BKH 10Q Q3 2013


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, 2013
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, 2013
Common stock, $1.00 par value
44,485,101

shares






TABLE OF CONTENTS
 
 
 
Page
 
Glossary of Terms and Abbreviations
 
 
 
 
 
PART I.
FINANCIAL INFORMATION
 
 
 
 
 
Item 1.
Financial Statements
 
 
 
 
 
 
Condensed Consolidated Statements of Income (Loss) - unaudited
 
 
 
   Three and Nine Months Ended Sept. 30, 2013 and 2012
 
 
 
 
 
 
Condensed Consolidated Statements of Comprehensive Income (Loss)- unaudited
 
 
 
   Three and Nine Months Ended Sept. 30, 2013 and 2012
 
 
 
 
 
 
Condensed Consolidated Balance Sheets - unaudited
 
 
 
   Sept. 30, 2013, Dec. 31, 2012 and Sept. 30, 2012
 
 
 
 
 
 
Condensed Consolidated Statements of Cash Flows - unaudited
 
 
 
   Nine Months Ended Sept. 30, 2013 and 2012
 
 
 
 
 
 
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
 
 
 
 
 
 
Index to Exhibits
 


2



GLOSSARY OF TERMS AND ABBREVIATIONS

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
AOCI
Accumulated Other Comprehensive Income (Loss)
ASU
Accounting Standards Update
Basin Electric
Basin Electric Power Cooperative
Bbl
Barrel
BHC
Black Hills Corporation; the Company
BHEP
Black Hills Exploration and Production, Inc., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, and Black Hills Gas Resources, Inc. and Black Hills Plateau Production, LLC, direct wholly-owned subsidiaries of Black Hills Exploration and Production, Inc.

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 of Black Hills Utility Holdings, Inc., and its subsidiaries
Black Hills Non-regulated Holdings
Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Power
Black Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Utility Holdings
Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Wyoming
Black Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Generation
Cheyenne Light
Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation
Cheyenne Prairie
Cheyenne Prairie Generating Station, a 132 megawatt generating facility, currently being constructed in Cheyenne, Wyo. by Cheyenne Light and Black Hills Power.
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 IPP
Black Hills Colorado IPP, LLC a direct wholly-owned subsidiary of Black Hills Electric Generation
Cooling degree day
A cooling degree day is equivalent to each degree that the average of the high and low temperature for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30-year average.
Conflict Minerals
As defined by Dodd-Frank, conflict minerals are cassiterite, columbite-tantalite, gold and wolframite that are mined in the Democratic Republic of the Congo or surrounding countries
CPCN
Certificate of Public Convenience and Necessity
CPUC
Colorado Public Utilities Commission
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

3



CTII
The 40 megawatt Gillette CT, a simple-cycle, gas-fired combustion turbine owned by Black Hills Wyoming
CVA
Credit Valuation Adjustment, an adjustment to the measurement of derivatives to reflect the default risk of the counterparty.
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)
Enserco
Enserco Energy Inc., representing our Energy Marketing segment, sold Feb. 29, 2012
FASB
Financial Accounting Standards Board
FERC
United States Federal Energy Regulatory Commission
Fitch
Fitch Ratings
GAAP
Accounting principles generally accepted in the United States of America
Heating Degree Day
A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30-year average.
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
United States Internal Revenue Service
IUB
Iowa Utilities Board
Kansas Gas
Black Hills Kansas Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
LIBOR
London Interbank Offered Rate
LOE
Lease Operating Expense
Mcf
Thousand cubic feet of natural gas
Mcfe
Thousand cubic feet equivalent. Natural gas liquid is converted by dividing gallons by 7. Crude oil is converted by multiplying barrels by 6.
MMBtu
Million British thermal units
Moody’s
Moody’s Investors Service, Inc.
MWh
Megawatt-hour
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

4



 
 
 
 
 
 
NGL
Natural Gas Liquids. One gallon equals 1/7 Mcfe
NOL
Net Operating Loss
OTC
Over-the-counter
PPA
Power Purchase Agreement
PSCo
Public Service Company of Colorado
Revolving Credit Facility
Our $500 million credit facility which matures in 2017
SDPUC
South Dakota Public Utilities Commission
SEC
U. S. Securities and Exchange Commission
S&P
Standard and Poor’s, a division of The McGraw-Hill Companies, Inc.
WPSC
Wyoming Public Service Commission

5





BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS)
(unaudited)
Three Months Ended Sept. 30,
Nine Months Ended Sept. 30,
 
2013
2012
2013
2012
 
(in thousands, except per share and per share amounts)
 
 
 
 
 
Revenue
$
259,907

$
246,808

$
920,404

$
855,022

 
 
 
 
 
Operating expenses:
 
 
 
 
Utilities -
 
 
 
 
Fuel, purchased power and cost of gas sold
71,503

62,582

338,848

283,217

Operations and maintenance
66,061

59,398

196,728

183,721

Non-regulated energy operations and maintenance
20,484

22,466

62,703

65,774

Gain on sale of operating assets

(27,285
)

(27,285
)
Depreciation, depletion and amortization
36,135

41,408

106,068

121,398

Taxes - property, production and severance
10,068

10,213

30,517

31,201

Impairment of long-lived assets



26,868

Other operating expenses
90

216

1,091

1,679

Total operating expenses
204,341

168,998

735,955

686,573

 
 
 
 
 
Operating income
55,566

77,810

184,449

168,449

 
 
 
 
 
Other income (expense):
 
 
 
 
Interest charges -
 
 
 
 
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts and realized settlements on interest rate swaps)
(23,840
)
(27,475
)
(70,881
)
(85,151
)
Allowance for funds used during construction - borrowed
347

1,127

831

2,608

Capitalized interest
273

175

811

467

Unrealized gain (loss) on interest rate swaps, net
3,144

605

29,393

(2,902
)
Interest income
565

364

1,325

1,428

Allowance for funds used during construction - equity
85

196

327

668

Other income (expense), net
318

(287
)
1,197

2,073

Total other income (expense), net
(19,108
)
(25,295
)
(36,997
)
(80,809
)
 
 
 
 
 
Income (loss) from continuing operations before earnings (loss) of unconsolidated subsidiaries and income taxes
36,458

52,515

147,452

87,640

Equity in earnings (loss) of unconsolidated subsidiaries

22

(86
)
(12
)
Income tax benefit (expense)
(13,334
)
(17,914
)
(50,527
)
(30,057
)
Income (loss) from continuing operations
23,124

34,623

96,839

57,571

Income (loss) from discontinued operations, net of tax

(166
)

(6,810
)
Net income (loss) available for common stock
$
23,124

$
34,457

$
96,839

$
50,761

 
 
 
 
 
Earnings (loss) per share, Basic -
 
 
 
 
Income (loss) from continuing operations, per share
$
0.52

$
0.79

$
2.19

$
1.31

Income (loss) from discontinued operations, per share



(0.16
)
Total income (loss) per share, Basic
$
0.52

$
0.79

$
2.19

$
1.15

Earnings (loss) per share, Diluted -
 
 
 
 
Income (loss) from continuing operations, per share
$
0.52

$
0.78

$
2.18

$
1.31

Income (loss) from discontinued operations, per share



(0.16
)
Total income (loss) per share, Diluted
$
0.52

$
0.78

$
2.18

$
1.15

Weighted average common shares outstanding:
 
 
 
 
Basic
44,201

43,847

44,143

43,792

Diluted
44,457

44,108

44,395

44,026

 
 
 
 
 
Dividends paid per share of common stock
$
0.380

$
0.370

$
1.140

$
1.110


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

6





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


(unaudited)
Three Months Ended
Sept. 30,
Nine Months Ended
Sept. 30,
 
2013
2012
2013
2012
 
(in thousands)
 
 
 
 
 
Net income (loss) available for common stock
$
23,124

$
34,457

$
96,839

$
50,761

 
 
 
 
 
Other comprehensive income (loss), net of tax:
 
 
 
 
Fair value adjustment on derivatives designated as cash flow hedges (net of tax (expense) benefit of $964 and $1,204 for the three months ended 2013 and 2012 and $(93) and $1,092 for the nine months ended 2013 and 2012, respectively)
(2,083
)
(3,591
)
134

(3,004
)
Reclassification adjustments related to defined benefit plan (net of tax of $(220) for the three months ended 2013 and $(663) for the nine months ended 2013)
417


1,238


Reclassification adjustments for cash flow hedges settled and included in net income (loss) (net of tax (expense) benefit of $(586) and $13 for the three months ended 2013 and 2012 and $(1,469) and $890 for the nine months ended 2013 and 2012, respectively)
1,426

28

3,095

(1,333
)
Other comprehensive income (loss), net of tax
(240
)
(3,563
)
4,467

(4,337
)
 
 
 
 
 
Comprehensive income (loss) available for common stock
$
22,884

$
30,894

$
101,306

$
46,424


See Note 7 for additional disclosures.

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
(unaudited)
As of
 
Sept. 30, 2013
 
Dec. 31, 2012
 
Sept. 30, 2012
 
(in thousands)
ASSETS
 
 
 
 
 
Current assets:
 
 
 
 
 
Cash and cash equivalents
$
13,637

 
$
15,462

 
$
247,192

Restricted cash and equivalents
6,782

 
7,916

 
7,302

Accounts receivable, net
114,137

 
163,698

 
104,482

Materials, supplies and fuel
95,230

 
77,643

 
80,900

Derivative assets, current
126

 
3,236

 
16,063

Income tax receivable, net
4,539

 

 
11,869

Deferred income tax assets, net, current
37,163

 
77,231

 
33,681

Regulatory assets, current
30,208

 
31,125

 
24,606

Other current assets
27,075

 
28,795

 
44,823

Total current assets
328,897

 
405,106

 
570,918

 
 
 
 
 
 
Investments
16,612

 
16,402

 
16,273

 
 
 
 
 
 
Property, plant and equipment
4,152,097

 
3,930,772

 
3,950,222

Less: accumulated depreciation and depletion
(1,258,450
)
 
(1,188,023
)
 
(1,253,808
)
Total property, plant and equipment, net
2,893,647

 
2,742,749

 
2,696,414

 
 
 
 
 
 
Other assets:
 
 
 
 
 
Goodwill
353,396

 
353,396

 
353,396

Intangible assets, net
3,453

 
3,620

 
3,675

Derivative assets, non-current

 
510

 
1,167

Regulatory assets, non-current
183,119

 
188,268

 
191,935

Other assets, non-current
22,116

 
19,420

 
19,850

Total other assets, non-current
562,084

 
565,214

 
570,023

 
 
 
 
 
 
TOTAL ASSETS
$
3,801,240

 
$
3,729,471

 
$
3,853,628


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

8



BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Continued)
(unaudited)
As of
 
Sept. 30, 2013
 
Dec. 31, 2012
 
Sept. 30, 2012
 
(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
 
 
Current liabilities:
 
 
 
 
 
Accounts payable
$
77,077

 
$
84,422

 
$
69,138

Accrued liabilities
152,911

 
154,389

 
179,284

Derivative liabilities, current
65,944

 
96,541

 
86,509

Accrued income tax, net

 
4,936

 

Regulatory liabilities, current
14,707

 
13,628

 
10,705

Notes payable
138,300

 
277,000

 
225,000

Current maturities of long-term debt
255,694

 
103,973

 
328,310

Total current liabilities
704,633

 
734,889

 
898,946

 
 
 
 
 
 
Long-term debt, net of current maturities
955,979

 
938,877

 
942,950

 
 
 
 
 
 
Deferred credits and other liabilities:
 
 
 
 
 
Deferred income tax liabilities, net, non-current
403,772

 
385,908

 
338,194

Derivative liabilities, non-current
11,388

 
16,941

 
41,410

Regulatory liabilities, non-current
131,730

 
127,656

 
120,491

Benefit plan liabilities
169,448

 
167,397

 
167,690

Other deferred credits and other liabilities
133,341

 
125,294

 
129,630

Total deferred credits and other liabilities
849,679

 
823,196

 
797,415

 
 
 
 
 
 
Commitments and contingencies (See Notes 5, 8, 10 and 13)


 

 

 
 
 
 
 
 
Stockholders’ equity:
 
 
 
 
 
Common stock equity —
 
 
 
 
 
Common stock $1 par value; 100,000,000 shares authorized; issued 44,532,245; 44,278,189; and 44,250,588 shares, respectively
44,532

 
44,278

 
44,251

Additional paid-in capital
740,209

 
733,095

 
731,176

Retained earnings
539,030

 
492,869

 
478,459

Treasury stock, at cost – 47,127; 71,782; and 75,420 shares, respectively
(1,801
)
 
(2,245
)
 
(2,354
)
Accumulated other comprehensive income (loss)
(31,021
)
 
(35,488
)
 
(37,215
)
Total stockholders’ equity
1,290,949

 
1,232,509

 
1,214,317

 
 
 
 
 
 
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
$
3,801,240

 
$
3,729,471

 
$
3,853,628


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

9



BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
Nine Months Ended Sept. 30,
 
 
2013
2012
 
Operating activities:
(in thousands)
 
Net income (loss) available to common stock
$
96,839

$
50,761

 
(Income) loss from discontinued operations, net of tax

6,810

 
Income (loss) from continuing operations
96,839

57,571

 
Adjustments to reconcile income (loss) from continuing operations to net cash provided by operating activities:
 
 
 
Depreciation, depletion and amortization
106,068

121,398

 
Deferred financing cost amortization
3,209

5,301

 
Impairment of long-lived assets

26,868

 
Derivative fair value adjustments
275

(3,522
)
 
Gain on sale of operating assets

(27,285
)
 
Stock compensation
9,100

5,974

 
Unrealized (gain) loss on interest rate swaps, net
(29,393
)
2,902

 
Deferred income taxes
54,865

28,718

 
Employee benefit plans
16,644

15,737

 
Other adjustments, net
9,434

2,837

 
Changes in certain operating assets and liabilities:
 
 
 
Materials, supplies and fuel
(12,522
)
3,085

 
Accounts receivable, unbilled revenues and other operating assets
28,762

56,301

 
Accounts payable and other current liabilities
(23,774
)
(22,041
)
 
Contributions to defined benefit pension plans
(12,500
)
(25,000
)
 
Other operating activities, net
4,759

(361
)
 
Net cash provided by operating activities of continuing operations
251,766

248,483

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

21,184

 
Net cash provided by operating activities
251,766

269,667

 
 
 
 
 
Investing activities:
 
 
 
Property, plant and equipment additions
(239,485
)
(261,414
)
 
Proceeds from sale of assets

268,482

 
Investment in notes receivable

(21,832
)
 
Other investing activities
2,846

5,057

 
Net cash provided by (used in) investing activities of continuing operations
(236,639
)
(9,707
)
 
Proceeds from sale of discontinued business operations

108,837

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

(824
)
 
Net cash provided by (used in) investing activities
(236,639
)
98,306

 
 
 
 
 
Financing activities:
 
 
 
Dividends paid on common stock
(50,678
)
(48,904
)
 
Common stock issued
3,606

3,835

 
Short-term borrowings - issuances
269,600

62,453

 
Short-term borrowings - repayments
(408,300
)
(182,453
)
 
Long-term debt - issuances
275,000


 
Long-term debt - repayments
(106,180
)
(11,647
)
 
Other financing activities

(2,833
)
 
Net cash provided by (used in) financing activities of continuing operations
(16,952
)
(179,549
)
 
Net cash provided by (used in) financing activities of discontinued operations


 
Net cash provided by (used in) financing activities
(16,952
)
(179,549
)
 
Net change in cash and cash equivalents
(1,825
)
188,424

 
Cash and cash equivalents, beginning of period
15,462

58,768

*
Cash and cash equivalents, end of period
$
13,637

$
247,192

 
*
Includes cash of discontinued operations of $37.1 million at Dec. 31, 2011.

See Note 2 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.

10



BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Reference is made to Notes to Consolidated Financial Statements
included in the Company’s 2012 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 2012 Annual Report on Form 10-K filed with the SEC.

We conduct our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation, Coal Mining and Oil and Gas. 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.

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, 2013, Dec. 31, 2012, and Sept. 30, 2012 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 electric utilities is June through August while the normal peak usage season for gas utilities is November through March. 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, 2013 and Sept. 30, 2012, and our financial condition as of Sept. 30, 2013, Dec. 31, 2012, and Sept. 30, 2012, 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.


11



Recently Adopted Accounting Standards

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income, ASU 2013-02

In February 2013, the FASB issued ASU 2013-02 which requires new disclosures for items reclassified out of AOCI. ASU 2013-02 requires disclosure of (1) changes in components of other comprehensive income, (2) items reclassified out of AOCI and into net income in their entirety, the effect of the reclassification on each affected net income line item and (3) cross references to other disclosures that provide additional detail for components of other comprehensive income that are not reclassified in their entirety to net income. Disclosures are required either on the face of the statements of income or as a separate disclosure in the notes to the financial statements. The new disclosure requirements are effective for interim and annual periods beginning after Dec. 15, 2012. The adoption of this standard did not have an impact on our financial position, results of operations or cash flows. See additional disclosures in Note 7.

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

In December 2011, the FASB issued revised accounting guidance to amend disclosure requirements for offsetting financial assets and liabilities to enhance current disclosures. 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 did not have an impact on our financial position, results of operations or cash flows. See additional disclosures in Note 11.

Inclusion of the Fed Funds Effective Swap Rate as a Benchmark Interest Rate for Hedge Accounting Purposes, ASU 2013-10

In July 2013, the FASB issued an amendment to accounting for derivatives and hedges to permit the Fed Funds Effective Swap Rate to be used as a U.S. benchmark interest rate for hedge accounting purposes effective for new or re-designated hedging relationships entered into on or after July 17, 2013. The amendment also removed the restriction on using different benchmark rates for similar hedges. The initial adoption had no impact on our consolidated financial position, results of operations or cash flows.


12



Recently Issued Accounting Pronouncements and Legislation

Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists, ASU 2013-11

In July 2013, the FASB issued an amendment to accounting for income taxes which provides guidance on financial statement presentation of an unrecognized tax benefit when an NOL carryforward, a similar tax loss, or a tax credit carryforward exists. The objective in issuing this amendment is to eliminate diversity in practice resulting from a lack of guidance on this topic in current GAAP. Under the amendment, an entity must present an unrecognized tax benefit, or a portion of an unrecognized tax benefit, in the financial statements as a reduction to a deferred tax asset for an NOL carryforward, a similar tax loss, or a tax credit carryforward except under certain conditions. The amendment is effective for fiscal years beginning after Dec. 15, 2013, and interim periods within those years and should be applied to all unrecognized tax benefits that exist as of the effective date. The adoption of this standard is not expected to have an impact on our financial position, results of operations or cash flows.

Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date, ASU 2013-04

In March 2013, the FASB issued new disclosure requirements for recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements including disclosure of the nature and amount of the obligations. The new disclosure requirements are effective for interim and annual periods beginning after Dec. 15, 2013. The amendment requires enhanced disclosures in the notes to financial statements, but will not have any other impact on our consolidated financial statements.

Dodd-Frank Wall Street Reform and Consumer Protection Act, SEC Final Rule No. 34-67716

In August 2012, under Dodd-Frank, the SEC adopted new requirements for companies that manufacture or contract to manufacture products that contain certain minerals and metals, known as conflict minerals. The final rule requires all issuers that file reports with the SEC and use conflict minerals to report supply chain and sourcing information on an annual basis. These new requirements will require due diligence efforts in 2013, with initial disclosure requirements beginning in May 2014. Based on our preliminary analysis, we do not believe that our products contain conflict minerals as defined by the rule; however, our assessment process to determine whether conflict minerals are necessary to the functionality or production of any of our products is not complete.

Tangible Personal Property, IRS T.D. 9636

In September 2013, the U.S. Treasury issued final regulations addressing the tax consequences associated with the acquisition, production and improvement of tangible property. We continue to evaluate what impact the adoption of the regulations will have on our consolidated financial statements. As of this date, we do not expect the adoption of the regulations to have a material impact on our consolidated financial statements.



13



(2)    SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

Supplemental disclosures of cash flow for the nine months ended are as follows (in thousands):
 
Nine Months Ended
 
Sept. 30, 2013
 
Sept. 30, 2012
 
 
Non-cash investing and financing activities from continuing operations—
 
 
 
Property, plant and equipment acquired with accrued liabilities
$
47,214

 
$
39,303

Increase (decrease) in capitalized assets associated with asset retirement obligations
$

 
$
3,806

 
 
 
 
Cash (paid) refunded during the period for continuing operations—
 
 
 
Interest (net of amounts capitalized)
$
(57,175
)
 
$
(69,901
)
Income taxes, net
$
(4,924
)
 
$
425



(3)    MATERIALS, SUPPLIES AND FUEL

The following amounts by major classification are included in Materials, supplies and fuel in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
 
Sept. 30, 2013
 
Dec. 31, 2012
 
Sept. 30, 2012
Materials and supplies
$
50,564

 
$
43,397

 
$
43,847

Fuel - Electric Utilities
6,384

 
8,589

 
8,289

Natural gas in storage held for distribution
38,282

 
25,657

 
28,764

Total materials, supplies and fuel
$
95,230

 
$
77,643

 
$
80,900


 

14



(4)    ACCOUNTS RECEIVABLE

Following is a summary of Accounts receivable, net included in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
 
Accounts
Unbilled
Less Allowance for
Accounts
Sept. 30, 2013
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
49,254

$
20,153

$
(648
)
$
68,759

Gas Utilities
20,693

11,877

(542
)
32,028

Power Generation
3



3

Coal Mining
2,677



2,677

Oil and Gas
8,463


(19
)
8,444

Corporate
2,226



2,226

Total
$
83,316

$
32,030

$
(1,209
)
$
114,137


 
Accounts
Unbilled
Less Allowance for
Accounts
Dec. 31, 2012
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
54,482

$
23,843

$
(527
)
$
77,798

Gas Utilities
31,495

39,962

(222
)
71,235

Power Generation
16



16

Coal Mining
2,247



2,247

Oil and Gas
11,622


(19
)
11,603

Corporate
799



799

Total
$
100,661

$
63,805

$
(768
)
$
163,698


 
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

Power Generation
4



4

Coal Mining
1,540



1,540

Oil and Gas
10,272


(105
)
10,167

Corporate
657



657

Total
$
77,473

$
27,921

$
(912
)
$
104,482




15



(5)    NOTES PAYABLE AND LONG-TERM DEBT

We had the following notes payable outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
 
Sept. 30, 2013
Dec. 31, 2012
Sept. 30, 2012
 
Balance Outstanding
Letters of Credit
Balance Outstanding
Letters of Credit
Balance Outstanding
Letters of Credit
Revolving Credit Facility
$
138,300

$
53,137

$
127,000

$
36,300

$
75,000

$
36,300

Term Loan due June 2013


150,000


150,000


Total
$
138,300

$
53,137

$
277,000

$
36,300

$
225,000

$
36,300


Replacement of Notes Payable and Long-Term Term Loan

On June 21, 2013, we entered into a new $275 million term loan expiring on June 19, 2015. The proceeds from this new term loan repaid the $150 million term loan due on June 24, 2013, the $100 million corporate term loan due on Sept. 30, 2013, and $25 million in short-term borrowing under our Revolving Credit Facility. At Sept. 30, 2013, the cost of borrowing under this new term loan was 1.3125 percent (LIBOR plus a margin of 1.125 percent). The covenants of the new term loan are substantially the same as the Revolving Credit Facility.

Debt Covenants

Our Revolving Credit Facility and our new Term Loan require compliance with the following financial covenant at the end of each quarter (dollars in thousands):
 
As of
 
 
 
Sept. 30, 2013
 
Covenant Requirement
Recourse Leverage Ratio
52.0
%
 
Less than
65.0
%

As of Sept. 30, 2013, we were in compliance with this covenant.



16



(6)    EARNINGS PER SHARE

A reconciliation of share amounts used to compute Earnings (loss) per share in the accompanying Condensed Consolidated Statements of Income (loss) is as follows (in thousands):
 
Three Months Ended Sept. 30,
 
Nine Months Ended Sept. 30,
 
2013
2012
 
2013
2012
 
 
 
 
 
 
Income (loss) from continuing operations
$
23,124

$
34,623

 
$
96,839

$
57,571

 
 
 
 
 
 
Weighted average shares - basic
44,201

43,847

 
44,143

43,792

Dilutive effect of:
 
 
 
 
 
Restricted stock
131

175

 
137

159

Stock options
13

12

 
13

14

Other dilutive effects
112

74

 
102

61

Weighted average shares - diluted
44,457

44,108

 
44,395

44,026


The following outstanding securities were not included in the computation of diluted earnings per share as their effect would have been anti-dilutive (in thousands):
 
Three Months Ended Sept. 30,
Nine Months Ended Sept. 30,
 
2013
2012
2013
2012
Stock options

77

9

101

Restricted stock

61


53

Other stock



19

Anti-dilutive shares

138

9

173




17



(7)
OTHER COMPREHENSIVE INCOME (LOSS)

The components of the reclassification adjustments, net of tax, included in Other Comprehensive Income (Loss) for the periods were as follows (in thousands):
 
Location on the Condensed Consolidated Statements of Income (Loss)
Amount Reclassified from AOCI
Three Months Ended
Nine Months Ended
Sept. 30, 2013
Sept. 30, 2012
Sept. 30, 2013
Sept. 30, 2012
Gains (losses) on cash flow hedges:
 
 
 
 
 
Interest rate swaps
Interest expense
$
1,844

$
1,853

$
5,460

$
5,518

Commodity contracts
Revenue
168

(1,838
)
(896
)
(7,741
)
 
 
2,012

15

4,564

(2,223
)
Income tax
Income tax benefit (expense)
(586
)
13

(1,469
)
890

Reclassification adjustments related to cash flow hedges, net of tax
 
$
1,426

$
28

$
3,095

$
(1,333
)
 
 
 
 
 
 
Amortization of defined benefit plans:
 
 
 
 
 
Prior service cost
Utilities - Operations and maintenance
$
(31
)
$

$
(93
)
$

 
Non-regulated energy operations and maintenance
(32
)

(96
)

 
 
 
 
 
 
Actuarial gain (loss)
Utilities - Operations and maintenance
425


1,267


 
Non-regulated energy operations and maintenance
275


823


 
 
637


1,901


Income tax
Income tax benefit (expense)
(220
)

(663
)

Reclassification adjustments related to defined benefit plans, net of tax
 
$
417

$

$
1,238

$



18



Balances by classification included within Accumulated other comprehensive income (loss) on the accompanying Condensed Consolidated Balance Sheets are as follows (in thousands):
 
Derivatives Designated as Cash Flow Hedges
Employee Benefit Plans
Total
Balance as of Dec. 31, 2011
$
(13,802
)
$
(19,076
)
$
(32,878
)
Other comprehensive income (loss), net of tax
(166
)

(166
)
Balance as of March 31, 2012
(13,968
)
(19,076
)
(33,044
)
Other comprehensive income (loss), net of tax
(608
)

(608
)
Balance as of June 30, 2012
(14,576
)
(19,076
)
(33,652
)
Other comprehensive income (loss), net of tax
(3,563
)

(3,563
)
Ending Balance Sept. 30, 2012
$
(18,139
)
$
(19,076
)
$
(37,215
)
 
 
 
 
Balance as of Dec. 31, 2012
$
(15,713
)
$
(19,775
)
$
(35,488
)
Other comprehensive income (loss), net of tax
(1,193
)
457

(736
)
Balance as of March 31, 2013
(16,906
)
(19,318
)
(36,224
)
Other comprehensive income (loss), net of tax
5,079

364

5,443

Balance as of June 30, 2013
(11,827
)
(18,954
)
(30,781
)
Other comprehensive income (loss), net of tax
(657
)
417

(240
)
Ending Balance Sept. 30, 2013
$
(12,484
)
$
(18,537
)
$
(31,021
)


(8)    EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plans

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

 
Three Months Ended Sept. 30,
Nine Months Ended Sept. 30,
 
2013
2012
2013
2012
Service cost
$
1,608

$
1,431

$
4,824

$
4,291

Interest cost
3,825

3,688

11,475

11,062

Expected return on plan assets
(4,654
)
(4,084
)
(13,962
)
(12,252
)
Prior service cost
16

22

48

66

Net loss (gain)
3,062

2,408

9,186

7,224

Net periodic benefit cost
$
3,857

$
3,465

$
11,571

$
10,391



19



Non-pension Defined Benefit Postretirement Healthcare Plans

The components of net periodic benefit cost for the Non-pension Defined Benefit Postretirement Healthcare Plans were as follows (in thousands):
 
Three Months Ended Sept. 30,
Nine Months Ended Sept. 30,
 
2013
2012
2013
2012
Service cost
$
419

$
402

$
1,257

$
1,206

Interest cost
417

523

1,251

1,569

Expected return on plan assets
(20
)
(19
)
(60
)
(57
)
Prior service cost (benefit)
(125
)
(125
)
(375
)
(375
)
Net loss (gain)
121

222

363

666

Net periodic benefit cost
$
812

$
1,003

$
2,436

$
3,009


Supplemental Non-qualified Defined Benefit and Defined Contribution Plans

The components of net periodic benefit cost for the Supplemental Non-qualified Defined Benefit and Defined Contribution Plans were as follows (in thousands):
 
Three Months Ended Sept. 30,
Nine Months Ended Sept. 30,
 
2013
2012
2013
2012
Service cost
$
348

$
243

$
1,044

$
735

Interest cost
332

331

996

993

Prior service cost
1

1

3

3

Net loss (gain)
198

202

594

606

Net periodic benefit cost
$
879

$
777

$
2,637

$
2,337


Contributions

We anticipate that we will make contributions to the benefit plans during 2013 and 2014. Contributions to the Defined Benefit Pension Plans are cash contributions made directly to the Pension Plan Trust accounts. Contributions to the Healthcare and Supplemental Plan are 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, 2013
Nine Months Ended Sept. 30, 2013
Contributions Anticipated for 2013
Contributions Anticipated for 2014
Defined Benefit Pension Plans
$
12,500

$
12,500

$

$
12,500

Non-pension Defined Benefit Postretirement Healthcare Plans
$
784

$
2,352

$
784

$
3,350

Supplemental Non-qualified Defined Benefit and Defined Contribution Plans
$
322

$
966

$
322

$
1,463




20



(9)    BUSINESS SEGMENT INFORMATION

Segment information and Corporate activities included in the accompanying Condensed Consolidated Statements of Income (Loss) were as follows (in thousands):
Three Months Ended Sept. 30, 2013
 
External
Operating
Revenue
 
Intercompany
Operating
Revenue
 
Income (Loss) from Continuing Operations
Utilities:
 
 
 
 
 
 
   Electric
 
$
169,401

 
$
2,003

 
$
15,097

   Gas
 
67,792

 

 
(1,450
)
Non-regulated Energy:
 
 
 
 
 
 
   Power Generation
 
1,575

 
20,393

 
6,707

   Coal Mining
 
6,713

 
8,604

 
2,142

   Oil and Gas
 
14,426

 

 
(1,682
)
Corporate activities (a)
 

 

 
2,310

Intercompany eliminations
 

 
(31,000
)
 

Total
 
$
259,907

 
$

 
$
23,124


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

 
$
3,736

 
$
14,573

   Gas
 
63,435

 

 
3

Non-regulated Energy:
 
 
 
 
 
 
   Power Generation
 
1,256

 
19,695

 
5,128

   Coal Mining
 
6,108

 
8,567

 
1,690

   Oil and Gas (b)
 
24,728

 

 
17,389

Corporate activities (a)
 

 

 
(4,160
)
Intercompany eliminations
 

 
(31,998
)
 

Total
 
$
246,808

 
$

 
$
34,623


21




Nine Months Ended Sept. 30, 2013
 
External
Operating
Revenues
 
Intercompany
Operating
Revenues
 
Income (Loss) from Continuing Operations
Utilities:
 
 
 
 
 
 
   Electric
 
$
482,222

 
$
9,844

 
$
38,063

   Gas
 
373,440

 

 
20,225

Non-regulated Energy:
 
 
 
 
 
 
   Power Generation
 
3,628

 
58,825

 
17,382

   Coal Mining
 
19,530

 
23,688

 
5,180

   Oil and Gas
 
41,584

 

 
(3,699
)
Corporate (a)
 

 

 
19,688

Intercompany eliminations
 

 
(92,357
)
 

Total
 
$
920,404

 
$

 
$
96,839


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:
 
 
 
 
 
 
   Power Generation
 
3,193

 
56,119

 
15,968

   Coal Mining
 
18,518

 
24,273

 
3,924

   Oil and Gas (b)
 
66,994

 

 
(2,219
)
Corporate (a)(c)
 

 

 
(13,949
)
Intercompany eliminations
 

 
(92,338
)
 

Total
 
$
855,022

 
$

 
$
57,571

__________
(a)
Income (loss) from continuing operations includes a $2.0 million and a $19.1 million net after-tax non-cash mark-to-market gain on certain interest rate swaps for the three and nine months ended Sept. 30, 2013, respectively, and a $0.4 million after-tax non-cash mark-to-market gain and a $1.9 million net after-tax non-cash mark-to-market loss for the three and nine months ended Sept. 30, 2012, respectively, for those same interest rate swaps.
(b)
Income (loss) from continuing operations for the nine months ended Sept. 30, 2012, includes a $17.3 million non-cash after-tax ceiling test impairment charge. Income (loss) from continuing operations for the three and nine months ended Sept. 30, 2012, includes an after-tax gain of $17.7 million relating to the sale of the Williston Basin assets. See Notes 14 and 15 for further information.
(c)
Certain indirect corporate costs and inter-segment interest expense after-tax totaling $1.6 million for the nine months ended Sept. 30, 2012, were included in the Corporate activities in continuing operations and were not reclassified as discontinued operations.


22



Segment information and Corporate balances included in the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands):
Total Assets (net of inter-company eliminations) as of:
Sept. 30, 2013
 
Dec. 31, 2012
 
Sept. 30, 2012
Utilities:
 
 
 
 
 
   Electric (a)
$
2,464,123

 
$
2,387,458

 
$
2,302,951

   Gas
757,746

 
765,165

 
710,099

Non-regulated Energy:
 
 
 
 
 
   Power Generation (a)
102,331

 
119,170

 
119,489

   Coal Mining
82,155

 
83,810

 
90,444

   Oil and Gas
264,785

 
258,460

 
263,088

Corporate activities
130,100

 
115,408

 
367,557

Total assets
$
3,801,240

 
$
3,729,471

 
$
3,853,628

__________
(a)
The PPA pertaining to the portion of the Pueblo Airport Generation Station owned by Colorado IPP that supports Colorado Electric customers is accounted for as a capital lease. Therefore, assets owned by the Power Generation segment are included in Total assets of Electric Utilities Segment under this accounting for a capital lease.


(10)    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 2012 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 in crude oil and natural gas reserves and production and our fuel procurement for certain of our gas-fired generation assets; and

Interest rate risk associated with our variable rate debt, including our project financing floating rate debt and our other short-term and long-term debt instruments.


23



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 high credit quality entities, 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.

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, 2013, our credit exposure included a $1.3 million exposure to a non-investment grade energy marketing company. The remainder of our credit exposure was concentrated primarily among retail utility customers, investment grade rated companies, cooperative utilities and federal agencies. Our derivative and hedging activities recorded in the accompanying Condensed Consolidated Balance Sheets, Condensed Consolidated Statements of Income (Loss) and Condensed Consolidated Statements of Comprehensive Income (Loss) are detailed below and in Note 11.

Oil and Gas

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.

To mitigate commodity price risk and preserve cash flows, we primarily use over-the-counter swaps, exchange traded futures and related options to hedge portions of our crude oil and natural gas production. We elect hedge accounting on these instruments. 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 were marked to fair value and were 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 AOCI in the accompanying Condensed Consolidated Balance Sheets and the ineffective portion, if any, is reported in Revenue in the accompanying Condensed Consolidated Statements of Income (Loss).


24



The contract or notional amounts, terms of our commodity derivatives, and the derivative balances for our Oil and Gas segment reflected on the Condensed Consolidated Balance Sheet were as follows (dollars in thousands) as of:
 
Sept. 30, 2013
 
Dec. 31, 2012
 
Sept. 30, 2012
 
Crude oil futures, swaps and options
Natural gas futures and swaps
 
Crude oil futures, swaps and options
Natural gas futures and swaps
 
Crude oil futures, swaps and options
Natural gas futures and swaps
Notional (a)
499,500

9,874,000

 
528,000

8,215,500

 
537,000

7,455,250

Maximum terms in years (b)
0.25

0.08

 
1.00

0.75

 
1.00

1.00

Derivative assets, current
$
13

$
113

 
$
1,405

$
1,831

 
$
1,651

$
2,032

Derivative assets, non-current
$

$

 
$
297

$
170

 
$
494

$
39

Derivative liabilities, current
$
98

$
52

 
$
847

$
507

 
$
527

$
1,040

Derivative liabilities, non-current
$

$

 
$

$

 
$
414

$
141

__________
(a)
Crude oil in Bbls, natural gas in MMBtus.
(b)
Refers to the term of the derivative instrument. Assets and liabilities are classified as current/non-current based on the term of the hedged transaction and the corresponding settlement of the derivative instrument.
Based on market prices at Sept. 30, 2013, a $0.1 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.

Utilities

The operations of our utilities, including power purchase arrangements where our utilities must provide the generation fuel (tolling agreements), expose our utility customers to volatility in natural gas prices; therefore, as allowed or required by state utility commissions, we have entered into commission-approved hedging programs utilizing 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, net of balance sheet offsetting as permitted by GAAP. Unrealized and realized gains and losses, as well as option premiums and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in the accompanying Condensed Consolidated Balance Sheets in accordance with state commission guidelines. Accordingly, the hedging activity is recognized in the Condensed Consolidated Statements of Income (Loss) or the Condensed Consolidated Statements of Comprehensive Income (Loss) when the related costs are recovered through our rates.

The contract or notional amounts and terms of the natural gas derivative commodity instruments held at our Utilities were as follows, as of:
 
Sept. 30, 2013
 
Dec. 31, 2012
 
Sept. 30, 2012
 
Notional
(MMBtus)
 
Maximum
Term
(months)
 
Notional
(MMBtus)
 
Maximum
Term
(months)
 
Notional
(MMBtus)
 
Maximum
Term
(months)
Natural gas futures purchased
14,010,000

 
74
 
15,350,000

 
83
 
14,690,000

 
75
Natural gas options purchased
6,810,000

 
6
 
2,430,000

 
2
 
5,560,000

 
6
Natural gas basis swaps purchased
9,790,000

 
63
 
12,020,000

 
72
 
8,800,000

 
75


25



We had the following derivative balances related to the hedges in our Utilities reflected in our Condensed Consolidated Balance Sheet as of (in thousands):
 
Sept. 30, 2013
Dec. 31, 2012
Sept. 30, 2012
Derivative assets, current
$

$

$
12,380

Derivative assets, non-current
$

$
43

$
634

Derivative liabilities, non-current
$

$

$
4,527

Net unrealized (gain) loss included in Regulatory assets or Regulatory liabilities
$
10,652

$
9,596

$
9,318


Financing Activities

We entered into floating-to-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations associated with our floating rate debt obligations. The contract or notional amounts, terms of our interest rate swaps and the interest rate swaps balances reflected on the Condensed Consolidated Balance Sheet were as follows (dollars in thousands) as of:
 
Sept. 30, 2013
 
Dec. 31, 2012
 
Sept. 30, 2012
 
Designated 
Interest Rate
Swaps (a)
De-designated
Interest Rate
Swaps (b)
 
Designated 
Interest Rate
Swaps (a)
De-designated
Interest Rate
Swaps (b)
 
Designated 
Interest Rate
Swaps (a)
De-designated
Interest Rate
Swaps (b)
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
3.25

0.25

 
4.00

1.00

 
4.25

1.25

Derivative liabilities, current
$
7,039

$
58,755

 
$
7,039

$
88,148

 
$
7,028

$
77,914

Derivative liabilities, non-current
$
11,388

$

 
$
16,941

$

 
$
18,660

$
17,668

__________
(a)
These swaps have been designated to $75.0 million of borrowings on our Revolving Credit Facility and $75.0 million of borrowings on our project financing debt at Black Hills Wyoming. The swaps that hedge the variable rate debt at Black Hills Wyoming were transferred from BHC. Both BHC and Black Hills Wyoming are jointly and severally obligated for the swaps’ obligations. These swaps are priced using three-month LIBOR, matching the floating portion of the related swaps.
(b)
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 $100.0 million notional terminate in approximately 5.25 years and de-designated swaps totaling $150.0 million notional terminate in approximately 15.25 years.

Collateral requirements based on our corporate credit rating apply to $50.0 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 $20.0 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. We had approximately $6.0 million cash collateral posted at Sept. 30, 2013.

Based on Sept. 30, 2013, market interest rates and balances related to our designated interest rate swaps, a loss of approximately $7.0 million would be realized, reported in pre-tax earnings and 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.

 

26



(11)    FAIR VALUE MEASUREMENTS

Derivative Financial Instruments

The accounting guidance for fair value measurements requires certain disclosures about assets and liabilities measured at fair value. This guidance establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. 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. For additional information see Notes 1, 3 and 4 to the Consolidated Financial Statements included in our 2012 Annual Report on Form 10-K filed with the SEC.

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 when the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs.

Valuation Methodologies for Derivatives

Oil and Gas Segment:

The commodity option contracts for our Oil and Gas segment are valued using the market approach and can 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 third party sources and therefore support Level 2 disclosure.

The commodity basis swaps for our Oil and Gas segment are valued using 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 Segments:

The commodity contracts for our Utilities Segments, 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 because these instruments are not traded on an exchange.

Corporate Activities:

The interest rate swaps are valued using the market 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.


27



Recurring Fair Value Measurements

There have been no significant transfers between Level 1 and Level 2 derivative balances. Amounts included in cash collateral and counterparty netting in the following tables represent the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions, netting of asset and liability positions permitted in accordance with accounting standards for offsetting as well as cash collateral posted with the same counterparties.

The following tables set forth by level within the fair value hierarchy our gross assets and gross liabilities and related offsetting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments. A discussion of fair value of financial instruments is included in Note 12:
 
As of Sept. 30, 2013
 
Level 1
Level 2
Level 3
 
Cash Collateral and Counterparty
Netting
Total
 
(in thousands)
Assets:
 
 
 
 
 
 
Commodity derivatives — Oil and Gas
 
 
 
 
 


    Options -- Oil
$

$
2

$

 
$

$
2

    Basis Swaps -- Oil

51


 
(40
)
11

    Options -- Gas



 


    Basis Swaps -- Gas

1,752


 
(1,639
)
113

Commodity derivatives — Utilities

2,351


 
(2,351
)

Total
$
13,637

$
4,156

$

 
$
(4,030
)
$
126

 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
Commodity derivatives — Oil and Gas
 
 
 
 
 


    Options -- Oil
$

$
142

$

 
$
(77
)
$
65

    Basis Swaps -- Oil

1,318


 
(1,284
)
34

    Options -- Gas



 


    Basis Swaps -- Gas

232


 
(181
)
51

Commodity derivatives — Utilities

10,747


 
(10,747
)

Interest rate swaps

83,142


 
(5,960
)
77,182

Total
$

$
95,581

$

 
$
(18,249
)
$
77,332




28




 
As of Dec. 31, 2012
 
Level 1
Level 2
Level 3
 
Cash Collateral and Counterparty
Netting
Total
 
(in thousands)
Assets:
 
 
 
 
 
 
Commodity derivatives — Oil and Gas
 
 
 
 
 
 
Options -- Oil
$

$
378

$

 
$

$
378

Basis Swaps -- Oil

1,325


 

1,325

Options -- Gas



 


Basis Swaps -- Gas

2,000


 

2,000

Commodity derivatives —Utilities


43

(a) 

43

Total
$

$
3,703

$
43

 
$

$
3,746

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

$
1,131

$

 
$
(336
)
$
795

Basis Swaps -- Oil

502


 
(450
)
52

Options -- Gas



 


Basis Swaps -- Gas

1,127


 
(620
)
507

Commodity derivatives — Utilities

10,162


 
(10,162
)

Interest rate swaps

118,088


 
(5,960
)
112,128

Total
$

$
131,010

$

 
$
(17,528
)
$
113,482

__________
(a)
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.


29



 
As of Sept. 30, 2012
 
Level 1
Level 2
Level 3
 
Cash Collateral and Counterparty
Netting
Total
 
(in thousands)
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

(a) 
15,740

13,014

Total
$

$
1,456

$
34

 
$
15,740

$
17,230

 
 
 
 
 
 
 
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)
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.


30



Fair Value Measures by Balance Sheet Classification

As required by accounting standards for derivatives and hedges, fair values within the following tables are presented on a gross basis reflecting the netting of asset and liability positions permitted in accordance with accounting standards for offsetting and under terms of our master netting agreements and the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions, however, the amounts do not include net cash collateral on deposit in margin accounts at Sept. 30, 2013, Dec. 31, 2012, and Sept. 30, 2012, to collateralize certain financial instruments, which are included in Derivative assets and/or Derivative liabilities. Therefore, the 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 10.

The following tables present the fair value and balance sheet classification of our derivative instruments (in thousands):
As of Sept. 30, 2013
 
Balance Sheet Location
 
Fair Value
of Asset
Derivatives
Fair Value
of Liability
Derivatives
Derivatives designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
846

$

Commodity derivatives
Derivative assets — non-current
 
959


Commodity derivatives
Derivative liabilities — current
 

1,317

Commodity derivatives
Derivative liabilities — non-current
 

375

Interest rate swaps
Derivative liabilities — current
 

7,039

Interest rate swaps
Derivative liabilities — non-current
 

11,388

Total derivatives designated as hedges
 
 
$
1,805

$
20,119

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

$

Commodity derivatives
Derivative assets — non-current
 


Commodity derivatives
Derivative liabilities — current
 

1,795

Commodity derivatives
Derivative liabilities — non-current
 

6,601

Interest rate swaps
Derivative liabilities — current
 

64,715

Interest rate swaps
Derivative liabilities — non-current
 


Total derivatives not designated as hedges
 
 
$

$
73,111


31




As of Dec. 31, 2012
 
Balance Sheet Location
 
Fair Value
of Asset
Derivatives
Fair Value
of Liability
Derivatives
Derivatives designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
2,874

$

Commodity derivatives
Derivative assets — non-current
 
510


Commodity derivatives
Derivative liabilities — current
 

1,993

Commodity derivatives
Derivative liabilities — non-current
 

821

Interest rate swaps
Derivative liabilities — current
 

7,038

Interest rate swaps
Derivative liabilities — non-current
 

16,941

Total derivatives designated as hedges
 
 
$
3,384

$
26,793

 
 
 
 
 
Derivatives not designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
362

$

Commodity derivatives
Derivative assets — non-current
 


Commodity derivatives
Derivative liabilities — current
 
1,180

4,957

Commodity derivatives
Derivative liabilities — non-current
 
406

5,153

Interest rate swaps
Derivative liabilities — current
 

94,108

Interest rate swaps
Derivative liabilities — non-current
 


Total derivatives not designated as hedges
 
 
$
1,948

$
104,218


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



32



Derivatives Offsetting

It is our policy to offset in our Condensed Consolidated Balance Sheets contracts which provide for legally enforceable netting of our accounts receivable and payable and derivative activities.

As required by accounting standards for derivatives and hedges, fair values within the following tables reconcile the gross amounts to the net amounts. Amounts included in Gross Amounts Offset on Condensed Consolidated Balance Sheets in the following tables includes the netting of asset and liability positions permitted in accordance with accounting standards for offsetting as well as the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions as well as cash collateral posted with the same counterparties. Additionally, the amounts reflect cash collateral on deposit in margin accounts at Sept. 30, 2013, Dec. 31, 2012, and Sept. 30, 2012, to collateralize certain financial instruments, which are included in Derivative assets and/or Derivative liabilities. Therefore, the gross amounts are not indicative of either our actual credit exposure or net economic exposure.

Offsetting of derivative assets and derivative liabilities on our Condensed Consolidated Balance Sheets was as follows:
 
As of Sept. 30, 2013
Derivative Assets
Gross Amounts of Derivative Assets
Gross Amounts Offset on Condensed Consolidated Balance Sheets
Net Amount of Total Derivative Assets on Condensed Consolidated Balance Sheets
 
(in thousands)
Subject to a master netting agreement or similar arrangement:
 
 
 
Commodity derivative:
 
 
 
Oil and Gas - Crude Basis Swaps
$
40

$
(40
)
$

Oil and Gas - Crude Options



Oil and Gas - Natural Gas Basis Swaps
1,639

(1,639
)

Utilities
2,351

(2,351
)

Total derivative assets subject to a master netting agreement or similar arrangement
4,030

(4,030
)

 
 
 
 
Not subject to a master netting agreement or similar arrangement:
 
 
 
Commodity derivative:
 
 
 
Oil and Gas - Crude Basis Swaps
11


11

Oil and Gas - Crude Options
2


2

Oil and Gas - Natural Gas Basis Swaps
113


113

Utilities



Total derivative assets not subject to a master netting agreement or similar arrangement
126


126

 
 
 
 
Total derivative assets
$
4,156

$
(4,030
)
$
126


33




 
As of Sept. 30, 2013
Derivative Liabilities
Gross Amounts of Derivative Liabilities
Gross Amounts Offset on Condensed Consolidated Balance Sheets
Net Amount of Total Derivative Liabilities on Condensed Consolidated Balance Sheets
 
(in thousands)
Subject to a master netting agreement or similar arrangement:
 
 
 
Commodity derivative:
 
 
 
Oil and Gas - Crude Basis Swaps
$
1,284

$
(1,284
)
$

Oil and Gas - Crude Options
77

(77
)

Oil and Gas - Natural Gas Basis Swaps
181

(181
)

Utilities
10,747

(10,747
)

Interest Rate Swaps



Total derivative liabilities subject to a master netting agreement or similar arrangement
12,289

(12,289
)

 
 
 
 
Not subject to a master netting agreement or similar arrangement:
 
 
 
Commodity derivative:
 
 
 
Oil and Gas - Crude Basis Swaps
34


34

Oil and Gas - Crude Options
65


65

Oil and Gas - Natural Gas Basis Swaps
51


51

Utilities



Interest Rate Swaps
83,142

(5,960
)
77,182

Total derivative liabilities not subject to a master netting agreement or similar arrangement
83,292

(5,960
)
77,332

 
 
 
 
Total derivative liabilities
$
95,581

$
(18,249
)
$
77,332



34




 
As of Dec. 31, 2012
Derivative Assets
Gross Amounts of Derivative Assets
Gross Amounts Offset on Condensed Consolidated Balance Sheets
Net Amount of Total Derivative Assets on Condensed Consolidated Balance Sheets
 
(in thousands)
Subject to master netting agreement or similar arrangement:
 
 
 
Commodity derivative:
 
 
 
Oil and Gas - Crude Basis Swaps
$
76

$

$
76

Oil and Gas - Crude Options
93


93

Oil and Gas - Natural Gas Basis Swaps
172


172

Utilities
1,629

(1,586
)
43

Total derivative assets subject to a master netting agreement or similar arrangement
1,970

(1,586
)
384

 
 
 
 
Not subject to a master netting agreement or similar arrangement:
 
 
 
Commodity derivative:
 
 
 
Oil and Gas - Crude Basis Swaps
1,249


1,249

Oil and Gas - Crude Options
285


285

Oil and Gas - Natural Gas Basis Swaps
1,828


1,828

Utilities



Total derivative assets not subject to a master netting agreement or similar arrangement
3,362


3,362

 
 
 
 
Total derivative assets
$
5,332

$
(1,586
)
$
3,746


35




 
As of Dec. 31, 2012
Derivative Liabilities
Gross Amounts of Derivative Liabilities
Gross Amounts Offset on Condensed Consolidated Balance Sheets
Net Amount of Total Derivative Liabilities on Condensed Consolidated Balance Sheets
 
(in thousands)
Subject to a master netting agreement or similar arrangement
 
 
 
Commodity derivative:
 
 
 
Oil and Gas - Crude Basis Swaps
$
449

$
(449
)
$

Oil and Gas - Crude Options
337

(337
)

Oil and Gas - Natural Gas Basis Swaps
620

(620
)

Utilities
10,162

(10,162
)

Interest Rate Swaps



Total derivative liabilities subject to a master netting agreement or similar arrangement
11,568

(11,568
)

 
 
 
 
Not subject to a master netting agreement or similar arrangement:
 
 
 
Commodity derivative:
 
 
 
Oil and Gas - Crude Basis Swaps
52


52

Oil and Gas - Crude Options
795


795

Oil and Gas - Natural Gas Basis Swaps
507


507

Utilities



Interest Rate Swaps
118,088

(5,960
)
112,128

Total derivative liabilities not subject to a master netting agreement or similar arrangement
119,442

(5,960
)
113,482

 
 
 
 
Total derivative liabilities
$
131,010

$
(17,528
)
$
113,482



36




 
As of Sept. 30, 2012
Derivative Assets
Gross Amounts of Derivative Assets
Gross Amounts Offset on Condensed Consolidated Balance Sheets
Net Amount of Total Derivative Assets on Condensed Consolidated Balance Sheets
 
(in thousands)
Subject to master netting agreements or similar arrangement:
 
 
 
Commodity derivative:
 
 
 
Oil and Gas - Crude Basis Swaps
$
95

$

$
95

Oil and Gas - Crude Options
194


194

Oil and Gas - Natural Gas Basis Swaps
5


5

Utilities
(2,726
)
15,740

13,014

Total derivative assets subject to a master netting agreement or similar arrangement
(2,432
)
15,740

13,308

 
 
 
 
Not subject to a master netting agreement or similar arrangement:
 
 
 
Commodity derivative:
 
 
 
Oil and Gas - Crude Basis Swaps
1,431


1,431

Oil and Gas - Crude Options
425


425

Oil and Gas - Natural Gas Basis Swaps
2,066


2,066

Utilities



Total derivative assets not subject to a master netting agreement or similar arrangement
3,922


3,922

 
 
 
 
Total derivative assets
$
1,490

$
15,740

$
17,230


37




 
As of Sept. 30, 2012
Derivative Liabilities
Gross Amounts of Derivative Liabilities
Gross Amounts Offset on Condensed Consolidated Balance Sheets
Net Amount of Total Derivative Liabilities on Condensed Consolidated Balance Sheets
 
(in thousands)
Subject to a master netting agreement or similar arrangement:
 
 
 
Commodity derivative:
 
 
 
Oil and Gas - Crude Basis Swaps
$

$

$

Oil and Gas - Crude Options



Oil and Gas - Natural Gas Basis Swaps



Utilities
4,527


4,527

Interest Rate Swaps



Total derivative liabilities subject to a master netting agreement or similar arrangement
4,527


4,527

 
 
 
 
Not subject to a master netting agreement or similar arrangement:
 
 
 
Commodity derivative:
 
 
 
Oil and Gas - Crude Basis Swaps
56


56

Oil and Gas - Crude Options
885


885

Oil and Gas - Natural Gas Basis Swaps
1,181


1,181

Utilities



Interest Rate Swaps
124,580

(3,310
)
121,270

Total derivative liabilities not subject to a master netting agreement or similar arrangement
126,702

(3,310
)
123,392

 
 
 
 
Total derivative liabilities
$
131,229

$
(3,310
)
$
127,919



38



Derivative assets and derivative liabilities and collateral held by counterparty included in our Condensed Consolidated Balance Sheets were (in thousands):

 
 
As of Sept. 30, 2013
 
 
 
Gross Amounts Not Offset on Condensed Consolidated Balance Sheets
 
Contract Type
 
Net Amount of Total Derivative Assets
Cash Collateral Received
Net Amount with Counterparty
Asset:
 
 
 
 
Oil and Gas
Counterparty A
$

$

$

Oil and Gas
Counterparty B
126


126

Utilities
Counterparty A



 
 
$
126

$

$
126


 
 
As of Sept. 30, 2013
 
 
 
Gross Amounts Not Offset on Condensed Consolidated Balance Sheets
 
Contract Type
 
Net Amount of Total Derivative Liabilities
Cash Collateral Posted
Net Amount with Counterparty
Liabilities
 
 
 
 
Oil and Gas
Counterparty A
$

$
(355
)
$
(355
)
Oil and Gas
Counterparty B
150


150

Utilities
Counterparty A

(3,333
)
(3,333
)
Interest Rate Swap
Counterparty D
3,563


3,563

Interest Rate Swap
Counterparty E
19,993


19,993

Interest Rate Swap
Counterparty F
9,858


9,858

Interest Rate Swap
Counterparty G
20,138


20,138

Interest Rate Swap
Counterparty H
8,857


8,857

Interest Rate Swap
Counterparty I
14,773


14,773

 
 
$
77,332

$
(3,688
)
$
73,644


39




 
 
As of Dec. 31, 2012
 
 
 
Gross Amounts Not Offset on Condensed Consolidated Balance Sheets
 
Contract Type
 
Net Amount of Total Derivative Assets
Cash Collateral Received
Net Amount with Counterparty
Assets:
 
 
 
 
Oil and Gas
Counterparty A
$
341

$

$
341

Oil and Gas
Counterparty B
3,362


3,362

Utilities
Counterparty A
43


43

 
 
$
3,746

$

$
3,746


 
 
As of Dec. 31, 2012
 
 
 
Gross Amounts Not Offset on Condensed Consolidated Balance Sheets
 
Contract Type
 
Net Amount of Total Derivative Liabilities
Cash Collateral Posted
Net Amount with Counterparty
Liabilities:
 
 
 
 
Oil and Gas
Counterparty A
$

$
(1,787
)
$
(1,787
)
Oil and Gas
Counterparty B
1,354


1,354

Utilities
Counterparty A

(4,354
)
(4,354
)
Interest Rate Swap
Counterparty D
4,588


4,588

Interest Rate Swap
Counterparty E
29,245


29,245

Interest Rate Swap
Counterparty F
12,721


12,721

Interest Rate Swap
Counterparty G
26,520


26,520

Interest Rate Swap
Counterparty H
16,809


16,809

Interest Rate Swap
Counterparty I
22,245


22,245

 
 
$
113,482

$
(6,141
)
$
107,341


40




 
 
As of Sept. 30, 2012
 
 
 
Gross Amounts Not Offset on Condensed Consolidated Balance Sheets
 
Contract Type
 
Net Amount of Total Derivative Assets
Cash Collateral Received
Net Amount with Counterparty
Assets:
 
 
 
 
Oil and Gas
Counterparty A
$
294

$
(2,414
)
$
(2,120
)
Oil and Gas
Counterparty B
3,922


3,922

Utilities
Counterparty A
13,014


13,014

 
 
$
17,230

$
(2,414
)
$
14,816


 
 
As of Sept. 30, 2012
 
 
 
Gross Amounts Not Offset on Condensed Consolidated Balance Sheets
 
Contract Type
 
Net Amount of Total Derivative Liabilities
Cash Collateral Posted
Net Amount with Counterparty
Liabilities:
 
 
 
 
Oil and Gas
Counterparty A
$

$

$

Oil and Gas
Counterparty B
2,122


2,122

Utilities
Counterparty A
4,527


4,527

Interest Rate Swap
Counterparty D
4,903


4,903

Interest Rate Swap
Counterparty E
31,147


31,147

Interest Rate Swap
Counterparty F
13,554


13,554

Interest Rate Swap
Counterparty G
27,610


27,610

Interest Rate Swap
Counterparty H
20,331


20,331

Interest Rate Swap
Counterparty I
23,725


23,725

 
 
$
127,919

$

$
127,919


A description of our derivative activities is included in Note 10. The following tables present the impact that derivatives had on our Condensed Consolidated Statements of Income (Loss).


41



Cash Flow Hedges

The impacts of cash flow hedges on our Condensed Consolidated Statements of Income (Loss) were as follows (in thousands):
Three Months Ended Sept. 30, 2013
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
 
$
(907
)
 
Interest expense
 
$
(1,844
)
 
 
 
$

Commodity derivatives
 
(2,140
)
 
Revenue
 
(168
)
 
 
 

Total
 
$
(3,047
)
 
 
 
$
(2,012
)
 
 
 
$


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
)
 
 
 
$


Nine Months Ended Sept. 30, 2013
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
 
$
141

 
Interest expense
 
$
(5,460
)
 
 
 
$

Commodity derivatives
 
86

 
Revenue
 
896

 
 
 

Total
 
$
227

 
 
 
$
(4,564
)
 
 
 
$


42




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

 
 
 
$


Derivatives Not Designated as Hedge Instruments

The impacts of derivative instruments not designated as hedge instruments on our Condensed Consolidated Statements of Income (Loss) were as follows (in thousands):
 
 
 
 
Three Months Ended
 
Nine Months Ended
 
 
 
 
Sept. 30, 2013
 
Sept. 30, 2013
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
 
$
3,144

 
$
29,393

Interest rate swaps - realized
 
Interest expense
 
(3,300
)
 
(10,056
)
 
 
 
 
$
(156
)
 
$
19,337


 
 
 
 
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
)



43



(12)    FAIR VALUE OF FINANCIAL INSTRUMENTS

The estimated fair values of our financial instruments, excluding derivatives which are presented in Note 11, were as follows (in thousands) as of:
 
Sept. 30, 2013
 
Dec. 31, 2012
 
Sept. 30, 2012
 
Carrying
Amount
Fair Value
 
Carrying
Amount
Fair Value
 
Carrying
Amount
Fair Value
Cash and cash equivalents (a)
$
13,637

$
13,637

 
$
15,462

$
15,462

 
$
247,192

$
247,192

Restricted cash and equivalents (a)
$
6,782

$
6,782

 
$
7,916

$
7,916

 
$
7,302

$
7,302

Notes receivable included in Other current assets(a)
$

$

 
$

$

 
$
21,832

$
21,832

Notes payable (a)
$
138,300

$
138,300

 
$
277,000

$
277,000

 
$
225,000

$
225,000

Long-term debt, including current maturities (b)
$
1,211,673

$
1,325,729

 
$
1,042,850

$
1,231,559

 
$
1,271,260

$
1,471,932

__________
(a)
Carrying value approximates fair 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)
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.


(13)    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 2012 Annual Report on Form 10-K except for those described below.

The following purchase power and power sales agreements were renewed during 2013:

Cheyenne Light renewed and received FERC approval for an agreement with Basin Electric whereby Cheyenne Light will receive 40 megawatts of capacity and energy from Basin Electric through Sept. 30, 2014.

Cheyenne Light renewed and received FERC approval for an agreement with Basin Electric whereby Cheyenne Light will provide 40 megawatts of capacity and energy to Basin Electric through Sept. 30, 2014.

Purchase and Sale Agreement

On May 6, 2013, Black Hills Wyoming entered into an agreement to sell its 40 megawatt CTII natural gas-fired generating unit to the City of Gillette, Wyo. for approximately $22 million, subject to closing adjustments. The sale is expected to close in August 2014 upon the expiration of an existing power sales agreement with Cheyenne Light under which Black Hills Wyoming sells the output of the CTII to Cheyenne Light. The sale is subject to FERC approval and certain other requirements included in the contract.


44



Other Commitments

Construction of Cheyenne Prairie, a 132 megawatt natural gas-fired electric generating facility jointly owned by Cheyenne Light and Black Hills Power is expected to cost approximately $222 million. Construction is expected to be completed by Sept. 30, 2014. As of Sept. 30, 2013, committed contracts for equipment purchases and for construction were 94 percent and 67 percent complete, respectively.

Oil Creek Fire

On June 29, 2012, a forest and grassland fire occurred in the western Black Hills. Black Hills Power subsequently received written damage claims from the State of Wyoming and one landowner seeking recovery for alleged injury to timber, grass, fencing, fire suppression and rehabilitation costs of approximately $8 million. On April 16, 2013, thirty-four private landowners filed suit in United States District Court for the District of Wyoming, asserting similar claims, based upon allegations of negligence, common law nuisance and trespass. The suit seeks recovery of both actual and punitive damages in an unspecified amount. Our investigation into the cause and origin of the fire is pending. We expect to deny and will vigorously defend all claims arising out of the lawsuit, pending the completion of our investigation. Given the uncertainty of litigation, however, a loss related to the fire and the litigation is reasonably possible. We cannot reasonably estimate the amount of a potential loss because our investigation is ongoing. Further claims may be presented by other parties. We cannot predict the outcome of our investigation, the viability of alleged claims or the outcome of the litigation. Based on information currently available, however, management does not expect the claims, if determined adversely to us, to have a material adverse effect on our financial condition or results of operations.

Sale of Enserco Energy Inc.

After the sale of Enserco, our Energy Marketing segment, on Feb. 29, 2012, and pursuant to the provisions of the Stock Purchase Agreement, the buyer requested purchase price adjustments, which we disputed. The buyer filed a petition in the Colorado District Court for the City and County of Denver, Colo., seeking an order compelling binding arbitration on all of the disputed claims. Following a hearing in July 2013, the court entered an order remanding all but one of the disputed adjustment claims to arbitration. We continue to dispute the validity of the adjustment claims within the arbitration process, which we expect will conclude before the end of 2013.


45



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, 2013, 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, 2013:

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, 2013, the restricted net assets at our Utilities Group were approximately $148.6 million.

As required by a covenant in the Black Hills Wyoming project financing, Black Hills Non-regulated Holdings has maintained restricted shareholders’ equity of at least $100 million.

Guarantees

As of Dec. 31, 2012, the Company had provided a guarantee for up to $33.3 million for Colorado Electric’s performance and payment obligations relating to the purchase of wind turbines for the Colorado Electric Busch Ranch project completed in 2012. The guarantee expired March 29, 2013, upon fulfillment of all contractual obligations.

A guarantee of $7.5 million to Cross Timbers Energy Services for the performance and payment obligation of Black Hills Utility Holdings for natural gas supply purchases expired on June 30, 2013, and was converted to a letter of credit for $5 million as a replacement to this guarantee.


(14)    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. An effective date of July 1, 2012, was used to determine the sales price.

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 Williston Basin asset sale significantly altered the relationship and accordingly we 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 temporarily decreased the depreciation, depletion and amortization rate.


46


Net cash proceeds, subsequent to the true-up of all post-closing adjustments, were as follows (in thousands):
Cash proceeds received on date of sale
$
243,314

 
 
Adjustments to proceeds:
 
Final post close adjustments
2,793

Transaction adviser fees
(1,400
)
Payment for contractual obligation related to "back-in" fee *
(16,847
)
 
 
Final net cash proceeds
$
227,860

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

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 million. Colorado Electric retains the remaining undivided interest and is the operator of this jointly owned facility. Commercial operation of the newly constructed wind farm was achieved on Oct. 16, 2012.


(15)    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 during the second quarter of 2012, we recorded a $26.9 million non-cash impairment of oil and gas assets included in our Oil and Gas segment as of Sept. 30, 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.


47



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

Our Utilities Group consists of our Electric and Gas Utilities segments. Our Electric Utilities segment generates, transmits and distributes electricity to approximately 202,000 customers in South Dakota, Wyoming, Colorado and Montana; and also distributes natural gas to approximately 35,000 Cheyenne Light customers in Wyoming. Our Gas Utilities serve approximately 532,000 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 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 while the normal peak usage season for gas utilities is November through March. 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, 2013 and 2012, and our financial condition as of Sept. 30, 2013, Dec. 31, 2012, and Sept. 30, 2012, 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 82.

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. As a result of the sale of Enserco on Feb. 29, 2012, the reportable segment previously reported as Energy Marketing is classified as discontinued operations.


48



Results of Operations

Executive Summary, Significant Events and Overview

Three Months Ended Sept. 30, 2013 Compared to Three Months Ended Sept. 30, 2012. Income from continuing operations for the three months ended Sept. 30, 2013 was $23.1 million, or $0.52 per share, compared to Income from continuing operations of $34.6 million, or $0.78 per share, reported for the same period in 2012. Net income for the three months ended Sept. 30, 2013 was $23.1 million, or $0.52 per share, compared to Net income of $34.5 million, or $0.78 per share, for the same period in 2012.

Nine Months Ended Sept. 30, 2013 Compared to Nine Months Ended Sept. 30, 2012. Income from continuing operations for the nine months ended Sept. 30, 2013 was $96.8 million, or $2.18 per share, compared to Income from continuing operations of $57.6 million, or $1.31 per share, reported for the same period in 2012. Net income for the nine months ended Sept. 30, 2013 was $96.8 million, or $2.18 per share, compared to Net income of $50.8 million, or $1.15 per share, for the same period in 2012.

The following table summarizes select financial results by operating segment and details significant items (in thousands):
 
Three Months Ended Sept. 30,
Nine Months Ended Sept. 30,
 
2013
2012
Variance
2013
2012
Variance
Revenue
 
 
 
 
 
 
Utilities
$
239,196

$
218,452

$
20,744

$
865,506

$
778,263

$
87,243

Non-regulated Energy
51,711

60,354

(8,643
)
147,255

169,097

(21,842
)
Intercompany eliminations
(31,000
)
(31,998
)
998

(92,357
)
(92,338
)
(19
)
 
$
259,907

$
246,808

$
13,099

$
920,404

$
855,022

$
65,382

 
 
 
 
 
 
 
Net income (loss)
 
 
 
 
 
 
Electric Utilities
$
15,097

$
14,573

$
524

$
38,063

$
37,478

$
585

Gas Utilities
(1,450
)
3

(1,453
)
20,225

16,369

3,856

Utilities
13,647

14,576

(929
)
58,288

53,847

4,441

 
 
 
 
 
 
 
Power Generation
6,707

5,128

1,579

17,382

15,968

1,414

Coal Mining
2,142

1,690

452

5,180

3,924

1,256

Oil and Gas (a)
(1,682
)
17,389

(19,071
)
(3,699
)
(2,219
)
(1,480
)
Non-regulated Energy
7,167

24,207

(17,040
)
18,863

17,673

1,190

 
 
 
 
 
 
 
Corporate activities and eliminations (b)(c)
2,310

(4,160
)
6,470

19,688

(13,949
)
33,637

 
 
 
 
 
 
 
Income (loss) from continuing operations
23,124

34,623

(11,499
)
96,839

57,571

39,268

 
 
 
 
 
 
 
Income (loss) from discontinued operations, net of tax

(166
)
166


(6,810
)
6,810

Net income (loss)
$
23,124

$
34,457

$
(11,333
)
$
96,839

$
50,761

$
46,078

(a)
Income (loss) from continuing operations for the three months and nine months ended Sept. 30, 2012 includes an after-tax gain of $17.7 million relating to the sale of the Williston Basin assets. Income (loss) from continuing operations for nine months ended Sept. 30, 2012 includes a $17.3 million non-cash after-tax ceiling test impairment. See Notes 14 and 15 of the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.
(b)
Corporate activities include a $2.0 million and a $19.1 million net after-tax non-cash mark-to-market gain on certain interest rate swaps for the three and nine months ended Sept. 30, 2013, respectively, and a $0.4 million net after-tax non-cash mark-to-market gain and a $1.9 million net after-tax non-cash mark-to-market loss for the three and nine months ended Sept. 30, 2012, respectively, for those same interest rate swaps.
(c)
Certain indirect corporate costs and inter-segment interest expenses after-tax totaling $1.6 million for the nine months ended Sept. 30, 2012 were included in the Corporate activities in continuing operations and were not reclassified as discontinued operations.


49



Overview of Business Segments and Corporate Activity

Utilities Group

On Sept. 17, 2013, the SDPUC approved a construction financing rider for the South Dakota portion of costs for Cheyenne Prairie in lieu of the typical AFUDC, with an effective date of April 1, 2013. The WPSC approved a similar construction financing rider for our Wyoming customers during 2012. The riders allow Black Hills Power and Cheyenne Light to recover financing costs during the construction period, while reducing the overall capital costs of the project. The Electric Utilities recorded additional gross margins of approximately $2.7 million and $5.0 million for the three and nine months ended Sept. 30, 2013, respectively, relating to these riders.

On Sept. 17, 2013, the SDPUC approved an annual rate increase of $8.8 million, or 6.4 percent, effective June 16, 2013 for Black Hills Power.

Construction and infrastructure work for Cheyenne Prairie, a natural gas-fired electric generating facility to serve Cheyenne Light and Black Hills Power customers, began in April 2013. The 132 megawatt generation project is expected to cost approximately $222 million, exclusive of construction financing costs which will be recovered through the construction financing riders. Project to date, we have expended approximately $122 million. The project is on schedule to be placed into service in the fourth quarter of 2014.

Gas Utilities results were favorably impacted by colder weather during 2013. Heating degree days were 33 percent higher for the nine months ended Sept. 30, 2013, compared to the same periods in 2012. Heating degree days for the nine months ended Sept. 30, 2013 were 8 percent higher than normal, compared to 21 percent lower than normal for the same periods in 2012.

On April 30, 2013, Colorado Electric filed its electric resource plan with the CPUC, addressing its projected resource requirements through 2019. The resource plan identifies a 40 megawatt, simple-cycle, natural gas-fired turbine as the replacement capacity for the retirement of the coal-fired, 42 megawatt W.N. Clark power plant. A CPCN was submitted with the CPUC requesting approval for the new generating capacity. The resource plan also recommends the retirement of Pueblo Units 5 and 6 as of Dec. 31, 2013. A CPCN was submitted to the CPUC seeking approval to retire these plants. A hearing with the CPUC is scheduled in November 2013 regarding the resource plan and the two CPCNs.

On Oct. 16, the CPUC denied Colorado Electric's application for approval of a wind solicitation for the acquisition of up to 30 megawatts of wind energy for its electric system. This solicitation and related requests for proposal were reviewed by an independent evaluator who verified that our Power Generation segment's bid was the lowest cost to customers. The CPUC found that the calculated customer benefits over the 20 year evaluation period were insufficient for all of the bids and stated its preference to consider renewable energy needs in Colorado Electric's upcoming Electric Resource Plan hearings scheduled for November 2013.

Gas Utilities continued its efforts to acquire small municipal gas distribution systems adjacent to our existing Gas Utility service territories. Four small gas systems have been acquired in 2013, adding approximately 900 customers.


50



Non-regulated Energy Group

Black Hills Wyoming entered into an agreement to sell its 40 megawatt CTII natural gas-fired generating unit to the City of Gillette, Wyo. for approximately $22 million, subject to closing adjustments. The sale is expected to close in August 2014 upon the expiration of an existing power sales agreement with Cheyenne Light. The sale is subject to FERC approval and certain other requirements included in the contract.

Oil and Gas reported a 32 percent and 31 percent reduction in total volumes sold for the three and nine months ended Sept. 30, 2013, respectively, reflecting the 2012 sale of the Williston Basin oil and gas assets. Oil and Gas results benefited from a 6 percent and 13 percent increase in average hedge price received for crude oil during the three and nine months ended Sept. 30, 2013, respectively, compared to the same periods in 2012, partially offset by an 8 percent and 18 percent decrease in average hedge price received for natural gas for those same periods.

Oil and Gas drilled two horizontal wells in the Mancos Shale formation in the Piceance Basin. We commenced completion operations and expect both wells to be completed and producing prior to year-end. The wells are part of a transaction in which we will earn approximately 20,000 net acres of Mancos Shale leasehold in the Piceance Basin in exchange for drilling and completing the two wells.

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 commodity prices.
Corporate Activities

On Sept. 25, 2013, Moody’s raised our corporate credit rating to Baa2 from Baa3 with continued positive outlook. On July 24, 2013, S&P raised our corporate credit rating to BBB from BBB- with a stable outlook. They also raised our senior unsecured rating to BBB from BBB-. On May 10, Fitch Ratings raised our Issuer Default Rating to BBB from BBB- with a positive outlook.

On June 21, 2013, we entered into a new $275 million term loan expiring on June 19, 2015. The proceeds from this new term loan repaid the $150 million term loan due on June 24, 2013, the $100 million corporate term loan due on Sept. 30, 2013, and $25 million in short-term borrowing under our Revolving Credit Facility.

Consolidated interest expense decreased by approximately $3.6 million and $14.3 million for the three and nine months ended Sept. 30, 2013, respectively, due primarily to the repayment of approximately $225 million of debt in 2012.

We recognized a non-cash unrealized mark-to-market gain (loss) related to certain interest rate swaps of $29.4 million and $(2.9) million for the nine months ended Sept. 30, 2013 and 2012, respectively.

Operating Results

A discussion of operating results from our segments and Corporate activities follows.



51



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.

Non-GAAP Financial Measure
The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, gross margin, that is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Gross margin (revenue less cost of sales) is a non-GAAP financial measure due to the exclusion of depreciation from the measure. The presentation of gross margin is intended to supplement investors’ understanding of our operating performance.

Gross margin for our Electric Utilities is calculated as operating revenue less cost of fuel, purchased power and cost of gas sold. Gross margin for our Gas Utilities is calculated as operating revenues less cost of gas sold. Our gross margin is impacted by the fluctuations in power purchases and natural gas and other fuel supply costs. However, while these fluctuating costs impact gross margin as a percentage of revenue, they only impact total gross margin if the costs cannot be passed through to our customers.

Our gross margin measure may not be comparable to other companies’ gross margin measure. Furthermore, this measure is not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.



52



Electric Utilities
 
Three Months Ended Sept. 30,
Nine Months Ended Sept. 30,
 
2013
2012
Variance
2013
2012
Variance
 
(in thousands)
Revenue — electric
$
167,152

$
151,465

$
15,687

$
469,300

$
442,731

$
26,569

Revenue — gas
4,252

3,552

700

22,766

21,189

1,577

Total revenue
171,404

155,017

16,387

492,066

463,920

28,146

 
 
 
 
 
 
 
Fuel, purchased power and cost of gas — electric
70,859

65,992

4,867

203,897

191,113

12,784

Purchased gas — gas
1,579

1,046

533

10,532

11,087

(555
)
Total fuel, purchased power and cost of gas
72,438

67,038

5,400

214,429

202,200

12,229

 
 
 
 
 
 
 
Gross margin — electric
96,293

85,473

10,820

265,403

251,618

13,785

Gross margin — gas
2,673

2,506

167

12,234

10,102

2,132

Total gross margin
98,966

87,979

10,987

277,637

261,720

15,917

 
 
 
 
 
 
 
Operations and maintenance
41,145

34,080

7,065

119,363

110,176

9,187

Depreciation and amortization
19,368

18,821

547

58,194

56,448

1,746

Total operating expenses
60,513

52,901

7,612

177,557

166,624

10,933

 
 
 
 
 
 
 
Operating income
38,453

35,078

3,375

100,080

95,096

4,984

 
 
 
 
 
 
 
Interest expense, net
(14,089
)
(12,527
)
(1,562
)
(42,296
)
(38,069
)
(4,227
)
Other income (expense), net
13

198

(185
)
471

1,207

(736
)
Income tax benefit (expense)
(9,280
)
(8,176
)
(1,104
)
(20,192
)
(20,756
)
564

Income (loss) from continuing operations
$
15,097

$
14,573

$
524

$
38,063

$
37,478

$
585



53



 
Three Months Ended Sept. 30,
 
Nine Months Ended Sept. 30,
Revenue - Electric (in thousands)
2013
 
2012
 
2013
 
2012
Residential:
 
 
 
 
 
 
 
Black Hills Power
$
16,951

 
$
15,794

 
$
46,928

 
$
43,903

Cheyenne Light
8,816

 
8,324

 
26,453

 
23,816

Colorado Electric
27,438

 
26,390

 
73,388

 
70,048

Total Residential
53,205

 
50,508

 
146,769

 
137,767

 
 
 
 
 
 
 
 
Commercial:
 
 
 
 
 
 
 
Black Hills Power
23,319

 
20,336

 
59,716

 
55,948

Cheyenne Light
14,738

 
13,003

 
41,981

 
42,346

Colorado Electric
23,531

 
20,898

 
66,345

 
61,595

Total Commercial
61,588

 
54,237

 
168,042

 
159,889

 
 
 
 
 
 
 
 
Industrial:
 
 
 
 
 
 
 
Black Hills Power
6,850

 
5,846

 
20,070

 
18,929

Cheyenne Light
5,522

 
4,551

 
15,721

 
10,863

Colorado Electric
9,872

 
8,476

 
29,156

 
27,689

Total Industrial
22,244

 
18,873

 
64,947

 
57,481

 
 
 
 
 
 
 
 
Municipal:
 
 
 
 
 
 
 
Black Hills Power
1,078

 
930

 
2,639

 
2,515

Cheyenne Light
499

 
454

 
1,447

 
1,352

Colorado Electric
4,018

 
3,419

 
10,057

 
10,031

Total Municipal
5,595

 
4,803

 
14,143

 
13,898

 
 
 
 
 
 
 
 
Total Retail Revenue - Electric
142,632

 
128,421

 
393,901

 
369,035

 
 
 
 
 
 
 
 
Contract Wholesale:
 
 
 
 
 
 
 
Total Contract Wholesale - Black Hills Power
5,847

 
5,627

 
16,540

 
14,902

 
 
 
 
 
 
 
 
Off-system Wholesale:
 
 
 
 
 
 
 
Black Hills Power
8,123

 
5,599

 
22,222

 
23,331

Cheyenne Light
1,603

 
1,532

 
6,379

 
6,012

Colorado Electric
2,035

 
1,663

 
5,275

 
2,073

Total Off-system Wholesale
11,761

 
8,794

 
33,876

 
31,416

 
 
 
 
 
 
 
 
Other Revenue:
 
 
 
 
 
 
 
Black Hills Power
5,100

 
7,002

 
19,802

 
22,248

Cheyenne Light
594

 
624

 
1,642

 
1,663

Colorado Electric
1,218

 
997

 
3,539

 
3,467

Total Other Revenue
6,912

 
8,623

 
24,983

 
27,378

 
 
 
 
 
 
 
 
Total Revenue - Electric
$
167,152

 
$
151,465

 
$
469,300

 
$
442,731



54



 
Three Months Ended
Sept. 30,
 
Nine Months Ended
Sept. 30,
Quantities Generated and Purchased (in MWh)
2013
 
2012
 
2013
 
2012
Generated —
 
 
 
 
 
 
 
Coal-fired:
 
 
 
 
 
 
 
Black Hills Power (a)
457,329

 
475,752

 
1,334,441

 
1,344,593

Cheyenne Light (b)
185,603

 
155,099

 
513,299

 
436,576

Colorado Electric (c)

 
61,820

 

 
177,712

Total Coal-fired
642,932

 
692,671

 
1,847,740

 
1,958,881

 
 
 
 
 
 
 
 
Gas, Oil and Wind:
 
 
 
 
 
 
 
Black Hills Power
18,275

 
21,543

 
25,953

 
28,122

Cheyenne Light

 

 

 

Colorado Electric (d)
74,631

 
50,691

 
236,227

 
72,271

Total Gas, Oil and Wind
92,906

 
72,234

 
262,180

 
100,393

 
 
 
 
 
 
 
 
Total Generated:
 
 
 
 
 
 
 
Black Hills Power
475,604

 
497,295

 
1,360,394

 
1,372,715

Cheyenne Light
185,603

 
155,099

 
513,299

 
436,576

Colorado Electric
74,631

 
112,511

 
236,227

 
249,983

Total Generated
735,838

 
764,905

 
2,109,920

 
2,059,274

 
 
 
 
 
 
 
 
Purchased —
 
 
 
 
 
 
 
Black Hills Power
361,390

 
280,815

 
1,098,772

 
1,228,072

Cheyenne Light
180,127

 
191,884

 
586,999

 
604,911

Colorado Electric
534,830

 
488,321

 
1,402,005

 
1,298,690

Total Purchased
1,076,347

 
961,020

 
3,087,776

 
3,131,673

 
 
 
 
 
 
 
 
Total Generated and Purchased:
 
 
 
 
 
 
 
Black Hills Power
836,994

 
778,110

 
2,459,166

 
2,600,787

Cheyenne Light
365,730

 
346,983

 
1,100,298

 
1,041,487

Colorado Electric
609,461

 
600,832

 
1,638,232

 
1,548,673

Total Generated and Purchased
1,812,185

 
1,725,925

 
5,197,696

 
5,190,947

__________
(a)
Megawatt hours generated for the three and nine months ended Sept. 30, 2013, were impacted by the suspension of operations at Ben French as of Aug. 31, 2012, while megawatt hours generated for the three months ended Sept. 30, 2012 were impacted by plant outages at Neil Simpson II and Wygen III.
(b)
Results for the three and nine months ended Sept. 30, 2012 reflect a planned and extended overhaul at Wygen II.
(c)
Decrease was primarily due to the suspension of operations at W.N. Clark as of Dec. 31, 2012.
(d)
Increase was primarily due to the addition of energy from the Busch Ranch wind project, which was placed into commercial operation in the fourth quarter of 2012 and higher usage of our gas-fired generation at the Pueblo Airport Generating Facility as a result of the suspension of operations at W.N. Clark as of Dec. 31, 2012 and a decrease in the amount of economy energy available to purchase from third parties.

55



 
Three Months Ended Sept. 30,
 
Nine Months Ended Sept. 30,
Quantity Sold (in MWh)
2013
2012
 
2013
2012
Residential:
 
 
 
 
 
Black Hills Power
131,664

139,282

 
406,159

396,267

Cheyenne Light
66,278

68,816

 
202,403

197,093

Colorado Electric
178,187

185,696

 
474,378

476,425

Total Residential
376,129

393,794

 
1,082,940

1,069,785

 
 
 
 
 
 
Commercial:
 
 
 
 
 
Black Hills Power
201,332

202,418

 
551,712

553,792

Cheyenne Light
136,062

141,433

 
397,705

449,718

Colorado Electric
187,770

198,839

 
538,815

548,964

Total Commercial
525,164

542,690

 
1,488,232

1,552,474

 
 
 
 
 
 
Industrial:
 
 
 
 
 
Black Hills Power
98,174

93,147

 
295,662

303,906

Cheyenne Light
74,316

62,397

 
209,984

151,326

Colorado Electric
102,156

89,305

 
273,572

267,739

Total Industrial
274,646

244,849

 
779,218

722,971

 
 
 
 
 
 
Municipal:
 
 
 
 
 
Black Hills Power
10,691

11,154

 
26,621

27,565

Cheyenne Light
2,412

2,318

 
7,150

7,028

Colorado Electric
38,749

35,461

 
85,844

95,649

Total Municipal
51,852

48,933

 
119,615

130,242

 
 
 
 
 
 
Total Retail Quantity Sold
1,227,791

1,230,266

 
3,470,005

3,475,472

 
 
 
 
 
 
Contract Wholesale:
 
 
 
 
 
Total Contract Wholesale - Black Hills Power
87,092

88,334

 
268,529

249,388

 
 
 
 
 
 
Off-system Wholesale:
 
 
 
 
 
Black Hills Power
261,567

190,143

 
777,854

943,522

Cheyenne Light
47,120

46,157

 
178,942

166,777

Colorado Electric
63,529

52,228

 
133,544

60,899

Total Off-system Wholesale
372,216

288,528

 
1,090,340

1,171,198

 
 
 
 
 
 
Total Quantity Sold:
 
 
 
 
 
Black Hills Power
790,520

724,478

 
2,326,537

2,474,440

Cheyenne Light
326,188

321,121

 
996,184

971,942

Colorado Electric
570,391

561,529

 
1,506,153

1,449,676

Total Quantity Sold
1,687,099

1,607,128

 
4,828,874

4,896,058

 
 
 
 
 
 
Losses and Company Use:
 
 
 
 
 
Black Hills Power
46,474

53,632

 
132,629

126,347

Cheyenne Light
39,542

25,863

 
104,114

69,545

Colorado Electric
39,070

39,302

 
132,079

98,997

Total Losses and Company Use
125,086

118,797

 
368,822

294,889

 
 
 
 
 
 
Total Quantity Sold
1,812,185

1,725,925

 
5,197,696

5,190,947




56



 
Three Months Ended Sept. 30,
Degree Days
2013
 
2012
 
Actual
 
Variance from
30-Year Average
 
Actual
 
Variance from
30-Year Average
Heating Degree Days:
 
 
 
 
 
 
 
Black Hills Power
107

 
(49
)%
 
99

 
(56
)%
Cheyenne Light
182

 
(36
)%
 
170

 
(40
)%
Colorado Electric
25

 
(71
)%
 
54

 
(45
)%
 
 
 
 
 
 
 
 
Cooling Degree Days:
 
 
 
 
 
 
 
Black Hills Power
646

 
15
 %
 
731

 
37
 %
Cheyenne Light
397

 
32
 %
 
430

 
44
 %
Colorado Electric
851

 
17
 %
 
898

 
31
 %

 
Nine Months Ended Sept. 30,
Degree Days
2013
 
2012
 
Actual
 
Variance from
30-Year Average
 
Actual
 
Variance from
30-Year Average
Heating Degree Days:
 
 
 
 
 
 
 
Black Hills Power
4,544

 
6
%
 
3,558

 
(50
)%
Cheyenne Light
4,665

 
4
%
 
3,772

 
(47
)%
Colorado Electric
3,527

 
2
%
 
2,753

 
(51
)%
 
 
 
 
 
 
 
 
Cooling Degree Days:
 
 
 
 
 
 
 
Black Hills Power
724

 
8
%
 
937

 
47
 %
Cheyenne Light
520

 
48
%
 
568

 
63
 %
Colorado Electric
1,227

 
28
%
 
1,321

 
47
 %
Electric Utilities Power Plant Availability
Three Months Ended Sept. 30,
Nine Months Ended Sept. 30,
 
 
2013
2012
2013
 
2012
 
Coal-fired plants 
97.6
%
 
95.4
%
 
96.8
%
 
89.1
%
(a) 
Other plants
95.8
%
 
98.5
%
 
96.7
%
 
96.6
%
 
Total availability
96.7
%
 
97.0
%
 
96.7
%
 
93.0
%
 
__________
(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.


57




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,
 
2013
 
2012
 
2013
 
2012
Revenue - Gas (in thousands):
 
 
 
 
 
 
 
Residential
$
2,719

 
$
2,362

 
$
14,284

 
$
12,947

Commercial
977

 
770

 
6,107

 
5,789

Industrial
356

 
248

 
1,759

 
1,882

Other Sales Revenue
200

 
172

 
616

 
571

Total Revenue - Gas
$
4,252

 
$
3,552

 
$
22,766

 
$
21,189

 
 
 
 
 
 
 
 
Gross Margin (in thousands):
 
 
 
 
 
 
 
Residential
$
1,977

 
$
1,864

 
$
8,611

 
$
7,092

Commercial
423

 
417

 
2,663

 
2,141

Industrial
73

 
53

 
344

 
302

Other Gross Margin
200

 
172

 
616

 
567

Total Gross Margin
$
2,673

 
$
2,506

 
$
12,234

 
$
10,102

 
 
 
 
 
 
 
 
Volumes Sold (Dth):
 
 
 
 
 
 
 
Residential
172,136

 
168,229

 
1,757,397

 
1,453,478

Commercial
128,320

 
119,344

 
1,033,171

 
918,131

Industrial
66,027

 
64,721

 
430,186

 
411,664

Total Volumes Sold
366,483

 
352,294

 
3,220,754

 
2,783,273



58



Results of Operations for the Electric Utilities for the Three Months Ended Sept. 30, 2013 Compared to the Three Months Ended Sept. 30, 2012: Income from continuing operations for the Electric Utilities was $15.1 million for the three months ended Sept. 30, 2013, compared to $14.6 million for the three months ended Sept. 30, 2012, as a result of:

Gross margin increased primarily due to a $2.4 million increase from higher electric rates, a $2.7 million increase related to the Cheyenne Prairie construction financing riders, a $1.0 million increase as a result of energy cost adjustments, a $0.5 million increase from wholesale quantities sold, and a $0.7 million increase from transmission riders.

Operations and maintenance increased primarily due to an increase in property taxes, vegetation management and employee compensation and benefit costs. The 2012 period included a $2.1 million reduction for major maintenance accruals relating to plant suspensions and retirements.

Depreciation and amortization increased primarily due to a higher asset base.

Interest expense, net increased primarily due to an increase in debt balances and lower AFUDC.

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

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

Results of Operations for the Electric Utilities for the Nine Months Ended Sept. 30, 2013 Compared to the Nine Months Ended Sept. 30, 2012: Income from continuing operations for the Electric Utilities was $38.1 million for the nine months ended Sept. 30, 2013, compared to $37.5 million for the nine months ended Sept. 30, 2012, as a result of:

Gross margin increased primarily due to a $3.9 million increase from higher electric rates, a $5.0 million increase related to the Cheyenne Prairie construction financing riders, a $1.9 million increase from transmission riders, a $1.2 million increase from wholesale quantities sold, a $1.0 million increase in gas demand from colder weather, and a $1.0 million increase in gas rates, partially offset by a $0.5 million decrease related to lower electric retail quantities sold and a $0.5 million decrease from off-system sales as a result of lower pricing and quantities sold.

Operations and maintenance increased primarily due to an increase in property taxes, vegetation management and increased employee compensation and benefit costs. Prior year included a $2.1 million reduction for major maintenance accruals relating to plant suspensions and retirements.

Depreciation and amortization increased primarily due to an increased asset base.

Interest expense, net increased primarily due to an increase in debt balances and lower AFUDC.

Other income (expense), net included higher AFUDC - equity in the prior year.

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



59



Gas Utilities
 
Three Months Ended Sept. 30,
Nine Months Ended Sept. 30,
 
2013
2012
Variance
2013
2012
Variance
 
(in thousands)
Natural gas — regulated
$
60,931

$
56,845

$
4,086

$
351,517

$
293,047

$
58,470

Other — non-regulated services
6,861

6,590

271

21,923

21,296

627

Total revenue
67,792

63,435

4,357

373,440

314,343

59,097

 
 
 
 
 
 
 
Natural gas — regulated
23,999

20,802

3,197

197,522

154,342

43,180

Other — non-regulated services
3,634

3,383

251

10,868

10,272

596

Total cost of sales
27,633

24,185

3,448

208,390

164,614

43,776

 
 
 
 
 
 
 
Gross margin
40,159

39,250

909

165,050

149,729

15,321

 
 
 
 
 
 
 
Operations and maintenance
30,459

28,339

2,120

95,537

88,121

7,416

Depreciation and amortization
6,594

6,338

256

19,680

18,748

932

Total operating expenses
37,053

34,677

2,376

115,217

106,869

8,348

 
 
 
 
 
 
 
Operating income (loss)
3,106

4,573

(1,467
)
49,833

42,860

6,973

 
 
 
 
 
 
 
Interest expense, net
(6,016
)
(5,370
)
(646
)
(18,200
)
(17,659
)
(541
)
Other income (expense), net
26

(2
)
28

33

82

(49
)
Income tax benefit (expense)
1,434

802

632

(11,441
)
(8,914
)
(2,527
)
Income (loss) from continuing operations
$
(1,450
)
$
3

$
(1,453
)
$
20,225

$
16,369

$
3,856



60



 
Three Months Ended Sept. 30,
 
Nine Months Ended Sept. 30,
Revenue (in thousands)
2013
 
2012
 
2013
 
2012
Residential:
 
 
 
 
 
 
 
Colorado
$
5,007

 
$
4,498

 
$
34,651

 
$
33,837

Nebraska
11,850

 
11,370

 
83,634

 
65,832

Iowa
10,471

 
9,776

 
67,361

 
56,216

Kansas
8,166

 
7,354

 
46,551

 
36,537

Total Residential
35,494

 
32,998

 
232,197

 
192,422

 
 
 
 
 
 
 
 
Commercial:
 
 
 
 
 
 
 
Colorado
1,253

 
898

 
6,691

 
6,525

Nebraska
2,436

 
2,742

 
25,781

 
20,760

Iowa
4,511

 
3,988

 
30,728

 
24,495

Kansas
2,208

 
1,973

 
15,049

 
10,702

Total Commercial
10,408

 
9,601

 
78,249

 
62,482

 
 
 
 
 
 
 
 
Industrial:
 
 
 
 
 
 
 
Colorado
900

 
1,110

 
1,455

 
1,756

Nebraska
242

 
306

 
547

 
735

Iowa
457

 
357

 
1,911

 
1,551

Kansas
7,748

 
7,078

 
14,748

 
12,314

Total Industrial
9,347

 
8,851

 
18,661

 
16,356

 
 
 
 
 
 
 
 
Transportation:
 
 
 
 
 
 
 
Colorado
98

 
113

 
726

 
616

Nebraska
1,958

 
1,866

 
9,069

 
7,337

Iowa
916

 
816

 
3,454

 
3,044

Kansas
1,402

 
1,338

 
4,904

 
4,367

Total Transportation
4,374

 
4,133

 
18,153

 
15,364

 
 
 
 
 
 
 
 
Other Sales Revenue:
 
 
 
 
 
 
 
Colorado
17

 
15

 
(35
)
 
65

Nebraska
491

 
469

 
1,731

 
1,561

Iowa
120

 
86

 
422

 
350

Kansas
680

 
692

 
2,139

 
4,447

Total Other Sales Revenue
1,308

 
1,262

 
4,257

 
6,423

 
 
 
 
 
 
 
 
Total Regulated Revenue
60,931

 
56,845

 
351,517

 
293,047

 
 
 
 
 
 
 
 
Non-regulated Services
6,861

 
6,590

 
21,923

 
21,296

 
 
 
 
 
 
 
 
Total Revenue
$
67,792

 
$
63,435

 
$
373,440

 
$
314,343



61



 
Three Months Ended Sept. 30,
 
Nine Months Ended Sept. 30,
Gross Margin (in thousands)
2013
 
2012
 
2013
 
2012
Residential:
 
 
 
 
 
 
 
Colorado
$
2,791

 
$
2,548

 
$
12,913

 
$
11,375

Nebraska
8,374

 
8,334

 
37,740

 
32,922

Iowa
8,032

 
7,850

 
31,018

 
28,373

Kansas
5,915

 
5,622

 
23,044

 
20,537

Total Residential
25,112

 
24,354

 
104,715

 
93,207

 
 
 
 
 
 
 
 
Commercial:
 
 
 
 
 
 
 
Colorado
480

 
399

 
2,048

 
1,818

Nebraska
1,264

 
1,404

 
8,191

 
7,027

Iowa
1,924

 
1,890

 
8,968

 
7,723

Kansas
1,139

 
1,087

 
5,302

 
4,365

Total Commercial
4,807

 
4,780

 
24,509

 
20,933

 
 
 
 
 
 
 
 
Industrial:
 
 
 
 
 
 
 
Colorado
279

 
307

 
467

 
509

Nebraska
72

 
99

 
157

 
204

Iowa
43

 
56

 
206

 
172

Kansas
1,011

 
1,096

 
1,985

 
2,090

Total Industrial
1,405

 
1,558

 
2,815

 
2,975

 
 
 
 
 
 
 
 
Transportation:
 
 
 
 
 
 
 
Colorado
98

 
113

 
726

 
617

Nebraska
1,958

 
1,866

 
9,069

 
7,337

Iowa
916

 
816

 
3,454

 
3,044

Kansas
1,402

 
1,338

 
4,904

 
4,367

Total Transportation
4,374

 
4,133

 
18,153

 
15,365

 
 
 
 
 
 
 
 
Other Sales Margins:
 
 
 
 
 
 
 
Colorado
17

 
15

 
(35
)
 
65

Nebraska
491

 
469

 
1,731

 
1,562

Iowa
120

 
86

 
422

 
351

Kansas
606

 
648

 
1,685

 
4,248

Total Other Sales Margins
1,234

 
1,218

 
3,803

 
6,226

 
 
 
 
 
 
 
 
Total Regulated Gross Margin
36,932

 
36,043

 
153,995

 
138,706

 
 
 
 
 
 
 
 
Non-regulated Services
3,227

 
3,207

 
11,055

 
11,023

 
 
 
 
 
 
 
 
Total Gross Margin
$
40,159

 
$
39,250

 
$
165,050

 
$
149,729



62



 
Three Months Ended Sept. 30,
 
Nine Months Ended Sept. 30,
Volumes Sold (in Dth)
2013
2012
 
2013
2012
Residential:
 
 
 
 
 
Colorado
471,618

372,722

 
4,661,845

3,773,819

Nebraska
646,900

681,361

 
8,441,465

6,032,705

Iowa
521,223

479,912

 
7,544,375

5,486,267

Kansas
463,083

422,708

 
4,723,982

3,581,184

Total Residential
2,102,824

1,956,703

 
25,371,667

18,873,975

 
 
 
 
 
 
Commercial:
 
 
 
 
 
Colorado
167,060

98,453

 
999,653

804,701

Nebraska
231,394

315,832

 
3,267,020

2,606,223

Iowa
552,814

527,923

 
4,523,365

3,424,736

Kansas
224,078

219,870

 
1,976,165

1,439,351

Total Commercial
1,175,346

1,162,078

 
10,766,203

8,275,011

 
 
 
 
 
 
Industrial:
 
 
 
 
 
Colorado
237,848

265,451

 
374,709

416,020

Nebraska
44,184

69,229

 
88,449

134,931

Iowa
87,726

74,535

 
359,822

297,494

Kansas
1,742,551

1,912,296

 
3,154,217

3,381,657

Total Industrial
2,112,309

2,321,511

 
3,977,197

4,230,102

 
 
 
 
 
 
Total Volumes Sold
5,390,479

5,440,292

 
40,115,067

31,379,088

 
 
 
 
 
 
Volumes Transported:
 
 
 
 
 
Colorado
81,309

98,893

 
710,351

607,469

Nebraska
6,099,764

6,453,607

 
20,822,085

20,042,972

Iowa
4,422,788

4,038,804

 
14,892,528

13,718,759

Kansas
3,601,940

3,993,675

 
10,990,576

11,640,182

Total Volumes Transported
14,205,801

14,584,979

 
47,415,540

46,009,382

 
 
 
 
 
 
Wholesale:
 
 
 
 
 
Kansas
12,359

8,427

 
86,568

40,380

Total Other Volumes
12,359

8,427

 
86,568

40,380

 
 
 
 
 
 
Total Volumes and Transportation Sold
19,608,639

20,033,698

 
87,617,175

77,428,850


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.


63



 
Three Months Ended Sept. 30,
 
2013
 
2012
Heating Degree Days:
Actual
 
Variance
From 30-Year
Average
 
Actual
 
Variance
From 30-Year
Average
Colorado
83

 
(54
)%
 
116

 
(39
)%
Nebraska
31

 
(68
)%
 
110

 
12
 %
Iowa
138

 
(1
)%
 
216

 
21
 %
Kansas (a)
16

 
(71
)%
 
42

 
(35
)%
Combined (b) 
79

 
(38
)%
 
150

 
5
 %

 
Nine Months Ended Sept. 30,
 
2013
 
2012
Heating Degree Days:
Actual
 
Variance
From 30-Year
Average
 
Actual
 
Variance
From 30-Year
Average
Colorado
3,927

 
1
%
 
3,018

 
(23
)%
Nebraska
3,929

 
6
%
 
2,880

 
(22
)%
Iowa
4,754

 
13
%
 
3,629

 
(19
)%
Kansas (a)
3,202

 
8
%
 
2,373

 
(21
)%
Combined (b) 
4,227

 
8
%
 
3,176

 
(21
)%
__________
(a)
Kansas Gas has an approved weather normalization mechanism within its rate structure, which minimizes weather impact on gross margins.
(b)
The combined heating degree days are calculated based on a weighted average of total customers by state excluding Kansas Gas due to its weather normalization mechanism.




64



Results of Operations for the Gas Utilities for the Three Months Ended Sept. 30, 2013 Compared to the Three Months Ended Sept. 30, 2012: Loss from continuing operations for the Gas Utilities was $1.5 million for the three months ended Sept. 30, 2013, compared to Income from continuing operations of $0.0 million for the three months ended Sept. 30, 2012, as a result of:

Gross margin increased primarily due to higher residential and commercial and transport volumes and higher weather normalized use per customer partially offset by lower industrial volumes.

Operations and maintenance increased primarily due to an increase in employee compensation and benefit costs and uncollectible accounts due to increased revenue.

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

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 benefit (expense): Each period presented produced a pre-tax loss that resulted in an income tax benefit. The income tax benefit recorded in 2012 was favorably impacted as a result of a true-up adjustment. No comparable adjustment was made in 2013.

Results of Operations for the Gas Utilities for the Nine Months Ended Sept. 30, 2013 Compared to the Nine Months Ended Sept. 30, 2012: Income from continuing operations for the Gas Utilities was $20.2 million for the nine months ended Sept. 30, 2013, compared to Income from continuing operations of $16.4 million for the nine months ended Sept. 30, 2012, as a result of:

Gross margin increased primarily due to higher residential consumption and transport volumes driven by 33 percent higher heating degree days compared to the same period in the prior year. Heating degree days were 8 percent higher than normal for the period.

Operations and maintenance increased primarily due to an increase in employee compensation and benefit costs and uncollectible accounts due to increased revenue.

Depreciation and amortization increased due to a higher asset base.

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



65



Regulatory Matters — Utilities Group

The following summarizes our recent state and federal rate case and initial surcharge orders (in millions):
 
Type of Service
Date Requested
Effective Date
Revenue Amount Requested
Revenue Amount Approved
Iowa Gas (a)
Gas
12/2012
6/2013
$
0.9

$
0.2

Black Hills Power (b)
Electric
12/2012
4/2013
$
13.7

$
8.8

Black Hills Power (c)
Electric
12/2012
4/2013
$
9.2

$
7.7

__________
(a)
On March 15, 2013, the IUB approved the Capital Infrastructure Automatic Adjustment Mechanism filed by Iowa Gas in December 2012. Approval was obtained for recovery of our 2012 capital investments. The mechanism was effective in April 2013 and will result in an annual revenue increase of approximately $0.2 million.

(b)
On Dec. 17, 2012, Black Hills Power filed a request with the SDPUC seeking a 9.94 percent, or $13.7 million, increase in annual electric revenue, and interim rates were implemented on June 16, 2013. On Sept. 17, 2013, the SDPUC approved a settlement agreement resulting in a global settlement and an annual rate increase of $8.8 million, or 6.4 percent, effective June 16, 2013. Customer refunds will begin Nov. 1, 2013.

(c) On Sept. 17, 2013, the SDPUC approved a construction financing rider in lieu of traditional AFUDC, effective date of April 1, 2013, for the South Dakota portion of costs for Cheyenne Prairie. The rider allows Black Hills Power to earn and collect a rate of return during the construction period on its approximately 40 percent share of the total project cost that relates to South Dakota customers.


Non-regulated Energy Group

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

Power Generation
 
Three Months Ended Sept. 30,
Nine Months Ended Sept. 30,
 
2013
2012
Variance
2013
2012
Variance
 
(in thousands)
Revenue
$
21,968

$
20,951

$
1,017

$
62,453

$
59,312

$
3,141

 
 
 
 
 
 
 
Operations and maintenance
6,336

7,788

(1,452
)
22,288

22,486

(198
)
Depreciation and amortization
1,303

1,165

138

3,842

3,395

447

Total operating expense
7,639

8,953

(1,314
)
26,130

25,881

249

 
 
 
 
 
 
 
Operating income
14,329

11,998

2,331

36,323

33,431

2,892

 
 
 
 
 
 
 
Interest expense, net
(2,846
)
(3,085
)
239

(8,226
)
(11,800
)
3,574

Other (expense) income, net
14

(4
)
18

11

10

1

Income tax (expense) benefit
(4,790
)
(3,781
)
(1,009
)
(10,726
)
(5,673
)
(5,053
)
 
 
 
 
 
 
 
Income (loss) from continuing operations
$
6,707

$
5,128

$
1,579

$
17,382

$
15,968

$
1,414



66



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,
 
2013
2012
 
2013
2012
Contracted power plant fleet availability:
 
 
 
 
 
Coal-fired plant
100.0
%
99.4
%
 
98.0
%
99.5
%
Natural gas-fired plants
99.2
%
99.4
%
 
99.0
%
99.3
%
Total availability
99.4
%
99.4
%
 
98.8
%
99.4
%

Results of Operations for Power Generation for the Three Months Ended Sept. 30, 2013 Compared to the Three Months Ended Sept. 30, 2012: Income from continuing operations for the Power Generation segment was $6.7 million for the three months ended Sept. 30, 2013, compared to Income from continuing operations of $5.1 million for the same period in 2012 as a result of:

Revenue increased primarily due to an increase in off-system sales from five megawatts of capacity at Wygen I not under contract, and an increase in megawatt hours delivered at a higher price.

Operations and maintenance decreased primarily due to decreases in transmission expense and property taxes, partially offset by increased costs as a result of additional megawatt hours generated.

Depreciation and amortization was comparable to the same period in the prior year. The generating facility located in Pueblo, Colo. is accounted for as a capital lease under GAAP; as such, depreciation expense for the original cost of the facility is recorded at Colorado Electric for segment reporting purposes.

Interest expense, net is comparable to the same period 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.


67



Results of Operations for Power Generation for the Nine Months Ended Sept. 30, 2013 Compared to the Nine Months Ended Sept. 30, 2012: Income from continuing operations for the Power Generation segment was $17.4 million for the nine months ended Sept. 30, 2013, compared to Income from continuing operations of $16.0 million for the same period in 2012 as a result of:

Revenue increased primarily due to an increase in megawatt hours delivered at a higher price, an increase in off-system sales from five megawatts of capacity not under contract at Wygen I.

Operations and maintenance was comparable to the same period in the prior year reflecting a decrease in property taxes partially offset by increased costs as a result of additional megawatt hours generated.

Depreciation and amortization was comparable to the same period in the prior year. The generating facility located in Pueblo, Colo. is accounted for as a capital lease under GAAP; as such, depreciation expense for the original cost of the facility is recorded at Colorado Electric for segment reporting purposes.

Interest expense, net decreased primarily due to lower debt balances.

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

Income tax (expense) benefit: The effective tax rate in the 2012 period was impacted by a favorable state tax true-up including certain tax credits pertaining to qualified plant expenditures related to capital investment and research and development.

Coal Mining
 
Three Months Ended Sept. 30,
Nine Months Ended Sept. 30,
 
2013
2012
Variance
2013
2012
Variance
 
(in thousands)
Revenue
$
15,317

$
14,675

$
642

$
43,218

$
42,791

$
427

 
 
 
 
 
 
 
Operations and maintenance
10,163

10,780

(617
)
29,565

32,141

(2,576
)
Depreciation, depletion and amortization
2,914

2,922

(8
)
8,743

9,573

(830
)
Total operating expenses
13,077

13,702

(625
)
38,308

41,714

(3,406
)
 
 
 


 
 
 
Operating income (loss)
2,240

973

1,267

4,910

1,077

3,833

 
 
 
 
 
 
 
Interest (expense) income, net
(172
)
1

(173
)
(482
)
1,159

(1,641
)
Other income, net
550

525

25

1,744

2,052

(308
)
Income tax benefit (expense)
(476
)
191

(667
)
(992
)
(364
)
(628
)
 
 
 
 
 
 
 
Income (loss) from continuing operations
$
2,142

$
1,690

$
452

$
5,180

$
3,924

$
1,256



68



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

 
Three Months Ended Sept. 30,
 
Nine Months Ended Sept. 30,
 
2013
2012
 
2013
2012
Tons of coal sold
1,133

1,105

 
3,265

3,191

Cubic yards of overburden moved
685

1,827

 
2,674

6,749


Results of Operations for Coal Mining for the Three Months Ended Sept. 30, 2013 Compared to the Three Months Ended Sept. 30, 2012: Income from continuing operations for the Coal Mining segment was $2.1 million for the three months ended Sept. 30, 2013, compared to Income from continuing operations of $1.7 million for the same period in 2012 as a result of:

Revenue increased primarily due to increased pricing and a 3 percent increase in tons sold.

Operations and maintenance decreased primarily due to mining in areas with lower overburden, decreased fuel costs and reduced labor and benefits, partially offset by additional costs associated with a weather related coal conveyor failure.

Depreciation, depletion and amortization were comparable to the same period in the prior year.

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

Other income, net was comparable to the same period in the prior year.
 
Income tax benefit (expense): The effective tax rate for 2012 was positively impacted by a favorable true-up adjustment that was primarily driven by an increased percentage depletion deduction reported on the 2011 tax return.

Results of Operations for Coal Mining for the Nine Months Ended Sept. 30, 2013 Compared to the Nine Months Ended Sept. 30, 2012: Income from continuing operations for the Coal Mining segment was $5.2 million for the nine months ended Sept. 30, 2013, compared to Income from continuing operations of $3.9 million for the same period in 2012 as a result of:

Revenue was comparable to the same period in the prior year, reflecting a 1 percent decrease in average price per ton partially offset by a 2 percent increase in tons sold as a result of customer outages that occurred in the prior year period. Approximately 50 percent of our coal production is sold under contracts that include price adjustments based on actual mining costs. Our mining costs have trended down due to lower operating costs, thereby decreasing our price per ton for these customers. Most of our remaining production is sold under contracts where the sales price escalates periodically based on published indices.

Operations and maintenance decreased primarily due to mining in areas with lower overburden, decreased fuel costs and reduced labor and benefits, partially offset by additional costs associated with a weather related coal conveyor failure.

Depreciation and amortization decreased primarily due to lower depreciation on mine assets and of mine reclamation asset retirement costs.

Interest (expense) income, net reflects decreased interest income primarily due to a decrease in the inter-company notes receivable balance reduced by payment of a dividend to our parent.

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

Income tax benefit (expense): The effective tax rate for 2012 was positively impacted by a favorable true-up adjustment that was primarily driven by an increased percentage depletion deduction reported on the 2011 tax return.


69



Oil and Gas
 
Three Months Ended Sept. 30,
Nine Months Ended Sept. 30,
 
2013
2012
Variance
2013
2012
Variance
 
(in thousands)
Revenue
$
14,426

$
24,728

$
(10,302
)
$
41,584

$
66,994

$
(25,410
)
 
 
 
 
 
 
 
Operations and maintenance
10,662

12,118

(1,456
)
30,912

33,290

(2,378
)
Gain on sale of operating assets

(27,285
)
27,285


(27,285
)
27,285

Depreciation, depletion and amortization
6,157

12,457

(6,300
)
16,738

34,813

(18,075
)
Impairment of long-lived assets




26,868

(26,868
)
Total operating expenses
16,819

(2,710
)
19,529

47,650

67,686

(20,036
)
 
 
 
 
 
 
 
Operating income (loss)
(2,393
)
27,438

(29,831
)
(6,066
)
(692
)
(5,374
)
 
 
 
 
 
 
 
Interest income (expense), net
(339
)
(1,112
)
773

(314
)
(3,882
)
3,568

Other income (expense), net
58

77

(19
)
62

193

(131
)
Income tax benefit (expense)
992

(9,014
)
10,006

2,619

2,162

457

 
 
 
 
 
 
 
Income (loss) from continuing operations
$
(1,682
)
$
17,389

$
(19,071
)
$
(3,699
)
$
(2,219
)
$
(1,480
)

The following tables provide certain operating statistics for our Oil and Gas segment:
 
Three Months Ended Sept. 30,
 
Nine Months Ended Sept. 30,
 
2013
2012
 
2013
2012
Production:
 
 
 
 
 
Bbls of oil sold
84,260

184,423

 
246,367

485,262

Mcf of natural gas sold
1,765,622

2,278,801

 
5,282,961

7,119,087

Gallons of NGL sold
988,682

1,099,198

 
2,830,216

2,751,409

Mcf equivalent sales
2,412,422

3,542,367

 
7,165,479

10,423,717


 
Three Months Ended Sept. 30,
 
Nine Months Ended Sept. 30,
 
2013
2012
 
2013
2012
Average price received: (a)
 
 
 
 
 
Oil/Bbl
$
94.32

$
88.69

 
$
92.60

$
81.65

Gas/Mcf  
$
2.82

$
3.07

 
$
2.69

$
3.27

NGL/gallon
$
0.71

$
0.65

 
$
0.79

$
0.77

 
 
 
 
 
 
Depletion expense/Mcfe
$
2.16

$
3.26

 
$
1.92

$
3.07

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


70



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

 
Three Months Ended Sept. 30, 2013
 
Three Months Ended Sept. 30, 2012
Producing Basin
LOE
Gathering,
 Compression
 and Processing
Production Taxes
Total
 
LOE
Gathering,
 Compression
and Processing
Production Taxes
Total
San Juan
$
1.39

$
0.42

$
0.44

$
2.25

 
$
1.42

$
0.33

$
0.46

$
2.21

Piceance
0.70

0.47

0.50

1.67

 
0.13

0.35

0.14

0.62

Powder River
1.53


1.15

2.68

 
1.00


1.11

2.11

Williston
1.19


1.24

2.43

 
0.70


1.48

2.18

All other properties
1.08


0.69

1.77

 
1.48


0.25

1.73

Total weighted average
$
1.26

$
0.25

$
0.70

$
2.21

 
$
0.99

$
0.17

$
0.74

$
1.90



 
Nine Months Ended Sept. 30, 2013
 
Nine Months Ended Sept. 30, 2012
Producing Basin
LOE
Gathering,
 Compression
 and Processing
Production Taxes
Total
 
LOE
Gathering,
 Compression
and Processing
Production Taxes
Total
San Juan
$
1.36

$
0.39

$
0.46

$
2.21

 
$
1.14

$
0.28

$
0.34

$
1.76

Piceance
0.72

0.54

0.36

1.62

 
0.20

0.39

0.13

0.72

Powder River
1.59


1.21

2.80

 
1.33


1.17

2.50

Williston
1.03


1.31

2.34

 
0.65


1.35

2.00

All other properties
0.81


0.18

0.99

 
1.58


0.17

1.75

Total weighted average
$
1.22

$

$
0.63

$
1.85

 
$
0.96

$
0.17

$
0.63

$
1.76

  
Results of Operations for Oil and Gas for the Three Months Ended Sept. 30, 2013 Compared to the Three Months Ended Sept. 30, 2012: Loss from continuing operations for the Oil and Gas segment was $1.7 million for the three months ended Sept. 30, 2013, compared to Income from continuing operations of $17.4 million for the same period in 2012 as a result of:

Revenue decreased primarily due to a 32 percent decrease in volumes sold as a result of the sale of our Williston Basin assets in 2012, and an 8 percent decrease in the average price received for natural gas sold, partially offset by a 6 percent increase in the average price received for crude oil sold.

Operations and maintenance decreased primarily due to lower non-operated well costs, lower production taxes and ad valorem taxes on lower revenue.

Depreciation, depletion and amortization decreased primarily due to a lower depletion rate per Mcfe and lower volumes. The lower depletion rate was primarily driven by the sale of our Williston Basin assets in 2012.


71



Gain on sale of operating assets was related to the sale of our Williston Basin assets in 2012. We follow the full-cost method of accounting for oil and gas activities, which typically does not allow for recognition of a gain or loss on sale unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves. The sale of the Williston Basin assets significantly altered the relationship and accordingly we recorded a gain of $27.3 million with the remainder of the proceeds recorded as a reduction in the full cost pool. 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 income (expense), net reflects lower interest expense primarily due to decreased debt as a result of proceeds from the sale of our Williston Basin assets in 2012.

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

Income tax (expense) benefit: In 2013, a pre-tax net loss was generated that resulted in an income tax benefit. The effective tax rate in the 2013 period reflects a favorable true-up adjustment that increased the tax benefit. For the 2012 period, pre-tax net income was generated as a result of the gain on sale of our Williston Basin assets. The effective tax rate is a reflection of such gain. 

Results of Operations for Oil and Gas for the Nine Months Ended Sept. 30, 2013 Compared to the Nine Months Ended Sept. 30, 2012: Loss from continuing operations for the Oil and Gas segment was $3.7 million for the nine months ended Sept. 30, 2013, compared to Loss from continuing operations of $2.2 million for the same period in 2012 as a result of:

Revenue decreased primarily due to a 31 percent decrease in volumes sold as a result of the sale of our Williston Basin asset in 2012, a natural production decline in our Mancos formation wells and an 18 percent decrease in the average price received for natural gas sold, partially offset by a 13 percent increase in the average price received for crude oil sold.

Operations and maintenance decreased primarily due to lower non-operated well costs, lower production taxes and ad valorem taxes on lower revenue.

Depreciation, depletion and amortization decreased primarily due to a lower depletion rate per Mcfe and lower volumes. The lower depletion rate was primarily driven by the sale of our Williston Basin assets in 2012.

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 in 2012. The write-down reflected a 12 month average NYMEX gas price of $3.15 per Mcf, adjusted to $2.66 per Mcf at the wellhead and $95.67 per barrel, adjusted to $85.36 per barrel for crude oil at the wellhead.

Gain on sale of operating assets was related to the sale of our Williston Basin assets in 2012. We follow the full-cost method of accounting for oil and gas activities, which typically does not allow for recognition of a gain or loss on sale unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves. The sale of the Williston Basin assets significantly altered the relationship and accordingly we recorded a gain of $27.3 million with the remainder of the proceeds recorded as a reduction in the full cost pool. 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 income (expense), net reflects lower interest expense primarily due to decreased debt as a result of proceeds from the sale of our Williston Basin assets in 2012.

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

Income tax (expense) benefit: Each period presented produced a pre-tax net loss that resulted in an income tax benefit. The effective tax rate in the 2013 period reflects a lesser tax benefit attributable to percentage depletion. 



72



Corporate Activity

Results of Operations for Corporate activities for the Three Months Ended Sept. 30, 2013 Compared to the Three Months Ended Sept. 30, 2012: Income from continuing operations for Corporate was $2.3 million for the three months ended Sept. 30, 2013, compared to Loss from continuing operations of $4.2 million for the three months ended Sept. 30, 2012 as a result of:

Market interest rate changes creating unrealized, non-cash mark-to-market gains of $3.1 million on certain interest rate swaps for the three months ended Sept. 30, 2013 as compared to a gain of $0.6 million on these same interest rate swaps for the three months ended Sept. 30, 2012.
The income from continuing operations for the three months ended Sept. 30, 2013, included lower interest expense as compared to the three months ended Sept. 30, 2012, as a result of an allocation of debt-related costs included in Corporate activities for the three months ended Sept. 30, 2012, now allocated among our segments for the three months Sept. 30, 2013, in order to better align the capital structure among the segments.
The losses for the quarter ended Sept. 30, 2012, included an incentive compensation accrual recorded as a result of the sale of the Williston Basin asset.

Results of Operations for Corporate activities for the Nine Months Ended Sept. 30, 2013 Compared to the Nine Months Ended Sept. 30, 2012: Income from continuing operations for Corporate was $19.7 million for the nine months ended Sept. 30, 2013, compared to Loss from continuing operations of $13.9 million for the nine months ended Sept. 30, 2012 as a result of:

Market interest rate changes creating unrealized, non-cash mark-to-market gains of $29.4 million on certain interest rate swaps for the nine months ended Sept. 30, 2013 as compared to losses of $2.9 million for these same interest rate swaps for the nine months ended Sept. 30, 2012.
The income from continuing operations for the nine months ended Sept. 30, 2013, included lower interest expense as compared to the nine months ended Sept. 30, 2012, as a result of an allocation of debt-related costs included in Corporate activities for the nine months ended Sept. 30, 2012, now allocated among our segments for the nine months ended Sept. 30, 2013, in order to better align the capital structure of the corporation among the segments.
The losses for the nine months ended Sept. 30, 2012, include costs originally allocated to our Energy Marketing segment, which could not be reclassified to discontinued operations in accordance with GAAP, and were included in Corporate activities for the nine months ended Sept. 30, 2012.
The losses for the nine months ended Sept. 30, 2012 included an incentive compensation accrual recorded as a result of the sale of the Williston Basin asset.



73



Discontinued Operations

Results of Operations for Discontinued Operations for the Three and Nine Months Ended Sept. 30, 2013, Compared to the Three and Nine Months Ended Sept. 30, 2012:

On Feb. 29, 2012, we sold the outstanding stock of Enserco, our Energy Marketing segment. We recorded a Loss from discontinued operations, net of tax, for the three and nine months ended Sept. 30, 2012, of $0.2 million and $6.8 million, respectively.

After the sale of Enserco and pursuant to the provisions of the Stock Purchase Agreement, the buyer requested purchase price adjustments, which we disputed. The buyer filed a petition in the Colorado District Court for the City and County of Denver, Colo., seeking an order compelling binding arbitration on all of the disputed claims. Following a hearing in July 2013, the court entered an order remanding all but one of the disputed adjustment claims to arbitration. We continue to dispute the validity of the adjustment claims within the arbitration process, which we expect will conclude before the end of 2013.


Critical Accounting Policies

There have been no material changes in our critical accounting policies from those reported in our 2012 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 2012 Annual Report on Form 10-K.


Liquidity and Capital Resources

OVERVIEW

BHC and its subsidiaries require cash to support and grow our business. Our predominant source of cash is supplied by our operations and supplemented with corporate borrowings. This cash is used for, among other things, working capital, capital expenditures, dividends, pension funding, investments in or acquisitions of assets and businesses, payment of debt obligations and redemption of outstanding debt and equity securities when required or financially appropriate.

The most significant items impacting cash are our capital expenditures, the purchase of natural gas for our Utilities Group and our Power Generation segment, and the payment of dividends to our shareholders. We could experience significant cash requirements during peak months of the winter heating season due to higher natural gas consumption and during periods of high natural gas prices.

We believe that our cash on hand, operating cash flows, existing borrowing capacity and ability to complete new debt and equity financings, taken in their entirety, provide sufficient capital resources to fund our ongoing operating requirements, debt maturities, anticipated dividends, and anticipated capital expenditures discussed in this section.


74



Significant Factors Affecting Liquidity

Although we believe we have sufficient resources to fund our cash requirements, there are many factors with the potential to influence our cash flow position, including seasonality, commodity prices, significant capital projects, requirements imposed by state and federal agencies, and economic market conditions. We have implemented risk mitigation programs, where possible, to stabilize cash flow; however, the potential for unforeseen events affecting cash needs will continue to exist.


Cash Flow Activities

The following table summarizes our cash flows for the nine months ended Sept. 30, 2013 and 2012, (in thousands):

Cash provided by (used in):
2013
2012
Increase (Decrease)
Operating activities
$
251,766

$
269,667

$
(17,901
)
Investing activities
$
(236,639
)
$
98,306

$
(334,945
)
Financing activities
$
(16,952
)
$
(179,549
)
$
162,597


Nine Months Ended Sept. 30, 2013 Compared to Nine Months Ended Sept. 30, 2012

Operating Activities

Net cash provided by operating activities was $17.9 million lower for the nine months ended Sept. 30, 2013, than for the same period in 2012 primarily attributable to:

Cash earnings (net income plus non-cash adjustments) were $30.5 million higher for the nine months ended Sept. 30, 2013 than for the same period in the prior year.

Net outflows from operating assets and liabilities were $7.5 million for the nine months ended Sept. 30, 2013, compared to net cash inflows of $37.3 million in the same period in the prior year. Changes are normal working capital changes influenced by increase in natural gas prices for the Utilities Group, expiration of the PPA with PSCo, and receipt of approximately $8 million from a government grant relating to the Busch Ranch wind project during 2013.

Cash contributions to the defined benefit pension plan of $12.5 million were made in the nine months ended Sept. 30, 2013 compared to $25.0 million in the same period in the prior year.

A $21.2 million decrease in net cash inflows from discontinued operations in 2013 compared to the same period in the prior year.


75



Investing Activities

Net cash used in investing activities was $236.6 million for the nine months ended Sept. 30, 2013, compared to net cash provided by investing activities of $98.3 million for the same period in 2012 for a variance of $334.9 million. The variance was driven by:

Cash proceeds received from assets sold during the nine months ended Sept. 30, 2012, including the sale of our Williston Basin assets, the partial sale of the Busch Ranch wind project, and the sale of Enserco.

Capital expenditures of approximately $96 million for the nine months ended Sept. 30, 2013, related to the construction of Cheyenne Prairie at our Electric Utilities segment compared to $3.6 million for the nine months ended Sept. 30, 2012, offset by a decrease in capital spending at Oil and Gas.

The 2012 period included approximately $22 million note receivable relating to our oil and gas properties.

Financing Activities

Net cash used in financing activities for the nine months ended Sept. 30, 2013, was $17.0 million, compared to net cash used in financing activities for the same period in 2012 of $179.5 million for a variance of $162.6 million. The variance was driven by:

Proceeds from the 2012 asset sales were used to pay down short-term borrowings on the Revolving Credit Facility.

Increased borrowings in 2013 to finance our construction of Cheyenne Prairie offset by decreased borrowings for capital expenditures in our Oil and Gas segment and the completion of Busch Ranch wind project in 2012.

The 2013 repayment of our $150 million and $100 million term loans was offset by the issuance of a $275 million long-term term loan.


Dividends

Dividends paid on our common stock totaled $50.7 million for the nine months ended Sept. 30, 2013, or $1.14 per share. On Oct. 29, 2013, our board of directors declared a quarterly dividend of $0.38 per share payable Dec. 1, 2013, which is equivalent to an annual dividend rate of $1.52 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.



76



Debt

Financing Transactions and Short-Term Liquidity

Our principal sources to meet day-to-day operating cash requirements are cash from operations and our corporate Revolving Credit Facility.

Revolving Credit Facility

We have a $500 million corporate Revolving Credit Facility that matures on Feb. 1, 2017, and has an accordion feature that allows us, with the consent of the administrative agent and issuing agents, to increase the capacity of the facility to $750 million. Borrowings are available under a base rate or various Eurodollar rate options. The interest costs associated with the letters of credit or borrowings and the commitment fee under the Revolving Credit Facility are determined based upon the lowest credit ratings of S&P and Moody’s that apply to our debt. Based on our 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, during the three and nine months ended Sept. 30, 2013. A commitment fee is charged on the unused amount of the Revolving Credit Facility and was 0.25 percent based on our credit rating.

On Sept. 25, 2013, Moody’s upgraded our credit rating, which triggered improved interest costs on our Revolving Credit Facility, which are based on the lowest credit ratings of S&P and Moody’s.  On Oct. 2, 2013, the margins for our base rate borrowings, Eurodollar borrowings and letters of credit changed to 0.375 percent, 1.375 percent and 1.375 percent, respectively. The commitment fee charged on the unused portion of the Revolving Credit Facility also changed to 0.20 percent.

Our Revolving Credit Facility had the following borrowings, outstanding letters of credit and available capacity (in millions):
 
 
Current
Borrowings at
Letters of Credit at
Available Capacity at
Credit Facility
Expiration
Capacity
Sept. 30, 2013
Sept. 30, 2013
Sept. 30, 2013
Revolving Credit Facility
Feb. 1, 2017
$
500

$
138.3

$
53.1

$
308.6


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 maintaining a certain minimum net worth and recourse leverage ratio. Under the Revolving Credit Facility, our recourse leverage ratio is the ratio of our recourse debt, letters of credit and certain guarantees issued, divided by total capital, which includes recourse indebtedness plus our net worth. Subject to applicable cure periods, a violation of any of these covenants would constitute an event of default that entitles the lenders to terminate their remaining commitments and accelerate all principal and interest outstanding. We were in compliance with these covenants as of Sept. 30, 2013.

The Revolving Credit Facility prohibits us from paying cash dividends if a default or an event of default exists prior to, or would result after, paying a dividend. Although these contractual restrictions exist, we do not anticipate triggering any default measures or restrictions.


77



Term Loans

On June 21, 2013, we entered into a new two-year $275 million term loan expiring on June 19, 2015. The proceeds from this new term loan repaid the $150 million term loan due on June 24, 2013, the $100 million corporate term loan due on Sept. 30, 2013, and $25 million in short-term borrowing under our Revolving Credit Facility. At Sept. 30, 2013, the cost of borrowing under this new term loan was 1.3125 percent (LIBOR plus a margin of 1.125 percent).

Future Financing Plans

We are considering the following financing activities:

Refinancing our $250 million, 9 percent senior unsecured notes that mature in May 2014;
Partial or full settlement of our de-designated interest rate swaps; and
Long-term financing options for the Cheyenne Prairie project.

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 (Loss). For the three and nine months ended Sept. 30, 2013, respectively, we recorded $3.1 million and $29.4 million pre-tax unrealized non-cash mark-to-market gains on the swaps. The mark-to-market value on these swaps was a liability of $58.8 million at Sept. 30, 2013. 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 divided by the term of the swaps would have a pre-tax impact of approximately $0.3 million. These swaps are for terms of approximately 5.25 years and 15.25 years and have early termination dates ranging from Dec. 15, 2013 to Dec. 31, 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 early termination dates.

In addition, we have $150 million notional amount floating-to-fixed interest rate swaps with a maximum remaining term of approximately 3.25 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 $18.4 million at Sept. 30, 2013.


78



Dividend Restrictions

As a utility holding company which owns several regulated utilities, we are subject to various regulations that could influence our liquidity. Our utilities in Colorado, Iowa, Kansas and Nebraska have regulatory agreements in which they cannot pay dividends if they have issued debt to third parties and the payment of a dividend would reduce their equity ratio to below 40 percent of their total capitalization; and neither Black Hills Utility Holdings nor its subsidiaries can extend credit to the Company except in ordinary course of business and upon reasonable terms consistent with market terms. The use of our utility assets as collateral generally requires the prior approval of the state regulators in the state in which the utility assets are located. Additionally, our utility subsidiaries may generally be limited to the amount of dividends allowed by state regulatory authorities to be paid to us as a utility holding company and also may have further restrictions under the Federal Power Act. As a result of our holding company structure, our right as a common shareholder to receive assets of any of our direct or indirect subsidiaries upon a subsidiary’s liquidation or reorganization is junior to the claims against the assets of such subsidiaries by their creditors. Therefore, our holding company debt obligations are effectively subordinated to all existing and future claims of the creditors of our subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities, and guarantee holders. As of Sept. 30, 2013, the restricted net assets at our Electric Utilities and Gas Utilities were approximately $148.6 million.
Our credit facilities and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. An event of default would be deemed to have occurred if we did not meet certain financial covenants. The most restrictive financial covenant from our Revolving Credit Facility is a recourse leverage ratio not to exceed 0.65 to 1.00. Additionally, covenants within Cheyenne Light’s financing agreements require Cheyenne Light to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of Sept. 30, 2013, we were in compliance with these covenants.

As required by a covenant of the Black Hills Wyoming project financing, Black Hills Non-regulated Holdings, the parent of Black Hills Electric Generation, which is the parent of Black Hills Wyoming, has restricted shareholders’ equity of at least $100 million. In addition, Black Hills Wyoming holds $6.8 million of restricted cash associated with the project financing requirements.

There have been no other material changes in our financing transactions and short-term liquidity from those reported in Item 7 of our 2012 Annual Report on Form 10-K filed with the SEC.


79



Credit Ratings

Financing for operational needs and capital expenditure requirements not satisfied by operating cash flows depends upon the cost and availability of external funds through both short and long-term financing. The inability to raise capital on favorable terms could negatively affect our ability to maintain or expand our businesses. Access to funds is dependent upon factors such as general economic and capital market conditions, regulatory authorizations and policies, our credit ratings, cash flows from routine operations and the credit ratings of counterparties. After assessing the current operating performance, liquidity and our credit ratings, management believes that we will have access to the capital markets at prevailing market rates for companies with comparable credit ratings. Credit ratings are prepared by third party rating agencies and are not recommendations to buy, sell, or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating.

The following table represents the credit ratings and outlook of BHC at Sept. 30, 2013:
Rating Agency
Senior Unsecured Rating
Outlook
S&P (a)
BBB
Stable
Moody’s (b)
Baa2
Positive
Fitch (c)
BBB
Positive
__________
(a)
On July 24, 2013, S&P upgraded the BHC credit rating to BBB with a Stable outlook.
(b)
On Sept. 25, 2013, Moody’s upgraded the BHC credit rating to Baa2 with a Positive outlook.
(c)
On May 10, 2013, Fitch upgraded the BHC credit rating to BBB with a Positive outlook.

The following table represents the credit ratings of Black Hills Power’s Senior Secured Mortgage Bonds at Sept. 30, 2013:
Rating Agency
Senior Secured Rating
S&P *
A-
Moody’s **
A2
Fitch
A-
___________
*
On July 24, 2013, S&P upgraded the BHP credit rating to A-.
**
On Sept. 25, 2013, Moody’s upgraded the BHP credit rating to A2 from A3.



80



Capital Requirements

Actual and forecasted capital requirements are as follows (in thousands):
 
Expenditures for the
 
Total
 
Total
 
Total
 
Nine Months Ended Sept. 30, 2013
 
2013 Planned
Expenditures
 
2014 Planned
Expenditures
 
2015 Planned
Expenditures
Utilities:
 
 
 
 
 
 
 
Electric Utilities
$
157,436

 
$
245,100

 
$
250,700

 
$
189,300

Gas Utilities
39,730

 
65,100

 
60,400

 
52,600

Non-regulated Energy:
 
 
 
 
 
 
 
Power Generation
3,755

 
14,900

 
2,500

 
5,200

Coal Mining
4,739

 
7,100

 
6,600

 
6,200

Oil and Gas
37,435

 
98,300

 
117,800

 
122,700

Corporate
8,416

 
12,700

 
8,800

 
5,900

 
$
251,511

 
$
443,200

 
$
446,800

 
$
381,900


We continue to evaluate potential future acquisitions and other growth opportunities that are dependent upon the availability of economic opportunities; as a result, capital expenditures may vary significantly from the estimates identified above.


Contractual Obligations

Except as noted below, there have been no significant changes in the contractual obligations from those previously disclosed in Note 19 of our Notes to the Consolidated Financial Statements in our 2012 Annual Report on Form 10-K.

Purchase Power and Power Sales Agreements

The following purchase power and power sales agreements were renewed:

Cheyenne Light renewed and received FERC approval for an agreement with Basin Electric whereby Cheyenne Light will receive 40 megawatts of capacity and energy from Basin Electric through Sept. 30, 2014.

Cheyenne Light renewed and received FERC approval for an agreement with Basin Electric whereby Cheyenne Light will provide 40 megawatts of capacity and energy to Basin Electric through Sept. 30, 2014.


81



Construction Commitments

Construction of Cheyenne Prairie, a 132 megawatt natural gas-fired electric generating facility jointly owned by Cheyenne Light and Black Hills Power is expected to cost approximately $222 million. Construction is expected to be completed by Sept. 30, 2014. As of Sept. 30, 2013, contracts for equipment purchases and for construction were 94 percent and 67 percent committed, respectively.

Purchase and Sale Agreement

Black Hills Wyoming entered into an agreement to sell its 40 megawatt CTII natural gas-fired generating unit to the City of Gillette, Wyo. for approximately $22 million, subject to closing adjustments. The sale is expected to close in August 2014 upon the expiration of an existing power sales agreement with Cheyenne Light under which Black Hills Wyoming sells the output of the CTII to Cheyenne Light. The sale is subject to FERC approval and certain other requirements included in the contract.

Sale of Enserco Energy Inc.

After the sale of Enserco, our Energy Marketing segment, on Feb. 29, 2012, and pursuant to the provisions of the Stock Purchase Agreement, the buyer requested purchase price adjustments, which we disputed. The buyer filed a petition in the Colorado District Court for the City and County of Denver, Colo., seeking an order compelling binding arbitration on all of the disputed claims. Following a hearing in July 2013, the court entered an order remanding all but one of the disputed adjustment claims to arbitration. We continue to dispute the validity of the adjustment claims within the arbitration process, which we expect will conclude before the end of 2013.


Guarantees

Except as noted below, there have been no significant changes to guarantees from those previously disclosed in Note 20 of the Notes to the Consolidated Financial Statements in our 2012 Annual Report on Form 10-K.

As of Dec. 31, 2012, the Company had provided a guarantee for up to $33.3 million for Colorado Electric’s performance and payment obligations relating to the purchase of wind turbines for the Colorado Electric Busch Ranch project completed in 2012. The guarantee expired March 29, 2013, upon fulfillment of all contractual obligations.

A guarantee of $7.5 million to Cross Timbers Energy Services for the performance and payment obligation of Black Hills Utility Holdings for natural gas supply purchases expired on June 30, 2013 and was converted to a letter of credit for $5 million as a replacement to this guarantee.


New Accounting Pronouncements

Other than the pronouncements reported in our 2012 Annual Report on Form 10-K filed with the SEC and those discussed in Note 1 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.



82



FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q contains forward-looking statements as defined by the SEC. Forward-looking statements are all statements other than statements of historical fact, including without limitation those statements that are identified by the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts” and similar expressions, and include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions and other statements that are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature, including statements contained within Item 2 - Management’s Discussion & Analysis of Financial Condition and Results of Operations.

Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including without limitation, management’s examination of historical operating trends, data contained in the Company’s records and other data available from third parties. Nonetheless, the Company’s expectations, beliefs or projections may not be achieved or accomplished.

Any forward-looking statement contained in this document speaks only as of the date on which the statement was made, and the Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which the statement was made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of the factors, nor can it assess the effect of each factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. All forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are expressly qualified by the risk factors and cautionary statements described in our 2012 Annual Report on Form 10-K including statements contained within Item 1A - Risk Factors of our 2012 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.


83




ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK


Utilities

Our utility customers are exposed to natural gas price volatility; therefore, as allowed or required by state utility commissions, we have entered into commission approved hedging programs utilizing natural gas futures, options and basis swaps to reduce our customers’ underlying exposure to these fluctuations. The fair value of our Utilities Group’s derivative contracts is summarized below (in thousands) as of:
 
Sept. 30, 2013
 
Dec. 31, 2012
 
Sept. 30, 2012
Net derivative (liabilities) assets
$
(8,396
)
 
$
(8,533
)
 
$
(7,253
)
Cash collateral offset in Derivatives
8,396

 
8,576

 
15,740

Cash Collateral included in Other current assets
3,333

 
4,354

 

Net receivable (liability) position
$
3,333

 
$
4,397

 
$
8,487



Oil and Gas Activities

We have entered into agreements to hedge a portion of our estimated 2013, 2014 and 2015 natural gas and crude oil production from the Oil and Gas segment. The hedge agreements in place at Sept. 30, 2013, were as follows:

Natural Gas

 
For the Three Months Ended
 
March 31,
June 30,
Sept. 30,
Dec. 31,
Total Year
2013
 
 
 
 
 
Swaps - MMBtu



1,154,000

1,154,000

Weighted Average Price per MMBtu
$

$

$

$
3.50

$
3.50

 
 
 
 
 
 
2014
 
 
 
 
 
Swaps - MMBtu
1,040,000

997,500

1,005,000

1,005,000

4,047,500

Weighted Average Price per MMBtu
$
3.74

$
3.80

$
3.99

$
3.99

$
3.88

 
 
 
 
 
 
2015
 
 
 
 
 
Swaps - MMBtu
900,000

862,500

500,000

455,000

2,717,500

Weighted Average Price per MMBtu
$
4.24

$
3.99

$
4.08

$
4.16

$
4.12



84



Crude Oil

 
For the Three Months Ended
 
March 31,
June 30,
Sept. 30,
Dec. 31,
Total Year
2013
 
 
 
 
 
Swaps - Bbls



24,000

24,000

Weighted Average Price per Bbl
$

$

$

$
101.47

$
101.47

 
 
 
 
 
 
Puts - Bbls



36,000

36,000

Weighted Average Price per Bbl
$

$

$

$
80.63

$
80.63

 
 
 
 
 
 
Calls - Bbls



36,000

36,000

Weighted Average Price per Bbl
$

$

$

$
97.25

$
97.25

 
 
 
 
 
 
2014
 
 
 
 
 
Swaps - Bbls
60,000

60,000

57,000

57,000

234,000

Weighted Average Price per Bbl
$
95.48

$
90.65

$
90.55

$
90.66

$
91.86

 
 
 
 
 
 
2015
 
 
 
 
 
Swaps - Bbls
55,500

51,000

39,000

24,000

169,500

Weighted Average Price per Bbl
$
89.98

$
87.84

$
87.73

$
87.68

$
88.49



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. Further details of the swap agreements are set forth in Note 3 of the Notes to Consolidated Financial Statements in our 2012 Annual Report on Form 10-K and in Note 10 of the Notes to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.


85



The contract or notional amounts, terms of our interest rate swaps and the interest rate swaps balances reflected on the Condensed Consolidated Balance Sheet were as follows (dollars in thousands) as of:
 
Sept. 30, 2013
 
Dec. 31, 2012
 
Sept. 30, 2012
 
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
3.25

 
0.25

 
4.00

 
1.00

 
4.25

 
1.25

Derivative liabilities, current
$
7,039

 
$
58,755

 
$
7,039

 
$
88,148

 
$
7,028

 
$
77,914

Derivative liabilities, non-current
$
11,388

 
$

 
$
16,941

 
$

 
$
18,660

 
$
17,668

Cash collateral receivable (payable) included in derivatives
$

 
$
5,960

 
$

 
$
5,960

 
$

 
$
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. If extended annually, de-designated swaps totaling $100.0 million terminate in approximately 5.25 years and de-designated swaps totaling $150.0 million terminate in approximately 15.25 years.

Based on Sept. 30, 2013 market interest rates and balances related to our designated interest rate swaps, a loss of approximately $7.0 million would be realized, reported in pre-tax earnings and 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.

ITEM 4.    CONTROLS AND PROCEDURES

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) as of Sept. 30, 2013. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective.

During the quarter ended Sept. 30, 2013, there have been no 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.


86



BLACK HILLS CORPORATION

Part II — Other Information

ITEM 1.
Legal Proceedings

For information regarding legal proceedings, see Note 19 in Item 8 of our 2012 Annual Report on Form 10-K and Note 13 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 13 is incorporated by reference into this item.

ITEM 1A.
Risk Factors

There are no material changes, except as noted below, to the risk factors previously disclosed in Item 1A of Part I in our 2012 Annual Report on Form 10-K.

OPERATING RISKS

Operating results can be adversely affected by variations from normal weather conditions.

Our utility businesses are seasonal businesses, and weather patterns can have a material impact on our operating performance. Demand for electricity is typically greater in the summer and winter months associated with cooling and heating. Because natural gas is primarily used for residential and commercial heating, the demand for this product depends heavily upon winter weather patterns throughout our service territory and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating seasons. Accordingly, our utility operations have historically generated lower revenues and income when weather conditions are cooler than normal in the summer and warmer than normal in the winter. Unusually mild summers and winters therefore could have an adverse effect on our financial condition and results of operations.

Our businesses are located in areas that could be subject to seasonal natural disasters such as severe snow and ice storms, flooding and wildfires. These factors could result in interruption of our business, damage to our property such as power lines and substations, and repair and clean-up costs associated with these storms. We may not be able to recover the costs incurred in restoring transmission and distribution property following these natural disasters through a change in our regulated rates thereby resulting in a negative impact on our results of operations, financial condition and cash flows.

Our coal mining operations are subject to operating risks that are beyond our control which could affect our profitability and production levels. Our surface mining operations could be disrupted or materially affected due to adverse weather or natural disasters such as heavy snow, strong winds, rain or flooding. Additionally, weather patterns can also affect electricity demand. Extreme temperatures, both hot and cold, cause increased power usage, and therefore, increased generating requirements and use of coal. Conversely, mild temperatures could result in lower electrical demand.

Weather conditions can also limit or temporarily halt our drilling, completion and producing activities and other crude oil and natural gas operations. Primarily in the winter and spring, our operations can be curtailed because of cold, snow, and wet conditions. Severe weather could further curtail these operations, including drilling and completing of new wells or production from existing wells. In addition, weather conditions and other events could temporarily impair our ability to transport our crude oil and natural gas production.


87



POWER GENERATION

Our inability to successfully complete the sale of Black Hills Wyoming’s CTII combustion turbine to the City of Gillette, Wyo. or to sell Black Hills Wyoming’s ownership interest in the Wygen I facility to Cheyenne Light could adversely affect our Power Generation segment.
Black Hills Wyoming entered into an agreement to sell its 40 megawatt simple-cycle, gas-fired combustion turbine (“CTII”) to the City of Gillette, Wyo. in August 2014 upon expiration of an existing power sales agreement under which Black Hills Wyoming sells the output of the CTII to our subsidiary Cheyenne Light.  This sale is subject to FERC approval and certain other requirements included in the contract.

Black Hills Wyoming also has a power sales agreement with Cheyenne Light which expires in December 2022.  This power sales agreement includes an option for Cheyenne Light to purchase Black Hills Wyoming’s ownership interest in the Wygen I facility between 2013 and 2019.  If Cheyenne Light exercises its purchase option, the sale would be subject to Wyoming Public Service Commission and FERC approval.

Failure of Black Hills Wyoming to complete the sale of CTII to the City of Gillette or the sale of its ownership interest in the Wygen I facility to Cheyenne Light if Cheyenne Light exercises its purchase option, whether due to failure to obtain regulatory approval or otherwise, could adversely affect our results of operations, financial position and liquidity, particularly if we are unable to obtain power sales contracts at reasonable rates to fully utilize these assets subsequent to the expiration of the power sales contracts that are currently in effect.  

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, 2013 -
 
 
 
 
 
 
 
 
July 31, 2013
 

 
$

 

 

 
 
 
 
 
 
 
 
 
Aug. 1, 2013 -
 
 
 
 
 
 
 
 
Aug. 31, 2013
 
2,746

 
$
52.82

 

 

 
 
 
 
 
 
 
 
 
Sept. 1, 2013 -
 
 
 
 
 
 
 
 
Sept. 30, 2013
 

 
$

 

 

 
 
 
 
 
 
 
 
 
Total
 
2,746

 
$
52.82

 

 

__________
(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.


88



ITEM 5.
Other Information

On Jan. 1, 2013, we adopted ASU No. 2011-11, Disclosures about Offsetting Assets and Liabilities, which enhances disclosures by requiring an entity to disclose information about netting arrangements, including rights of offset, to enable users of its financial statements to understand the effect of those arrangements on its financial position. This ASU was effective for annual and interim reporting periods beginning on or after Jan. 1, 2013 and is to be applied retrospectively for all comparative periods presented. The impact of retrospectively adjusting for the adoption of this ASU was immaterial to our historical consolidated financial statements.

The following presents the unaudited retrospective application of ASU 2011-11 by providing reconciliation between the gross assets and gross liabilities reflected on the Consolidated Balance Sheet and the potential effects of master netting arrangements on the fair value of our derivative contracts at Dec. 31, 2011.

Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheet was as follows (in thousands):
 
As of Dec. 31, 2011
Derivative Assets
Gross Amounts of Derivative Assets
Gross Amounts Offset on Consolidated Balance Sheet
Net Amount of Total Derivative Assets on Consolidated Balance Sheet
 
 
Subject to a master netting agreement or similar arrangement:
 
 
 
Commodity derivative:
 
 
 
Utilities
$
965

$
8,931

$
9,896

Total derivative assets subject to a master netting agreement or similar arrangement
965

8,931

9,896

 
 
 
 
Not subject to a master netting agreement or similar arrangement:
 
 
 
Commodity derivative:
 
 
 
Oil and Gas - Crude Basis Swaps
1,500


1,500

Oil and Gas - Natural Gas Basis Swaps
9,158


9,158

Total derivative assets not subject to a master netting agreement or similar arrangement
10,658


10,658

 
 
 
 
Total derivative assets
$
11,623

$
8,931

$
20,554



89



 
As of Dec. 31, 2011
Derivative Liabilities
Gross Amounts of Derivative Liabilities
Gross Amounts Offset on Consolidated Balance Sheet
Net Amount of Total Derivative Liabilities on Consolidated Balance Sheet
 
 
Subject to a master netting agreement or similar arrangement:
 
 
 
Commodity derivative:
 
 
 
Utilities
$
17,643

$
(10,487
)
$
7,156

Total derivative liabilities subject to a master netting agreement or similar arrangement
17,643

(10,487
)
7,156

 
 
 
 
Not subject to a master netting agreement or similar arrangement:
 
 
 
Commodity derivative:
 
 
 
Oil and Gas - Crude Options
3,370


3,370

Oil and Gas - Natural Gas Basis Swaps
7


7

Interest Rate Swaps
122,867


122,867

Total derivative liabilities not subject to a master netting agreement or similar arrangement
126,244


126,244

 
 
 
 
Total derivative liabilities
$
143,887

$
(10,487
)
$
133,400


Derivative assets and derivative liabilities and collateral held by counterparty on our Consolidated Balance Sheet were (in thousands):
 
 
As of Dec. 31, 2011
 
 
 
Gross Amounts Not Offset on Consolidated Balance Sheet
 
Contract Type
 
Net Amount of Total Derivative Assets
Cash Collateral Received
Net Amount with Counterparty
Asset:
 
 
 
 
Oil and Gas
Counterparty A
$

$

$

Oil and Gas
Counterparty B
10,658


10,658

Utilities
Counterparty A
9,896


9,896

 
 
$
20,554

$

$
20,554



90



 
 
As of Dec. 31, 2011
 
 
 
Gross Amounts Not Offset on Consolidated Balance Sheet
 
Contract Type
 
Net Amount of Total Derivative Liabilities
Cash Collateral Posted
Net Amount with Counterparty
Liabilities
 
 
 
 
Oil and Gas
Counterparty A
$

$

$

Oil and Gas
Counterparty B
3,377


3,377

Utilities
Counterparty A
7,156


7,156

Interest Rate Swap
Counterparty D
5,140


5,140

Interest Rate Swap
Counterparty E
31,095


31,095

Interest Rate Swap
Counterparty F
13,880


13,880

Interest Rate Swap
Counterparty G
26,329


26,329

Interest Rate Swap
Counterparty H
23,203


23,203

Interest Rate Swap
Counterparty I
23,220


23,220

 
 
$
133,400

$

$
133,400



91


ITEM 6.
Exhibits

Exhibit Number
Description
 
 
Exhibit 2.1*
Stock Purchase Agreement by and between Twin Eagle Resource Management, LLC and Black Hills Non-Regulated Holdings LLC for the purchase of capital stock of Enserco Energy Inc., dated January 18, 2012 (filed as Exhibit 10.1 to the Registrant’s Form 10-Q for the quarterly period ended March 31, 2012).
 
 
Exhibit 2.2*
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) (filed as Exhibit 2 to the Registrant’s Form 10-Q for the quarterly period ended September 30, 2012).
 
 
Exhibit 3.1*
Restated Articles of Incorporation of the Registrant (filed as Exhibit 3 to the Registrant’s Form 10-K for 2004).
 
 
Exhibit 3.2*
Amended and Restated Bylaws of the Registrant dated January 28, 2010 (filed as Exhibit 3 to the Registrant’s Form 8-K filed on February 3, 2010).
 
 
Exhibit 4.1*
Indenture dated as of May 21, 2003 between the Registrant and Wells Fargo Bank, National Association (as successor to LaSalle Bank National Association), as Trustee (filed as Exhibit 4.1 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2003). First Supplemental Indenture dated as of May 21, 2003 (filed as Exhibit 4.2 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2003). Second Supplemental Indenture dated as of May 14, 2009 (filed as Exhibit 4 to the Registrant’s Form 8-K filed on May 14, 2009). Third Supplemental Indenture dated as of July 16, 2010 (filed as Exhibit 4 to the Registrant’s Form 8-K filed on July 15, 2010).
 
 
Exhibit 4.2*
Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as Exhibit 4.19 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669)). First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to JPMorgan Chase Bank), as Trustee (filed as Exhibit 4.20 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S‑3 (No. 333‑150669)). Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 4.21 to the Registrant’s Post-Effective Amendment No. 2 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669)).
 
 
Exhibit 4.3*
Form of Stock Certificate for Common Stock, Par Value $1.00 Per Share (filed as Exhibit 4.2 to the Registrant’s Form 10-K for 2000).

92




Exhibit Number
Description
 
 
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.
__________
*
Previously filed as part of the filing indicated and incorporated by reference herein.



93



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 5, 2013
 


94



INDEX TO EXHIBITS

Exhibit Number
Description
 
 
Exhibit 2.1*
Stock Purchase Agreement by and between Twin Eagle Resource Management, LLC and Black Hills Non-Regulated Holdings LLC for the purchase of capital stock of Enserco Energy Inc., dated January 18, 2012 (filed as Exhibit 10.1 to the Registrant’s Form 10-Q for the quarterly period ended March 31, 2012).
 
 
Exhibit 2.2*
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) (filed as Exhibit 2 to the Registrant’s Form 10-Q for the quarterly period ended September 30, 2012).
 
 
Exhibit 3.1*
Restated Articles of Incorporation of the Registrant (filed as Exhibit 3 to the Registrant’s Form 10-K for 2004).
 
 
Exhibit 3.2*
Amended and Restated Bylaws of the Registrant dated January 28, 2010 (filed as Exhibit 3 to the Registrant’s Form 8-K filed on February 3, 2010).
 
 
Exhibit 4.1*
Indenture dated as of May 21, 2003 between the Registrant and Wells Fargo Bank, National Association (as successor to LaSalle Bank National Association), as Trustee (filed as Exhibit 4.1 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2003). First Supplemental Indenture dated as of May 21, 2003 (filed as Exhibit 4.2 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2003). Second Supplemental Indenture dated as of May 14, 2009 (filed as Exhibit 4 to the Registrant’s Form 8-K filed on May 14, 2009). Third Supplemental Indenture dated as of July 16, 2010 (filed as Exhibit 4 to the Registrant’s Form 8-K filed on July 15, 2010).
 
 
Exhibit 4.2*
Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as Exhibit 4.19 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669)). First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to JPMorgan Chase Bank), as Trustee (filed as Exhibit 4.20 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S‑3 (No. 333‑150669)). Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 4.21 to the Registrant’s Post-Effective Amendment No. 2 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669)).
 
 
Exhibit 4.3*
Form of Stock Certificate for Common Stock, Par Value $1.00 Per Share (filed as Exhibit 4.2 to the Registrant’s Form 10-K for 2000).



95



Exhibit Number
Description
 
 
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.
__________
*
Previously filed as part of the filing indicated and incorporated by reference herein.


96