BKH 093012 10Q


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 September 30, 2012
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 at October 31, 2012
 
 
Common stock, $1.00 par value
44,180,030 shares






TABLE OF CONTENTS
 
 
 
Page
 
Glossary of Terms and Abbreviations
 
 
 
 
 
PART I.
FINANCIAL INFORMATION
 
 
 
 
 
Item 1.
Financial Statements
 
 
 
 
 
 
Condensed Consolidated Statements of Income - unaudited
 
 
 
   Three and Nine Months Ended Sept. 30, 2012 and 2011
 
 
 
 
 
 
Condensed Consolidated Statements of Comprehensive Income (Loss) - unaudited
 
 
 
   Three and Nine Months Ended Sept. 30, 2012 and 2011
 
 
 
 
 
 
Condensed Consolidated Balance Sheets - unaudited
 
 
 
   Sept. 30, 2012, Dec. 31, 2011 and Sept. 30, 2011
 
 
 
 
 
 
Condensed Consolidated Statements of Cash Flows - unaudited
 
 
 
   Nine Months Ended Sept. 30, 2012 and 2011
 
 
 
 
 
 
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 4.
Mine Safety Disclosures
 
 
 
 
 
Item 5.
Other Information
 
 
 
 
 
Item 6.
Exhibits
 
 
 
 
 
 
Signatures
 
 
 
 
 
 
Exhibit Index
 


2



GLOSSARY OF TERMS AND ABBREVIATIONS
AND ACCOUNTING STANDARDS

The following terms and abbreviations appear in the text of this report and have the definitions described below:
AFUDC
Allowance for Funds Used During Construction
AltaGas
AltaGas Renewable Energy Colorado, LLC
AOCI
Accumulated Other Comprehensive Income (Loss)
ARO
Asset Retirement Obligation
ASC
Accounting Standards Codification
ASU
Accounting Standards Update
Bbl
Barrel
Bcf
Billion cubic feet
Bcfe
Billion cubic feet equivalent
BHC
Black Hills Corporation, the "Company"
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
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
Commodity Futures 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
CT
Combustion Turbine
CVA
Credit Valuation Adjustment
CWIP
Construction Work-In-Progress
De-designated interest rate swaps
The $250 million notional amount interest rate swaps that were originally designated as cash flow hedges under accounting for derivatives and hedges but were subsequently de-designated.
Dodd-Frank
Dodd-Frank Wall Street Reform and Consumer Protection Act
Dth
Dekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu)
ECA
Energy Cost Adjustment

3



Enserco
Enserco Energy Inc., representing our Energy Marketing segment, sold Feb. 29, 2012
Equity Forward Instrument
Equity Forward Agreement with J.P. Morgan connected to a public offering of 4,413,519 shares of Black Hills Corporation common stock
FASB
Financial Accounting Standards Board
FDIC
Federal Deposit Insurance Corporation
FERC
Federal Energy Regulatory Commission
GAAP
Generally Accepted Accounting Principles of the United States
Global Settlement
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
IFRS
International Financial Reporting Standards
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
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. Natural gas liquid is converted by dividing gallons by 7. Crude oil is converted by multiplying barrels by 6.
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
NGL
Natural Gas Liquids
NPSC
Nebraska Public Service Commission
NYMEX
New York Mercantile Exchange
OTC
Over-the-counter
PGA
Purchase Gas Adjustment
PPA
Power Purchase Agreement
REPA
Renewable Energy Purchase Agreement
Revolving Credit Facility
Our $500 million five-year revolving credit facility which commenced on Feb. 1, 2012 and expires on Feb. 1, 2017
S&P
Standard and Poor's
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, representing our Coal Mining segment


4





BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS)
(unaudited)
 
Three Months Ended
Sept. 30,
Nine Months Ended
Sept. 30,
 
2012
2011
2012
2011
 
(in thousands, except per share amounts)
Revenue:
 
 
 
 
Utilities
$
214,716

$
223,714

$
766,317

$
834,463

Non-regulated energy
32,092

25,809

88,705

76,544

Total revenue
246,808

249,523

855,022

911,007

 
 
 
 
 
Operating expenses:
 
 
 
 
Utilities -
 
 
 
 
Fuel, purchased power and cost of gas sold
62,582

86,127

283,217

400,465

Operations and maintenance
59,398

58,313

183,721

184,411

Non-regulated energy operations and maintenance
22,466

22,813

65,774

69,438

Gain on sale of operating assets
(27,285
)

(27,285
)

Depreciation, depletion and amortization
41,408

33,278

121,398

97,434

Taxes - property, production and severance
10,213

9,161

31,201

24,598

Impairment of long-lived assets


26,868


Other operating expenses
216

259

1,679

562

Total operating expenses
168,998

209,951

686,573

776,908

 
 
 
 
 
Operating income
77,810

39,572

168,449

134,099

 
 
 
 
 
Other income (expense):
 
 
 
 
Interest charges -
 
 
 
 
Interest expense incurred (including amortization of debt issuance costs, premiums, discounts and realized settlements on interest rate swaps)
(27,475
)
(29,303
)
(85,151
)
(87,099
)
Allowance for funds used during construction - borrowed
1,127

3,520

2,608

9,874

Capitalized interest
175

2,981

467

8,198

Unrealized gain (loss) on interest rate swaps, net
605

(38,246
)
(2,902
)
(40,608
)
Interest income
364

536

1,428

1,547

Allowance for funds used during construction - equity
196

189

668

676

Other income (expense), net
(287
)
528

2,073

1,763

Total other income (expense)
(25,295
)
(59,795
)
(80,809
)
(105,649
)
 
 
 
 
 
Income (loss) before equity in earnings (loss) of unconsolidated subsidiaries and income taxes
52,515

(20,223
)
87,640

28,450

Equity in earnings (loss) of unconsolidated subsidiaries
22

43

(12
)
1,076

Income tax benefit (expense)
(17,914
)
9,017

(30,057
)
(7,915
)
Income (loss) from continuing operations
34,623

(11,163
)
57,571

21,611

Income (loss) from discontinued operations, net of tax
(166
)
638

(6,810
)
2,526

Net income (loss) available for common stock
$
34,457

$
(10,525
)
$
50,761

$
24,137

 
 
 
 
 
Income (loss) per share, Basic -
 
 
 
 
Income (loss) from continuing operations, per share
$
0.79

$
(0.29
)
$
1.31

$
0.55

Income (loss) from discontinued operations, per share

0.02

(0.16
)
0.07

Total income (loss) per share, Basic
$
0.79

$
(0.27
)
$
1.15

$
0.62

Income (loss) per share, Diluted -
 
 
 
 
Income (loss) from continuing operations, per share
$
0.78

$
(0.29
)
$
1.31

$
0.54

Income (loss) from discontinued operations, per share

0.02

(0.16
)
0.07

Total income (loss) per share, Diluted
$
0.78

$
(0.27
)
$
1.15

$
0.61

Weighted average common shares outstanding:
 
 
 
 
Basic
43,847

39,145

43,792

39,105

Diluted
44,108

39,145

44,026

39,792

 
 
 
 
 
Dividends paid per share of common stock
$
0.370

$
0.365

$
1.110

$
1.095


The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.

5




BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(unaudited)

 
Three Months Ended
Sept. 30,
Nine Months Ended
Sept. 30,
 
2012
2011
2012
2011
 
(in thousands)
 
 
 
 
 
Net income (loss) available for common stock
$
34,457

$
(10,525
)
$
50,761

$
24,137

 
 
 
 
 
Other comprehensive income (loss), net of tax:
 
 
 
 
Fair value adjustment of derivatives designated as cash flow hedges (net of tax of $1,204 and $(1,215) for the three months ended 2012 and 2011 and $1,092 and $653 for the nine months ended 2012 and 2011, respectively)
(3,591
)
1,922

(3,004
)
(991
)
Reclassification adjustments of cash flow hedges settled and included in net income (loss) (net of tax of $13 and $(129) for the three months ended 2012 and 2011 and $890 and $(985) for the nine months ended 2012 and 2011, respectively)
28

285

(1,333
)
1,907

Other comprehensive income (loss), net of tax
(3,563
)
2,207

(4,337
)
916

 
 
 
 
 
Comprehensive income (loss)
$
30,894

$
(8,318
)
$
46,424

$
25,053


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
(unaudited)

 
Sept. 30, 2012
 
Dec. 31, 2011
 
Sept. 30, 2011
 
(in thousands)
ASSETS
 
 
 
 
 
Current assets:
 
 
 
 
 
Cash and cash equivalents
$
247,192

 
$
21,628

 
$
30,198

Restricted cash and equivalents
7,302

 
9,254

 
4,080

Accounts receivable, net
104,482

 
156,774

 
102,673

Materials, supplies and fuel
80,900

 
84,064

 
84,607

Derivative assets, current
16,063

 
18,583

 
12,177

Income tax receivable, net
11,869

 
9,344

 
4,728

Deferred income tax assets, net, current
33,681

 
37,202

 
37,931

Regulatory assets, current
24,606

 
59,955

 
45,713

Other current assets
44,823

 
21,266

 
25,269

Assets of discontinued operations

 
340,851

 
332,503

Total current assets
570,918

 
758,921

 
679,879

 
 
 
 
 
 
Investments
16,273

 
17,261

 
17,338

 
 
 
 
 
 
Property, plant and equipment
3,950,222

 
3,724,016

 
3,656,762

Less accumulated depreciation and depletion
(1,253,808
)
 
(934,441
)
 
(931,299
)
Total property, plant and equipment, net
2,696,414

 
2,789,575

 
2,725,463

 
 
 
 
 
 
Other assets:
 
 
 
 
 
Goodwill
353,396

 
353,396

 
353,396

Intangible assets, net
3,675

 
3,843

 
3,899

Derivative assets, non-current
1,167

 
1,971

 
3,246

Regulatory assets, non-current
191,935

 
182,175

 
142,267

Other assets, non-current
19,850

 
19,941

 
20,081

Total other assets
570,023

 
561,326

 
522,889

 
 
 
 
 
 
TOTAL ASSETS
$
3,853,628

 
$
4,127,083

 
$
3,945,569


The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.

7



BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Continued)
(unaudited)


 
Sept. 30, 2012
 
December 31,
2011
 
Sept. 30, 2011
 
(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDERS' EQUITY
 
 
 
 
 
Current liabilities:
 
 
 
 
 
Accounts payable
$
69,138

 
$
104,748

 
$
91,628

Accrued liabilities
179,284

 
151,319

 
161,650

Derivative liabilities, current
86,509

 
84,367

 
101,312

Regulatory liabilities, current
10,705

 
16,231

 
10,568

Notes payable
225,000

 
345,000

 
359,000

Current maturities of long-term debt
328,310

 
2,473

 
2,893

Liabilities of discontinued operations

 
173,929

 
171,685

Total current liabilities
898,946

 
878,067

 
898,736

 
 
 
 
 
 
Long-term debt, net of current maturities
942,950

 
1,280,409

 
1,282,194

 
 
 
 
 
 
Deferred credits and other liabilities:
 
 
 
 
 
Deferred income tax liabilities, net, non-current
338,194

 
300,988

 
317,864

Derivative liabilities, non-current
41,410

 
49,033

 
22,475

Regulatory liabilities, non-current
120,491

 
108,217

 
85,074

Benefit plan liabilities
167,690

 
177,480

 
124,214

Other deferred credits and other liabilities
129,630

 
123,553

 
127,007

Total deferred credits and other liabilities
797,415

 
759,271

 
676,634

 
 
 
 
 
 
Commitments and contingencies (See Notes 6, 7, 9, 11, 12 and 14)


 

 

 
 
 
 
 
 
Stockholders' equity:
 
 
 
 
 
Common stock —
 
 
 
 
 
Common stock $1 par value: 100,000,000 shares authorized: issued 44,250,588; 43,957,502 and 39,491,616 shares, respectively
44,251

 
43,958

 
39,492

Additional paid-in capital
731,176

 
722,623

 
604,945

Retained earnings
478,459

 
476,603

 
467,043

Treasury stock at cost – 75,420; 32,766 and 28,041 shares, respectively
(2,354
)
 
(970
)
 
(810
)
Accumulated other comprehensive income (loss)
(37,215
)
 
(32,878
)
 
(22,665
)
Total stockholders' equity
1,214,317

 
1,209,336

 
1,088,005

 
 
 
 
 
 
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY
$
3,853,628

 
$
4,127,083

 
$
3,945,569


The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.

8



BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
Nine Months Ended Sept. 30,
 
2012
2011
Operating activities:
(unaudited, in thousands)
Net income (loss) available to common stock
$
50,761

$
24,137

(Income) loss from discontinued operations, net of tax
6,810

(2,526
)
Income (loss) from continuing operations
57,571

21,611

Adjustments to reconcile income (loss) from continuing operations to net cash provided by operating activities:
 
 
Depreciation, depletion and amortization
121,398

97,434

Deferred financing cost amortization
5,301

5,040

Impairment of long-lived assets
26,868


Derivative fair value adjustments
(3,522
)
(2,305
)
Gain on sale of operating assets
(27,285
)

Stock compensation
5,974

4,840

Unrealized mark-to-market (gain) loss on interest rate swaps
2,902

40,608

Deferred income taxes
28,718

20,854

Allowance for funds used during construction - equity
(668
)
(676
)
Employee benefit plans
15,737

10,930

Other adjustments, net
3,505

3,177

Changes in certain operating assets and liabilities:
 
 
Materials, supplies and fuel
3,085

(21,692
)
Accounts receivable, unbilled revenues and other current assets
43,447

50,649

Accounts payable and other current liabilities
(22,042
)
(51,846
)
Regulatory assets
15,544

22,357

Regulatory liabilities
(1,983
)
5,041

Contributions to defined benefit pension plans
(25,000
)
(11,050
)
Other operating activities, net
(1,067
)
(1,755
)
Net cash provided by operating activities of continuing operations
248,483

193,217

Net cash provided by (used in) operating activities of discontinued operations
21,184

13,309

Net cash provided by operating activities
269,667

206,526

 
 
 
Investing activities:
 
 
Property, plant and equipment additions
(261,414
)
(326,543
)
Proceeds from sale of assets
268,482

583

Investment in notes receivable
(21,832
)

Other investing activities
5,057

1,051

Net cash provided by (used in) investing activities of continuing operations
(9,707
)
(324,909
)
Proceeds from sale of discontinued business operations
108,837


Net cash provided by (used in) investing activities of discontinued operations
(824
)
(1,953
)
Net cash provided by (used in) investing activities
98,306

(326,862
)
 
 
 
Financing activities:
 
 
Dividends paid on common stock
(48,904
)
(43,169
)
Common stock issued
3,835

2,199

Short-term borrowings - issuances
62,453

770,000

Short-term borrowings - repayments
(182,453
)
(560,000
)
Long-term debt - repayments
(11,647
)
(6,169
)
Other financing activities
(2,833
)
(28
)
Net cash provided by (used in) financing activities of continuing operations
(179,549
)
162,833

Net cash provided by (used in) financing activities of discontinued operations

(157
)
Net cash provided by (used in) financing activities
(179,549
)
162,676

Net change in cash and cash equivalents
188,424

42,340

Cash and cash equivalents, beginning of period*
58,768

32,438

Cash and cash equivalents, end of period*
$
247,192

$
74,778

_______________________
*
Includes cash of discontinued operations of $37.1 million, $44.6 million and $16.0 million at Dec. 31, 2011, Sept. 30, 2011 and Dec. 31, 2010, respectively.
See Note 3 for supplemental disclosure of cash flow information.
The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.

9



BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Reference is made to Notes to Consolidated Financial Statements
included in the Company's 2011 Annual Report on Form 10-K)

(1)    MANAGEMENT'S STATEMENT

The unaudited Condensed Consolidated Financial Statements included herein have been prepared by Black Hills Corporation (together with our subsidiaries the "Company," "us," "we," or "our"), 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 Consolidated Financial Statements should be read in conjunction with the consolidated financial statements and the notes thereto included in our 2011 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 Consolidated Financial Statements reflects all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the Sept. 30, 2012, December 31, 2011 and Sept. 30, 2011 financial information and are of a normal recurring nature. Certain industries in which we operate are highly seasonal, and revenue 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 and nine months ended Sept. 30, 2012 and Sept. 30, 2011, and our financial condition as of Sept. 30, 2012, December 31, 2011, and Sept. 30, 2011 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.

On Feb. 29, 2012, we sold our Energy Marketing segment, which resulted in this segment being classified as discontinued operations. For comparative purposes, all prior periods presented have been restated to reflect the classification of this segment as discontinued operations. For further information see Note 17.

Certain prior year data presented in the financial statements has been reclassified to conform to the current year presentation. Specifically, the Company has reclassified deferred financing cost amortization into a separate line on the Condensed Consolidated Statements of Cash Flows. This reclassification had no effect on total assets, net income, cash flows or earnings per share.


(2)    RECENTLY ADOPTED AND RECENTLY ISSUED ACCOUNTING STANDARDS AND LEGISLATION

Recently Adopted Accounting Standards and Legislation

Other Comprehensive Income: Presentation of Comprehensive Income, ASU 2011-05 and ASU 2011-12

FASB issued an accounting standards update amending accounting guidance for Comprehensive Income to improve the comparability, consistency and transparency of reporting of comprehensive income. The update amends existing guidance by allowing only two options for presenting the components of net income and other comprehensive income: (1) in a single continuous financial statement, statement of comprehensive income or (2) in two separate but consecutive financial statements, consisting of an income statement followed by a separate statement of other comprehensive income. Also, items that are reclassified from other comprehensive income to net income must be presented on the face of the financial statements. ASU 2011-05 requires retrospective application, and is effective for the fiscal years, and interim periods within those years beginning after Dec. 15, 2011. In December 2011, FASB issued ASU 2011-12, which indefinitely deferred the provisions of ASU 2011-05 requiring the presentation of reclassification adjustments on the face of the financial statements for items reclassified from other comprehensive income to net income.


10



At Dec. 31, 2011, we elected to early adopt the provisions of ASU 2011-05 as amended by ASU 2011-12. The adoption changed our presentation of certain financial statements, but did not have any other impact on our financial statements.

Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements, ASU 2011-04

In May 2011, FASB issued an accounting standards update amending accounting guidance for Fair Value Measurements and Disclosures to achieve common fair value measurement and disclosure requirements between GAAP and IFRS. Additional disclosure requirements in the update include: (1) for Level 3 fair value measurements - quantitative information about unobservable inputs used, a description of the valuation processes used by the entity, and a qualitative discussion about the sensitivity of the measurements to changes in the unobservable inputs; (2) for an entity's use of a non-financial asset that is different from the asset's highest and best use - the reason for the difference; (3) for financial instruments not measured at fair value but for which disclosure of fair value is required - the fair value hierarchy level in which the fair value measurements were determined; and (4) the disclosure of all transfers between Level 1 and Level 2 of the fair value hierarchy. ASU 2011-04 is effective for fiscal years, and interim periods within those years, beginning after Dec. 31, 2011. The amendment required additional details in notes to financial statements, but did not have any other impact on our financial statements. Additional disclosures are included in Notes 12 and 13.

Intangibles - Goodwill and Other: Testing Goodwill for Impairment, ASU 2011-08

In September 2011, the FASB issued an amendment to accounting guidance to Intangibles - Goodwill and Other to provide an option to perform a qualitative assessment to determine whether further impairment testing of goodwill is necessary. Specifically, an entity has the option to first assess qualitative factors to determine whether it is necessary to perform the current two-step test. If an entity believes, as a result of its qualitative assessment, that it is more-likely-than-not that the fair value of a reporting unit is less than its carrying amount, the quantitative impairment test is required. Otherwise, no further testing is required. This standard is effective for annual and interim goodwill impairment testing performed for fiscal years beginning after Dec. 15, 2011. We perform our annual impairment testing in November of each year. The adoption of this standard will not have an impact on our financial statements.

Recently Issued Accounting Standards and Legislation

Balance Sheet: Disclosure about Offsetting Assets and Liabilities, ASU 2011-11

In December 2011, the FASB issued revised accounting guidance to amend accounting guidance for Balance Sheet related to the existing disclosure requirements for offsetting financial assets and liabilities to enhance current disclosures, as well as to improve comparability of balance sheets prepared under GAAP and IFRS. The revised disclosure guidance affects all companies that have financial instruments and derivative instruments that are either offset in the balance sheet (i.e., presented on a net basis) or subject to an enforceable master netting and/or similar arrangement. In addition, the revised guidance requires that certain enhanced quantitative and qualitative disclosures are made with respect to a company's netting arrangements and/or rights of offset associated with its financial instruments and/or derivative instruments. The revised disclosure guidance is effective on a retrospective basis for interim and annual periods beginning Jan. 1, 2013. The adoption of this standard will not have an impact on our financial position, results of operations or cash flows.

Intangible - Goodwill and Other: Testing Indefinite Lived Intangible Assets for Impairment, ASU 2012-02

In July 2012, the FASB issued an amendment to accounting guidance for Intangibles - Goodwill and Other to provide an option to perform a qualitative assessment to determine whether further impairment testing of indefinite lived intangible assets is necessary. This ASU aligns the impairment testing for intangible assets with that of goodwill as amended by ASU 2011-08. This guidance is effective for interim and annual periods beginning after Sept. 15, 2012, with early adoption permitted. The adoption of this standard will not have an impact on our financial statements.

Dodd-Frank Wall Street Reform and Consumer Protection Act, SEC Final Rule No. 34-67717 and No. 33-9338

In August 2012, the SEC approved a final rule implementing Section 1504 of Dodd-Frank. The rule requires issuers engaged in the commercial development of oil, natural gas or minerals to disclose cash payments made to a foreign government or the United States government. We are in the process of evaluating our reporting requirements. The adoption of this rule will not have an impact on our financial statements.


11



Additionally, in July 2012, the CFTC and SEC published final rules that define “swap,” “security-based swap” and other key terms and concepts that are critical to the implementation of the derivatives reforms required by Dodd-Frank. We are in the process of evaluating our reporting requirements. The adoption of this rule will not have an impact on our financial position, results of operations or cash flows.


(3)    SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
 
Nine Months Ended
 
Sept. 30, 2012
 
Sept. 30, 2011
 
(in thousands)
Non-cash investing activities from continuing operations—
 
 
 
Property, plant and equipment acquired with accounts payable and accrued liabilities
$
39,303

 
$
49,566

Capitalized assets associated with retirement obligations
$
3,806

 
$

Cash (paid) refunded during the period for continuing operations—
 
 
 
Interest (net of amounts capitalized)
$
(69,901
)
 
$
(60,934
)
Income taxes, net
$
425

 
$
11,939



(4)    MATERIALS, SUPPLIES AND FUEL

The amounts of materials, supplies and fuel included in the accompanying Condensed Consolidated Balance Sheets, by major classification, were as follows (in thousands) as of:
 
 
Sept. 30, 2012
 
Dec. 31, 2011
 
Sept. 30, 2011
Materials and supplies
 
$
43,847

 
$
40,838

 
$
37,327

Fuel - Electric Utilities
 
8,289

 
8,201

 
8,639

Natural gas in storage held for distribution
 
28,764

 
35,025

 
38,641

Total materials, supplies and fuel
 
$
80,900

 
$
84,064

 
$
84,607



(5)    ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS

Accounts receivable consists primarily of customer trade accounts. The Gas Utilities' accounts receivable balance fluctuates primarily due to seasonality. We maintain an allowance for doubtful accounts that reflects our estimate of uncollectible trade receivables. We regularly review our trade receivable allowances by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect our ability to collect.
Following is a summary of receivables (in thousands) as of:
 
Accounts
Unbilled
Less Allowance for
Accounts
Sept. 30, 2012
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
46,802

$
18,441

$
(603
)
$
64,640

Gas Utilities
18,198

9,480

(204
)
27,474

Oil and Gas
10,272


(105
)
10,167

Coal Mining
1,540



1,540

Power Generation
4



4

Corporate
657



657

Total
$
77,473

$
27,921

$
(912
)
$
104,482



12



 
Accounts
Unbilled
Less Allowance for
Accounts
Dec. 31, 2011
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
42,773

$
21,151

$
(545
)
$
63,379

Gas Utilities
39,353

38,992

(1,011
)
77,334

Oil and Gas
11,282


(105
)
11,177

Coal Mining
4,056



4,056

Power Generation
282



282

Corporate
546



546

Total
$
98,292

$
60,143

$
(1,661
)
$
156,774


 
Accounts
Unbilled
Less Allowance for
Accounts
Sept. 30, 2011
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
41,889

$
16,401

$
(590
)
$
57,700

Gas Utilities
21,168

12,518

(789
)
32,897

Oil and Gas
8,820


(161
)
8,659

Coal Mining
1,845



1,845

Power Generation
119



119

Corporate
1,453



1,453

Total
$
75,294

$
28,919

$
(1,540
)
$
102,673



(6)    NOTES PAYABLE

Our credit facility and debt securities contain certain restrictive financial covenants. We were in compliance with all of these covenants at Sept. 30, 2012.

We had the following short-term debt outstanding at the Condensed Consolidated Balance Sheet dates (in thousands) as of:

 
Sept. 30, 2012
Dec. 31, 2011
Sept. 30, 2011
 
Notes Payable
Letters of Credit
Notes Payable
Letters of Credit
Notes Payable
Letters of Credit
Revolving Credit Facility
$
75,000

$
36,300

$
195,000

$
43,700

$
209,000

$
42,355

Term Loan due June 2013 (a)
150,000


150,000


150,000


Total
$
225,000

$
36,300

$
345,000

$
43,700

$
359,000

$
42,355

______________
(a)    In June 2012, this short-term loan was extended for one year. See discussion below.

Revolving Credit Facility

On Feb. 1, 2012, we entered into a new $500 million Revolving Credit Facility expiring Feb. 1, 2017. The facility contains an accordion feature allowing us, with the consent of the administrative agent, to increase the capacity of the facility to $750 million. The Revolving Credit 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 credit ratings, the margins for base rate borrowings, Eurodollar borrowings and letters of credit were 0.50 percent, 1.50 percent and 1.50 percent, respectively, at Sept. 30, 2012. The facility contains a commitment fee that is charged on the unused amount of the Revolving Credit Facility. Based upon current credit ratings, the fee is 0.25 percent.

13




Deferred financing costs on the Revolving Credit Facility of $2.8 million are being amortized over the estimated useful life of the Revolving Credit Facility and are included in Interest expense on the accompanying Condensed Consolidated Statements of Income. Upon entering into the Revolving Credit Facility, $1.5 million of deferred financing costs relating to the previous credit facility were written off through Interest expense.

Term Loans

On June 24, 2012, we extended the term of the $150 million term loan to June 24, 2013. The cost of borrowing is based on 1.10 percent over LIBOR.

Debt Covenants

Certain debt obligations require compliance with the following covenants at the end of each quarter (dollars in thousands):

 
As of
 
 
 
Sept. 30, 2012
 
Covenant Requirement
Consolidated Net Worth
$
1,214,317

 
Greater than
$
909,511

Recourse Leverage Ratio
56.3
%
 
Less than
65.0
%


(7)    LONG TERM DEBT

On May 15, 2012, Black Hills Power repaid its 4.8 percent Pollution Control Revenue Bonds in full for $6.5 million principal and interest. These bonds were originally due to mature on Oct. 1, 2014.


(8)    EARNINGS PER SHARE

Basic Income (loss) per share from continuing operations is computed by dividing Income (loss) from continuing operations by the weighted-average number of common shares outstanding during the period. Diluted Income (loss) per share is computed by including all dilutive common shares potentially outstanding during a period.

A reconciliation of share amounts used to compute Income (loss) per share is as follows (in thousands):

 
Three Months Ended
Sept. 30,
 
Nine Months Ended
Sept. 30,
 
2012
2011
 
2012
2011
 
 
 
 
 
 
Income (loss) from continuing operations
$
34,623

$
(11,163
)
 
$
57,571

$
21,611

 
 
 
 
 
 
Weighted average shares - basic
43,847

39,145

 
43,792

39,105

Dilutive effect of:
 
 
 
 
 
Restricted stock
175


 
159

147

Stock options
12


 
14

16

Equity forward instruments


 

473

Other dilutive effects
74


 
61

51

Weighted average shares - diluted
44,108

39,145

 
44,026

39,792



14



Below is a discussion of our potentially dilutive shares that were not included in the computation of diluted earnings per share as their effect would have been anti-dilutive.

Due to our net loss for the quarter ended Sept. 30, 2011, potentially dilutive securities, consisting of outstanding stock options, restricted common stock, restricted stock units, non-vested performance-based share awards and warrants, were excluded from the diluted loss per share calculation due to their anti-dilutive effect. In computing diluted net loss per share, 11,880 options to purchase shares of common stock, 159,873 vested and non-vested restricted stock shares, 31,408 warrants and other performance shares and 424,715 forward equity instruments were excluded from the computations for the three months ended Sept. 30, 2011.

In addition to these potentially dilutive shares excluded due to our net loss for third quarter of 2011, the following outstanding securities also were excluded in the computation of diluted Income (loss) per share from continuing operations as their inclusion would have been anti-dilutive (in thousands):
 
Three Months Ended
Sept. 30,
Nine Months Ended
Sept. 30,
 
2012
2011
2012
2011
Stock options
77

176

101

119

Restricted stock
61

20

53

17

Other stock

27

19

19

Anti-dilutive shares
138

223

173

155



(9)    EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plans

We have three non-contributory defined benefit pension plans (Pension Plans). One covers certain eligible employees of Black Hills Service Company, Black Hills Power, WRDC and BHEP, one covers certain eligible employees of Cheyenne Light, and one covers certain eligible employees of Black Hills Energy. As of Jan. 1, 2012, all Pension Plans have been frozen to new employees and certain eligible employees who did not meet age and service based criteria at the time the Pension Plans were frozen. Additionally, effective Oct. 1, 2012, the Cheyenne Light Pension Plan was merged into the Black Hills Corporation Pension Plan. The Pension Plan benefits are based on years of service and compensation levels.

The components of net periodic benefit cost for the Pension Plans were as follows (in thousands):

 
Three Months Ended
Sept. 30,
Nine Months Ended
Sept. 30,
 
2012
2011
2012
2011
Service cost
$
1,431

$
1,355

$
4,291

$
4,066

Interest cost
3,688

3,732

11,062

11,196

Expected return on plan assets
(4,084
)
(4,239
)
(12,252
)
(12,717
)
Prior service cost
22

25

66

75

Net loss (gain)
2,408

1,135

7,224

3,405

Net periodic benefit cost
$
3,465

$
2,008

$
10,391

$
6,025


Non-pension Defined Benefit Postretirement Healthcare Plans

We sponsor the following retiree healthcare plans (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.


15



The components of net periodic benefit cost for the Healthcare Plans were as follows (in thousands):
 
Three Months Ended
Sept. 30,
Nine Months Ended
Sept. 30,
 
2012
2011
2012
2011
Service cost
$
402

$
375

$
1,206

$
1,125

Interest cost
523

542

1,569

1,626

Expected return on plan assets
(19
)
(41
)
(57
)
(123
)
Prior service cost (benefit)
(125
)
(120
)
(375
)
(360
)
Net loss (gain)
222

169

666

507

Net periodic benefit cost
$
1,003

$
925

$
3,009

$
2,775


Supplemental Non-qualified Defined Benefit Plans

We have various supplemental retirement plans for key executives (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
Sept. 30,
Nine Months Ended
Sept. 30,
 
2012
2011
2012
2011
Service cost
$
243

$
257

$
735

$
771

Interest cost
331

324

993

973

Prior service cost
1

1

3

3

Net loss (gain)
202

128

606

383

Net periodic benefit cost
$
777

$
710

$
2,337

$
2,130


Contributions

We anticipate that we will make contributions to the benefit plans during 2012 and 2013. Contributions to the Pension Plans will be made in cash, and contributions to the Healthcare Plans and the Supplemental Plans are expected to be made in the form of benefit payments. Contributions and anticipated contributions are as follows (in thousands):
 
Contributions Made
Contributions Made
Additional
 
 
Three Months Ended Sept. 30, 2012
Nine Months Ended Sept. 30, 2012
Contributions Anticipated for 2012
Contributions Anticipated for 2013
Defined Benefit Pension Plans
$

$
25,000

$

$
4,500

Non-pension Defined Benefit Postretirement Healthcare Plans
$
1,063

$
3,189

$
1,063

$
4,380

Supplemental Non-qualified Defined Benefit Plans
$
278

$
834

$
278

$
1,090



(10)    BUSINESS SEGMENT INFORMATION

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. All of our operations and assets are located within the United States.

On Feb. 29, 2012, we sold our Energy Marketing segment, Enserco, which resulted in this segment being classified as discontinued operations. For comparative purposes, all prior periods presented have been restated to reflect the classification of this segment as discontinued operations. Indirect corporate costs and inter-segment interest expense related to Enserco that have not been classified as discontinued operations have been reclassified to our Corporate segment. For further information see Note 17.


16



We conduct our operations through the following five reportable segments:

Utilities Group —

Electric Utilities, which supplies electric utility service to areas in South Dakota, Wyoming, Colorado and Montana and natural gas utility service to Cheyenne, Wyo. and vicinity; and

Gas Utilities, which supplies natural gas utility service to areas in Colorado, Iowa, Kansas and Nebraska.

Non-regulated Energy Group —

Oil and Gas, which acquires, explores for, develops and produces crude 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 and Colorado; and

Coal Mining, which engages in the mining and sale of coal from our mine near Gillette, Wyo.

Segment information follows the accounting policies described in Note 1 of the Notes to Consolidated Financial Statements in our 2011 Annual Report on Form 10-K.

Segment information included in the accompanying Condensed Consolidated Statements of Income and Condensed Consolidated Balance Sheets was as follows (in thousands):

Three Months Ended Sept. 30, 2012
 
External
Operating
Revenues
 
Intercompany
Operating
Revenues
 
Income (Loss) from Continuing Operations
Utilities:
 
 
 
 
 
 
   Electric
 
$
151,281

 
$
3,736

 
$
14,573

   Gas
 
63,435

 

 
3

Non-regulated Energy:
 
 
 
 
 
 
   Oil and Gas (a)
 
24,728

 

 
17,389

   Power Generation
 
1,256

 
19,695

 
5,128

   Coal Mining
 
6,108

 
8,567

 
1,690

Corporate (b)
 

 

 
(4,160
)
Intercompany eliminations
 

 
(31,998
)
 

Total
 
$
246,808

 
$

 
$
34,623


Three Months Ended Sept. 30, 2011
 
External
Operating
Revenues
 
Intercompany
Operating
Revenues
 
Income (Loss) from Continuing Operations
Utilities:
 
 
 
 
 
 
   Electric
 
$
151,063

 
$
2,653

 
$
15,790

   Gas
 
72,651

 

 
572

Non-regulated Energy:
 
 
 
 
 
 
   Oil and Gas  
 
19,163

 

 
241

   Power Generation
 
1,011

 
7,089

 
337

   Coal Mining
 
9,184

 
8,651

 
555

Corporate (b)(c)
 

 

 
(28,307
)
Intercompany eliminations
 

 
(21,942
)
 
(351
)
Total
 
$
253,072

 
$
(3,549
)
 
$
(11,163
)

17




Nine Months Ended Sept. 30, 2012
 
External
Operating
Revenues
 
Intercompany
Operating
Revenues
 
Income (Loss) from Continuing Operations
Utilities:
 
 
 
 
 
 
   Electric
 
$
451,974

 
$
11,946

 
$
37,478

   Gas
 
314,343

 

 
16,369

Non-regulated Energy:
 
 
 
 
 
 
   Oil and Gas (a)(d)
 
66,994

 

 
(2,219
)
   Power Generation
 
3,193

 
56,119

 
15,968

   Coal Mining
 
18,518

 
24,273

 
3,924

Corporate (b)
 

 

 
(13,949
)
Intercompany eliminations
 

 
(92,338
)
 

Total
 
$
855,022

 
$

 
$
57,571



Nine Months Ended Sept. 30, 2011
 
External
Operating
Revenues
 
Intercompany
Operating
Revenues
 
Income (Loss) from Continuing Operations
Utilities:
 
 
 
 
 
 
   Electric
 
$
431,624

 
$
9,902

 
$
34,653

   Gas
 
402,839

 

 
24,275

Non-regulated Energy:
 
 
 
 
 
 
   Oil and Gas  
 
55,907

 

 
(553
)
   Power Generation
 
2,589

 
20,911

 
2,071

   Coal Mining
 
23,064

 
25,806

 
(1,124
)
Corporate (b)(c)
 

 

 
(37,299
)
Intercompany eliminations
 

 
(61,635
)
 
(412
)
Total
 
$
916,023

 
$
(5,016
)
 
$
21,611

____________
Income Statement Notes:
(a)
Income (loss) from continuing operations includes a $17.7 million after-tax gain on the sale of the Williston Basin assets. See Note 15.
(b)
Income (loss) from continuing operations includes $0.4 million net after-tax non-cash mark-to-market gain and $1.9 million net after-tax non-cash mark-to-market loss on interest rate swaps for the three and nine months ended Sept. 30, 2012, respectively, and a $24.9 million and $26.4 million net after-tax non-cash mark-to-market loss on interest rate swaps for the three and nine months ended Sept. 30, 2011, respectively.
(c)
Certain indirect corporate costs and inter-segment interest expenses after-tax totaling $0.5 million for the three months ended Sept. 30, 2011 and $1.6 million and $1.5 million for the nine months ended Sept. 30, 2012 and 2011 were included in the Corporate segment in continuing operations and were not reclassified as discontinued operations. See Note 17 for further information.
(d)
Income (loss) from continuing operations includes a $17.3 million non-cash after-tax ceiling test impairment expense. See Note 16 for further information.


18




Total Assets (net of inter-company eliminations) as of:
Sept. 30, 2012
 
Dec. 31, 2011
 
Sept. 30, 2011
 
Utilities:
 
 
 
 
 
 
   Electric (a)
$
2,302,951

 
$
2,254,914

 
$
1,917,184

 
   Gas
710,099

 
746,444

 
683,163

 
Non-regulated Energy:
 
 
 
 
 
 
   Oil and Gas (b)
263,088

 
425,970

 
405,513

 
   Power Generation (a)
119,489

 
129,121

 
372,313

 
   Coal Mining
90,444

 
88,704

 
94,908

 
Corporate
367,557

 
141,079

(c) 
139,985

(c) 
Discontinued operations

 
340,851

(d) 
332,503

(d) 
Total assets
$
3,853,628

 
$
4,127,083

 
$
3,945,569

 
____________
(a)
Upon commercial operation on Dec. 31, 2011 of the new generating facility constructed by Colorado IPP at our Pueblo Airport Generation site, the PPA under which energy and capacity is sold to Colorado Electric is accounted for as a capital lease. Therefore, commencing Dec. 31, 2011, assets previously recorded at Power Generation are now accounted for at Colorado Electric as a capital lease.
(b)
2012 includes a ceiling test impairment and the sale of the Williston Basin assets by our Oil and Gas segment. See Notes 15 and 16.
(c)
Assets of the Corporate segment were reclassified due to deferred taxes that were not classified as discontinued operations.
(d)
See Note 17 for further information relating to discontinued operations.


(11)    RISK MANAGEMENT ACTIVITIES

Our activities in the regulated and non-regulated energy sectors 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 credit risk. To manage and mitigate these identified risks, we have adopted the Black Hills Corporation Risk Policies and Procedures as discussed in our 2011 Annual Report on Form 10-K.

Market Risk

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 including, but not limited to:

Commodity price risk associated with our natural long position with crude oil and natural gas 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 regulated and non-regulated segments; and

Interest rate risk associated with our variable rate credit facility, project financing floating rate debt and our derivative instruments.

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 and commodity prices, the volatility of these prices and rates, and the liquidity of the related interest rate and commodity markets.

Credit Risk

Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty.

For production and generation activities, we attempt to mitigate our credit exposure by conducting business primarily with investment grade rated companies, setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements, and mitigating credit exposure with less creditworthy counterparties through parental guarantees, prepayments, letters of credit, and other security agreements.


19



We perform ongoing credit evaluations of our customers and adjust credit limits based upon payment history and the customer's current creditworthiness, as determined by review of their current credit information. We maintain a provision for estimated credit losses based upon historical experience and any specific customer collection issue that is identified.

As of Sept. 30, 2012, our credit exposure (exclusive of retail customers of the regulated utilities) was concentrated primarily among investment grade rated companies, cooperative utilities and federal agencies.

We actively manage our exposure to certain market and credit risks as described in Note 3 of the Notes to the Consolidated Financial Statements in our 2011 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 below and in Note 12.

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 hold a portfolio of swaps and options to hedge portions of our crude oil and natural gas production. We elect hedge accounting on those OTC swaps and options. These transactions were designated at inception as cash flow hedges, documented under accounting standards for derivatives and hedging, and initially met prospective effectiveness testing. Effectiveness of our hedging position is evaluated at least quarterly.

The derivatives are 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 for which we have elected cash flow hedge accounting is reported in Accumulated other comprehensive income (loss) and the ineffective portion, if any, is reported in Revenue.

We had the following derivatives and related balances for our Oil and Gas segment (dollars in thousands) as of:
 
Sept. 30, 2012
 
Dec. 31, 2011
 
Sept. 30, 2011
 
Crude Oil
Swaps/
Options
Natural Gas
Swaps
 
Crude Oil
Swaps/
Options
Natural Gas
Swaps
 
Crude Oil
Swaps/
Options
Natural Gas
Swaps
Notional (a)
537,000

7,455,250

 
528,000

5,406,250

 
414,000

4,957,250

Maximum terms in years (b)
1.00

1.00

 
1.25

1.75

 
1.00

0.25

Derivative assets, current
$
1,651

$
2,032

 
$
729

$
8,010

 
$
1,885

$
6,937

Derivative assets, non-current
$
494

$
39

 
$
771

$
1,148

 
$
2,529

$
717

Derivative liabilities, current
$
527

$
1,040

 
$
2,559

$

 
$

$

Derivative liabilities, non-current
$
414

$
141

 
$
811

$
7

 
$

$
7

Pre-tax accumulated other comprehensive income (loss)
$
428

$
(344
)
 
$
(1,928
)
$
9,152

 
$
4,257

$
7,647

Cash collateral included in Derivative liabilities
$

$

 
$

$

 
$

$

Cash collateral included in Other current assets
$
1,126

$
1,288

 
$

$

 
$

$

Expense included in Revenue (c)
$
350

$
54

 
$
58

$

 
$
157

$

____________
(a)
Crude oil in Bbls, gas in MMBtus.
(b)
Refers to the term of the derivative instrument. Assets and liabilities are classified as current or non-current based on the term of the hedged transaction and the corresponding settlement of the derivative instruments.
(c)
Represents the amortization of put premiums.
Based on Sept. 30, 2012 market prices, a $1.2 million gain would be reclassified from AOCI during the next 12 months. Estimated and actual realized gains or losses will change during future periods as market prices fluctuate.


20



Utilities

Our utility 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 natural gas futures, options and basis swaps to reduce our customers' underlying exposure to these fluctuations. These transactions are considered derivatives and in accordance with accounting standards for derivatives and hedging, 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 and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in accordance with accounting standards for regulated utility operations. Accordingly, the hedging activity is recognized in the Condensed Consolidated Statements of Income when the related costs are recovered through our rates or adjustment mechanisms.

The contract notional amounts and terms of the natural gas derivative commodity instruments held at our Utilities were as follows as of:
 
Sept. 30, 2012
 
Dec. 31, 2011
 
Sept. 30, 2011
 
Notional
(MMBtus)
 
Maximum
Term
(months)
 
Notional
(MMBtus)
 
Maximum
Term
(months)
 
Notional
(MMBtus)
 
Maximum
Term
(months)
Natural gas futures purchased
14,690,000

 
75

 
14,310,000

 
84

 
9,890,000

 
18

Natural gas options purchased
5,560,000

 
6

 
1,720,000

 
3

 
3,880,000

 
6

Natural gas basis swaps purchased
8,800,000

 
75

 
7,160,000

 
60

 

 


We had the following derivative balances related to the hedges in our Utilities (in thousands) as of:
 
Sept. 30, 2012
 
Dec. 31, 2011
 
Sept. 30, 2011
Derivative assets, current
$
12,380

 
$
9,844

 
$
3,355

Derivative assets, non-current
$
634

 
$
52

 
$

Derivative liabilities, non-current
$
4,527

 
$
7,156

 
$
1,360

Net unrealized (gain) loss included in Regulatory assets or Regulatory liabilities
$
9,318

 
$
17,556

 
$
11,813

Included in Derivatives:
 
 
 
 
 
  Cash collateral receivable (payable)
$
15,740

 
$
19,416

 
$
12,058

  Option premiums and commissions
$
2,065

 
$
880

 
$
1,750



21



Financing Activities

We have entered into floating-to-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations associated with our floating rate debt obligations. Our interest rate swaps and related balances were as follows (dollars in thousands) as of:
 
Sept. 30, 2012
 
Dec. 31, 2011
 
Sept. 30, 2011
 
Designated 
Interest Rate
Swaps
De-designated
Interest Rate
Swaps*
 
Designated
Interest Rate
Swaps
De-designated
Interest Rate
Swaps*
 
Designated
Interest Rate
Swaps
De-designated
Interest Rate
Swaps*
Notional
$
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
4.25

1.25

 
5.00

2.00

 
5.25

0.25

Derivative liabilities, current
$
7,028

$
77,914

 
$
6,513

$
75,295

 
$
6,724

$
94,588

Derivative liabilities, non-current
$
18,660

$
17,668

 
$
20,363

$
20,696

 
$
21,108

$

Pre-tax accumulated other comprehensive income (loss)
$
(25,688
)
$

 
$
(26,876
)
$

 
$
(27,832
)
$

Year-to Date pre-tax gain (loss)
$

$
(2,902
)
 
$

$
(42,010
)
 
$

$
(40,608
)
Cash collateral receivable (payable) included in derivative
$

$
3,310

 
$

$

 
$

$

_____________
*
Maximum terms in years reflect the amended early termination dates. If the early termination dates are not extended, the swaps will require cash settlement based on the swap value on the termination date. If extended, de-designated swaps totaling $100 million notional terminate in 6.25 years and de-designated swaps totaling $150 million notional terminate in 16.25 years.

Collateral requirements based on our corporate credit rating apply to $50 million of our de-designated swaps. At our current credit ratings, we are required to post collateral for any amount by which the swaps' negative mark-to-market fair value exceeds $20 million. If our senior unsecured credit rating drops to BB+ or below by S&P, or to Ba1 or below by Moody's, we would be required to post collateral for the entire amount of the swaps' negative mark-to-market fair value.

Based on Sept. 30, 2012 market interest rates and balances related to our designated interest rate swaps, a loss of approximately $7.0 million would be reclassified from AOCI during the next 12 months. Estimated and actual realized gains or losses will change during future periods as market interest rates change.


(12)    FAIR VALUE MEASUREMENTS

Derivative Financial Instruments

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The ASC on Fair Value Measurements and Disclosure Requirements establishes a hierarchy for grouping assets and liabilities, based on significance of inputs. For additional information see Notes 3 and 4 included in our 2011 Annual Report on Form 10-K filed with the SEC. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments.

Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable such as the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs.


22



Valuation Methodologies

Oil and Gas Segment:

The commodity option contracts for the Oil and Gas segment are valued under the market approach and include calls and puts. Fair value was derived using quoted prices from third party brokers for similar instruments as to quantity and timing. The prices are then validated through multiple third party sources and therefore support Level 2 disclosure.

The commodity basis swaps for the Oil and Gas segment are valued under the market approach using the instrument's current forward price strip hedged for the same quantity and date and discounted based on the three-month LIBOR. We utilize observable inputs which support Level 2 disclosure.

Utilities Segment:

The commodity contracts for the Utilities, valued using the market approach, include exchange-traded futures, options and basis swaps (Level 2) and OTC basis swaps (Level 3) for natural gas contracts. For Level 2 assets and liabilities, fair value was derived using broker quotes validated by the Chicago Mercantile Exchange pricing for similar instruments. For Level 3 assets and liabilities, fair value was derived using average price quotes from the OTC contract broker and an independent third party market participant.

Corporate Segment:

The interest rate swaps are valued using the market valuation approach. We establish fair value by obtaining price quotes directly from the counterparty which are based on the floating three-month LIBOR curve for the term of the contract. The fair value obtained from the counterparty is then validated by utilizing a nationally recognized service that obtains observable inputs to compute fair value for the same instrument. In addition, the fair value for the interest rate swap derivatives includes a CVA component. The CVA considers the fair value of the interest rate swap and the probability of default based on the life of the contract. For the probability of a default component, we utilize observable inputs supporting Level 2 disclosure by using our credit default spread, if available, or a generic credit default spread curve that takes into account our credit ratings.


23



Recurring Fair Value Measurements

There have been no significant transfers between Level 1 and Level 2 derivative balances. The following tables set forth by level within the fair value hierarchy our assets and liabilities that were accounted for at fair value on a recurring basis (in thousands):
 
 
As of Sept. 30, 2012
 
 
Level 1
Level 2
Level 3
 
Counterparty
Netting
Cash Collateral
Total
Assets:
 
 
 
 
 
 
 
 
Commodity derivatives — Oil and Gas
 
 
 
 
 
 
 


    Options -- Oil
 
$

$
619

$

 
$

$

$
619

    Basis Swaps -- Oil
 

1,526


 


1,526

    Options -- Gas
 



 



    Basis Swaps -- Gas
 

2,071


 


2,071

Commodity derivatives — Utilities
 

(2,760
)
34

(b) 

15,740

13,014

Cash and cash equivalents (a)
 
247,192



 


247,192

Total
 
$
247,192

$
1,456

$
34

 
$

$
15,740

$
264,422

 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
Commodity derivatives — Oil and Gas
 
 
 
 
 
 
 


    Options -- Oil
 
$

$
885

$

 
$

$

$
885

    Basis Swaps -- Oil
 

56


 


56

    Options -- Gas
 



 



    Basis Swaps -- Gas
 

1,181


 


1,181

Commodity derivatives — Utilities
 

4,527


 


4,527

Interest rate swaps
 

124,580


 

(3,310
)
121,270

Total
 
$

$
131,229

$

 
$

$
(3,310
)
$
127,919

______________
(a)
Level 1 assets and liabilities are described in Note 13.
(b)
The significant unobservable inputs used in the fair value measurement of the long-term OTC contracts are based on the average of price quotes from an independent third party market participant and the OTC contract broker. The unobservable inputs are long-term natural gas prices. Significant changes to these inputs along with the contract term would impact the derivative asset/liability and regulatory asset/liability, but will not impact the results of operations until the contract is settled under the original terms of the contract. The contracts will be classified as Level 2 once settlement is within 60 months of maturity and quoted market prices from a market exchange are available.

24




 
 
As of Dec. 31, 2011
 
 
Level 1
Level 2
Level 3
 
Counterparty
Netting
Cash Collateral
Total
Assets:
 
 
 
 
 
 
 
 
Commodity derivatives — Oil and Gas
 
 
 
 
 
 
 
 
Options -- Oil
 
$

$

$
768

(a) 
$
5

$

$
773

Basis Swaps -- Oil
 

727


 


727

Options -- Gas
 



 



Basis Swaps -- Gas
 

9,158


 


9,158

Commodity derivatives —Utilities
 

(9,520
)

 

19,416

9,896

Money market funds
 
6,005



 


6,005

Total
 
$
6,005

$
365

$
768

(a) 
$
5

$
19,416

$
26,559

 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
Commodity derivatives — Oil and Gas
 
 
 
 
 
 
 
 
Options -- Oil
 
$

$

$
1,165

(a) 
$
5

$

$
1,170

Basis Swaps -- Oil
 

2,200


 


2,200

Options -- Gas
 



 



Basis Swaps -- Gas
 

7


 


7

Commodity derivatives — Utilities
 

7,156


 


7,156

Interest rate swaps
 

122,867


 


122,867

Total
 
$

$
132,230

$
1,165

(a) 
$
5

$

$
133,400

_________
(a)
Of the net balance included as Level 3, transfers out of Level 3 included settlement of losses of approximately $0.5 million within AOCI and approximately $0.9 million transferred to level 2 as inputs becoming more observable.


25



 
 
As of Sept. 30, 2011
 
 
Level 1
Level 2
Level 3
 
Counterparty
Netting
Cash Collateral
Total
Assets:
 
 
 
 
 
 
 
 
Commodity derivatives — Oil and Gas
 
 
 
 
 
 
 
 
Options -- Oil
 
$

$

$
328

 
$

$

$
328

Basis Swaps -- Oil
 

4,086


 


4,086

Options -- Gas
 



 



Basis Swaps -- Gas
 

7,654


 


7,654

Commodity derivatives — Utilities
 

(8,703
)

 

12,058

3,355

Money market funds
 
9,006



 


9,006

Total
 
$
9,006

$
3,037

$
328

 
$

$
12,058

$
24,429

 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
Commodity derivatives — Oil and Gas
 
 
 
 
 
 
 
 
Options -- Oil
 
$

$

$

 
$

$

$

Basis Swaps -- Oil
 



 



Options -- Gas
 



 



Basis Swaps -- Gas
 

7


 


7

Commodity derivatives — Utilities
 

1,360


 


1,360

Interest rate swaps
 

122,420


 


122,420

Total
 
$

$
123,787

$

 
$

$

$
123,787


Fair Value Measures

As required by accounting standards for derivatives and hedges, fair values within the following tables are presented on a gross basis and do not reflect the netting of asset and liability positions permitted in accordance with accounting standards for offsetting and under terms of our master netting agreements. Further, the amounts do not include net cash collateral on deposit in margin accounts at Sept. 30, 2012, Dec. 31, 2011, and Sept. 30, 2011, to collateralize certain financial instruments, which are included in Derivative assets and/or Derivative liabilities. Therefore, the gross balances are not indicative of either our actual credit exposure or net economic exposure. Additionally, the amounts below will not agree with the amounts presented on our Condensed Consolidated Balance Sheets, nor will they correspond to the fair value measurements presented in Note 11.


26



The following tables present the fair value and balance sheet classification of our derivative instruments (in thousands):

As of Sept. 30, 2012
 
Balance Sheet Location
 
Fair Value
of Asset
Derivatives
Fair Value
of Liability
Derivatives
Derivatives designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
3,263

$

Commodity derivatives
Derivative assets — non-current
 
533


Commodity derivatives
Derivative liabilities — current
 

1,534

Commodity derivatives
Derivative liabilities — non-current
 

555

Interest rate swaps
Derivative liabilities — current
 

7,029

Interest rate swaps
Derivative liabilities — non-current
 

18,661

Total derivatives designated as hedges
 
 
$
3,796

$
27,779

 
 
 
 
 
Derivatives not designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
421

$
3,361

Commodity derivatives
Derivative assets — non-current
 

(634
)
Commodity derivatives
Derivative liabilities — current
 

33

Commodity derivatives
Derivative liabilities — non-current
 

4,527

Interest rate swaps
Derivative liabilities — current
 

77,913

Interest rate swaps
Derivative liabilities — non-current
 

20,977

Total derivatives not designated as hedges
 
 
$
421

$
106,177


As of Dec. 31, 2011
 
Balance Sheet Location
 
Fair Value
of Asset
Derivatives
Fair Value
of Liability
Derivatives
Derivatives designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
8,739

$

Commodity derivatives
Derivative assets — non-current
 
1,919


Commodity derivatives
Derivative liabilities — current
 

2,559

Commodity derivatives
Derivative liabilities — non-current
 

818

Interest rate swaps
Derivative liabilities — current
 

6,513

Interest rate swaps
Derivative liabilities — non-current
 

20,363

Total derivatives designated as hedges
 
 
$
10,658

$
30,253

 
 
 
 
 
Derivatives not designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$

$
9,572

Commodity derivatives
Derivative assets — non-current
 

(52
)
Commodity derivatives
Derivative liabilities — current
 


Commodity derivatives
Derivative liabilities — non-current
 

7,156

Interest rate swaps
Derivative liabilities — current
 

75,295

Interest rate swaps
Derivative liabilities — non-current
 

20,696

Total derivatives not designated as hedges
 
 
$

$
112,667



27



As of Sept. 30, 2011
 
Balance Sheet Location
 
Fair Value
of Asset
Derivatives
Fair Value
of Liability
Derivatives
Derivatives designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
8,822

$

Commodity derivatives
Derivative assets — non-current
 
3,246


Commodity derivatives
Derivative liabilities — current
 


Commodity derivatives
Derivative liabilities — non-current
 

7

Interest rate swaps
Derivative liabilities — current
 

6,724

Interest rate swaps
Derivative liabilities — non-current
 

21,108

Total derivatives designated as hedges
 
 
$
12,068

$
27,839

 
 
 
 
 
Derivatives not designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$

$
8,703

Commodity derivatives
Derivative assets — non-current
 


Commodity derivatives
Derivative liabilities — current
 
(2
)
(1,360
)
Commodity derivatives
Derivative liabilities — non-current
 


Interest rate swaps
Derivative liabilities — current
 

94,588

Interest rate swaps
Derivative liabilities — non-current
 


Total derivatives not designated as hedges
 
 
$
(2
)
$
101,931


A description of our derivative activities is included in Note 11. The following tables present the impact that derivatives had on our Condensed Consolidated Statements of Income.

Cash Flow Hedges

The impact of cash flow hedges on our Condensed Consolidated Statements of Income was as follows (in thousands):
Three Months Ended Sept. 30, 2012
Derivatives in Cash Flow Hedging Relationships
 
Amount of
Gain/(Loss)
Recognized
in AOCI
Derivative
(Effective
Portion)
 
Location
of Gain/(Loss)
Reclassified
from AOCI
into Income
(Effective
Portion)
 
Amount of
Reclassified
Gain/(Loss)
from AOCI
into Income
(Effective
Portion)
 
Location of
Gain/(Loss)
Recognized
in Income
on Derivative
(Ineffective
Portion)
 
Amount of
Gain/(Loss)
Recognized in
Income on
Derivative
(Ineffective
Portion)
Interest rate swaps
 
$
(1,684
)
 
Interest expense
 
$
(1,853
)
 
 
 
$

Commodity derivatives
 
(3,111
)
 
Revenue
 
1,838

 
 
 

Total
 
$
(4,795
)
 
 
 
$
(15
)
 
 
 
$


Three Months Ended Sept. 30, 2011
Derivatives in Cash Flow Hedging Relationships
 
Amount of
Gain/(Loss)
Recognized
in AOCI
Derivative
(Effective
Portion)
 
Location
of Gain/(Loss)
Reclassified
from AOCI
into Income
(Effective
Portion)
 
Amount of
Reclassified
Gain/(Loss)
from AOCI
into Income
(Effective
Portion)
 
Location of
Gain/(Loss)
Recognized
in Income
on Derivative
(Ineffective
Portion)
 
Amount of
Gain/(Loss)
Recognized in
Income on
Derivative
(Ineffective
Portion)
Interest rate swaps
 
$
(6,958
)
 
Interest expense
 
$
(1,930
)
 
 
 
$

Commodity derivatives
 
10,095

 
Revenue
 
1,516

 
 
 

Total
 
$
3,137

 
 
 
$
(414
)
 
 
 
$



28



Nine Months Ended Sept. 30, 2012
Derivatives in Cash Flow Hedging Relationships
 
Amount of
Gain/(Loss)
Recognized
in AOCI
Derivative
(Effective
Portion)
 
Location
of Gain/(Loss)
Reclassified
from AOCI
into Income
(Effective
Portion)
 
Amount of
Reclassified
Gain/(Loss)
from AOCI
into Income
(Effective
Portion)
 
Location of
Gain/(Loss)
Recognized
in Income
on Derivative
(Ineffective
Portion)
 
Amount of
Gain/(Loss)
Recognized in
Income on
Derivative
(Ineffective
Portion)
Interest rate swaps
 
$
(4,697
)
 
Interest expense
 
$
(5,518
)
 
 
 
$

Commodity derivatives
 
601

 
Revenue
 
7,741

 
 
 

Total
 
$
(4,096
)
 
 
 
$
2,223

 
 
 
$


Nine Months Ended Sept. 30, 2011
Derivatives in Cash Flow Hedging Relationships
 
Amount of
Gain/(Loss)
Recognized
in AOCI
Derivative
(Effective
Portion)
 
Location
of Gain/(Loss)
Reclassified
from AOCI
into Income
(Effective
Portion)
 
Amount of
Reclassified
Gain/(Loss)
from AOCI
into Income
(Effective
Portion)
 
Location of
Gain/(Loss)
Recognized
in Income
on Derivative
(Ineffective
Portion)
 
Amount of
Gain/(Loss)
Recognized in
Income on
Derivative
(Ineffective
Portion)
Interest rate swaps
 
$
(11,428
)
 
Interest expense
 
$
(5,741
)
 
 
 
$

Commodity derivatives
 
9,784

 
Revenue
 
2,849

 
 
 

Total
 
$
(1,644
)
 
 
 
$
(2,892
)
 
 
 
$


Derivatives Not Designated as Hedge Instruments

The impact of derivative instruments that have not been designated as hedging instruments on our Condensed Consolidated Statements of Income was as follows (in thousands):

 
 
 
 
Three Months Ended
 
Nine Months Ended
 
 
 
 
Sept. 30, 2012
 
Sept. 30, 2012
Derivatives Not Designated
 as Hedging Instruments
 
Location of Gain/(Loss)
 on Derivatives
 Recognized in Income
 
Amount of Gain/(Loss)
on Derivatives
Recognized in Income
 
Amount of Gain/(Loss)
on Derivatives
Recognized in Income
Interest rate swaps - unrealized
 
Unrealized gain (loss) on interest rate swaps, net
 
$
605

 
$
(2,902
)
Interest rate swaps - realized
 
Interest expense
 
(3,250
)
 
(9,697
)
Commodity derivatives
 
Revenue
 
(14
)
 
(14
)
 
 
 
 
$
(2,659
)
 
$
(12,613
)

 
 
 
 
Three Months Ended
 
Nine Months Ended
 
 
 
 
Sept. 30, 2011
 
Sept. 30, 2011
Derivatives Not Designated
 as Hedging Instruments
 
Location of Gain/(Loss)
 on Derivatives
 Recognized in Income
 
Amount of Gain/(Loss)
on Derivatives
Recognized in Income
 
Amount of Gain/(Loss)
on Derivatives
Recognized in Income
Interest rate swaps - unrealized
 
Unrealized gain (loss) on interest rate swaps, net
 
$
(38,246
)
 
$
(40,608
)
Interest rate swaps - realized
 
Interest expense
 
(3,373
)
 
(10,077
)
 
 
 
 
$
(41,619
)
 
$
(50,685
)



29



(13)    FAIR VALUE OF FINANCIAL INSTRUMENTS

The estimated fair values of our financial instruments are as follows (in thousands) as of:

 
Sept. 30, 2012
 
Dec. 31, 2011
 
Sept. 30, 2011
 
Carrying
Amount
Fair Value
 
Carrying
Amount
Fair Value
 
Carrying
Amount
Fair Value
Cash and cash equivalents (a)
$
247,192

$
247,192

 
$
21,628

$
21,628

 
$
30,198

$
30,198

Restricted cash and equivalents (a)
$
7,302

$
7,302

 
$
9,254

$
9,254

 
$
4,080

$
4,080

Notes receivable (a)
$
21,832

$
21,832

 
$

$

 
$

$

Notes payable (b)
$
225,000

$
225,000

 
$
345,000

$
345,000

 
$
359,000

$
359,000

Long-term debt, including current maturities (c)
$
1,271,260

$
1,471,932

 
$
1,282,882

$
1,464,289

 
$
1,285,087

$
1,430,271

____________
(a)
Fair value approximates carrying value due to either the short-term length of maturity or variable interest rates that approximate prevailing market rates and therefore is classified in Level 1 in the fair value hierarchy.
(b)
The carrying amounts of our notes payable approximate fair value due to their variable interest rates with short reset periods.
(c)
Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy.

The following methods and assumptions were used to estimate the fair value of each class of our financial instruments.

Cash and Cash Equivalents

Included in cash and cash equivalents are cash, overnight repurchase agreement accounts, money market funds and term deposits. As part of our cash management process, excess operating cash is invested in overnight repurchase agreements with our bank. Repurchase agreements are not deposits and are not insured by the U.S. Government, the FDIC or any other government agency and involve investment risk including possible loss of principal. We believe, however, that the market risk arising from holding these financial instruments is minimal.

Restricted Cash and Equivalents

Restricted cash and equivalents represent restricted cash and uninsured term deposits.

Notes Receivable

Notes receivable, included in Other current assets on the accompanying Condensed Consolidated Balance Sheet, represents cash held by a third party related to tax planning strategies for effecting like-kind exchange structuring for the purchase of additional oil and gas leases.

Notes Payable

Notes Payable represent our short-term corporate term loan and borrowings under our Revolving Credit Facility.

Long-term Debt

Our debt instruments are marked to fair value using the market valuation approach. The fair value for our fixed rate debt instruments is estimated based on quoted market prices and yields for debt instruments having similar maturities and debt ratings. The carrying amounts of our variable rate debt approximate fair value due to the variable interest rates with short reset periods.



30



(14)    COMMITMENTS AND CONTINGENCIES

Commitments and Contingencies

There have been no significant changes to commitments and contingencies from those previously disclosed in Note 19 of our Notes to the Consolidated Financial Statements in our 2011 Annual Report on Form 10-K.

Dividend Restrictions

Our Revolving Credit Facility and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. As of Sept. 30, 2012, we were in compliance with these 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 stockholders 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 at Sept. 30, 2012:

Our utilities are generally limited to the amount of dividends allowed to be paid to us as a utility holding company under the Federal Power Act and settlement agreements with state regulatory jurisdictions. As of Sept. 30, 2012, the restricted net assets at our Utilities Group were approximately $227.2 million.

As required by the covenant in the Black Hills Wyoming project financing, Black Hills Non-regulated Holdings has maintained restricted equity of at least $100.0 million.


(15)     SALE OF ASSETS

Oil and Gas

On Sept. 27, 2012, our Oil and Gas segment sold a majority of its Bakken and Three Forks shale assets in the Williston Basin of North Dakota. The sale included approximately 73 gross wells, 28,000 net lease acres and had an effective date of July 1, 2012.

Our Oil and Gas segment follows the full-cost method of accounting for oil and gas activities. Typically this methodology does not allow for gain or loss on sale and proceeds from sale are credited against the full cost pool. Gain or loss recognition is allowed when such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. The Sept. 27, 2012 sale significantly alters the relationship and accordingly we have recorded a gain of $27.3 million with the remainder of the proceeds recorded as a reduction in the full cost pool. This reduction in the full cost pool will decrease in the depreciation, depletion and amortization rate.

Net cash proceeds were as follows (in thousands):
Cash proceeds received on date of sale
$
243,314

 
 
Adjustments to proceeds:
 
Post close adjustments
1,490

Transaction adviser fees
(1,400
)
Estimated payment for contractual obligation related to "back-in" fee *
(16,847
)
 
 
Net cash proceeds
$
226,557

_____________
* Required payment, triggered by the sale of the property, arising from a contractual obligation contained in the original participation agreement with the property operator.


31



Electric Utilities

On Sept. 18, 2012, Colorado Electric completed the sale of an undivided 50 percent ownership interest in the 29 megawatt Busch Ranch Wind project to AltaGas for $25.0 million. Colorado Electric retains the remaining undivided interest and will be the operator of this jointly owned facility. Commercial operation of the newly constructed wind farm was achieved on Oct. 16, 2012. Colorado Electric will purchase AltaGas's interest in the energy produced by the wind farm through a REPA expiring on Oct. 16, 2037.


(16)    IMPAIRMENT OF LONG-LIVED ASSETS

Under the full cost method of accounting used by our Oil and Gas segment to account for exploration, development, and acquisition of crude oil and natural gas reserves, all costs attributable to these activities are capitalized. These capitalized costs, less accumulated amortization and related deferred income taxes, are subject to a ceiling test that limits the pooled costs to the aggregate of the discounted value of future net revenue attributable to proved natural gas and crude oil reserves using a discount rate defined by the SEC plus the lower of cost or market value of unevaluated properties. Any costs in excess of the ceiling are written off as a non-cash charge.

As a result of continued low commodity prices, we recorded a $26.9 million non-cash impairment of oil and gas assets included in our Oil and Gas segment in the second quarter of 2012. In determining the ceiling value of our assets, we utilized the average of the quoted prices from the first day of each month from the previous 12 months. For natural gas, the average NYMEX price was $3.15 per Mcf, adjusted to $2.66 per Mcf at the wellhead; for crude oil, the average NYMEX price was $95.67 per barrel, adjusted to $85.36 per barrel at the wellhead.


(17)    DISCONTINUED OPERATIONS

On Feb. 29, 2012, we sold the outstanding stock of Enserco, our Energy Marketing segment. The transaction was completed through a stock purchase agreement and certain other ancillary agreements. Net cash proceeds on the date of the sale were approximately $166.3 million, subject to final post-closing adjustments. The proceeds represent $108.8 million received from the buyer and $57.5 million cash retained from Enserco prior to closing.

Pursuant to the provisions of the stock purchase agreement, the buyer requested purchase price adjustments totaling $7.2 million. We contested this proposed adjustment and estimated the amount owed at $1.4 million, which is accrued for in the accompanying financial statements as of Sept. 30, 2012. If we do not reach a negotiated agreement with the buyer regarding the purchase price adjustment, resolution will occur through the dispute resolution provision of the stock purchase agreement.

The accompanying Condensed Consolidated Financial Statements have been classified to reflect Enserco as discontinued operations. For comparative purposes, all prior periods presented have been restated to reflect the classification.


32



Operating results of the Energy Marketing segment included in Income (loss) from discontinued operations, net of tax on the accompanying Condensed Consolidated Statements of Income were as follows (in thousands):
 
For the Three Months Ended
For the Nine Months Ended
 
Sept. 30, 2012
Sept. 30, 2011
Sept. 30, 2012
Sept. 30, 2011
 
 
 
 
 
Revenue
$

$
6,937

$
(604
)
$
21,878

 
 
 
 
 
Pre-tax income (loss) from discontinued operations
$
(311
)
$
1,495

$
(6,622
)
$
4,404

Pre-tax gain (loss) on sale


(3,787
)

Income tax (expense) benefit
145

(857
)
3,599

(1,878
)
 
 
 
 
 
Income (loss) from discontinued operations, net of tax (a)
$
(166
)
$
638

$
(6,810
)
$
2,526

_____________
(a)
Includes transaction related costs, net of tax, of $0.2 million and $2.5 million for three and nine months ended Sept. 30, 2012, respectively.

Indirect corporate costs and inter-segment interest expense after-tax totaling $0.5 million for the three months ended Sept. 30, 2011, and $1.6 million and $1.5 million for the nine months ended Sept. 30, 2012 and 2011, respectively, were reclassified from the Energy Marketing segment to the Corporate segment in continuing operations on the accompanying Condensed Consolidated Statements of Income.

Net assets of the Energy Marketing segment included in Assets/Liabilities of discontinued operations in the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands) as of:
 
Dec. 31, 2011
Sept. 30, 2011
 
 
 
Other current assets
$
280,221

$
282,361

Derivative assets, current and non-current
52,859

50,519

Property, plant and equipment, net
5,828

5,391

Goodwill
1,435

1,435

Other non-current assets
508

(7,204
)
Other current liabilities
(132,951
)
(134,747
)
Derivative liabilities, current and non-current
(26,084
)
(31,978
)
Other non-current liabilities
(14,894
)
(4,959
)
Net assets
$
166,922

$
160,818



(18)    SUBSEQUENT EVENTS

Long-term Debt

On Oct. 31, 2012, we redeemed our $225.0 million of senior unsecured 6.5 percent notes, which were originally scheduled to mature on May 15, 2013. The total payment was $238.8 million, including accrued interest expense and a make-whole provision payment of $7.1 million.


33



ITEM 2.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

We are an integrated energy company operating principally in the United States with two major business groups — Utilities and Non-regulated Energy. We report our business groups in the following financial segments:

Business Group
Financial Segment
 
 
Utilities
Electric Utilities
 
Gas Utilities
 
 
Non-regulated Energy*
Power Generation
 
Coal Mining
 
Oil and Gas
_______________
*
On Feb. 29, 2012, we sold the stock of Enserco, our Energy Marketing segment, to a third party buyer and therefore we now classify the segment as discontinued operations.

Our Utilities Group consists of our Electric and Gas Utilities segments. Our Electric Utilities segment generates, transmits and distributes electricity to approximately 201,500 customers in South Dakota, Wyoming, Colorado and Montana; and also distributes natural gas to approximately 34,800 Cheyenne Light customers in Wyoming. Our Gas Utilities serve approximately 528,800 natural gas customers in Colorado, Iowa, Kansas and Nebraska. Our Non-regulated Energy Group consists of our Power Generation, Coal Mining and Oil and Gas segments. Our Power Generation segment produces electric power from our generating plants and sells the electric capacity and energy principally to our utilities under long-term contracts. Our Coal Mining segment produces coal at our coal mine near Gillette, Wyo. and sells the coal primarily to on-site, mine-mouth power generation facilities. Our Oil and Gas segment principally engages in exploration, development and production of crude oil and natural gas, primarily in the Rocky Mountain region.

Certain industries in which we operate are highly seasonal, and revenue 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 prices. In particular, the normal peak usage season for electric utilities is June through August with sensitivity from the degree of humidity while 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 and nine months ended Sept. 30, 2012 and 2011, and our financial condition as of Sept. 30, 2012, Dec. 31, 2011, and Sept. 30, 2011 are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period or for the entire year.
See Forward-Looking Information in the Liquidity and Capital Resources section of this Item 2, beginning on Page 64.

The following business group and segment information does not include intercompany eliminations. Minor differences in amounts may result due to rounding. All amounts are presented on a pre-tax basis unless otherwise indicated. Information has been revised to remove information related to the operations of our Energy Marketing segment, now classified as discontinued operations, as a result of the sale of Enserco on Feb. 29, 2012.


34



Results of Operations

Executive Summary, Significant Events and Overview

Three Months Ended Sept. 30, 2012 Compared to Three Months Ended Sept. 30, 2011. Income from continuing operations for the three months ended Sept. 30, 2012 was $34.6 million, or $0.78 per share, compared to Loss from continuing operations of $11.2 million, or $0.29 per share, reported for the same period in 2011. The 2012 Income from continuing operations included an after-tax gain on sale of $17.7 million relating to the sale of the Williston Basin assets of our Oil and Gas segment, an incentive accrual of $2.2 million after-tax relating to the Williston Basin asset sale and a $0.4 million non-cash after-tax unrealized mark-to-market gain on certain interest rate swaps. The 2011 Loss from continuing operations included a $24.9 million after-tax non-cash unrealized mark-to-market loss on the same interest rate swaps.

Net income for the three months ended Sept. 30, 2012 was $34.5 million, or $0.78 per share, compared to Net loss of $10.5 million, or $0.27 per share, for the same period in 2011. Net income for the three months ended Sept. 30, 2012 and 2011 include the same significant items discussed above.

Nine Months Ended Sept. 30, 2012 Compared to Nine Months Ended Sept. 30, 2011. Income from continuing operations for the nine months ended Sept. 30, 2012 was $57.6 million, or $1.31 per share, compared to Income from continuing operations of $21.6 million, or $0.54 per share, reported for the same period in 2011. The 2012 Income from continuing operations included an after-tax gain of $17.7 million relating to the sale of the Williston Basin assets of our Oil and Gas segment, an incentive accrual of $2.2 million after-tax relating to the Williston Basin asset sale, a non-cash after-tax ceiling test impairment of $17.3 million, a $1.9 million non-cash after-tax unrealized mark-to-market loss on certain interest rate swaps, and an after-tax write-off of $1.0 million of deferred financing costs related to our previous revolving credit facility. The 2011 Income from continuing operations included a $26.4 million after-tax unrealized non-cash mark-to-market loss on the same interest rate swaps.

Net income for the nine months ended Sept. 30, 2012 was $50.8 million, or $1.15 per share, compared to $24.1 million, or $0.61 per share, for the same period in 2011. Net income for the nine months ended Sept. 30, 2012 and 2011 include the same significant items discussed above.

35




 
Three Months Ended
Sept. 30,
Nine Months Ended
Sept. 30,
 
2012
2011
Variance
2012
2011
Variance
 
(in thousands)
Revenue
 
 
 
 
 
 
Utilities
$
218,452

$
226,367

$
(7,915
)
$
778,263

$
844,365

$
(66,102
)
Non-regulated Energy
60,354

45,098

15,256

169,097

128,277

40,820

Intercompany eliminations
(31,998
)
(21,942
)
(10,056
)
(92,338
)
(61,635
)
(30,703
)
 
$
246,808

$
249,523

$
(2,715
)
$
855,022

$
911,007

$
(55,985
)
 
 
 
 
 
 
 
Net income (loss)
 
 
 
 
 
 
Electric Utilities
$
14,573

$
15,790

$
(1,217
)
$
37,478

$
34,653

$
2,825

Gas Utilities
3

572

(569
)
16,369

24,275

(7,906
)
Utilities
14,576

16,362

(1,786
)
53,847

58,928

(5,081
)
 
 
 
 
 
 
 
Power Generation
5,128

337

4,791

15,968

2,071

13,897

Coal Mining
1,690

555

1,135

3,924

(1,124
)
5,048

Oil and Gas (a)
17,389

241

17,148

(2,219
)
(553
)
(1,666
)
Non-regulated Energy
24,207

1,133

23,074

17,673

394

17,279

 
 
 
 
 
 
 
Corporate and eliminations (b)(c)
(4,160
)
(28,658
)
24,498

(13,949
)
(37,711
)
23,762

 
 
 
 
 
 
 
Income (loss) from continuing operations
34,623

(11,163
)
45,786

57,571

21,611

35,960

 
 
 
 
 
 
 
Income (loss) from discontinued operations, net of tax
(166
)
638

(804
)
(6,810
)
2,526

(9,336
)
Net income (loss)
$
34,457

$
(10,525
)
$
44,982

$
50,761

$
24,137

$
26,624

______________
(a)
Net income (loss) for three and nine months ended Sept. 30, 2012 includes a $17.7 million after-tax gain on the sale of the Williston Basin assets and Net income (loss) for the nine months ended Sept. 30, 2012 also includes a $17.3 million non-cash after-tax ceiling test impairment. See Notes 15 and 16 of the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.
(b)
Financial results of our Energy Marketing segment have been classified as discontinued operations. Certain indirect corporate costs and inter-segment interest expenses totaling $0.5 million after-tax for the three months ended Sept. 30, 2011 and $1.6 million and $1.5 million for the nine months ended Sept. 30, 2012 and 2011, respectively were not reclassified as discontinued operations and are included in the Corporate segment in continuing operations. See Note 17 of the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.
(c)
Income (loss) from continuing operations includes $0.4 million net after-tax non-cash mark-to-market gain and $1.9 million net after-tax non-cash mark-to-market loss on interest rate swaps for the three and nine months ended Sept. 30, 2012, respectively, and a $24.9 million and $26.4 million net after-tax non-cash mark-to-market loss on interest rate swaps for the three and nine months ended Sept. 30, 2011, respectively.

Business Group highlights for 2012 include:

Utilities Group

On Sept. 18, 2012, Colorado Electric completed the sale of a 50 percent ownership interest in the 29 megawatt Busch Ranch Wind project for $25.0 million. The wind turbine project commenced commercial operation on Oct. 16, 2012.

On June 18, 2012, the WPSC approved a stipulation and agreement for Cheyenne Light resulting in an annual revenue increase of $2.7 million for electric customers and $1.6 million for gas customers effective July 1, 2012. The settlement also included a return on equity of 9.6 percent with a capital structure of 54 percent equity and 46 percent debt.


36



On June 4, 2012, Colorado Gas filed a request with the CPUC for an increase in annual gas revenues to recover capital investments and increased operation and maintenance expenses. The CPUC required this rate case filing as part of a previous settlement agreement when we purchased Colorado Gas. All parties reached a rate case settlement and the settlement hearing was held on Oct. 12, 2012. A decision is expected in the first quarter of 2013. The settlement, if approved, includes a $0.2 million revenue increase, a return on equity of 9.6 percent and a capital structure of 50 percent equity and 50 percent debt.

Weather was a contributing factor for our utilities for the quarter and the year. Year-to-date utility results were unfavorably impacted by warm weather, particularly at the Gas Utilities. Our service territories reported warmer weather, as measured by degree days, compared to the 30-year average and last year. Heating degree days year-to-date were 21 percent lower than weighted average norms for our Gas Utilities. When compared to colder than normal weather during the same period in 2011, heating degree days were 40 percent lower than the same period in 2011 for our Gas Utilities. For our Electric Utilities, although temperatures were above normal, weather-related demand was tempered by significantly lower humidity in 2012 than 2011 in our service territories.

Colorado Electric’s new $230 million, 180 megawatt power plant near Pueblo, Colo. began commercial operations and started serving utility customers on Jan. 1, 2012. New rates and cost adjustments were effective Jan. 1, 2012, providing an additional $30.0 million in gross margins at Colorado Electric for the nine months ended Sept. 30, 2012.

Cheyenne Light and Black Hills Power received final approvals and permits for the Cheyenne Prairie Generating Station. The WPSC approved the CPCN on July 31, 2012 authorizing the construction, operation and maintenance of a new $237 million, 132 megawatt natural gas-fired electric generating facility in Cheyenne, Wyo. The state of Wyoming issued the air permit for the project on Aug. 31, 2012 and the U.S. Environmental Protection Agency issued the greenhouse gas air permit on Sept. 27, 2012. Upon receipt of the final permit, the major equipment for the project was ordered. Commencement of construction for the new plant is expected in spring 2013. Project costs for plant construction and associated transmission are estimated at $222 million, with up to $15 million of construction financing costs, for a total of $237 million.

On Oct. 30, 2012 Cheyenne Light and Black Hills Power received approval from the WPSC to use a construction financing rider during construction of the Cheyenne Prairie Generating Station in lieu of traditional AFUDC. The rider allows Cheyenne Light and Black Hills Power to earn a rate of return during the construction period on the approximately 60 percent of the project cost related to serving Wyoming customers. We are evaluating filing for a similar rider in South Dakota.

On Aug. 6, 2012 Black Hills Power and Colorado Electric announced plans to suspend plant operations at some of our older coal-fired and natural gas-fired facilities. In addition, we also identified retirement dates for the older coal-fired power plants because of federal and state environmental regulations. The affected plants are listed in the table below with their operations suspension date (if applicable) and their ultimate retirement date (if identified).
Plant
Company
Megawatts
Type of Plant
Suspend Date
Retirement Date
Age of Plant (in years)
Osage
Black Hills Power
34.5
Coal
Oct. 1, 2010
March 21, 2014
64
Ben French
Black Hills Power
25
Coal
Aug. 31, 2012
March 21, 2014
52
Neil Simpson I
Black Hills Power
21.8
Coal
NA
March 21, 2014
43
W.N. Clark
Colorado Electric
40
Coal
Dec. 31, 2012
Dec. 31, 2013
57
Pueblo Unit #5
Colorado Electric
9
Gas
Dec. 31, 2012
to be determined
71
Pueblo Unit #6
Colorado Electric
20
Gas
Dec. 31, 2012
to be determined
63
 
On July 30, 2012, Colorado Electric filed its Electric Resource Plan with the CPUC seeking to develop and own replacement capacity for the retirement of the coal-fired W.N. Clark power plant, which must be retired pursuant to the Colorado Clean Air – Clean Jobs Act. The CPUC dismissed the initial filing and directed Colorado Electric to re-file an Energy Resource Plan by Jan. 18, 2013 in order to address alternatives for the replacement capacity of W.N. Clark power plant, as well as the retirement of Pueblo No. 5 and No. 6. The CPUC also directed Colorado Electric to request a CPCN for any replacement capacity that Colorado Electric seeks to develop and own.



37



Non-regulated Energy Group

On Sept. 27, 2012, our Oil and Gas segment sold 85 percent of its Williston Basin assets, including approximately 73 gross wells and 28,000 net lease acres, for net cash proceeds of $226.6 million. We recognized a gain of $27.3 million on the sale. The portion of the sale amount not recognized as gain reduced the full-cost pool and will decrease our depreciation, depletion and amortization rate.

Our Coal Mining segment received all necessary permits and approval for a revised mine plan relocating mining operations to an area in the mine with lower overburden, reducing overall mining costs for the next several years. The new mine plan went into effect during the second quarter of 2012.

In the second quarter of 2012, our Oil and Gas segment recorded a $26.9 million non-cash ceiling test impairment loss as a result of continued low natural gas prices.

Colorado IPP’s new $261 million, 200 megawatt power plant near Pueblo, Colo. began serving customers on Jan. 1, 2012. Output from the plant is sold under a 20-year power purchase agreement to Colorado Electric.

Corporate

On Oct. 31, 2012, we redeemed our $225.0 million of senior unsecured 6.5 percent notes, which originally were scheduled to mature on May 15, 2013.
 
On June 24, 2012, we extended for one year our $150 million term loan at an interest rate of 1.10 percent over LIBOR.

On Feb. 1, 2012, we entered into a new $500 million Revolving Credit Facility expiring Feb. 1, 2017. Deferred financing costs of $1.5 million relating to the previous credit facility were written off during the first quarter of 2012.

We recognized a non-cash unrealized mark-to-market loss related to certain interest rate swaps of $2.9 million for the nine months ended Sept. 30, 2012 compared to a $40.6 million non-cash unrealized mark-to-market loss on these swaps for the same period in 2011.

Discontinued Operations

On Feb. 29, 2012, we sold the outstanding stock of Enserco, our Energy Marketing segment. The transaction was completed through a stock purchase agreement and certain other ancillary agreements. Net cash proceeds from the transaction were approximately $166.3 million, subject to final post-closing adjustments. Pursuant to the provisions of the stock purchase agreement, the buyer requested purchase price adjustments totaling $7.2 million. We contested this proposed adjustment and estimated the amount owed at $1.4 million, which is accrued in the accompanying financial statements as of Sept. 30, 2012. If we do not reach a negotiated agreement with the buyer regarding the purchase price adjustment, resolution will occur through the dispute resolution provision of the stock purchase agreement.


Utilities Group

We report two segments within the Utilities Group: Electric Utilities and Gas Utilities. The Electric Utilities segment includes the electric operations of Black Hills Power, Colorado Electric and the electric and natural gas operations of Cheyenne Light. The Gas Utilities segment includes the regulated natural gas utility operations of Black Hills Energy in Colorado, Iowa, Kansas and Nebraska.



38



Electric Utilities

 
Three Months Ended Sept. 30,
Nine Months Ended Sept. 30,
 
2012
2011
Variance
2012
2011
Variance
 
(in thousands)
Revenue — electric
$
151,465

$
149,664

$
1,801

$
442,731

$
417,512

$
25,219

Revenue — gas
3,552

4,052

(500
)
21,189

24,014

(2,825
)
Total revenue
155,017

153,716

1,301

463,920

441,526

22,394

 
 
 
 
 
 
 
Fuel, purchased power and cost of gas — electric
65,992

71,387

(5,395
)
191,113

203,319

(12,206
)
Purchased gas — gas
1,046

1,703

(657
)
11,087

13,583

(2,496
)
Total fuel, purchased power and cost of gas
67,038

73,090

(6,052
)
202,200

216,902

(14,702
)
 
 
 
 
 
 
 
Gross margin — electric
85,473

78,277

7,196

251,618

214,193

37,425

Gross margin — gas
2,506

2,349

157

10,102

10,431

(329
)
Total gross margin
87,979

80,626

7,353

261,720

224,624

37,096

 
 
 
 
 
 
 
Operations and maintenance
34,080

34,837

(757
)
110,176

106,107

4,069

Gain on sale of operating assets

(768
)
768


(768
)
768

Depreciation and amortization
18,821

13,221

5,600

56,448

39,051

17,397

Total operating expenses
52,901

47,290

5,611

166,624

144,390

22,234

 
 
 
 
 
 
 
Operating income
35,078

33,336

1,742

95,096

80,234

14,862

 
 
 
 
 
 
 
Interest expense, net
(12,527
)
(9,729
)
(2,798
)
(38,069
)
(29,780
)
(8,289
)
Other income (expense), net
198

200

(2
)
1,207

556

651

Income tax benefit (expense)
(8,176
)
(8,017
)
(159
)
(20,756
)
(16,357
)
(4,399
)
Income (loss) from continuing operations
$
14,573

$
15,790

$
(1,217
)
$
37,478

$
34,653

$
2,825



39



The following tables summarize revenue, quantities generated and purchased, quantities sold, degree days and power plant availability for our Electric Utilities:
 
Three Months Ended
Sept. 30,
 
Nine Months Ended
Sept. 30,
Revenue - Electric (in thousands)
2012
 
2011
 
2012
 
2011
Residential:
 
 
 
 
 
 
 
Black Hills Power
$
15,794

 
$
15,034

 
$
43,903

 
$
44,977

Cheyenne Light
8,324

 
7,826

 
23,816

 
22,923

Colorado Electric
26,390

 
24,462

 
70,048

 
64,053

Total Residential
50,508

 
47,322

 
137,767

 
131,953

 
 
 
 
 
 
 
 
Commercial:
 
 
 
 
 
 
 
Black Hills Power
20,336

 
19,889

 
55,948

 
54,962

Cheyenne Light
13,003

 
14,802

 
42,346

 
40,840

Colorado Electric
20,898

 
19,784

 
61,595

 
54,742

Total Commercial
54,237

 
54,475

 
159,889

 
150,544

 
 
 
 
 
 
 
 
Industrial:
 
 
 
 
 
 
 
Black Hills Power
5,846

 
6,716

 
18,929

 
18,944

Cheyenne Light
4,551

 
3,017

 
10,863

 
8,573

Colorado Electric
8,476

 
8,086

 
27,689

 
24,520

Total Industrial
18,873

 
17,819

 
57,481

 
52,037

 
 
 
 
 
 
 
 
Municipal:
 
 
 
 
 
 
 
Black Hills Power
930

 
908

 
2,515

 
2,425

Cheyenne Light
454

 
475

 
1,352

 
1,321

Colorado Electric
3,419

 
3,442

 
10,031

 
9,564

Total Municipal
4,803

 
4,825

 
13,898

 
13,310

 
 
 
 
 
 
 
 
Total Retail Revenue - Electric
128,421

 
124,441

 
369,035

 
347,844

 
 
 
 
 
 
 
 
Contract Wholesale:
 
 
 
 
 
 
 
Total Contract Wholesale - Black Hills Power
5,627

 
4,519

 
14,902

 
13,509

 
 
 
 
 
 
 
 
Off-system Wholesale:
 
 
 
 
 
 
 
Black Hills Power
5,599

 
9,158

 
23,331

 
23,553

Cheyenne Light
1,532

 
1,535

 
6,012

 
7,002

Colorado Electric (a)
1,663

 

 
2,073

 

Total Off-system Wholesale (a)
8,794

 
10,693

 
31,416

 
30,555

 
 
 
 
 
 
 
 
Other Revenue:
 
 
 
 
 
 
 
Black Hills Power
7,002

 
8,716

 
22,248

 
21,862

Cheyenne Light
624

 
649

 
1,663

 
1,905

Colorado Electric
997

 
646

 
3,467

 
1,837

Total Other Revenue
8,623

 
10,011

 
27,378

 
25,604

 
 
 
 
 
 
 
 
Total Revenue - Electric
$
151,465

 
$
149,664

 
$
442,731

 
$
417,512

____________
(a)
Off-system sales revenue during 2010 and 2011 was deferred until a sharing mechanism was approved by the CPUC in December 2011, and recognition of 25 percent of the revenue commenced Jan. 2, 2012. As a result, Colorado Electric deferred $2.0 million and $8.4 million in off-system revenue during the three and nine months ended Sept. 30, 2011.


40



 
Three Months Ended
Sept. 30,
 
Nine Months Ended
Sept. 30,
Quantities Generated and Purchased (in MWh)
2012
 
2011
 
2012
 
2011
Generated —
 
 
 
 
 
 
 
Coal-fired:
 
 
 
 
 
 
 
Black Hills Power
475,752

 
463,032

 
1,344,593

 
1,286,876

Cheyenne Light
155,099

 
170,643

 
436,576

 
511,209

Colorado Electric
61,820

 
74,470

 
177,712

 
202,381

Total Coal-fired
692,671

 
708,145

 
1,958,881

 
2,000,466

 
 
 
 
 
 
 
 
Gas and Oil-fired:
 
 
 
 
 
 
 
Black Hills Power
21,543

 
11,424

 
28,122

 
13,595

Cheyenne Light

 

 

 

Colorado Electric
50,691

 
2,748

 
72,271

 
2,778

Total Gas and Oil-fired
72,234

 
14,172

 
100,393

 
16,373

 
 
 
 
 
 
 
 
Total Generated:
 
 
 
 
 
 
 
Black Hills Power
497,295

 
474,456

 
1,372,715

 
1,300,471

Cheyenne Light
155,099

 
170,643

 
436,576

 
511,209

Colorado Electric
112,511

 
77,218

 
249,983

 
205,159

Total Generated
764,905

 
722,317

 
2,059,274

 
2,016,839

 
 
 
 
 
 
 
 
Purchased —
 
 
 
 
 
 
 
Black Hills Power
280,815

 
409,174

 
1,228,072

 
1,186,004

Cheyenne Light
191,884

 
172,520

 
604,911

 
548,768

Colorado Electric
488,321

 
527,975

 
1,298,690

 
1,496,812

Total Purchased
961,020

 
1,109,669

 
3,131,673

 
3,231,584

 
 
 
 
 
 
 
 
Total Generated and Purchased:
 
 
 
 
 
 
 
Black Hills Power
778,110

 
883,630

 
2,600,787

 
2,486,475

Cheyenne Light
346,983

 
343,163

 
1,041,487

 
1,059,977

Colorado Electric
600,832

 
605,193

 
1,548,673

 
1,701,971

Total Generated and Purchased
1,725,925

 
1,831,986

 
5,190,947

 
5,248,423



41



 
Three Months Ended
Sept. 30,
 
Nine Months Ended
Sept. 30,
Quantity Sold (in MWh)
2012
 
2011
 
2012
 
2011
Residential:
 
 
 
 
 
 
 
Black Hills Power
139,282

 
132,571

 
396,267

 
414,654

Cheyenne Light
68,816

 
65,643

 
197,093

 
197,053

Colorado Electric
185,696

 
185,775

 
476,425

 
481,774

Total Residential
393,794

 
383,989

 
1,069,785

 
1,093,481

 
 
 
 
 
 
 
 
Commercial:
 
 
 
 
 
 
 
Black Hills Power
202,418

 
198,774

 
553,792

 
544,660

Cheyenne Light
141,433

 
157,138

 
449,718

 
446,382

Colorado Electric
198,839

 
201,266

 
548,964

 
547,168

Total Commercial
542,690

 
557,178

 
1,552,474

 
1,538,210

 
 
 
 
 
 
 
 
Industrial:
 
 
 
 
 
 
 
Black Hills Power
93,147

 
106,658

 
303,906

 
301,268

Cheyenne Light
62,397

 
44,857

 
151,326

 
128,327

Colorado Electric
89,305

 
90,895

 
267,739

 
265,992

Total Industrial
244,849

 
242,410

 
722,971

 
695,587

 
 
 
 
 
 
 
 
Municipal:
 
 
 
 
 
 
 
Black Hills Power
11,154

 
9,917

 
27,565

 
25,958

Cheyenne Light
2,318

 
2,528

 
7,028

 
7,122

Colorado Electric
35,461

 
36,657

 
95,649

 
96,483

Total Municipal
48,933

 
49,102

 
130,242

 
129,563

 
 
 
 
 
 
 
 
Total Retail Quantity Sold
1,230,266

 
1,232,679

 
3,475,472

 
3,456,841

 
 
 
 
 
 
 
 
Contract Wholesale:
 
 
 
 
 
 
 
Total Contract Wholesale - Black Hills Power
88,334

 
84,346

 
249,388

 
256,558

 
 
 
 
 
 
 
 
Off-system Wholesale:
 
 
 
 
 
 
 
Black Hills Power
190,143

 
299,511

 
943,522

 
819,753

Cheyenne Light
46,157

 
47,615

 
166,777

 
211,541

Colorado Electric
52,228

 
48,643

 
60,899

 
222,091

Total Off-system Wholesale
288,528

 
395,769

 
1,171,198

 
1,253,385

 
 
 
 
 
 
 
 
Total Quantity Sold:
 
 
 
 
 
 
 
Black Hills Power
724,478

 
831,777

 
2,474,440

 
2,362,851

Cheyenne Light
321,121

 
317,781

 
971,942

 
990,425

Colorado Electric
561,529

 
563,236

 
1,449,676

 
1,613,508

Total Quantity Sold
1,607,128

 
1,712,794

 
4,896,058

 
4,966,784

 
 
 
 
 
 
 
 
Losses and Company Use:
 
 
 
 
 
 
 
Black Hills Power
53,632

 
51,853

 
126,347

 
123,624

Cheyenne Light
25,863

 
25,382

 
69,545

 
69,552

Colorado Electric
39,302

 
41,957

 
98,997

 
88,463

Total Losses and Company Use
118,797

 
119,192

 
294,889

 
281,639

 
 
 
 
 
 
 
 
Total Quantity Sold
1,725,925

 
1,831,986

 
5,190,947

 
5,248,423



42



 
Three Months Ended
Sept. 30,
Degree Days
2012
 
2011
Heating Degree Days:
Actual
 
Variance from
30-Year Average
 
Actual
 
Variance from
30-Year Average
 
 
 
 
 
 
 
 
Black Hills Power
99

 
(56
)%
 
153

 
(33
)%
Cheyenne Light
170

 
(40
)%
 
197

 
(40
)%
Colorado Electric
54

 
(45
)%
 
46

 
(50
)%
 
 
 
 
 
 
 
 
Cooling Degree Days:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Black Hills Power
731

 
37
 %
 
620

 
26
 %
Cheyenne Light
430

 
44
 %
 
399

 
73
 %
Colorado Electric
898

 
31
 %
 
958

 
36
 %

 
Nine Months Ended
Sept. 30,
Degree Days
2012
 
2011
 
Actual
 
Variance from
30-Year Average
 
Actual
 
Variance from
30-Year Average
Heating Degree Days:
 
 
 
 
 
 
 
Black Hills Power
3,558

 
(50
)%
 
5,050

 
(30
)%
Cheyenne Light
3,772

 
(47
)%
 
4,674

 
(37
)%
Colorado Electric
2,753

 
(51
)%
 
3,465

 
(38
)%
 
 
 
 
 
 
 
 
Cooling Degree Days:
 
 
 
 
 
 
 
Black Hills Power
937

 
47
 %
 
676

 
13
 %
Cheyenne Light
568

 
63
 %
 
429

 
57
 %
Colorado Electric
1,321

 
47
 %
 
1,252

 
36
 %
Electric Utilities Power Plant Availability
Three Months Ended
Sept. 30,
 
Nine Months Ended
Sept. 30,
 
 
2012
 
2011
 
2012
 
2011
 
Coal-fired plants
95.4
%
 
95.1
%
 
89.1
%
(a) 
91.6
%
(b) 
Other plants
98.5
%
 
98.6
%
 
96.6
%
 
95.7
%
 
Total availability
97.0
%
 
96.4
%
 
93.0
%
 
93.1
%
 
_________________________
(a)
Reflects an unplanned outage due to a transformer failure and a planned outage at Neil Simpson II, and a planned and extended overhaul at Wygen II.
(b)
Reflects a major overhaul and an unplanned outage at the PacifiCorp-operated Wyodak plant.


43



Cheyenne Light Natural Gas Distribution

Included in the Electric Utilities is Cheyenne Light's natural gas distribution system. The following table summarizes certain operating information for these natural gas distribution operations:

 
Three Months Ended
Sept. 30,
 
Nine Months Ended
Sept. 30,
 
2012
 
2011
 
2012
 
2011
Revenue - Gas (in thousands):
 
 
 
 
 
 
 
Residential
$
2,362

 
$
2,561

 
$
12,947

 
$
14,592

Commercial
770

 
946

 
5,789

 
6,492

Industrial
248

 
370

 
1,882

 
2,226

Other Sales Revenue
172

 
175

 
571

 
704

Total Revenue - Gas
$
3,552

 
$
4,052

 
$
21,189

 
$
24,014

 
 
 
 
 
 
 
 
Gross Margin (in thousands):
 
 
 
 
 
 
 
Residential
$
1,864

 
$
1,739

 
$
7,092

 
$
7,459

Commercial
417

 
387

 
2,141

 
2,293

Industrial
53

 
63

 
302

 
338

Other Gross Margin
172

 
160

 
567

 
341

Total Gross Margin
$
2,506

 
$
2,349

 
$
10,102

 
$
10,431

 
 
 
 
 
 
 
 
Volumes Sold (Dth):
 
 
 
 
 
 
 
Residential
168,229

 
179,602

 
1,453,478

 
1,745,313

Commercial
119,344

 
122,138

 
918,131

 
1,048,404

Industrial
64,721

 
66,962

 
411,664

 
463,618

Total Volumes Sold
352,294

 
368,702

 
2,783,273

 
3,257,335



44



Results of Operations for the Electric Utilities for the Three Months Ended Sept. 30, 2012 Compared to Three Months Ended Sept. 30, 2011: Income from continuing operations for the Electric Utilities was $14.6 million for the three months ended Sept. 30, 2012 compared to $15.8 million for the three months ended Sept. 30, 2011 as a result of:

Gross margin increased primarily due to a $9.6 million increase related to rate adjustments that include a return on significant capital investments at Colorado Electric, partially offset by a $0.7 million decrease in wholesale and transmission margins as a result of decreased pricing, a decrease of $0.3 million in off-system sales and a decrease of $0.6 million from expiration of a reserve capacity agreement with PacifiCorp.

Operations and maintenance decreased primarily due to a $2.1 million reduction of major maintenance accruals related to the power plants announced for retirement and cost containment efforts, partially offset by costs associated with operating the new generating facility in Pueblo, Colo. including increased corporate allocations.

Gain on sale of operating assets in 2011 relates to the sale of assets to a related party and the gain was eliminated in the consolidation.

Depreciation and amortization increased primarily due to a higher asset base associated with the new 180 megawatt generating facility constructed in Pueblo, Colo. and the capital lease assets associated with the 200 megawatt generating facility providing capacity and energy from Colorado IPP.

Interest expense, net increased primarily due to interest associated with the financing of the Pueblo generating facility completed in December 2011. Interest costs were capitalized during construction in the prior year.

Other income (expense), net was comparable to the same period in the prior year.

Income tax benefit (expense): The effective tax rate in 2012 was impacted by a unfavorable true-up adjustment while 2011 was impacted by a favorable true-up adjustment.

Results of Operations for the Electric Utilities for the Nine Months Ended Sept. 30, 2012 Compared to Nine Months Ended Sept. 30, 2011: Income from continuing operations for the Electric Utilities was $37.5 million for the nine months ended Sept. 30, 2012 compared to $34.7 million for the nine months ended Sept. 30, 2011 as a result of:

Gross margin increased primarily due to a $30.0 million increase related to rate adjustments that include a return on significant capital investments at Colorado Electric, a $1.5 million increase from wholesale and transmission margins from increased pricing, a $0.4 million increase in off-system sales mainly from higher quantities sold, a $1.2 million increase from an Environmental Improvement Cost Recovery Adjustment rider at Black Hills Power and increased retail margins as a result of higher quantities sold driven by warmer weather partially offset by a decrease of $0.6 million from the expiration of a reserve capacity agreement with PacifiCorp.

Operations and maintenance increased primarily due to the costs associated with operating the new generating facility in Pueblo, Colo. including increased corporate allocations partially offset by a $2.1 million reduction of major maintenance accruals related to the power plants announced for retirement and cost containment efforts.

Gain on sale of operating assets in 2011 relates to the sale of assets to a related party and the gain was eliminated in the consolidation.

Depreciation and amortization increased primarily due to a higher asset base associated with the new 180 megawatt generating facility in Pueblo, Colo. and the capital lease assets associated with the 200 megawatt generating facility providing capacity and energy from Colorado IPP.

Interest expense, net increased primarily due to interest associated with financing of the Pueblo generating facility completed in December 2011. Interest costs were capitalized during construction in the prior year.

Other income (expense), net was comparable to the same period in the prior year.

Income tax benefit (expense): The effective tax rate increased due to a favorable benefit in the prior year for a repairs deduction taken for tax purposes and the flow-through treatment of such tax benefit.



45



Gas Utilities

 
Three Months Ended Sept. 30,
Nine Months Ended Sept. 30,
 
2012
2011
Variance
2012
2011
Variance
 
(in thousands)
Natural gas — regulated
$
56,845

$
65,887

$
(9,042
)
$
293,047

$
382,517

$
(89,470
)
Other — non-regulated services
6,590

6,764

(174
)
21,296

20,322

974

Total revenue
63,435

72,651

(9,216
)
314,343

402,839

(88,496
)
 
 
 
 
 
 
 
Natural gas — regulated
20,802

29,693

(8,891
)
154,342

229,152

(74,810
)
Other — non-regulated services
3,383

3,480

(97
)
10,272

10,260

12

Total cost of sales
24,185

33,173

(8,988
)
164,614

239,412

(74,798
)
 
 
 
 
 
 
 
Gross margin
39,250

39,478

(228
)
149,729

163,427

(13,698
)
 
 
 
 
 
 
 
Operations and maintenance
28,339

28,317

22

88,121

91,126

(3,005
)
Depreciation and amortization
6,338

6,064

274

18,748

18,032

716

Total operating expenses
34,677

34,381

296

106,869

109,158

(2,289
)
 
 
 
 
 
 
 
Operating income (loss)
4,573

5,097

(524
)
42,860

54,269

(11,409
)
 
 
 
 
 
 
 
Interest expense, net
(5,370
)
(6,329
)
959

(17,659
)
(19,640
)
1,981

Other income (expense), net
(2
)
27

(29
)
82

176

(94
)
Income tax benefit (expense)
802

1,777

(975
)
(8,914
)
(10,530
)
1,616

Income (loss) from continuing operations
$
3

$
572

$
(569
)
$
16,369

$
24,275

$
(7,906
)


46



The following tables summarize revenue, gross margin, volumes sold and degree days for our Gas Utilities:

Revenue (in thousands)
Three Months Ended
Sept. 30,
 
Nine Months Ended
Sept. 30,
 
2012
 
2011
 
2012
 
2011
Residential:
 
 
 
 
 
 
 
Colorado
$
4,498

 
$
5,493

 
$
33,837

 
$
39,228

Nebraska
11,370

 
12,736

 
65,832

 
91,798

Iowa
9,776

 
11,235

 
56,216

 
77,259

Kansas
7,354

 
7,928

 
36,537

 
46,449

Total Residential
32,998

 
37,392

 
192,422

 
254,734

 
 
 
 
 
 
 
 
Commercial:
 
 
 
 
 
 
 
Colorado
898

 
1,352

 
6,525

 
8,167

Nebraska
2,742

 
3,520

 
20,760

 
29,823

Iowa
3,988

 
4,397

 
24,495

 
33,082

Kansas
1,973

 
2,076

 
10,702

 
14,316

Total Commercial
9,601

 
11,345

 
62,482

 
85,388

 
 
 
 
 
 
 
 
Industrial:
 
 
 
 
 
 
 
Colorado
1,110

 
1,174

 
1,756

 
1,872

Nebraska
306

 
194

 
735

 
530

Iowa
357

 
334

 
1,551

 
1,478

Kansas
7,078

 
10,437

 
12,314

 
18,406

Total Industrial
8,851

 
12,139

 
16,356

 
22,286

 
 
 
 
 
 
 
 
Transportation:
 
 
 
 
 
 
 
Colorado
113

 
84

 
616

 
591

Nebraska
1,866

 
1,626

 
7,337

 
8,057

Iowa
816

 
687

 
3,044

 
2,839

Kansas
1,338

 
1,311

 
4,367

 
4,503

Total Transportation
4,133

 
3,708

 
15,364

 
15,990

 
 
 
 
 
 
 
 
Other Sales Revenue:
 
 
 
 
 
 
 
Colorado
15

 
22

 
65

 
78

Nebraska
469

 
432

 
1,561

 
1,551

Iowa
86

 
122

 
350

 
441

Kansas
692

 
727

 
4,447

 
2,049

Total Other Sales Revenue
1,262

 
1,303

 
6,423

 
4,119

 
 
 
 
 
 
 
 
Total Regulated Revenue
56,845

 
65,887

 
293,047

 
382,517

 
 
 
 
 
 
 
 
Non-regulated Services
6,590

 
6,764

 
21,296

 
20,322

 
 
 
 
 
 
 
 
Total Revenue
$
63,435

 
$
72,651

 
$
314,343

 
$
402,839



47



Gross Margin (in thousands)
Three Months Ended
Sept. 30,
 
Nine Months Ended
Sept. 30,
 
2012
 
2011
 
2012
 
2011
Residential:
 
 
 
 
 
 
 
Colorado
$
2,548

 
$
2,695

 
$
11,375

 
$
12,575

Nebraska
8,334

 
8,480

 
32,922

 
37,861

Iowa
7,850

 
8,291

 
28,373

 
34,885

Kansas
5,622

 
5,465

 
20,537

 
21,663

Total Residential
24,354

 
24,931

 
93,207

 
106,984

 
 
 
 
 
 
 
 
Commercial:
 
 
 
 
 
 
 
Colorado
399

 
460

 
1,818

 
2,105

Nebraska
1,404

 
1,486

 
7,027

 
8,462

Iowa
1,890

 
1,862

 
7,723

 
8,458

Kansas
1,087

 
1,006

 
4,365

 
4,731

Total Commercial
4,780

 
4,814

 
20,933

 
23,756

 
 
 
 
 
 
 
 
Industrial:
 
 
 
 
 
 
 
Colorado
307

 
239

 
509

 
402

Nebraska
99

 
48

 
204

 
139

Iowa
56

 
38

 
172

 
176

Kansas
1,096

 
1,144

 
2,090

 
2,136

Total Industrial
1,558

 
1,469

 
2,975

 
2,853

 
 
 
 
 
 
 
 
Transportation:
 
 
 
 
 
 
 
Colorado
113

 
84

 
617

 
590

Nebraska
1,866

 
1,626

 
7,337

 
8,057

Iowa
816

 
687

 
3,044

 
2,839

Kansas
1,338

 
1,311

 
4,367

 
4,503

Total Transportation
4,133

 
3,708

 
15,365

 
15,989

 
 
 
 
 
 
 
 
Other Sales Margins:
 
 
 
 
 
 
 
Colorado
15

 
22

 
65

 
78

Nebraska
469

 
433

 
1,562

 
1,552

Iowa
86

 
122

 
351

 
441

Kansas
648

 
695

 
4,248

 
1,712

Total Other Sales Margins
1,218

 
1,272

 
6,226

 
3,783

 
 
 
 
 
 
 
 
Total Regulated Gross Margin
36,043

 
36,194

 
138,706

 
153,365

 
 
 
 
 
 
 
 
Non-regulated Services
3,207

 
3,284

 
11,023

 
10,062

 
 
 
 
 
 
 
 
Total Gross Margin
$
39,250

 
$
39,478

 
$
149,729

 
$
163,427



48



Volumes Sold (in Dth)
Three Months Ended
Sept. 30,
 
Nine Months Ended
Sept. 30,
 
2012
 
2011
 
2012
 
2011
Residential:
 
 
 
 
 
 
 
Colorado
372,722

 
450,778

 
3,773,819

 
4,298,162

Nebraska
681,361

 
764,676

 
6,032,705

 
8,607,301

Iowa
479,912

 
564,426

 
5,486,267

 
7,485,204

Kansas
422,708

 
461,169

 
3,581,184

 
4,710,725

Total Residential
1,956,703

 
2,241,049

 
18,873,975

 
25,101,392

 
 
 
 
 
 
 
 
Commercial:
 
 
 
 
 
 
 
Colorado
98,453

 
145,413

 
804,701

 
980,931

Nebraska
315,832

 
373,386

 
2,606,223

 
3,465,363

Iowa
527,923

 
486,758

 
3,424,736

 
4,375,492

Kansas
219,870

 
203,109

 
1,439,351

 
1,830,720

Total Commercial
1,162,078

 
1,208,666

 
8,275,011

 
10,652,506

 
 
 
 
 
 
 
 
Industrial:
 
 
 
 
 
 
 
Colorado
265,451

 
202,956

 
416,020

 
318,278

Nebraska
69,229

 
30,816

 
134,931

 
67,010

Iowa
74,535

 
56,401

 
297,494

 
234,864

Kansas
1,912,296

 
2,010,001

 
3,381,657

 
3,518,599

Total Industrial
2,321,511

 
2,300,174

 
4,230,102

 
4,138,751

 
 
 
 
 
 
 
 
Total Volumes Sold
5,440,292

 
5,749,889

 
31,379,088

 
39,892,649

 
 
 
 
 
 
 
 
Transportation:
 
 
 
 
 
 
 
Colorado
98,893

 
75,828

 
607,469

 
604,493

Nebraska
6,453,607

 
5,910,136

 
20,042,972

 
18,546,617

Iowa
4,038,804

 
4,068,243

 
13,718,759

 
13,647,342

Kansas
3,993,675

 
4,331,612

 
11,640,182

 
11,712,421

Total Transportation
14,584,979

 
14,385,819

 
46,009,382

 
44,510,873

 
 
 
 
 
 
 
 
Other Volumes:
 
 
 
 
 
 
 
Colorado

 

 

 

Nebraska

 

 

 

Iowa

 

 

 

Kansas (a)
8,427

 
4,086

 
40,380

 
66,152

Total Other Volumes
8,427

 
4,086

 
40,380

 
66,152

 
 
 
 
 
 
 
 
Total Volumes and Transportation Sold
20,033,698

 
20,139,794

 
77,428,850

 
84,469,674

___________
(a) Other volumes represent wholesale customers.


49



 
Three Months Ended Sept. 30, 2012
 
Nine Months Ended Sept. 30, 2012
Heating Degree Days:
Actual
 
Variance
From
 Normal
 
Actual
 
Variance
From
 Normal
Colorado
116

 
(39)%
 
3,018

 
(23)%
Nebraska
110

 
12%
 
2,880

 
(22)%
Iowa
216

 
21%
 
3,629

 
(19)%
Kansas (a)
42

 
(35)%
 
2,373

 
(21)%
Combined (b) 
150

 
5%
 
3,176

 
(21)%

 
Three Months Ended Sept. 30, 2011
 
Nine Months Ended Sept. 30, 2011
Heating Degree Days:
Actual
 
Variance
From
 Normal
 
Actual
 
Variance
From
 Normal
Colorado
116

 
(38
)%
 
3,717

 
(7
)%
Nebraska
157

 
49
 %
 
4,023

 
4
 %
Iowa
235

 
38
 %
 
4,780

 
3
 %
Kansas (a)
54

 
74
 %
 
3,085

 
1
 %
Combined (b) 
178

 
36
 %
 
4,247

 
2
 %
_______________
(a)
Our gross margin in Kansas utilizes normal degree days from an approved weather normalization mechanism.
(b)
The combined heating degree days are calculated based on a weighted average of total customers by state excluding Kansas Gas which has an approved weather normalization mechanism.

Our Gas Utilities are highly seasonal, and sales volumes vary considerably with weather and seasonal heating and industrial loads. Over 70 percent of our Gas Utilities' revenue and margins are expected in the first and fourth quarters of each year. Therefore, revenue for and certain expenses of these operations fluctuate significantly among quarters. Depending upon the state in which our Gas Utilities operate, the winter heating season begins around Nov. 1 and ends around March 31.

Results of Operations for the Gas Utilities for the Three Months Ended Sept. 30, 2012 Compared to Three Months Ended Sept. 30, 2011: Income from continuing operations for the Gas Utilities was $0.0 million for the three months ended Sept. 30, 2012 compared to Income from continuing operations of $0.6 million for the three months ended Sept. 30, 2011 as a result of:

Gross margin was comparable to the same period in the prior year.

Operations and maintenance was comparable to the same period in the prior year.

Depreciation and amortization was comparable to the same period in the prior year.

Interest expense, net decreased primarily due to lower interest rates.

Other income (expense), net was comparable to the same period in the prior year.

Income tax benefit (expense): The deviation in the effective tax rate from the statutory rate is the result of a favorable true-up adjustment that had a more pronounced impact in 2012 due to significantly lower pre-tax net loss. The prior year also realized a favorable true up adjustment for flow-through treatment of certain property-related temporary differences.


50



Results of Operations for the Gas Utilities for the Nine Months Ended Sept. 30, 2012 Compared to Nine Months Ended Sept. 30, 2011: Income from continuing operations for the Gas Utilities was $16.4 million for the nine months ended Sept. 30, 2012 compared to Income from continuing operations of $24.3 million for the nine months ended Sept. 30, 2011 as a result of:

Gross margin decreased primarily due to a $9.6 million impact from milder weather compared to the same period in the prior year. Heating degree days were 25 percent lower for the nine months ended Sept. 30, 2012 compared to the same period in the prior year and 21 percent lower than normal. A reclassification adjustment was made in the current year, recording $4.9 million against gross margin in prior year that was included in operations and maintenance.

Operations and maintenance decreased primarily due to lower bad debt costs, cost efficiencies and a reclassification accounting adjustment that was made in the current year recording $4.9 million of operating costs in gross margin.

Depreciation and amortization was comparable to the same period in the prior year.

Interest expense, net decreased primarily due to lower interest rates.

Other income (expense), net was comparable to the same period in the prior year.

Income tax benefit (expense): The effective tax rate increased as a result of an unfavorable state true-up adjustment. Additionally, the 2011 period was favorably impacted as a result of federal research and development credits and a flow-through tax adjustment at Iowa Gas.

Regulatory Matters — Utilities Group

The following summarizes our recent state and federal rate case and initial surcharge orders (dollars in millions):
                        
 
 
 
 
 
 
 
 
Revenue
 
Revenue
 
 
 
Approved Capital
Structure
 
 
Type of
 Service
 
Date
Requested
 
Date
Effective
 
Amount
Requested
 
Amount
Approved
 
Return on
Equity
 
Equity
 
Debt
Nebraska Gas (1)
 
Gas
 
12/2009
 
9/2010
 
$
12.1

 
$
8.3

 
10.1%
 
52.0%
 
48.0%
Iowa Gas (2)
 
Gas
 
6/2010
 
2/2011
 
$
4.7

 
$
3.4

 
Global Settlement
 
Global Settlement
 
Global Settlement
Colorado Electric (2)
 
Electric
 
4/2011
 
1/2012
 
$
40.2

 
$
28.0

 
9.8% - 10.2%
 
49.1%
 
50.9%
Cheyenne Light (3)
 
Electric/Gas
 
12/2011
 
7/2012
 
$
8.5

 
$
4.3

 
9.6%
 
54.0%
 
46.0%
Black Hills Power (2)
 
Electric
 
1/2011
 
6/2011
 
Not Applicable
 
$
3.1

 
Not Applicable
 
Not Applicable
 
Not Applicable
Colorado Gas (4)
 
Gas
 
6/2012
 
Pending
 
$
1.0

 
Pending
 
Pending
 
Pending
 
Pending

(1)
The Nebraska Public Advocate filed an appeal with the District Court related to the rate case decision which has been denied. Subsequently, the Nebraska Public Advocate filed a notice of appeal in the Court of Appeals. On March 20, 2012, the Court of Appeals affirmed the earlier decision of the District Court. The Nebraska Public Advocate petitioned the Nebraska Supreme Court to hear an appeal which was denied. Accordingly, the appeals of the rate case decision have been exhausted and the rate case decision is upheld as a final decision of the NPSC.

(2)
These rate settlements were the most recent for the jurisdiction and were previously described in our 2011 Annual Report on Form 10-K.

(3)
On June 18, 2012, the WPSC approved a settlement agreement resulting in annual revenue increases of $2.7 million for electric customers and $1.6 million for gas customers effective July 1, 2012. The cost adjustment mechanism relating to transmission, fuel and purchased power costs was modified to eliminate the $1.0 million threshold and changed the sharing mechanism to 85 percent to the customer for these cost adjustment mechanisms. The agreement approved a return on equity of 9.6 percent with a capital structure of 54 percent equity and 46 percent debt.

(4)
On June 4, 2012, Colorado Gas filed a request with the CPUC for an increase in annual gas revenues of $1.0 million to recover capital investments and increased operation and maintenance expenses. The CPUC required this rate case filing as part of a previous settlement agreement when we purchased Colorado Gas. All parties reached a rate case settlement, and the settlement hearing was held on Oct. 12, 2012. A decision is expected in the first quarter of 2013. The settlement, if approved, includes a $0.2 million revenue increase, a return on equity of 9.6 percent and a capital structure of 50 percent equity and 50 percent debt.

51



 

Non-regulated Energy Group

We report three segments within our Non-regulated Energy Group: Power Generation, Coal Mining and Oil and Gas.

For more than 15 years, we also owned and operated Enserco, an energy marketing business that engaged in natural gas, crude oil, coal, power and environmental marketing and trading in the United States and Canada. We sold Enserco on Feb. 29, 2012, which resulted in our Energy Marketing segment being classified as discontinued operations. For comparative purposes, all prior periods presented have been restated to reflect the classification of this segment as discontinued operations.

Power Generation
 
Three Months Ended Sept. 30,
Nine Months Ended Sept. 30,
 
2012
2011
Variance
2012
2011
Variance
 
(in thousands)
Revenue
$
20,951

$
8,100

$
12,851

$
59,312

$
23,500

$
35,812

 
 
 
 
 
 
 
Operations and maintenance
7,788

4,602

3,186

22,486

12,881

9,605

Depreciation and amortization
1,165

1,064

101

3,395

3,168

227

Total operating expense
8,953

5,666

3,287

25,881

16,049

9,832

 
 
 
 
 
 
 
Operating income
11,998

2,434

9,564

33,431

7,451

25,980

 
 
 
 
 
 
 
Interest expense, net
(3,085
)
(1,835
)
(1,250
)
(11,800
)
(5,461
)
(6,339
)
Other (expense) income
(4
)
(5
)
1

10

1,220

(1,210
)
Income tax (expense) benefit
(3,781
)
(257
)
(3,524
)
(5,673
)
(1,139
)
(4,534
)
 
 
 
 
 
 
 
Income (loss) from continuing operations
$
5,128

$
337

$
4,791

$
15,968

$
2,071

$
13,897


The following table provides certain operating statistics for our plants within the Power Generation segment:

 
Three Months Ended
Sept. 30,
 
Nine Months Ended
Sept. 30,
 
2012
 
2011
 
2012
 
2011
Contracted power plant fleet availability:
 
 
 
 
 
 
 
Coal-fired plant
99.4
%
 
97.1
%
 
99.5
%
 
98.9
%
Natural gas-fired plants
99.4
%
 
100.0
%
 
99.3
%
 
100.0
%
Total availability
99.4
%
 
98.1
%
 
99.4
%
 
99.3
%

Results of Operations for Power Generation for the Three Months Ended Sept. 30, 2012 Compared to Three Months Ended Sept. 30, 2011: Income from continuing operations for the Power Generation segment was $5.1 million for the three months ended Sept. 30, 2012 compared to Income from continuing operations of $0.3 million for the same period in 2011 as a result of:

Revenue increased due to the commencement of commercial operation of our new 200 megawatt generating facility in Pueblo, Colo. on Jan. 1, 2012.

Operations and maintenance increased primarily due to the costs to operate and corporate allocations relating to our new 200 megawatt generating facility in Pueblo, Colo., which began serving customers on Jan. 1, 2012.

Depreciation and amortization was comparable to the same period in the prior year. The new generating facility's PPA to supply capacity and energy to Colorado Electric is accounted for as a capital lease under GAAP; as such, depreciation expense for the facility is recorded at Colorado Electric for segment reporting purposes.


52



Interest expense, net increased due to interest costs for financing the Pueblo generating facility. Interest costs were capitalized during construction in the prior year.

Other (expense) income, net was comparable to the same period in the prior year.

Income tax (expense) benefit: The effective tax rate was comparable to the same period in the prior year.

Results of Operations for Power Generation for the Nine Months Ended Sept. 30, 2012 Compared to Nine Months Ended Sept. 30, 2011: Income from continuing operations for the Power Generation segment was $16.0 million for the nine months ended Sept. 30, 2012 compared to Income from continuing operations of $2.1 million for the same period in 2011 as a result of:

Revenue increased due to the commencement of commercial operation of our new 200 megawatt generating facility in Pueblo, Colo. on Jan. 1, 2012.

Operations and maintenance increased primarily due to the costs to operate and corporate allocations relating to our new 200 megawatt generating facility in Pueblo, Colo. on Jan. 1, 2012.

Depreciation and amortization was comparable to the same period in the prior year. The new generating facility's PPA to supply capacity and energy to Colorado Electric is accounted for as a capital lease under GAAP; as such, depreciation expense for the facility is recorded at Colorado Electric for segment reporting purposes.

Interest expense, net increased due to interest costs for financing the Pueblo generating facility. Interest costs were capitalized during construction in the prior year.

Other (expense) income, net in 2011 included a gain on sale of ownership interest in the partnership that held the Idaho generating facilities.

Income tax (expense) benefit: The effective tax rate in 2012 was impacted by a favorable state tax true-up that included certain tax credits. Such credits are the result of meeting certain applicable state requirements including the ability to utilize these tax credits. The tax credits pertain to qualified plant expenditures related to capital investment and research and development.

Coal Mining
 
Three Months Ended Sept. 30,
Nine Months Ended Sept. 30,
 
2012
2011
Variance
2012
2011
Variance
 
(in thousands)
Revenue
$
14,675

$
17,835

$
(3,160
)
$
42,791

$
48,870

$
(6,079
)
 
 
 
 
 
 
 
Operations and maintenance
10,780

14,171

(3,391
)
32,141

41,754

(9,613
)
Depreciation, depletion and amortization
2,922

5,151

(2,229
)
9,573

14,364

(4,791
)
Total operating expenses
13,702

19,322

(5,620
)
41,714

56,118

(14,404
)
 
 
 


 
 
 
Operating income (loss)
973

(1,487
)
2,460

1,077

(7,248
)
8,325

 
 
 
 
 
 
 
Interest income, net
1

972

(971
)
1,159

2,868

(1,709
)
Other income
525

532

(7
)
2,052

1,650

402

Income tax benefit (expense)
191

538

(347
)
(364
)
1,606

(1,970
)
 
 
 
 
 
 
 
Income (loss) from continuing operations
$
1,690

$
555

$
1,135

$
3,924

$
(1,124
)
$
5,048



53



The following table provides certain operating statistics for our Coal Mining segment (in thousands):

 
Three Months Ended Sept. 30,
 
Nine Months Ended Sept. 30,
 
2012
 
2011
 
2012
 
2011
Tons of coal sold
1,105

 
1,550

 
3,191

 
4,155

Cubic yards of overburden moved
1,827

 
3,873

 
6,749

 
10,261


Results of Operations for Coal Mining for the Three Months Ended Sept. 30, 2012 Compared to Three Months Ended Sept. 30, 2011: Income from continuing operations for the Coal Mining segment was $1.7 million for the three months ended Sept. 30, 2012 compared to Income from continuing operations of $0.6 million for the same period in 2011, as a result of:

Revenue decreased primarily due to a 29 percent decrease in tons sold as a result of the December 2011 expiration of an unprofitable train load-out contract which represented approximately 29 percent of our tons sold in 2011, partially offset by an increase in average sales price as a result of price escalators and adjustments in certain of our sales contracts. Approximately 50 percent of our current coal production is sold under contracts that include price adjustments based on actual mining costs.

Operations and maintenance decreased primarily due to reduced overburden moved related to lower sales volumes and mining efficiencies, including decreased fuel costs and headcount reductions as a result of the revised mine plan and termination of the train load-out contract at Dec. 31, 2011.

Depreciation, depletion and amortization decreased primarily due to lower equipment usage and lower depreciation of mine reclamation asset retirement costs.

Interest income, net decreased primarily due to a decrease in inter-company notes receivable upon payment of a dividend to our parent.

Other income was comparable to the same period in the prior year.
 
Income tax benefit (expense): The change in the effective tax rate was primarily due to the impact of percentage depletion and a tax return true-up.

Results of Operations for Coal Mining for the Nine Months Ended Sept. 30, 2012 Compared to Nine Months Ended Sept. 30, 2011: Income from continuing operations for the Coal Mining segment was $3.9 million for the nine months ended Sept. 30, 2012 compared to Loss from continuing operations of $1.1 million for the same period in 2011, as a result of:

Revenue decreased primarily due to a 23 percent decrease in tons sold. This decrease was due to the December 2011 expiration of an unprofitable train load-out contract, which represented approximately 29 percent of our tons sold in 2011. Additionally, tons sold decreased due to a planned and unplanned outages at Neil Simpson II and a planned and extended outage at the Wygen II facility partially offset by increased tons sold to the Wyodak plant that experienced an outage in 2011. Approximately 50 percent of our current coal production is sold under contracts that include price adjustments based on actual mining cost increases.

Operations and maintenance decreased primarily due to reduced overburden moved related to lower tons sold and mining efficiencies, including decreased fuel costs and headcount reductions resulting from the revised mine plan and termination of the train load-out contract at Dec. 31, 2011.

Depreciation, depletion and amortization decreased primarily due to lower equipment usage and lower depreciation of mine reclamation asset retirement costs.

Interest income, net decreased primarily due to a decrease in inter-company notes receivable upon payment of a dividend to our parent.

Other income was comparable to the same period in the prior year.

Income tax benefit (expense): The change in the effective tax rate was primarily due to the impact of percentage depletion, a tax return true-up and the impact in 2011 of a favorable research and development credit.


54



Oil and Gas
 
Three Months Ended Sept. 30,
Nine Months Ended Sept. 30,
 
2012
2011
Variance
2012
2011
Variance
 
(in thousands)
Revenue
$
24,728

$
19,163

$
5,565

$
66,994

$
55,907

$
11,087

 
 
 
 
 
 
 
Operations and maintenance
12,118

9,573

2,545

33,290

30,327

2,963

Gain on sale of operating assets
(27,285
)

(27,285
)
(27,285
)

(27,285
)
Depreciation, depletion and amortization
12,457

7,714

4,743

34,813

22,637

12,176

Impairment of long-lived assets



26,868


26,868

Total operating expenses
(2,710
)
17,287

(19,997
)
67,686

52,964

14,722

 
 
 
 
 
 
 
Operating income (loss)
27,438

1,876

25,562

(692
)
2,943

(3,635
)
 
 
 
 
 
 
 
Interest expense, net
(1,112
)
(1,460
)
348

(3,882
)
(4,232
)
350

Other income (expense), net
77

54

23

193

(43
)
236

Income tax benefit (expense)
(9,014
)
(229
)
(8,785
)
2,162

779

1,383

 
 
 
 
 
 
 
Income (loss) from continuing operations
$
17,389

$
241

$
17,148

$
(2,219
)
$
(553
)
$
(1,666
)


The following tables provide certain operating statistics for our Oil and Gas segment:

 
Three Months Ended
Sept. 30,
 
Nine Months Ended
Sept. 30,
 
2012
 
2011
 
2012
 
2011
Production:
 
 
 
 
 
 
 
Bbls of oil sold
184,423

 
98,950

 
485,262

 
303,401

Mcf of natural gas sold
2,278,801

 
2,147,172

 
7,119,087

 
6,264,460

Gallons of NGL sold
1,099,198

 
993,752

 
2,751,409

 
2,847,011

Mcf equivalent sales
3,542,367

 
2,882,837

 
10,423,717

 
8,491,582


 
Three Months Ended
Sept. 30,
 
Nine Months Ended
Sept. 30,
 
2012
 
2011
 
2012
 
2011
Average price received: (a)
 
 
 
 
 
 
 
Oil/Bbl
$
88.69

 
$
82.76

 
$
81.65

 
$
76.25

Gas/Mcf  
$
3.07

 
$
4.24

 
$
3.27

 
$
4.39

NGL/gallon
$
0.65

 
$
0.88

 
$
0.77

 
$
0.94

 
 
 
 
 
 
 
 
Depletion expense/Mcfe
$
3.26

 
$
2.38

 
$
3.07

 
$
2.38

____________
(a)
Net of hedge settlement gains and losses.

55




The following is a summary of certain average operating expenses per Mcfe:

 
Three Months Ended Sept. 30, 2012
 
Three Months Ended Sept. 30, 2011
Producing Basin
LOE
Gathering,
 Compression
 and Processing
Production Taxes
Total
 
LOE
Gathering,
 Compression
and Processing
Production Taxes
Total
San Juan
$
1.42

$
0.33

$
0.46

$
2.21

 
$
1.06

$
0.25

$
0.52

$
1.83

Piceance *
0.13

0.35

0.14

0.62

 
0.80

0.63

0.28

1.71

Powder River
1.00


1.11

2.11

 
1.20


1.26

2.46

Williston
0.70


1.48

2.18

 
1.01


1.74

2.75

All other properties
1.48


0.25

1.73

 
0.62


0.38

1.00

Total weighted average
$
0.99

$
0.17

$
0.74

$
1.90

 
$
0.99

$
0.18

$
0.72

$
1.89


 
Nine Months Ended Sept. 30, 2012
 
Nine Months Ended Sept. 30, 2011
Producing Basin
LOE
Gathering,
 Compression
 and Processing
Production Taxes
Total
 
LOE
Gathering,
 Compression
and Processing
Production Taxes
Total
San Juan
$
1.14

$
0.28

$
0.34

$
1.76

 
$
1.17

$
0.35

$
0.54

$
2.06

Piceance *
0.20

0.39

0.13

0.72

 
0.77

0.73

0.06

1.56

Powder River
1.33


1.17

2.50

 
1.31


1.31

2.62

Williston
0.65


1.35

2.00

 
0.59


1.58

2.17

All other properties
1.58


0.17

1.75

 
1.17


0.26

1.43

Total weighted average
$
0.96

$
0.17

$
0.63

$
1.76

 
$
1.11

$
0.23

$
0.70

$
2.04

___________
* Decrease in LOE is primarily due to increased volumes from two additional wells that commenced production in December 2011.


Results of Operations for Oil and Gas for the Three Months Ended Sept. 30, 2012 Compared to Three Months Ended Sept. 30, 2011: Income from continuing operations for the Oil and Gas segment was $17.4 million for the three months ended Sept. 30, 2012 compared to Income from continuing operations of $0.2 million for the same period in 2011 as a result of:

Revenue increased primarily due to an 86 percent increase in crude oil sales, due primarily to activities from new wells in our drilling program in the Bakken shale formation and a 7 percent increase in the average price received for crude oil sold. A 6 percent increase in natural gas and NGL volumes, due primarily to the production from three Mancos formation test wells in the San Juan and Piceance Basins, was partially offset by a 28 percent decrease in the average price received for natural gas.

Operations and maintenance costs increased primarily due to higher costs from non-operated wells and higher compensation and benefit costs.

Depreciation, depletion and amortization increased primarily due to the year-to-date impact from adjusting expected 2012 reserve additions due to the deferred drilling activities in the San Juan Mancos formation, as well as higher cost reserves associated with our Bakken activities and a higher depletion rate per Mcfe on higher volumes.

Gain on sale of operating assets represents the gain on the sale of our Williston Basin assets. We follow the full-cost method of accounting for oil and gas activities, which typically does not allow for gain on sale recognition unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves. The remainder of the sales amount, not recognized as gain, reduces the full-cost pool and should significantly decrease the future depreciation, depletion and amortization rate.

Interest expense, net was comparable to the same period in the prior year.

Other income (expense), net was comparable to the same period in the prior year.


56



Income tax (expense) benefit: For 2012, the benefit generated by percentage depletion had a significantly reduced impact on the effective tax rate compared to the same period in 2011.

Results of Operations for Oil and Gas for the Nine Months Ended Sept. 30, 2012 Compared to Nine Months Ended Sept. 30, 2011: Loss from continuing operations for the Oil and Gas segment was $2.2 million for the nine months ended Sept. 30, 2012 compared to Loss from continuing operations of $0.6 million for the same period in 2011 as a result of:

Revenue increased primarily due to a 60 percent increase in crude oil volume sold along with a 7 percent increase in the average price received for crude oil sales. Crude oil production increases reflect volumes from new wells in our drilling program in the Bakken shale formation. A 13 percent increase in natural gas and NGL volumes, due primarily to the production from three Mancos formation test wells in the San Juan and Piceance Basins, was partially offset by a 26 percent decrease in average price received for natural gas.

Operations and maintenance costs increased primarily due to higher costs from non-operated wells and higher compensation and benefit costs.

Depreciation, depletion and amortization increased primarily due to the year-to-date impact from adjusting our expected 2012 reserve additions due to the deferred drilling activities in the San Juan Mancos formation, as well as higher cost reserves associated with our Bakken activities and a higher depletion rate per Mcfe on higher volumes.

Gain on sale of operating assets represents the gain on the sale of our Williston Basin assets. We follow the full-cost method of accounting for oil and gas activities, which typically does not allow for gain on sale recognition unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves. The remainder of the sale amount not recognized as gain, reduced the full-cost pool and will decrease our depreciation, depletion and amortization rate.

Impairment of long-lived assets represents a write-down in the value of our natural gas and crude oil properties driven by low natural gas prices. The write-down reflected a 12-month average NYMEX price of $3.15 per Mcf, adjusted to $2.66 per Mcf at the wellhead, for natural gas, and $95.67 per barrel, adjusted to $85.36 per barrel at the wellhead, for crude oil.

Interest expense, net was comparable to the same period in the prior year.

Other income (expense), net was comparable to the same period in the prior year.

Income tax (expense) benefit: The effective tax rate for the nine months ended Sept. 30, 2011 was positively impacted by a research and development credit and the benefit generated by percentage depletion had a significantly lesser impact on the effective tax rate in 2012 compared to the same period in 2011.


Corporate

Results of Operations for Corporate for the Three Months Ended Sept. 30, 2012 Compared to Three Months Ended Sept. 30, 2011: Loss from continuing operations for Corporate was $4.2 million for the three months ended Sept. 30, 2012 compared to Loss from continuing operations of $28.3 million for the three months ended Sept. 30, 2011. The loss for the quarter ended Sept. 30, 2012 was primarily due to an incentive compensation accrual recorded as a result of the Williston Basin asset sale offset by an unrealized, non-cash mark-to-market gain on certain interest rate swaps of approximately $0.6 million. The loss for the quarter ended Sept. 30, 2011 was primarily due to a $38.2 million unrealized, non-cash mark-to-market loss on these interest rate swaps.

Costs of $0.5 million after-tax previously allocated to our Energy Marketing segment were reclassified to the Corporate segment consistent with accounting for discontinued operations for the three months ended Sept. 30, 2011. There were no allocated costs related to our Energy Marketing segment for the three months ended Sept. 30, 2012.

Results of Operations for Corporate for the Nine Months Ended Sept. 30, 2012 Compared to Nine Months Ended Sept. 30, 2011: Loss from continuing operations for Corporate was $13.9 million for the nine months ended Sept. 30, 2012 compared to Loss from continuing operations of $37.3 million for the nine months ended Sept. 30, 2011. The loss for the nine months ended Sept. 30, 2012 was primarily due to an incentive compensation accrual recorded as a result of the Williston Basin asset sale and an unrealized, non-cash mark-to-market loss on certain interest rate swaps of approximately $2.9 million. The loss for the nine months ended Sept. 30, 2011 was primarily due to a $40.6 million unrealized, non-cash mark-to-market loss on these interest rate swaps.


57



Costs of $1.6 million after-tax previously allocated to our Energy Marketing segment were reclassified to the Corporate segment consistent with accounting for discontinued operations for the nine months ended Sept. 30, 2012 compared to after-tax costs of $1.5 million for the nine months ended Sept. 30, 2011.


Discontinued Operations

Results of Operations for Discontinued Operations for the Three and Nine Months Ended Sept. 30, 2012, Compared to Three and Nine Months Ended Sept. 30, 2011:

On Feb. 29, 2012, we sold the outstanding stock of Enserco, our Energy Marketing segment. The transaction was completed through a stock purchase agreement and certain other ancillary agreements. Net cash proceeds on the date of the sale were approximately $166.3 million, subject to final post-closing adjustments. The proceeds represent $108.8 million received from the buyer and $57.5 million cash retained from Enserco prior to closing.

Loss from discontinued operations for the three months ended Sept. 30, 2012 was $0.2 million relating to additional operating costs to discontinue the operations and $6.8 million for the nine months ended Sept. 30, 2012, including an after-tax loss on sale of $2.4 million and transaction related costs, net of tax benefit of $2.5 million.

Pursuant to the provisions of the Stock Purchase Agreement, the buyer requested purchase price adjustments totaling $7.2 million. We contested this proposed adjustment and estimated the amount owed at $1.4 million, which is accrued in the loss from discontinued operations for the nine months ended Sept. 30, 2012. If we do not reach a negotiated agreement with the buyer regarding the purchase price adjustment, resolution will occur through the dispute resolution provision of the Stock Purchase Agreement.


Critical Accounting Policies

Except as noted below, there have been no material changes in our critical accounting policies from those reported in our 2011 Annual Report on Form 10-K filed with the SEC. For more information on our critical accounting policies, see Part II, Item 7 of our 2011 Annual Report on Form 10-K.

Full-Cost Method of Accounting for Oil and Gas Activities

As previously disclosed in our 2011 Annual Report filed in Form 10-K, we utilize the full-cost method of accounting for our oil and gas activities in accordance with SEC Rule 4-10 of Regulation S-X (Rule 4-10). Under the full-cost method, sales of oil and gas properties generally are recorded as an adjustment to capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between the capitalized costs and proved oil and gas reserves. The Company's Sept. 27, 2012 sale of oil and gas properties in the Williston Basin of North Dakota was significant as defined by Rule 4-10, and accordingly a $27.3 million pre-tax gain on sale was recorded. Total net cash proceeds from the sale were approximately $227 million.

Under the guidance of Rule 4-10, if a gain or loss is recognized on such a sale, total capitalized costs shall be allocated between the reserves sold and the reserves retained on the same basis used to compute amortization, unless there are substantial economic differences between the properties sold and those retained, in which case capitalized costs shall be allocated on the basis of the relative fair value of the properties in the cost center. Because of the substantial differences between the crude oil properties we sold and those properties retained, which were predominantly natural gas, we allocated based on relative fair values.
If a different method of allocating the capitalized costs was chosen, the gain recorded on our transaction could vary substantially. For example, if the allocation was made on the same basis used to compute amortization as noted within Rule 4-10 and we utilized the ratio of proven reserve quantities from the properties sold compared to total proven reserve quantities in our cost center, we would have recorded a gain on sale of approximately $160 million. Because of the value associated with the undeveloped acreage sold, we did not believe this was an appropriate methodology for allocation.
Any change in the gain recorded would impact the amount of adjustment to our capitalized costs therefore impacting our future depletion expense recorded within our financial statements.



58



Liquidity and Capital Resources

All amounts are presented on a pre-tax basis unless otherwise indicated.

Cash Flow Activities

The following table summarizes our cash flows for the nine months ended Sept. 30, 2012 and 2011 (in thousands):

Cash provided by (used in):
2012
2011
Increase (Decrease)
Operating activities
$
269,667

$
206,526

$
63,141

Investing activities
$
98,306

$
(326,862
)
$
425,168

Financing activities
$
(179,549
)
$
162,676

$
(342,225
)

Year-to-Date 2012 Compared to Year-to-Date 2011

Operating Activities

Net cash provided by operating activities was $63.1 million higher for the nine months ended Sept. 30, 2012 than for the same period in 2011 primarily attributable to:

Cash earnings (net income plus non-cash adjustments) were $35.0 million higher for the nine months ended Sept. 30, 2012 than for the same period the prior year.

Net inflows from operating assets and liabilities were $38.1 million for the nine months ended Sept. 30, 2012, an increase of $33.5 million from the same period in the prior year. In addition to other normal working capital changes, the increase primarily related to decreased gas volumes in inventory and lower natural gas prices.

Cash contributions to the defined benefit pension plan were $25.0 million in 2012 compared to $11.0 million in 2011.

Investing Activities

Net cash provided by investing activities was $98.3 million in 2012 compared to net cash used by investing activities of $326.9 million in 2011 for a variance of $425.2 million. The variance was driven by cash proceeds from assets sold during 2012, including $243.3 million from the sale of 85 percent of our Williston Basin assets by our Oil and Gas segment, $25 million from the sale of a 50 percent ownership interest in the Busch Ranch Wind project, and $108.8 million for the sale of Enserco. Additionally, in 2012 we had reduced capital expenditures of $65.1 million due to the completion of construction of our Pueblo generation facility and $21.8 million note receivable for oil and gas properties.

Financing Activities

Net cash used in financing activities in 2012 was $179.5 million compared to net cash provided by financing activities in 2011 of $162.7 million for a variance of $342.2 million. The variance was driven by applying the proceeds from the sale of Enserco to pay down short-term borrowings on the Revolving Credit Facility of approximately $110 million while in the same period in the prior year we increased borrowings $210 million primarily to finance our construction program in Pueblo, Colo. Cash dividends on common stock of $48.9 million were paid in 2012 compared to cash dividends paid of $43.2 million in 2011. In addition, in May 2012 Black Hills Power repaid its Pollution Control Revenue Bonds for $6.5 million.


Dividends

Dividends paid on our common stock totaled $48.9 million for the nine months ended Sept. 30, 2012, or $1.11 per share. On Oct. 30, 2012, our board of directors declared a quarterly dividend of $0.37 per share payable Dec. 1, 2012, which is equivalent to an annual dividend rate of $1.48 per share. The determination of the amount of future cash dividends, if any, to be declared and paid will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under our Revolving Credit Facility and our future business prospects.


59




Financing Transactions and Short-Term Liquidity

Our principal sources of short-term liquidity are our Revolving Credit Facility and cash provided by operations. In addition to availability under our Revolving Credit Facility described below, as of Sept. 30, 2012 we had approximately $247 million of unrestricted cash included in Cash and cash equivalents on our Condensed Consolidated Balance Sheet resulting, in part, from the September 2012 sale of our Williston Basin assets. A portion of this cash was used on Oct. 31, 2012 to redeem our $225 million senior unsecured notes originally due in May 2013. In the first quarter of 2012, the net cash proceeds from the Enserco sale were utilized to reduce short-term debt on the Revolving Credit Facility by approximately $110 million.

Revolving Credit Facility

Our $500 million Revolving Credit Facility expiring Feb. 1, 2017 can be used for the issuance of letters of credit, to fund working capital needs and for general 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 were 0.50 percent, 1.50 percent and 1.50 percent, respectively. The facility contains a commitment fee that is charged on the unused amount of the facility. Based upon current credit ratings, the fee is 0.25 percent. The facility contains an accordion feature that allows us, with the consent of the administrative agent, to increase the capacity of the facility to $750 million.

At Sept. 30, 2012, we had borrowings of $75 million and letters of credit outstanding of $36 million on our Revolving Credit Facility. Available capacity remaining was approximately $389 million at Sept. 30, 2012.

The Revolving Credit Facility contains customary affirmative and negative covenants, such as limitations on the creation of new indebtedness and on certain liens, restrictions on certain transactions and a recourse leverage ratio not to exceed 0.65 to 1.00. At Sept. 30, 2012, our recourse leverage ratio as calculated under our Revolving Credit Facility was approximately 0.56 to 1.0. At Sept. 30, 2012, our long-term debt ratio was 46.2 percent and our total debt leverage ratio (long-term debt and short-term debt) was 55.2 percent.

In addition to covenant violations, an event of default under the Revolving Credit Facility may be triggered by other events, such as a failure to make payments when due or a failure to make payments when due in respect of, or a failure to perform obligations relating to, other debt obligations of $35 million or more. Subject to applicable cure periods (none of which apply to a failure to timely pay indebtedness), an event of default would permit the lenders to restrict our ability to further access the credit facility for loans and new letters of credit, and could require both the immediate repayment of any outstanding principal and interest and the cash collateralization of outstanding letter of credit obligations.

We were in compliance with the covenants and were not in default of the terms of the Revolving Credit Facility as of Sept. 30, 2012.

Short-Term Corporate Term Loan

In June 2012, we extended our one-year $150 million unsecured, single draw term loan for one year. The cost of borrowing under the extended loan now due on June 24, 2013 is based on a spread of 1.10 percent over LIBOR (1.35 percent at Sept. 30, 2012). The covenants are substantially the same as those included in the Revolving Credit Facility with an additional requirement to maintain a minimum consolidated net worth. We were in compliance with these covenants as of Sept. 30, 2012.


60



Long-term Corporate Term Loan

In December 2010, we entered into a one-year $100 million term loan with J.P. Morgan and Union Bank due in December 2011. On Sept. 30, 2011, we extended that term loan under the existing terms to Sept. 30, 2013. The cost of borrowing under this term loan is based on a spread of 1.375 percent over LIBOR (1.63 percent at Sept. 30, 2012). The covenants are substantially the same as those included in the Revolving Credit Facility with an additional requirement to maintain a minimum consolidated net worth. We were in compliance with these covenants as of Sept. 30, 2012.

Repayment of Long-term Debt

On Oct. 31, 2012, we redeemed our 6.5 percent senior unsecured notes originally due to mature on May 15, 2013 for $225.0 million plus interest and a one-time after-tax make whole-provision payment of $4.6 million.

On May 15, 2012, Black Hills Power repaid its 4.8 percent Pollution Control Revenue Bonds in full for $6.5 million including principal and interest. These bonds were originally due to mature on Oct. 1, 2014.

Dividend Restrictions

Certain of our debt agreements impose restrictions on our ability to pay dividends. Any determination to pay dividends in the future will be at the discretion of our Board of Directors and will depend upon our results of operations, financial condition, restrictions imposed by applicable law and our financing agreements and other factors that our Board of Directors deems relevant.

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 stockholders is derived from these cash flows.

As a result of certain statutory limitations or regulatory or financing agreements, we could have restrictions on the amount of distributions allowed to be made by our subsidiaries.

Our utility subsidiaries are generally limited by state regulatory authorities in the amount of dividends allowed that they can pay the utility holding company and also may have further restrictions under the Federal Power Act. As of Sept. 30, 2012, the restricted net assets at our Electric and Gas Utilities were approximately $227.2 million.

As required by the covenants in the Black Hills Wyoming project financing, Black Hills Non-regulated Holdings has restricted equity of at least $100.0 million. In addition, Black Hills Wyoming holds $7.3 million of restricted cash associated with the project financing requirements.

Future Financing Plans

We have substantial future capital expenditures planned, which primarily include construction of additional utility generation to serve Black Hills Power and Cheyenne Light customers and meet governmental pollution control mandates and potential capital deployment in oil and gas drilling to prove-up reserves. Our capital requirements are expected to be financed through a combination of available cash, operating cash flows, borrowings on our Revolving Credit Facility, term loans and long-term financings and other debt or equity issuances.

After the repayment of our $225 million senior unsecured 6.5 percent notes originally due to mature in 2013 discussed above, we have term loans of $250 million expiring in 2013 and debt due of $250 million in 2014. With these upcoming financing requirements, we continue to evaluate various financing options that include senior unsecured notes, first mortgage bonds, term loans and project financing opportunities.

We intend to maintain a consolidated debt-to-capitalization level in the range of 50 percent to 55 percent; however, due to capital projects, we may exceed this level on a temporary basis. We anticipate that our existing credit capacity and available cash will be sufficient to fund our working capital needs and our maintenance capital requirements.


61



Hedges and Derivatives

Interest Rate Swaps

We have entered into floating-to-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations.

We have interest rate swaps with a notional amount of $250 million that are not designated as hedge instruments. Accordingly, mark-to-market changes in value on these swaps are recorded within the Condensed Consolidated Statements of Income. For the three and nine months ended Sept. 30, 2012, respectively, we recorded $0.6 million pre-tax unrealized non-cash mark-to-market gain and $2.9 million pre-tax unrealized non-cash mark-to-market loss on the swaps. The mark-to-market value on these swaps was a liability of $95.6 million at Sept. 30, 2012. Subsequent mark-to-market adjustments could have a significant impact on our results of operations. A one basis point move in the interest rate curves over the term of the swaps would have a pre-tax impact of approximately $0.3 million. These swaps are for terms of 6.25 and 16.25 years and have early termination dates ranging from Dec. 15, 2012 to Dec. 16, 2013. We anticipate extending these agreements upon their early termination dates and have continued to maintain these swaps in anticipation of our upcoming financing needs. Alternatively, we may choose to cash settle these swaps at fair value prior to the early termination dates, or unless these dates are extended we will cash settle these swaps for an amount equal to their fair values on the termination dates.

In addition, we have $150 million notional amount floating-to-fixed interest rate swaps with a maximum remaining term of 4.3 years. These swaps have been designated as cash flow hedges, and accordingly their mark-to-market adjustments are recorded in Accumulated other comprehensive income (loss) on the accompanying Condensed Consolidated Balance Sheets. The mark-to-market value of these swaps was a liability of $25.7 million at Sept. 30, 2012.

There have been no other material changes in our financing transactions and short-term liquidity from those reported in Item 7 of our 2011 Annual Report on Form 10-K filed with the SEC.

Credit Ratings

Credit ratings impact our ability to obtain short- and long-term financing, the cost of such financing, and vendor payment terms including collateral requirements. As of Sept. 30, 2012, our senior unsecured credit ratings, as assessed by the three major credit rating agencies, were as follows:
Rating Agency
Rating
Outlook
 
 
 
Fitch
BBB-
Stable
Moody's (a)
Baa3
Stable
S&P (a) (b)
BBB-
Stable
_______
(a) In October 2012, both Moody's and S&P upgraded our outlook from Stable to Positive.
(b) In July 2012, S&P published its updated credit review, leaving our senior unsecured credit rating of BBB- and upgraded our risk profile from strong to excellent.

In addition, as of Sept. 30, 2012, Black Hills Power's first mortgage bonds were rated as follows:
Rating Agency
Rating
Outlook
Fitch
A-
Stable
Moody's (a)
A3
Stable
S&P (a)
BBB+
Stable
_______
(a) In October 2012, both Moody's and S&P upgraded our outlook from Stable to Positive.



62



Capital Requirements

Actual and forecasted capital requirements for maintenance capital and development capital are as follows (in thousands):
 
Expenditures for the
 
Total
 
Total
 
Total
 
Nine Months Ended Sept. 30, 2012
 
2012 Planned
Expenditures
 
2013 Planned
Expenditures
 
2014 Planned
Expenditures
Utilities:
 
 
 
 
 
 
 
Electric Utilities (1) (2)
$
119,668

 
$
163,500

 
$
285,500

 
$
216,000

Gas Utilities
31,982

 
52,000

 
56,000

 
57,600

Non-regulated Energy:
 
 
 
 
 
 
 
Power Generation
5,122

 
7,400

 
4,200

 
6,800

Coal Mining
10,806

 
18,850

 
5,100

 
6,000

Oil and Gas (3)
88,223

 
97,200

 
98,300

 
84,300

Corporate
7,456

 
10,300

 
11,800

 
4,700

 
$
263,257

 
$
349,250

 
$
460,900

 
$
375,400

____________
(1)
Planned expenditures in 2012 and 2013 of $22 million and $27 million, respectively, for the proposed 88 MW of gas-fired generation at Colorado Electric have been removed from the forecasted expenditures reported in our 2011 Annual Report on Form 10-K as a result of the denial of our request for a CPCN. Additionally, capital expenditures required to comply with environmental regulations at Neil Simpson II have been removed.
(2)
2012 forecasted capital expenditures include a reduction of $25 million for the sale of 50 percent of the Busch Ranch Wind project.
(3)
Capital expenditures at our Oil and Gas Segment are driven by economics and may vary depending on the pricing environment for crude oil and natural gas. Forecasted expenditures for 2012, 2013 and 2014 shown above for the Oil and Gas segment have been decreased from the amounts reported in our 2011 Annual Report on Form 10-K due to delaying our gas drilling program as a result of lower natural gas prices and the sale of the majority of our Williston Basin assets.

We continually evaluate all of our forecasted capital expenditures, and if determined prudent, we may defer some of these expenditures for a period of time. Future projects are dependent upon the availability of attractive economic opportunities, and as a result, actual expenditures may vary significantly from forecasted estimates.


Contractual Obligations

There have been no significant changes to contractual obligations or any off-balance sheet arrangements from those previously disclosed in Note 19 of our Notes to the Consolidated Financial Statements in our 2011 Annual Report on Form 10-K.


Guarantees

There have been no significant changes to guarantees from those previously disclosed in Note 20 of our Notes to the Consolidated Financial Statements in our 2011 Annual Report on Form 10-K.


New Accounting Pronouncements

Other than the pronouncements reported in our 2011 Annual Report on Form 10-K filed with the SEC and those discussed in Note 2 of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q, there have been no new accounting pronouncements that are expected to have a material effect on our financial statements.


63




FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q contains forward-looking information. All statements, other than statements of historical fact, included in this report that address activities, events, or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. Forward-looking information involves risks and uncertainties, and certain important factors can cause actual results to differ materially from those anticipated. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. The factors which may cause our results to vary significantly from our forward-looking statements include the risk factors described in Item 1A of our 2011 Annual Report on Form 10-K, Part II, Item 1A of this Quarterly Report on Form 10-Q, and other reports that we file with the SEC from time to time, and the following:

Our ability to successfully resolve the purchase price adjustments in question from the sale of Enserco.

We anticipate that our existing credit capacity, available cash and operating cash flows will be sufficient to fund our working capital needs and our maintenance capital requirements. Some important factors that could cause actual results to differ materially from those anticipated include:

Our access to revolving credit capacity depends on maintaining compliance with loan covenants. If we violate these covenants, we may lose revolving credit capacity and therefore may not have sufficient cash available for our peak winter needs and other working capital requirements, and our forecasted capital expenditure requirements.

Counterparties may default on their obligations to supply commodities, return collateral to us, or otherwise meet their obligations under commercial contracts, including those designed to hedge against movements in commodity prices.

Capital market conditions and other economic or market uncertainties beyond our control may affect our ability to raise capital on favorable terms.

We have term loans of $250 million expiring in 2013. In addition, we have senior unsecured bonds of $250 million due in 2014. We are evaluating financing options including senior notes, first mortgage bonds, term loans, project financing and equity issuance in the capital markets. Some important factors that could impact our ability to complete one or more of these financings include:

Our ability to access the bank loan and debt and equity capital markets depends on market conditions beyond our control. If the capital markets deteriorate, we may not be able to refinance our short-term debt and fund our capital projects on reasonable terms, if at all.

Our ability to raise capital in the debt capital markets depends upon our financial condition and credit ratings, among other things. If our financial condition deteriorates unexpectedly, or our credit ratings are lowered, we may not be able to refinance some short-term debt and fund our power generation projects on reasonable terms, if at all.

64




We expect to make approximately $349.3 million, $460.9 million and $375.4 million of capital expenditures in 2012, 2013 and 2014, respectively. Some important factors that could cause actual expenditures to differ materially from those anticipated include:

The timing of planned generation, transmission or distribution projects for our Utilities Group is influenced by state and federal regulatory authorities and third parties. The occurrence of events that impact (favorably or unfavorably) our ability to make planned or unplanned capital expenditures have caused and could cause our forecasted capital expenditures to change.

Forecasted capital expenditures associated with our Oil and Gas segment are driven, in part, by current commodity prices, our ability to obtain permits, availability and costs of drilling and service equipment, and crews and other services, and our ability to negotiate agreements with property owners for land use. An inability to obtain permits, equipment or land use rights could delay drilling efforts. Our plans may also be negatively impacted by weather conditions and existing or proposed regulations, including possible hydraulic fracturing regulations.

Our ability to complete the planning, permitting, construction, start-up and operation of power generation facilities in a cost-efficient and timely manner.

We expect contributions to our defined benefit pension plans to be approximately $0.0 million and $4.5 million for the remainder of 2012 and for 2013, respectively. Some important factors that could cause actual contributions to differ materially from anticipated amounts include:

The actual value of the plans' invested assets.

The discount rate used in determining the funding requirement.

We expect the goodwill related to our utility assets to fairly reflect the long-term value of stable, long-lived utility assets. Some important factors that could cause us to revisit the fair value of this goodwill include:

A significant and sustained deterioration of the market value of our common stock.

Negative regulatory orders, condemnation proceedings or other events that materially impact our Utilities Groups' ability to generate sufficient stable cash flow over an extended period of time.

The effects of changes in the market including significant changes in the risk-adjusted discount rate or growth rates.

The timing, volatility, and extent of changes in energy and commodity prices, supply or volume, the cost and availability of transportation of commodities, changes in interest rates, and the demand for our services, any of which can affect our earnings, our financial liquidity and the underlying value of our assets, including the possibility that we may be required to take future impairment charges under the SEC's full cost ceiling test for natural gas and crude oil reserves.

Federal and state laws concerning climate change and air emissions, including emission reduction mandates, carbon emissions and renewable energy portfolio standards, may materially increase our generation and production costs and could render some of our generating units uneconomical to operate and maintain or which could mandate or require closure of one or more of our generating units.



65



ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK


Utilities

Our utility customers are exposed to the effect of volatile natural gas prices. We produce, purchase and distribute power in four states and purchase and distribute natural gas in five states, and we utilize natural gas as fuel at our Electric Utilities. All of our gas utilities have PGA provisions that allow them to pass the prudently-incurred cost of gas and services through to the customer. To the extent that gas prices are higher or lower than amounts in our current billing rates, adjustments are made on a periodic basis to true-up billed amounts to match the actual natural gas cost we incurred. These adjustments are subject to periodic prudence reviews by the state utility commissions. We have ECA mechanisms in South Dakota, Colorado, Wyoming and Montana for our electric utilities that serve a purpose similar to the PGAs for our gas utilities. To the extent that our fuel and purchased power energy costs and transmission costs are higher or lower than the energy cost built into our tariffs, the difference (or a portion thereof) is passed through to the customer.

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 the volatility of natural gas prices. These transactions are considered derivatives and are marked-to-market. Gains or losses, as well as option premiums on these transactions, are recorded in Regulatory assets or Regulatory liabilities. Once settled, the gains and losses are passed on to our customers through the PGA.

The fair value of our Utilities Group's derivative contracts is summarized below (in thousands) as of:
 
Sept. 30, 2012
 
Dec. 31, 2011
 
Sept. 30, 2011
Net derivative (liabilities) assets
$
(7,253
)
 
$
(16,676
)
 
$
(10,064
)
Cash collateral
15,740

 
19,416

 
12,058

 
$
8,487

 
$
2,740

 
$
1,994



Oil and Gas Activities

We have entered into agreements to hedge a portion of our estimated 2012, 2013 and 2014 natural gas and crude oil production from the Oil and Gas segment. The hedge agreements in place at Sept. 30, 2012 were as follows:

Natural Gas

 
For the Three Months Ended
 
March 31,
June 30,
Sept. 30,
Dec. 31,
Total Year
2012
 
 
 
 
 
Swaps - MMBtu
 
 
 
1,196,000

1,196,000

Weighted Average Price per MMBtu
 
 
 
$
3.74

$
3.74

 
 
 
 
 
 
2013
 
 
 
 
 
Swaps - MMBtu
1,220,000

1,233,000

1,246,000

1,155,250

4,854,250

Weighted Average Price per MMBtu
$
4.01

$
3.55

$
3.33

$
3.51

$
3.60

 
 
 
 
 
 
2014
 
 
 
 
 
Swaps - MMBtu
950,000

455,000

 
 
1,405,000

Weighted Average Price per MMBtu
$
3.71

$
3.45

 
 
$
3.63



66



Crude Oil

 
For the Three Months Ended
 
March 31,
June 30,
Sept. 30,
Dec. 31,
Total Year
2012
 
 
 
 
 
Swaps - Bbls
 
 
 
42,000

42,000

Weighted Average Price per Bbl
 
 
 
$
97.99

$
97.99

 
 
 
 
 
 
Puts - Bbls
 
 
 
21,000

21,000

Weighted Average Price per Bbl
 
 
 
$
76.43

$
76.43

 
 
 
 
 
 
Calls - Bbls
 
 
 
21,000

21,000

Weighted Average Price per Bbl
 
 
 
$
95.00

$
95.00

 
 
 
 
 
 
2013
 
 
 
 
 
Swaps - Bbls
30,000

21,000

15,000

15,000

81,000

Weighted Average Price per Bbl
$
101.62

$
108.96

$
110.20

$
101.75

$
105.13

 
 
 
 
 
 
Puts - Bbls
30,000

36,000

39,000

36,000

141,000

Weighted Average Price per Bbl
$
76.75

$
78.96

$
79.81

$
80.63

$
79.15

 
 
 
 
 
 
Calls - Bbls
30,000

36,000

39,000

36,000

141,000

Weighted Average Price per Bbl
$
96.50

$
97.17

$
97.08

$
97.25

$
97.02

 
 
 
 
 
 
2014
 
 
 
 
 
Swaps - Bbls
45,000

45,000

 
 
90,000

Weighted Average Price per Bbl
$
94.38

$
90.82

 
 
$
92.60



Financing Activities

We engage in activities to manage risks associated with changes in interest rates. We have entered into floating-to-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations associated with our floating rate debt obligations. As of Sept. 30, 2012, we had $150 million of notional amount floating-to-fixed interest rate swaps, having a maximum term of 4.25 years. These swaps have been designated as hedges in accordance with accounting standards for derivatives and hedges and accordingly their mark-to-market adjustments are recorded in Accumulated other comprehensive income (loss) on the Condensed Consolidated Balance Sheets.

We also have interest rate swaps with a notional amount of $250 million, which were entered into for the purpose of hedging interest rate movements that would impact long-term financings that were originally expected to occur in 2008. The swaps were originally designated as cash flow hedges and the mark-to-market value was recorded in Accumulated other comprehensive income (loss) on the Condensed Consolidated Balance Sheets. Based on credit market conditions that transpired during the fourth quarter of 2008, we determined it was probable that the forecasted long-term debt financings would not occur in the time period originally specified and, as a result, the swaps were no longer effective hedges and the hedge relationships were de-designated. Mark-to-market adjustments on the swaps are now recorded within the Condensed Consolidated Statements of Income. For the three months and nine months ended Sept. 30, 2012, we recorded pre-tax unrealized non-cash mark-to-market gain of $0.6 million and a pre-tax unrealized non-cash mark-to-market loss of $2.9 million, respectively. For the three months and nine months ended Sept. 30, 2011, we recorded pre-tax unrealized non-cash mark-to-market losses of $38.2 million and $40.6 million, respectively. The mark-to-market value on these swaps was a liability of $95.6 million at Sept. 30, 2012. Subsequent mark-to-market adjustments could have a significant impact on our results of operations. A one basis point move in the interest rate curves over the term would have a pre-tax impact of approximately $0.3 million. These swaps are 6.25 and 16.25 year swaps which have early termination dates ranging from Dec. 15, 2012 to Dec. 16, 2013.


67



We have continued to maintain these swaps in anticipation of our upcoming financing needs, particularly our upcoming holding company debt maturities. Alternatively, we may choose to cash settle these swaps at fair value prior to the early termination dates, or unless these dates are extended we will cash settle these swaps for an amount equal to their fair values on the stated termination dates.

Further details of the swap agreements are set forth in Note 11 of the Notes to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

Our interest rate swaps and related balances were as follows (dollars in thousands) as of:
 
Sept. 30, 2012
 
Dec. 31, 2011
 
Sept. 30, 2011
 
Designated 
Interest Rate
Swaps
 
De-designated
Interest Rate
Swaps*
 
Designated
Interest Rate
Swaps
 
De-designated
Interest Rate
Swaps*
 
Designated
Interest Rate
Swaps
 
De-designated
Interest Rate
Swaps*
Notional
$
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
4.25

 
1.25

 
5.00

 
2.00

 
5.25

 
0.25

Derivative liabilities, current
$
7,028

 
$
77,914

 
$
6,513

 
$
75,295

 
$
6,724

 
$
94,588

Derivative liabilities, non-current
$
18,660

 
$
17,668

 
$
20,363

 
$
20,696

 
$
21,108

 
$

Pre-tax accumulated other comprehensive loss included in Condensed Consolidated Balance Sheets
$
(25,688
)
 
$

 
$
(26,876
)
 
$

 
$
(27,832
)
 
$

Pre-tax (loss) gain included in Condensed Consolidated Statements of Income
$

 
$
(2,902
)
 
$

 
$
(42,010
)
 
$

 
$
(40,608
)
Cash collateral receivable (payable) included in accounts receivable
$

 
$
3,310

 
$

 
$

 
$

 
$

__________
*
Maximum terms in years for our de-designated interest rate swaps reflect the amended early termination dates. If the early termination dates are not extended, the swaps will require cash settlement based on the swap value on the termination date. When extended annually, de-designated swaps totaling $100 million terminate in 6.25 years and de-designated swaps totaling $150 million terminate in 16.25 years.

Based on Sept. 30, 2012 market interest rates and balances for our designated interest rate swaps, a loss of approximately $7.0 million would be realized and reported in pre-tax earnings during the next 12 months. Estimated and realized losses will change during the next 12 months as market interest rates change.

Collateral requirements based on our corporate credit rating apply to $50 million of our de-designated swaps. At our current credit ratings, we are required to post collateral for any amount by which the swaps' negative mark-to-market fair value exceeds $20 million. If our senior unsecured credit rating drops to BB+ or below by S&P, or to Ba1 or below by Moody's, we would be required to post collateral for the entire amount of the swaps' negative mark-to-market fair value.



68



ITEM 4.    CONTROLS AND PROCEDURES

This section should be read in conjunction with Item 9A, "Controls and Procedures" included in our Annual Report on Form 10-K for the year ended Dec. 31, 2011.

Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (Exchange Act)) as of Sept. 30, 2012 and concluded that, because of the material weakness in our internal control over financial reporting related to accounting for income taxes as previously disclosed in Item 9A, “Controls and Procedures” in our Annual Report on Form 10-K for the year ended Dec. 31, 2011, our disclosure controls and procedures were not effective as of Sept. 30, 2012. Additional review, evaluation and oversight have been undertaken to ensure our unaudited Condensed Consolidated Financial Statements were prepared in accordance with generally accepted accounting principles and as a result, our management, including our Chief Executive Officer and Chief Financial Officer, have concluded that the Condensed Consolidated Financial Statements in this Form 10-Q fairly present in all material respects our financial position, results of operations and cash flows for the periods presented in conformity with accounting principles generally accepted in the United States.

As discussed in our 2011 Annual Report on Form 10-K, management concluded that while we had appropriately designed control procedures for income tax accounting and disclosures, the existence of non-routine transactions, insufficient tax resources, and ineffective communications between the tax department and Controller organization caused us to poorly execute the controls for evaluating and recording income taxes. Management has developed and implemented a remediation plan to address this material weakness in internal controls surrounding accounting for income taxes. Key aspects of the remediation plan include enhanced resources and skill sets, and implementation of formal periodic meetings among the Chief Financial Officer, Controller and the tax department.

While we concluded our internal controls surrounding income taxes were not effective as of Sept. 30, 2012, we are remediating the material weakness and will continue to execute our remediation plan and track our performance against the plan.

During the quarter ended Sept. 30, 2012, there have been no other changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.


69



BLACK HILLS CORPORATION

Part II — Other Information

ITEM 1.
Legal Proceedings

For information regarding legal proceedings, see Note 19 in Item 8 of our 2011 Annual Report on Form 10-K and Note 14 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 14 is incorporated by reference into this item.

ITEM 1A.
Risk Factors

There are no material changes to the Risk Factors previously disclosed in Item 1A of Part I in our Annual Report on Form 10-K for the year ended Dec. 31, 2011.

ITEM 2.
Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities

Period
 
Total
Number
of
Shares
Purchased(1)
 
Average
Price Paid
per Share
 
Total Number
of Shares
Purchased as
Part of Publicly
Announced
Plans for Programs
 
Maximum Number (or
Approximate Dollar
Value) of Shares
That May Yet Be
Purchased Under
the Plans or Programs
July 1, 2012 -
 
 
 
 
 
 
 
 
July 31, 2012
 

 
$

 

 

 
 
 
 
 
 
 
 
 
Aug. 1, 2012 -
 
 
 
 
 
 
 
 
Aug. 31, 2012
 
262

 
$
31.46

 

 

 
 
 
 
 
 
 
 
 
Sept. 1, 2012 -
 
 
 
 
 
 
 
 
Sept. 30, 2012
 

 
$

 

 

 
 
 
 
 
 
 
 
 
Total
 
262

 
$
31.46

 

 

____________
(1)
Shares were acquired from certain officers and key employees under the share withholding provisions of the Omnibus Incentive Plan for the payment of taxes associated with the vesting of shares of restricted stock.


ITEM 4.
Mine Safety Disclosures

Information concerning mine safety violations or other regulatory matters required by Sections 1503(a) of Dodd-Frank is included in Exhibit 95 of this Quarterly Report on Form 10-Q.

ITEM 5.
Other Information

None.

70



ITEM 6.
Exhibits

 
Exhibit 2
Purchase and Sale Agreement, dated as of August 23, 2012, by and among Black Hills Exploration and Production, Inc. and Other Sellers and QEP Energy Company, as Purchaser (excluding exhibits and certain schedules, which the Registrant agrees to furnish supplementally to the Securities and Exchange Commission upon request).
 
 
 
 
Exhibit 31.1
Certification of Chief Executive Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
 
 
 
 
Exhibit 31.2
Certification of Chief Financial Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
 
 
 
 
Exhibit 32.1
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.
 
 
 
 
Exhibit 32.2
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.
 
 
 
 
Exhibit 95
Mine Safety and Health Administration Safety Data
 
 
 
 
Exhibit 101
Financial Statements for XBRL Format


71



BLACK HILLS CORPORATION

Signatures

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

BLACK HILLS CORPORATION
 
 
/s/ David R. Emery
 
 
David R. Emery, Chairman, President and
 
 
  Chief Executive Officer
 
 
 
 
 
/s/ Anthony S. Cleberg
 
 
Anthony S. Cleberg, Executive Vice President and
 
 
  Chief Financial Officer
 
 
 
Dated:
November 8, 2012
 


72



EXHIBIT INDEX


Exhibit Number
Description
Exhibit 2
Purchase and Sale Agreement, dated as of August 23, 2012, by and among Black Hills Exploration and Production, Inc. and Other Sellers and QEP Energy Company, as Purchaser (excluding exhibits and certain schedules, which the Registrant agrees to furnish supplementally to the Securities and Exchange Commission upon request).
 
 
Exhibit 31.1
Certification of Chief Executive Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
 
 
Exhibit 31.2
Certification of Chief Financial Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
 
 
Exhibit 32.1
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.
 
 
Exhibit 32.2
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.
 
 
Exhibit 95
Mine Safety and Health Administration Safety Data
 
 
Exhibit 101
Financial Statements for XBRL Format


73