 31, 2010
 
Crude Oil
Swaps/
Options
 
Natural Gas
Swaps
 
Crude Oil
Swaps/
Options
 
Natural Gas
Swaps
 
Crude Oil
Swaps/
Options
 
Natural Gas
Swaps
Notional*
487,500
 
 
5,974,800
 
 
424,500
 
 
6,821,800
 
 
565,500
 
 
10,142,050
 
Maximum terms in years **
1
 
 
0.25
 
 
0.25
 
 
0.25
 
 
0.25
 
 
0.75
 
Derivative assets, current
$
108
 
 
$
6,649
 
 
$
248
 
 
$
7,675
 
 
$
2,816
 
 
$
9,151
 
Derivative assets, non-current
$
 
 
$
975
 
 
$
19
 
 
$
2,606
 
 
$
220
 
 
$
3,248
 
Derivative liabilities, current
$
4,688
 
 
$
 
 
$
3,814
 
 
$
 
 
$
2,655
 
 
$
53
 
Derivative liabilities, non-current
$
2,678
 
 
$
157
 
 
$
1,301
 
 
$
 
 
$
1,428
 
 
$
 
Pre-tax accumulated other comprehensive income (loss) included in balance sheets
$
(7,613
)
 
$
7,467
 
 
$
(5,313
)
 
$
10,281
 
 
$
(1,908
)
 
$
12,346
 
Earnings
$
355
 
 
$
 
 
$
465
 
 
$
 
 
$
861
 
 
$
 
____________
*    Crude oil in Bbls, gas in MMBtu.
**    Refers to the term of the derivative instrument. Assets and liabilities are classified as current/non-current based on the timing of the hedged transaction and the corresponding settlement of the derivative instrument.
 
Based on March 31, 2011 market prices, a $1.6 million gain would be realized and reported in pre-tax earnings during the next 12 months related to hedges of production. Estimated and actual realized gains will likely change during the next 12 months as market prices change.
 
Gas Utilities - Gas Hedges
 
Our Gas Utilities segment purchases and distributes natural gas in four states. During the winter heating season, our gas customers are exposed to the effect of volatile natural gas prices; therefore, as allowed or required by state utility commissions, we have entered into certain exchange traded natural gas futures, options and basis swaps to reduce our customers' underlying exposure to these fluctuations. These transactions are considered derivatives in accordance with accounting standards for derivatives and mark-to-market adjustments are recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets. Gains and losses, as well as option premiums upon settlement, on these transactions are recorded as Regulatory assets or Regulatory liabilities in accordance with accounting standards for regulated operations. Accordingly, the earnings impact is recognized in the Consolidated Income Statements as a component of PGA costs when the related costs are recovered through our rates as part of PGA costs in operating revenue.
 
The contract or notional amounts and terms of our natural gas derivative commodity instruments held at our Gas Utilities were as follows:
 
 
Outstanding at
 
Outstanding at
 
Outstanding at
 
March 31, 2011
 
December 31, 2010
 
March 31, 2010
 
Notional
Amounts (MMBtus)
 
Latest
Expiration
(months)
 
Notional
Amounts (MMBtus)
 
Latest
Expiration
(months)
 
Notional
Amounts (MMBtus)
 
Latest
Expiration
(months)
Natural gas futures purchased
4,680,000
 
 
24
 
 
6,670,000
 
 
15
 
 
4,740,000
 
 
24
 
Natural gas options purchased
 
 
 
 
1,730,000
 
 
3
 
 
 
 
 
 

23

 

We had the following derivative balances related to the hedges in our Gas Utilities (in thousands):
 
 
March 31,
2011
 
December 31,
2010
 
March 31,
2010
Derivative assets, current
$
1,056
 
 
$
4,787
 
 
$
1,943
 
Derivative assets, non-current
$
209
 
 
$
 
 
$
 
Derivative liabilities, non-current
$
 
 
$
1,620
 
 
$
324
 
Net unrealized gain (loss) included in regulatory assets
$
(2,455
)
 
$
(8,030
)
 
$
(6,475
)
Cash collateral receivable (payable) included in derivative assets/liabilities
$
3,720
 
 
$
10,355
 
 
$
8,094
 
 
 
 
 
 
 
Option premium included in Derivative assets, current
$
 
 
$
842
 
 
$
 
 
Financing Activities
 
We are exposed to interest rate risk associated with fluctuations in the interest rate on our variable interest rate debt. To manage this risk, we have entered into floating-to-fixed interest rate swap agreements with the intention to convert the debt's variable interest rate to a fixed rate.
 
Our interest rate swaps and related balances were as follows (dollars in thousands):
 
 
March 31, 2011
 
December 31, 2010
 
March 31, 2010
 
Designated 
Interest Rate
Swaps
 
Dedesignated
Interest Rate
Swaps*
 
Designated
Interest Rate
Swaps
 
Dedesignated
Interest Rate
Swaps*
 
Designated
Interest Rate
Swaps
 
Dedesignated
Interest Rate
Swaps*
Current notional amount
$
150,000
 
 
$
250,000
 
 
$
150,000
 
 
$
250,000
 
 
$
150,000
 
 
$
250,000
 
Weighted average fixed interest rate
5.04
%
 
5.67
%
 
5.04
%
 
5.67
%
 
5.04
%
 
5.67
%
Maximum terms in years
5.75
 
 
0.75
 
 
6.00
 
 
1.00
 
 
6.75
 
 
0.75
 
Derivative liabilities, current
$
6,769
 
 
$
48,515
 
 
$
6,823
 
 
$
53,980
 
 
$
6,571
 
 
$
41,822
 
Derivative liabilities, non-current
$
12,955
 
 
$
 
 
$
14,976
 
 
$
 
 
$
10,917
 
 
$
 
Pre-tax accumulated other comprehensive gain (loss) included in Condensed Consolidated Balance Sheets
$
(19,724
)
 
$