BKH 10Q Q2 2014


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 June 30, 2014
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 July 31, 2014
Common stock, $1.00 par value
44,641,421

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 Six Months Ended June 30, 2014 and 2013
 
 
 
 
 
 
Condensed Consolidated Statements of Comprehensive Income (Loss) - unaudited
 
 
 
   Three and Six Months Ended June 30, 2014 and 2013
 
 
 
 
 
 
Condensed Consolidated Balance Sheets - unaudited
 
 
 
   June 30, 2014, December 31, 2013 and June 30, 2013
 
 
 
 
 
 
Condensed Consolidated Statements of Cash Flows - unaudited
 
 
 
   Six Months Ended June 30, 2014 and 2013
 
 
 
 
 
 
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 issued by the FASB
Bbl
Barrel
BHC
Black Hills Corporation; the Company
Black Hills Electric Generation
Black Hills Electric Generation, LLC, 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
Btu
British thermal unit
Cheyenne Light
Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation
Cheyenne Prairie
Cheyenne Prairie Generating Station currently being constructed in Cheyenne, Wyoming by Cheyenne Light and Black Hills Power. Construction is expected to be completed for this 132 megawatt facility in 2014.
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
CT
Combustion turbine
CVA
Credit Valuation Adjustment
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 subsequently de-designated in December 2008. These swaps were settled in November 2013.
Dth
Dekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu)
EPA
United States Environmental Protection Agency
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
GCA
Gas Cost Adjustment -- adjustments that allow us to pass the prudently-incurred cost of gas and certain services through to customers.

3



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.
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
KCC
Kansas Corporation Commission
kV
Kilovolt
LIBOR
London Interbank Offered Rate
LOE
Lease Operating Expense
Mcf
Thousand cubic feet
Mcfe
Thousand cubic feet equivalent.
MMBtu
Million British thermal units
Moody’s
Moody’s Investors Service, Inc.
MW
Megawatts
MWh
Megawatt-hours
NGL
Natural Gas Liquids (7 Gallons equals 1 Mcfe)
NOAA
National Oceanic and Atmospheric Administration
NOAA Climate Normals
This dataset is produced once every 10 years. This dataset contains daily and monthly normals of temperature, precipitation, snowfall, heating and cooling degree days, frost/freeze dates, and growing degree days calculated from observations at approximately 9,800 stations operated by NOAA’s National Weather Service.
NOL
Net Operating Loss
OTC
Over-the-counter
PPA
Power Purchase Agreement
Revolving Credit Facility
Our $500 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, which matures in 2019.
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
WRDC
Wyodak Resources Development Corp., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings

4





BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS)
(unaudited)
Three Months Ended
June 30,
Six Months Ended
June 30,
 
2014
2013
2014
2013
 
(in thousands, except per share amounts)
 
 
 
 
 
Revenue
$
283,237

$
279,826

$
743,406

$
660,497

 
 
 
 
 
Operating expenses:
 
 
 
 
Utilities -
 
 
 
 
Fuel, purchased power and cost of natural gas sold
101,331

99,172

331,799

267,345

Operations and maintenance
66,074

64,977

137,301

130,667

Non-regulated energy operations and maintenance
21,350

20,890

43,682

42,219

Depreciation, depletion and amortization
36,712

35,152

72,795

69,933

Taxes - property, production and severance
11,044

10,069

21,380

20,449

Other operating expenses
149

529

274

1,001

Total operating expenses
236,660

230,789

607,231

531,614

 
 
 
 
 
Operating income
46,577

49,037

136,175

128,883

 
 
 
 
 
Other income (expense):
 
 
 
 
Interest charges -
 
 
 
 
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts and realized settlements on interest rate swaps)
(17,886
)
(23,369
)
(35,746
)
(47,041
)
Allowance for funds used during construction - borrowed
256

411

526

484

Capitalized interest
246

272

503

538

Unrealized gain (loss) on interest rate swaps, net

18,793


26,249

Interest income
576

475

966

760

Allowance for funds used during construction - equity
293

42

531

242

Other income (expense), net
409

473

1,000

879

Total other income (expense), net
(16,106
)
(2,903
)
(32,220
)
(17,889
)
 
 
 
 
 
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes
30,471

46,134

103,955

110,994

Equity in earnings (loss) of unconsolidated subsidiaries



(86
)
Income tax benefit (expense)
(10,651
)
(15,616
)
(36,017
)
(37,193
)
Net income (loss) available for common stock
$
19,820

$
30,518

$
67,938

$
73,715

 
 
 
 
 
Earnings (loss) per share of common stock:
 
 
 
 
Earnings (loss) per share, Basic -
 
 
 
 
Total income (loss) per share, Basic
$
0.45

$
0.69

$
1.53

$
1.67

Earnings (loss) per share, Diluted -
 
 
 
 
Total income (loss) per share, Diluted
$
0.44

$
0.69

$
1.52

$
1.66

Weighted average common shares outstanding:
 
 
 
 
Basic
44,399

44,172

44,365

44,113

Diluted
44,588

44,412

44,571

44,363

 
 
 
 
 
Dividends paid per share of common stock
$
0.39

$
0.38

$
0.78

$
0.76


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

5





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


(unaudited)
Three Months Ended
June 30,
Six Months Ended
June 30,
 
2014
2013
2014
2013
 
(in thousands)
 
 
 
 
 
Net income (loss) available for common stock
$
19,820

$
30,518

$
67,938

$
73,715

 
 
 
 
 
Other comprehensive income (loss), net of tax:
 
 
 
 
Fair value adjustments on derivatives designated as cash flow hedges (net of tax (expense) benefit of $1,115 and $(2,174) for the three months ended 2014 and 2013 and $2,422 and $(1,057) for the six months ended 2014 and 2013, respectively)
(1,959
)
3,878

(4,216
)
2,217

Reclassification adjustments for cash flow hedges settled and included in net income (loss) (net of tax (expense) benefit of $(774) and $(647) for the three months ended 2014 and 2013 and $(1,199) and $(883) for the six months ended 2014 and 2013, respectively)
1,403

1,201

2,183

1,669

Benefit plan liability adjustments - net gain (loss) (net of tax of $0 and $0 for the three months ended 2014 and 2013 and $2 and $0 for the six months ended 2014 and 2013, respectively)


(2
)

Benefit plan liability tax adjustments - net gain (loss)
(394
)

(394
)

Benefit plan liability adjustments - prior service cost (net of tax of $0 and $0 for the three months ended 2014 and 2013 and $(90) and $0 for the six months ended 2014 and 2013, respectively)


164


Reclassification adjustments of benefit plan liability - prior service cost (net of tax of $39 and $(268) for the three months ended 2014 and 2013 and $43 and $(251) for the six months ended 2014 and 2013, respectively)
(70
)
364

(79
)
318

Reclassification adjustments of benefit plan liability - net gain (loss) (net of tax of $(91) and $0 for the three months ended 2014 and 2013 and $(176) and $(192) for the six months ended 2014 and 2013, respectively)
168


325

503

Other comprehensive income (loss), net of tax
(852
)
5,443

(2,019
)
4,707

 
 
 
 
 
Comprehensive income (loss) available for common stock
$
18,968

$
35,961

$
65,919

$
78,422


See Note 11 for additional disclosures.

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

6



BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)
As of
 
June 30,
2014
 
December 31, 2013
 
June 30,
2013
 
(in thousands)
ASSETS
 
 
 
 
 
Current assets:
 
 
 
 
 
Cash and cash equivalents
$
14,697

 
$
7,841

 
$
30,633

Restricted cash and equivalents
2

 
2

 
7,279

Accounts receivable, net
135,145

 
177,573

 
132,726

Materials, supplies and fuel
81,164

 
88,478

 
73,768

Derivative assets, current
1,737

 
717

 
903

Income tax receivable, net
1,043

 
1,460

 
146

Deferred income tax assets, net, current
23,872

 
18,889

 
38,764

Regulatory assets, current
64,735

 
24,451

 
26,258

Other current assets
21,660

 
25,877

 
27,595

Total current assets
344,055

 
345,288

 
338,072

 
 
 
 
 
 
Investments
17,096

 
16,697

 
16,566

 
 
 
 
 
 
Property, plant and equipment
4,408,291

 
4,259,445

 
4,066,502

Less: accumulated depreciation and depletion
(1,325,660
)
 
(1,269,148
)
 
(1,234,578
)
Total property, plant and equipment, net
3,082,631

 
2,990,297

 
2,831,924

 
 
 
 
 
 
Other assets:
 
 
 
 
 
Goodwill
353,396

 
353,396

 
353,396

Intangible assets, net
3,286

 
3,397

 
3,508

Regulatory assets, non-current
138,226

 
138,197

 
180,646

Other assets, non-current
31,808

 
27,906

 
22,402

Total other assets, non-current
526,716

 
522,896

 
559,952

 
 
 
 
 
 
TOTAL ASSETS
$
3,970,498

 
$
3,875,178

 
$
3,746,514


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

7



BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Continued)
(unaudited)
As of
 
June 30,
2014
 
December 31, 2013
 
June 30,
2013
 
(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
 
 
Current liabilities:
 
 
 
 
 
Accounts payable
$
100,098

 
$
130,416

 
$
88,071

Accrued liabilities
141,177

 
151,277

 
135,819

Derivative liabilities, current
3,480

 
3,474

 
69,270

Regulatory liabilities, current
828

 
10,727

 
20,550

Notes payable
132,700

 
82,500

 
100,000

Current maturities of long-term debt
275,000

 

 
255,507

Total current liabilities
653,283

 
378,394

 
669,217

 
 
 
 
 
 
Long-term debt, net of current maturities
1,121,950

 
1,396,948

 
958,559

 
 
 
 
 
 
Deferred credits and other liabilities:
 
 
 
 
 
Deferred income tax liabilities, net, non-current
476,059

 
432,287

 
387,674

Derivative liabilities, non-current
4,251

 
5,614

 
12,384

Regulatory liabilities, non-current
119,462

 
109,429

 
129,013

Benefit plan liabilities
116,403

 
111,479

 
177,216

Other deferred credits and other liabilities
137,765

 
133,279

 
129,763

Total deferred credits and other liabilities
853,940

 
792,088

 
836,050

 
 
 
 
 
 
Commitments and contingencies (See Notes 7, 8, 13, 14 and 15)


 

 

 
 
 
 
 
 
Stockholders’ equity:
 
 
 
 
 
Common stock equity —
 
 
 
 
 
Common stock $1 par value; 100,000,000 shares authorized; issued 44,682,885; 44,550,239; and 44,516,472 shares, respectively
44,683

 
44,550

 
44,517

Additional paid-in capital
744,505

 
742,344

 
737,729

Retained earnings
573,379

 
540,244

 
532,810

Treasury stock, at cost – 40,951; 50,877; and 42,480 shares, respectively
(1,801
)
 
(1,968
)
 
(1,587
)
Accumulated other comprehensive income (loss)
(19,441
)
 
(17,422
)
 
(30,781
)
Total stockholders’ equity
1,341,325

 
1,307,748

 
1,282,688

 
 
 
 
 
 
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
$
3,970,498

 
$
3,875,178

 
$
3,746,514


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

8



BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
Six Months Ended June 30,
 
2014
2013
Operating activities:
(in thousands)
Net income (loss) available for common stock
$
67,938

$
73,715

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
Depreciation, depletion and amortization
72,795

69,933

Deferred financing cost amortization
1,107

2,188

Derivative fair value adjustments
(1,660
)
4,248

Stock compensation
6,908

6,896

Unrealized (gain) loss on interest rate swaps, net

(26,249
)
Deferred income taxes
35,514

36,607

Employee benefit plans
7,409

11,096

Other adjustments, net
1,481

8,967

Changes in certain operating assets and liabilities:
 
 
Materials, supplies and fuel
7,314

8,940

Accounts receivable, unbilled revenues and other operating assets
(5,851
)
28,377

Accounts payable and other operating liabilities
(24,978
)
(26,739
)
Other operating activities, net
5,858

(594
)
Net cash provided by (used in) operating activities
173,835

197,385

 
 
 
Investing activities:
 
 
Property, plant and equipment additions
(177,302
)
(147,230
)
Other investing activities
(2,994
)
2,006

Net cash provided by (used in) investing activities
(180,296
)
(145,224
)
 
 
 
Financing activities:
 
 
Dividends paid on common stock
(34,803
)
(33,774
)
Common stock issued
1,693

2,570

Short-term borrowings - issuances
214,100

133,300

Short-term borrowings - repayments
(163,900
)
(310,300
)
Long-term debt - issuances

275,000

Long-term debt - repayments

(103,786
)
Other financing activities
(3,773
)

Net cash provided by (used in) financing activities
13,317

(36,990
)
Net change in cash and cash equivalents
6,856

15,171

Cash and cash equivalents, beginning of period
7,841

15,462

Cash and cash equivalents, end of period
$
14,697

$
30,633


See Note 12 for supplemental disclosure of cash flow information.

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

9



BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Reference is made to Notes to Consolidated Financial Statements
included in the Company’s 2013 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 2013 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 June 30, 2014, December 31, 2013, and June 30, 2013 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 six months ended June 30, 2014 and June 30, 2013, and our financial condition as of June 30, 2014, December 31, 2013, and June 30, 2013, 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.

Recently Issued and Adopted Accounting Standards

We have implemented all new accounting pronouncements that are in effect and may impact our financial statements and do not believe that there are any other new accounting pronouncements that have been issued that might have a material impact on our financial position, results of operations, or cash flows.

Revenue from Contracts with Customers, ASU 2014-09
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The standard provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer, as opposed to recognizing revenue when the risks and rewards transfer to the customer under the existing revenue guidance. ASU 2014-09 is effective for annual and interim reporting periods beginning after December 15, 2016 and early adoption is not permitted. We are currently assessing the impact, if any, that ASU 2014-09 will have on our financial position, results of operations, or cash flows.



10




(2)    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 June 30, 2014
 
External
Operating
Revenue
 
Inter-company
Operating
Revenue
 
Net Income (Loss)
Utilities:
 
 
 
 
 
 
   Electric
 
$
158,740

 
$
3,144

 
$
11,427

   Gas
 
102,499

 

 
1,994

Non-regulated Energy:
 
 
 
 
 
 
   Power Generation
 
1,267

 
20,713

 
7,194

   Coal Mining
 
5,583

 
9,068

 
2,016

   Oil and Gas
 
15,148

 

 
(1,660
)
Corporate activities
 

 

 
(1,151
)
Inter-company eliminations
 

 
(32,925
)
 

Total
 
$
283,237

 
$

 
$
19,820


Three Months Ended June 30, 2013
 
External
Operating
Revenue
 
Inter-company
Operating
Revenue
 
Net Income (Loss)
Utilities:
 
 
 
 
 
 
   Electric
 
$
154,338

 
$
3,694

 
$
10,610

   Gas
 
105,836

 

 
3,192

Non-regulated Energy:
 
 
 
 
 
 
   Power Generation
 
1,031

 
19,094

 
5,031

   Coal Mining
 
6,807

 
7,511

 
1,973

   Oil and Gas
 
11,814

 

 
(1,964
)
Corporate activities (a)
 

 

 
11,679

Inter-company eliminations
 

 
(30,299
)
 
(3
)
Total
 
$
279,826

 
$

 
$
30,518


Six Months Ended June 30, 2014
 
External
Operating
Revenues
 
Intercompany
Operating
Revenues
 
Net Income (Loss)
Utilities:
 
 
 
 
 
 
   Electric
 
$
336,835

 
$
7,151

 
$
26,002

   Gas
 
361,836

 

 
26,692

Non-regulated Energy:
 
 
 
 
 
 
   Power Generation
 
2,536

 
41,792

 
15,267

   Coal Mining
 
12,201

 
17,948

 
4,480

   Oil and Gas
 
29,998

 

 
(3,682
)
Corporate activities
 

 

 
(821
)
Inter-company eliminations
 

 
(66,891
)
 

Total
 
$
743,406

 
$

 
$
67,938


11



Six Months Ended June 30, 2013
 
External
Operating
Revenues
 
Intercompany
Operating
Revenues
 
Net Income (Loss)
Utilities:
 
 
 
 
 
 
   Electric
 
$
312,821

 
$
7,841

 
$
22,966

   Gas
 
305,648

 

 
21,675

Non-regulated Energy:
 
 
 
 
 
 
   Power Generation
 
2,053

 
38,432

 
10,675

   Coal Mining
 
12,817

 
15,084

 
3,038

   Oil and Gas
 
27,158

 

 
(2,017
)
Corporate activities (a)
 

 

 
17,378

Inter-company eliminations
 

 
(61,357
)
 

Total
 
$
660,497

 
$

 
$
73,715

__________
(a)
Corporate activities include a $12 million and a $17 million after-tax non-cash mark-to-market gain for the three and six months ended June 30, 2013, respectively on certain interest rate swaps.

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:
June 30, 2014
 
December 31, 2013
 
June 30, 2013
Utilities:
 
 
 
 
 
   Electric (a)
$
2,603,900

 
$
2,525,947

 
$
2,417,952

   Gas
799,365

 
805,617

 
734,337

Non-regulated Energy:
 
 
 
 
 
   Power Generation (a)
85,269

 
95,692

 
108,515

   Coal Mining
73,701

 
78,825

 
82,553

   Oil and Gas
307,837

 
288,366

 
256,855

Corporate activities
100,426

 
80,731

 
146,302

Total assets
$
3,970,498

 
$
3,875,178

 
$
3,746,514

__________
(a)
The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation Station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease.


12



 
(3)    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
June 30, 2014
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
48,333

$
21,716

$
(622
)
$
69,427

Gas Utilities
43,104

9,265

(1,027
)
51,342

Power Generation
1,388



1,388

Coal Mining
1,866



1,866

Oil and Gas
9,123


(13
)
9,110

Corporate
2,012



2,012

Total
$
105,826

$
30,981

$
(1,662
)
$
135,145


 
Accounts
Unbilled
Less Allowance for
Accounts
December 31, 2013
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
52,437

$
23,823

$
(666
)
$
75,594

Gas Utilities
49,162

41,195

(558
)
89,799

Power Generation
1,722



1,722

Coal Mining
1,711



1,711

Oil and Gas
8,156


(13
)
8,143

Corporate
604



604

Total
$
113,792

$
65,018

$
(1,237
)
$
177,573


 
Accounts
Unbilled
Less Allowance for
Accounts
June 30, 2013
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
45,250

$
24,290

$
(630
)
$
68,910

Gas Utilities
38,749

13,192

(1,074
)
50,867

Power Generation
157



157

Coal Mining
2,503



2,503

Oil and Gas
8,373


(19
)
8,354

Corporate
1,935



1,935

Total
$
96,967

$
37,482

$
(1,723
)
$
132,726



13




(4)    REGULATORY ACCOUNTING

We had the following regulatory assets and liabilities (in thousands):
 
Maximum
As of
As of
As of
 
Amortization (in years)
June 30, 2014
December 31, 2013
June 30, 2013
Regulatory assets
 
 
 
 
Deferred energy and fuel cost adjustments - current (a)(d)
1
$
29,605

$
16,775

$
15,951

Deferred gas cost adjustments and natural gas price derivatives (a)(d)
7
39,040

12,366

13,090

AFUDC (b)
45
12,468

12,315

12,456

Employee benefit plans (c)
13
65,874

67,059

115,379

Environmental (a)
subject to approval
1,314

1,800

1,798

Asset retirement obligations (a)
44
3,278

3,266

3,257

Bond issue cost (a)
24
3,347

3,419

3,489

Renewable energy standard adjustment (a)
5
14,501

14,186

14,694

Flow through accounting (c)
35
22,754

20,916

17,995

Other regulatory assets (a)
15
10,780

10,546

8,795

 
 
$
202,961

$
162,648

$
206,904

 
 
 
 
 
Regulatory liabilities
 
 
 
 
Deferred energy and gas costs (a)
1
$
6,490

$
11,708

$
22,340

Employee benefit plans (c)
13
34,356

34,431

60,214

Cost of removal (a)
44
70,841

64,970

59,461

Other regulatory liabilities (c)
25
8,603

9,047

7,548

 
 
$
120,290

$
120,156

$
149,563

__________
(a)
Recovery of costs, but we are not allowed a rate of return.
(b)
In addition to recovery of costs, we are allowed a rate of return.
(c)
In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base, respectively.
(d)
Our deferred energy, fuel cost, and gas cost adjustments represent the cost of electricity and gas delivered to our electric and gas utility customers that is either higher or lower than current rates and will be recovered or refunded in future rates. Increases in the current year balances as of June 30, 2014 are primarily due to higher natural gas prices driven by demand and market conditions during our peak winter heating season. Our electric and gas utilities file periodic quarterly, semi-annual, and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state utility commissions.


(5)    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:
 
June 30, 2014
 
December 31, 2013
 
June 30, 2013
Materials and supplies
$
51,925

 
$
50,196

 
$
51,334

Fuel - Electric Utilities
7,679

 
6,213

 
6,817

Natural gas in storage held for distribution
21,560

 
32,069

 
15,617

Total materials, supplies and fuel
$
81,164

 
$
88,478

 
$
73,768



14




(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 June 30,
 
Six Months Ended June 30,
 
2014
2013
 
2014
2013
 
 
 
 
 
 
Net income (loss) available for common stock
$
19,820

$
30,518

 
$
67,938

$
73,715

 
 
 
 
 
 
Weighted average shares - basic
44,399

44,172

 
44,365

44,113

Dilutive effect of:
 
 
 
 
 
Equity compensation
189

240

 
206

250

Weighted average shares - diluted
44,588

44,412

 
44,571

44,363


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 June 30,
 
Six Months Ended June 30,
 
2014
2013
 
2014
2013
 
 
 
 
 
 
Equity compensation
81

28

 
63

34

Anti-dilutive shares
81

28

 
63

34



(7)    NOTES PAYABLE AND CURRENT MATURITIES OF LONG-TERM DEBT

We had the following short-term debt outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
 
June 30, 2014
December 31, 2013
June 30, 2013
 
Balance Outstanding
Letters of Credit
Balance Outstanding
Letters of Credit
Balance Outstanding
Letters of Credit
Revolving Credit Facility
$
132,700

$
20,272

$
82,500

$
22,100

$
100,000

$
43,157


Revolving Credit Facility

On May 29, 2014, we amended our $500 million corporate Revolving Credit Facility agreement to extend the term through May 29, 2019. This facility is substantially similar to the former agreement, which includes 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 continue to be 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 our most favorable Corporate credit rating from S&P and Moody’s for our unsecured debt. Based on our credit ratings, the margins for base rate borrowings, Eurodollar borrowings and letters of credit were 0.125%, 1.125% and 1.125%, respectively, from May 29, 2014 through June 30, 2014; a reduction of 0.25% for each method of borrowing as compared to the previous arrangement. Borrowings under the facility are primarily Eurodollar based. A commitment fee is charged on the unused amount of the Revolving Credit Facility and was 0.175% based on our credit rating, a reduction of 0.025% compared to the prior arrangement.

Current Maturities Of Long-Term Debt

As of June 30, 2014, our Corporate term loan due June 19, 2015, for $275 million has been re-classified to Current maturities of long-term debt from Long-term debt, net of current maturities.




15





Debt Covenants

Our Revolving Credit Facility and our Term Loan require compliance with the following financial covenant at the end of each quarter:
 
As of June 30, 2014
 
Covenant Requirement
Recourse Leverage Ratio
54%
 
Less than
65%

As of June 30, 2014, we were in compliance with this covenant.

(8)    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 2013 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.

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 June 30, 2014, our credit exposure included a $0.5 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 9.


16



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 OTC 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).

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 Sheets were as follows (dollars in thousands) as of:
 
June 30, 2014
 
December 31, 2013
 
June 30, 2013
 
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)
424,500

9,265,000

 
412,500

7,082,500

 
520,500

10,712,500

Maximum terms in months (b)
1

1

 
3

1

 
6

1

Derivative assets, current
$

$

 
$
55

$

 
$
610

$
293

Derivative assets, non-current
$

$

 
$

$

 
$

$

Derivative liabilities, current
$

$

 
$

$

 
$
130

$
276

Derivative liabilities, non-current
$

$

 
$

$

 
$

$

__________
(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.
A $3.4 million loss is included in AOCI at June 30, 2014, and would be realized over the next 12 months if market prices remained equal to June 30, 2014 prices. Future realized gains or losses fluctuate with market prices.

Utilities

The operations of our utilities, including natural gas sold by our Gas Utilities and natural gas used for Electric Utility generation plants or those plants under PPAs where our Electric 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. When the related costs are recovered through our rates, the hedging activity is recognized in the Condensed Consolidated Statements of Income (Loss).

17




The contract or notional amounts and terms of the natural gas derivative commodity instruments held at our Utilities were as follows, as of:
 
June 30, 2014
 
December 31, 2013
 
June 30, 2013
 
Notional
(MMBtus)
 
Maximum
Term
(months)
 
Notional
(MMBtus)
 
Maximum
Term
(months)
 
Notional
(MMBtus)
 
Maximum
Term
(months)
Natural gas futures purchased
16,240,000

 
78
 
17,930,000

 
84
 
13,330,000

 
77
Natural gas options purchased
3,980,000

 
9
 
3,890,000

 
8
 
2,850,000

 
5
Natural gas basis swaps purchased
13,415,000

 
66
 
14,785,000

 
60
 
10,650,000

 
66

We had the following derivative balances related to the hedges in our Utilities reflected in our Condensed Consolidated Balance Sheets as of (in thousands):
 
June 30, 2014
December 31, 2013
June 30, 2013
Derivative assets, current
$
1,737

$
662

$

Derivative assets, non-current
$

$

$

Derivative liabilities, non-current
$

$

$

Net unrealized (gain) loss included in Regulatory assets or Regulatory liabilities
$
3,561

$
7,567

$
8,450


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 Sheets were as follows (dollars in thousands) as of:
 
June 30, 2014
 
December 31, 2013
 
June 30, 2013
 
Interest Rate
Swaps (a)
 
Interest Rate
Swaps (a)
 
Interest Rate
Swaps (b)
De-designated
Interest Rate
Swaps (c)
Notional
$
75,000

 
$
75,000

 
$
150,000

$
250,000

Weighted average fixed interest rate
4.97
%
 
4.97
%
 
5.04
%
5.67
%
Maximum terms in years
2.5

 
3.0

 
3.5

0.5

Derivative liabilities, current
$
3,480

 
$
3,474

 
$
6,965

$
61,899

Derivative liabilities, non-current
$
4,251

 
$
5,614

 
$
12,384

$

__________
(a)
These swaps are designated to borrowings on our Revolving Credit Facility, and are priced using three-month LIBOR, matching the floating portion of the related debt.
(b)
At June 30, 2013, $75 million of these interest rate swaps were designated to borrowings on our Revolving Credit Facility and $75 million were designated to borrowings on our project financing debt at Black Hills Wyoming. These swaps are priced using three-month LIBOR, matching the floating portion of the related debt. The portion of the swaps that were designated to Black Hills Wyoming were settled during the fourth quarter of 2013 upon repayment of the Black Hills Wyoming project financing.
(c)
These swaps were settled during the fourth quarter of 2013.

Based on June 30, 2014, market interest rates and balances related to our interest rate swaps, a loss of approximately $3.5 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.


18



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 June 30, 2014
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
 
$
(337
)
 
Interest expense
 
$
(926
)
 
 
 
$

Commodity derivatives
 
(2,737
)
 
Revenue
 
(1,251
)
 
 
 

Total
 
$
(3,074
)
 
 
 
$
(2,177
)
 
 
 
$


Three Months Ended June 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
 
$
1,067

 
Interest expense
 
$
(1,820
)
 
 
 
$

Commodity derivatives
 
4,985

 
Revenue
 
(28
)
 
 
 

Total
 
$
6,052

 
 
 
$
(1,848
)
 
 
 
$


Six Months Ended June 30, 2014
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
 
$
(429
)
 
Interest expense
 
$
(1,820
)
 
 
 
$

Commodity derivatives
 
(6,209
)
 
Revenue
 
(1,562
)
 
 
 

Total
 
$
(6,638
)
 
 
 
$
(3,382
)
 
 
 
$


Six Months Ended June 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
 
$
1,048

 
Interest expense
 
$
(3,616
)
 
 
 
$

Commodity derivatives
 
2,226

 
Revenue
 
1,064

 
 
 

Total
 
$
3,274

 
 
 
$
(2,552
)
 
 
 
$



19



 
(9)    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, 8 and 10 to the Consolidated Financial Statements included in our 2013 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 with 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 a 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 a 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.


20



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 10:

 
As of June 30, 2014
 
Level 1
Level 2
Level 3
 
Cash Collateral and Counterparty
Netting
Total
 
(in thousands)
Assets:
 
 
 
 
 
 
Commodity derivatives — Oil and Gas
 
 
 
 
 


    Options -- Oil
$

$

$

 
$

$

    Basis Swaps -- Oil



 


    Options -- Gas



 


    Basis Swaps -- Gas

600


 
(600
)

Commodity derivatives — Utilities

4,342


 
(2,605
)
1,737

Total
$

$
4,942

$

 
$
(3,205
)
$
1,737

 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
Commodity derivatives — Oil and Gas
 
 
 
 
 


Options -- Oil
$

$

$

 
$

$

Basis Swaps -- Oil

4,020


 
(4,020
)

Options -- Gas



 


Basis Swaps -- Gas

2,030


 
(2,030
)

Commodity derivatives — Utilities

5,989


 
(5,989
)

Interest rate swaps

7,731


 

7,731

Total
$

$
19,770

$

 
$
(12,039
)
$
7,731




21




 
As of December 31, 2013
 
Level 1
Level 2
Level 3
 
Cash Collateral and Counterparty
Netting
Total
 
(in thousands)
Assets:
 
 
 
 
 
 
Commodity derivatives — Oil and Gas
 
 
 
 
 
 
Options -- Oil
$

$

$

 
$

$

Basis Swaps -- Oil

130


 
(75
)
55

Options -- Gas



 


Basis Swaps -- Gas

815


 
(815
)

Commodity derivatives —Utilities

3,030


 
(2,368
)
662

Total
$

$
3,975

$

 
$
(3,258
)
$
717

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

$

$

 
$

$

Basis Swaps -- Oil

1,229


 
(1,229
)

Options -- Gas



 


Basis Swaps -- Gas

531


 
(531
)

Commodity derivatives — Utilities

9,100


 
(9,100
)

Interest rate swaps

9,088


 

9,088

Total
$

$
19,948

$

 
$
(10,860
)
$
9,088



 
As of June 30, 2013
 
Level 1
Level 2
Level 3
 
Cash Collateral and Counterparty
Netting
Total
 
(in thousands)
Assets:
 
 
 
 
 
 
Commodity derivatives — Oil and Gas
 
 
 
 
 
 
Options -- Oil
$

$
45

$

 
$
(6
)
$
39

Basis Swaps -- Oil

1,109


 
(538
)
571

Options -- Gas



 


Basis Swaps -- Gas

1,882


 
(1,589
)
293

Commodity derivatives — Utilities

1,378


 
(1,378
)

Total
$

$
4,414

$

 
$
(3,511
)
$
903

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

$
181

$

 
$
(98
)
$
83

Basis Swaps -- Oil

350


 
(303
)
47

Options -- Gas



 


Basis Swaps -- Gas

445


 
(169
)
276

Commodity derivatives — Utilities

8,581


 
(8,581
)

Interest rate swaps

87,208


 
(5,960
)
81,248

Total
$

$
96,765

$

 
$
(15,111
)
$
81,654



22




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 June 30, 2014, December 31, 2013, and June 30, 2013, 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 8.

The following tables present the fair value and balance sheet classification of our derivative instruments (in thousands):
As of June 30, 2014
 
Balance Sheet Location
 
Fair Value
of Asset
Derivatives
Fair Value
of Liability
Derivatives
Derivatives designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
262

$

Commodity derivatives
Derivative assets — non-current
 
338


Commodity derivatives
Derivative liabilities — current
 

3,702

Commodity derivatives
Derivative liabilities — non-current
 

2,348

Interest rate swaps
Derivative liabilities — current
 

3,480

Interest rate swaps
Derivative liabilities — non-current
 

4,251

Total derivatives designated as hedges
 
 
$
600

$
13,781

 
 
 
 
 
Derivatives not designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
1,737

$

Commodity derivatives
Derivative assets — non-current
 


Commodity derivatives
Derivative liabilities — current
 


Commodity derivatives
Derivative liabilities — non-current
 

3,384

Total derivatives not designated as hedges
 
 
$
1,737

$
3,384


As of December 31, 2013
 
Balance Sheet Location
 
Fair Value
of Asset
Derivatives
Fair Value
of Liability
Derivatives
Derivatives designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
248

$

Commodity derivatives
Derivative assets — non-current
 
698


Commodity derivatives
Derivative liabilities — current
 

1,541

Commodity derivatives
Derivative liabilities — non-current
 

219

Interest rate swaps
Derivative liabilities — current
 

3,474

Interest rate swaps
Derivative liabilities — non-current
 

5,614

Total derivatives designated as hedges
 
 
$
946

$
10,848

 
 
 
 
 
Derivatives not designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
662

$

Commodity derivatives
Derivative assets — non-current
 


Commodity derivatives
Derivative liabilities — current
 


Commodity derivatives
Derivative liabilities — non-current
 

6,732

Total derivatives not designated as hedges
 
 
$
662

$
6,732



23



As of June 30, 2013
 
Balance Sheet Location
 
Fair Value
of Asset
Derivatives
Fair Value
of Liability
Derivatives
Derivatives designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
1,225

$

Commodity derivatives
Derivative assets — non-current
 
1,651


Commodity derivatives
Derivative liabilities — current
 

889

Commodity derivatives
Derivative liabilities — non-current
 

41

Interest rate swaps
Derivative liabilities — current
 

6,965

Interest rate swaps
Derivative liabilities — non-current
 

12,384

Total derivatives designated as hedges
 
 
$
2,876

$
20,279

 
 
 
 
 
Derivatives not designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
160

$

Commodity derivatives
Derivative assets — non-current
 


Commodity derivatives
Derivative liabilities — current
 

1,884

Commodity derivatives
Derivative liabilities — non-current
 

5,365

Interest rate swaps
Derivative liabilities — current
 

67,859

Interest rate swaps
Derivative liabilities — non-current
 


Total derivatives not designated as hedges
 
 
$
160

$
75,108

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 



24




(10)    FAIR VALUE OF FINANCIAL INSTRUMENTS

The estimated fair values of our financial instruments, excluding derivatives which are presented in Note 9, were as follows (in thousands) as of:
 
June 30, 2014
 
December 31, 2013
 
June 30, 2013
 
Carrying
Amount
Fair Value
 
Carrying
Amount
Fair Value
 
Carrying
Amount
Fair Value
Cash and cash equivalents (a)
$
14,697

$
14,697

 
$
7,841

$
7,841

 
$
30,633

$
30,633

Restricted cash and equivalents (a)
$
2

$
2

 
$
2

$
2

 
$
7,279

$
7,279

Notes payable (a)
$
132,700

$
132,700

 
$
82,500

$
82,500

 
$
100,000

$
100,000

Long-term debt, including current maturities (b)
$
1,396,950

$
1,578,756

 
$
1,396,948

$
1,491,422

 
$
1,214,066

$
1,323,543

__________
(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.


(11)
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
Six Months Ended
June 30, 2014
June 30, 2013
June 30, 2014
June 30, 2013
Gains (losses) on cash flow hedges:
 
 
 
 
 
Interest rate swaps
Interest expense
$
926

$
1,820

$
1,820

$
3,616

Commodity contracts
Revenue
1,251

28

1,562

(1,064
)
 
 
2,177

1,848

3,382

2,552

Income tax
Income tax benefit (expense)
(774
)
(647
)
(1,199
)
(883
)
Reclassification adjustments related to cash flow hedges, net of tax
 
$
1,403

$
1,201

$
2,183

$
1,669

 
 
 
 
 
 
Amortization of defined benefit plans:
 
 
 
 
 
Prior service cost
Utilities - Operations and maintenance
$
(25
)
$
(31
)
$
(51
)
$
(62
)
 
Non-regulated energy operations and maintenance
(84
)
(32
)
(71
)
(64
)
 
 
 
 
 
 
Actuarial gain (loss)
Utilities - Operations and maintenance
158

421

315

842

 
Non-regulated energy operations and maintenance
101

274

186

548

 
 
150

632

379

1,264

Income tax
Income tax benefit (expense)
(52
)
(268
)
(133
)
(443
)
Reclassification adjustments related to defined benefit plans, net of tax
 
$
98

$
364

$
246

$
821



25



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 December 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
)
 
 
 
 
Balance as of December 31, 2013
$
(7,133
)
$
(10,289
)
$
(17,422
)
Other comprehensive income (loss), net of tax
(1,478
)
311

(1,167
)
Balance as of March 31, 2014
(8,611
)
(9,978
)
(18,589
)
Other comprehensive income (loss), net of tax
(556
)
(296
)
(852
)
Balance as of June 30, 2014
$
(9,167
)
$
(10,274
)
$
(19,441
)


(12)    SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

Six months ended
June 30, 2014
 
June 30, 2013
 
(in thousands)
Non-cash investing and financing activities from continuing operations—
 
 
 
Property, plant and equipment acquired with accrued liabilities
$
40,611

 
$
45,000

Increase (decrease) in capitalized assets associated with asset retirement obligations
$
(2,785
)
 
$

 
 
 
 
Cash (paid) refunded during the period for continuing operations—
 
 
 
Interest (net of amounts capitalized)
$
(35,009
)
 
$
(44,191
)
Income taxes, net
$
(396
)
 
$
(5,406
)


(13)    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 June 30,
Six Months Ended June 30,
 
2014
2013
2014
2013
Service cost
$
1,362

$
1,608

$
2,724

$
3,216

Interest cost
3,963

3,825

7,926

7,650

Expected return on plan assets
(4,516
)
(4,654
)
(9,032
)
(9,308
)
Prior service cost
16

16

32

32

Net loss (gain)
1,201

3,062

2,403

6,124

Net periodic benefit cost
$
2,026

$
3,857

$
4,053

$
7,714



26



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 June 30,
Six Months Ended June 30,
 
2014
2013
2014
2013
Service cost
$
425

$
419

$
850

$
838

Interest cost
480

417

959

834

Expected return on plan assets
(21
)
(20
)
(42
)
(40
)
Prior service cost (benefit)
(107
)
(125
)
(214
)
(250
)
Net loss (gain)
40

121

80

242

Net periodic benefit cost
$
817

$
812

$
1,633

$
1,624


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 June 30,
Six Months Ended June 30,
 
2014
2013
2014
2013
Service cost
$
374

$
348

$
749

$
696

Interest cost
362

332

724

664

Prior service cost
1

1

1

2

Net loss (gain)
124

198

249

396

Net periodic benefit cost
$
861

$
879

$
1,723

$
1,758


Contributions

We anticipate that we will make contributions to the benefit plans during 2014 and 2015. 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 June 30, 2014
Six Months Ended June 30, 2014
Contributions Anticipated for 2014
Contributions Anticipated for 2015
Defined Benefit Pension Plans
$

$

$

$
2,806

Non-pension Defined Benefit Postretirement Healthcare Plans
$
956

$
1,912

$
1,912

$
3,822

Supplemental Non-qualified Defined Benefit and Defined Contribution Plans
$
373

$
746

$
746

$
1,494



27




(14)    COMMITMENTS AND CONTINGENCIES

There have been no significant changes to commitments and contingencies from those previously disclosed in Note 18 of our Notes to the Consolidated Financial Statements in our 2013 Annual Report on Form 10-K except for those described below.

Bond Purchase Agreements

On June 30, 2014, Black Hills Power and Cheyenne Light entered into agreements to issue $160 million of first mortgage bonds to finance Cheyenne Prairie. Black Hills Power will issue $85 million of 4.43% coupon first mortgage bonds due October 20, 2044, and Cheyenne Light will issue $75 million of 4.53% coupon first mortgage bonds due October 20, 2044. The closing for the sale of the first mortgage bonds for both utilities is anticipated to be October 1, 2014, subject to satisfaction of customary closing conditions.
 

Natural Gas Delivery Agreement

In 2012, we entered into a ten-year gas gathering and processing contract for natural gas production from our properties in the Piceance Basin in Colorado, under which we pay a gathering fee per Mcf. The contract requires us to deliver a minimum of 20,000 Mcf per day. This agreement became effective in first quarter of 2014 upon completion of the processing infrastructure capable of handling the committed volumes. We believe that our reserves dedicated to the gathering system, and the projected volumes are adequate to materially satisfy our delivery commitments under this agreement.

Turbine Sale Agreement

On May 6, 2013, Black Hills Wyoming entered into an agreement to sell its 40 MW CTII natural-gas fired generating unit to the City of Gillette, Wyoming for approximately $22 million, upon expiration of the PPA with Cheyenne Light in August 2014. As part of the sale, Black Hills Wyoming will provide services to the City of Gillette through an economy energy PPA. The sale received FERC approval on July 14, 2014, and is expected to close by August 31, 2014.

Reimbursement Agreement

We have a reimbursement agreement in place with Wells Fargo on behalf of Cheyenne Light for the 2009A bonds of $10 million due in 2027 and the 2009B bonds of $7.0 million due in 2021. In the case of default, we hold the assumption of liability for drawings on Cheyenne Light’s Letter of Credit attached to these bonds.

Other Commitments

Construction of Cheyenne Prairie, a 132 MW 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 September 30, 2014. As of June 30, 2014, committed contracts for equipment purchases and for construction were 100% and 98% complete, respectively.

Oil Creek Fire

On June 29, 2012, a forest and grassland fire occurred in the western Black Hills of Wyoming. A state fire investigator concluded that the fire was caused by the failure of a transmission structure owned, operated and maintained by Black Hills Power. On April 16, 2013, a lawsuit was filed in the United States District Court for the District of Wyoming, which forty-seven plaintiffs and the State of Wyoming have now joined, asserting claims for damages against Black Hills Power. The claims include allegations of negligence, negligence per se, common law nuisance, and trespass. In addition to claims for these compensatory damages, the lawsuit seeks recovery of punitive damages. Our investigation of the cause and origin of the fire is ongoing. We have denied and will vigorously defend all claims arising out of the fire, pending the completion of our investigation. We cannot predict the outcome of our investigation, the viability of alleged claims or the outcome of the litigation.


28



Civil litigation of this kind, however, is likely to lead to settlement negotiations, including negotiations prompted by pre-trial civil court procedures. We believe such negotiations would effect a settlement of all claims. Regardless of whether the litigation is determined at trial or through settlement, we expect to incur significant investigation, legal and expert services expenses associated with the litigation. We maintain insurance coverage to limit our exposure to losses due to civil liability claims, and related litigation expense. The deductible applicable to some types of claims arising out of this fire is $1.0 million. We expect this coverage to limit our exposure, and we will pursue recoveries to the maximum extent available under the policies. Based upon information currently available, we believe that a loss associated with settlement of pending claims is probable. Accordingly, as of June 30, 2014, we recorded a loss contingency liability related to these claims, and we recorded a receivable for costs we believe are reimbursable and probable of recovery under our insurance coverage. Both of these entries reflect our reasonable estimate of probable future litigation expense and settlement costs; we did not base these contingencies on any determination that it is probable we would be found liable for these claims were they to be litigated.

Given the uncertainty of litigation, however, a loss related to the fire, the litigation and related claims in excess of the loss we have determined to be probable is reasonably possible. However, we cannot reasonably estimate the amount of such possible loss because our investigation and review of damage claims documentation is ongoing, and there are significant factual and legal issues to be resolved. Further claims may be presented by these and other parties. While we have received claims seeking recovery for fire suppression, reclamation and rehabilitation costs, damage to fencing and other personal property, alleged injury to timber, grass or hay, livestock and related operations, and diminished value of real estate, currently totaling $50 million, we are not yet able, for the reasons described above, to reasonably estimate the amount of any reasonable possible losses in excess of the amount we have accrued. Based upon information currently available, however, management does not expect the outcome of the claims to have a material adverse effect upon our consolidated financial condition, results of operations or cash flows.

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 June 30, 2014, 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 June 30, 2014:

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 June 30, 2014, the restricted net assets at our Utilities Group were approximately $141 million.

(15)    GUARANTEES

We have entered into various agreements providing financial or performance assurance to third parties on behalf of certain of our subsidiaries. The agreements include indemnification for reclamation and surety bonds.

We had the following guarantees in place (in thousands):
 
Maximum Exposure at
 
Nature of Guarantee
June 30, 2014
Expiration
Indemnification for subsidiary reclamation/surety bonds (1)
$
65,744

Ongoing
_______________________
(1)
We have guarantees in place for reclamation and surety bonds for our subsidiaries. The guarantees were entered into in the normal course of business. To the extent liabilities are incurred as a result of activities covered by the surety bonds, such liabilities are included in our Condensed Consolidated Balance Sheets.

During the second quarter, guarantees of Black Hills Utility Holdings’ payment obligations up to $70 million arising from commodity transactions for natural gas supply were removed, primarily due to improvement of the corporate credit rating, as well as the conversion of certain guarantees to letters of credit.



29



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

We are a growth-oriented, vertically-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 203,500 customers in South Dakota, Wyoming, Colorado and Montana; and also distributes natural gas to approximately 35,500 Cheyenne Light customers in Wyoming. Our Gas Utilities serve approximately 538,000 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, Wyoming 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 six months ended June 30, 2014 and 2013, and our financial condition as of June 30, 2014, December 31, 2013 and June 30, 2013, 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 59.

The following business group and segment information does not include inter-company eliminations. Minor differences in amounts may result due to rounding. All amounts are presented on a pre-tax basis unless otherwise indicated.


30



Results of Operations

Executive Summary, Significant Events and Overview

Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013. Net income (loss) for the three months ended June 30, 2014 was $20 million, or $0.44 per share, compared to Net income (loss) of $31 million, or $0.69 per share, reported for the same period in 2013.

Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013. Net income (loss) for the six months ended June 30, 2014 was $68 million, or $1.52 per share, compared to Net income (loss) of $74 million, or $1.66 per share, reported for the same period in 2013.

The following table summarizes select financial results by operating segment and details significant items (in thousands):
 
Three Months Ended June 30,
Six Months Ended June 30,
 
2014
2013
Variance
2014
2013
Variance
Revenue
 
 
 
 
 
 
Utilities
$
264,383

$
263,868

$
515

$
705,822

$
626,310

$
79,512

Non-regulated Energy
51,779

46,257

5,522

104,475

95,544

8,931

Inter-company eliminations
(32,925
)
(30,299
)
(2,626
)
(66,891
)
(61,357
)
(5,534
)
 
$
283,237

$
279,826

$
3,411

$
743,406

$
660,497

$
82,909

 
 
 
 
 
 
 
Net income (loss)
 
 
 
 
 
 
Electric Utilities
$
11,427

$
10,610

$
817

$
26,002

$
22,966

$
3,036

Gas Utilities
1,994

3,192

(1,198
)
26,692

21,675

5,017

Utilities
13,421

13,802

(381
)
52,694

44,641

8,053

 
 
 
 
 
 
 
Power Generation
7,194

5,031

2,163

15,267

10,675

4,592

Coal Mining
2,016

1,973

43

4,480

3,038

1,442

Oil and Gas
(1,660
)
(1,964
)
304

(3,682
)
(2,017
)
(1,665
)
Non-regulated Energy
7,550

5,040

2,510

16,065

11,696

4,369

 
 
 
 
 
 
 
Corporate activities and eliminations (a)
(1,151
)
11,676

(12,827
)
(821
)
17,378

(18,199
)
 
 
 
 
 
 
 
Net income (loss)
$
19,820

$
30,518

$
(10,698
)
$
67,938

$
73,715

$
(5,777
)
__________
(a)
Corporate activities for the three and six months ended June 30, 2013 include a $12 million and a $17 million net after-tax non-cash mark-to-market gain on certain interest rate swaps. These same interest rate swaps were settled in November 2013.

31



Overview of Business Segments and Corporate Activity

Utilities Group

Gas Utilities experienced milder weather during the three months ended June 30, 2014 resulting in a 16% decrease in heating degree days compared to the same period in 2013. Year-to-date results were favorably impacted by colder weather during the first quarter of 2014. Heating degree days were 2% higher for the six months ended June 30, 2014, compared to the same period in 2013. Heating degree days for the three and six months ended June 30, 2014 were 5% and 12% higher than normal, respectively, compared to 24% and 9% higher than normal for the same periods in 2013.

Construction continued on Cheyenne Prairie, a natural gas-fired electric generating facility to serve Cheyenne Light and Black Hills Power customers. The 132 MW generation project is expected to cost approximately $222 million, exclusive of construction financing costs which are being recovered through construction financing riders. The Electric Utilities recorded additional gross margins of approximately $3.7 million and $7.8 million, respectively, for the three and six months ended June 30, 2014, related to these riders. To date, we have expended approximately $196 million. The project is expected to be completed at or less than budget and is on schedule to be placed into service in October 2014.

On July 31, 2014, the WPSC approved rate case settlement agreements authorizing an increase for Cheyenne Light of $8.4 million and $0.8 million for annual electric and natural gas revenue, respectively, effective October 1, 2014. The settlement also included a return on equity of 9.9%, and a capital structure of 54% equity and 46% debt.

On July 22, 2014, Black Hills Power filed a CPCN with the WPSC to construct the Wyoming portion of a $54 million, 230-kV, 144 mile-long transmission line that would connect the Teckla Substation in northeast Wyoming, to the Lange Substation near Rapid City, South Dakota. On June 30, 2014, Black Hills Power filed an application with the SDPUC, for a permit to construct the South Dakota portion of this line. Approval by the WPSC and SDPUC is anticipated in the fourth quarter of 2014.

On June 30, 2014, Black Hills Power and Cheyenne Light entered into agreements to issue $160 million of first mortgage bonds to finance Cheyenne Prairie. Black Hills Power will issue $85 million of 4.43% coupon first mortgage bonds due October 20, 2044, and Cheyenne Light will issue $75 million of 4.53% coupon first mortgage bonds due October 20, 2044. The closing for the sale of the first mortgage bonds for both utilities is anticipated to be October 1, 2014, subject to satisfaction of customary closing conditions.

On May 5, 2014, Colorado Electric issued an all-source generation request for approximately 42 MW of summer seasonal firm capacity in 2017, 2018, and 2019, and up to 60 MW of eligible renewable energy resources to serve its customers in southern Colorado. Colorado IPP submitted solar and wind bids in response to this request. Proposed bids were due by July 31, 2014, and pending Colorado Electric’s review of the bids and other regulatory proceedings, a CPUC decision on Colorado Electric’s portfolio of generation resources is expected by the end of February 2015.

On April 30, 2014, Colorado Electric filed a rate request with the CPUC for an annual revenue increase of $8.0 million to recover operating expenses and infrastructure investments, including those for the Busch Ranch Wind Farm. Colorado Electric seeks approval of a new rider pursuant to the Clean Air-Clean Jobs Act Adjustment, to recover a return on the expenditures associated with the construction of a $65 million natural gas-fired combustion turbine unit, previously approved by the CPUC to replace the W.N. Clark retirement. The filing seeks a return on equity of 10.3% and a capital structure of approximately 50.5% equity and 49.5% debt. A subsequent filing on June 27, 2014 reduced our request to $7.2 million to reflect updated cost information.

On April 29, 2014, Kansas Gas filed a rate request with the KCC to increase annual revenue by $7.3 million primarily to recover infrastructure and increased operating costs. The filing seeks a return on equity of 10.6%, and a capital structure of approximately 50.3% equity and 49.7% debt.

On April 25, 2014 Cheyenne Light received FERC approval to establish rates for transmission services under their Open Access Transmission Tariff, effective May 3, 2014. The approval includes a return on equity of 10.6% and a capital structure of 54% equity and 46% debt.

On March 31, 2014, Black Hills Power filed a rate request with the SDPUC to increase annual revenue by $14.6 million to recover operating expenses and infrastructure investments, primarily for Cheyenne Prairie. The filing seeks a return on equity of 10.25%, and a capital structure of approximately 53.3% equity and 46.7% debt.

32




On March 21, 2014, Black Hills Power retired the Ben French, Neil Simpson I, and Osage coal-fired power plants. These three plants totaling 81 MW were closed because of federal environmental regulations. These plants will largely be replaced by Black Hills Power’s share of Cheyenne Prairie.

On February 25, 2014, the CPUC issued a final order after rehearing, approving a CPCN for the retirement of Pueblo Unit #5 and #6, effective December 31, 2013.

On January 17, 2014, Black Hills Power filed a rate request with the WPSC for an annual revenue increase of $2.8 million to recover investments made in electric infrastructure, primarily for Cheyenne Prairie. The filing seeks a return on equity of 10.25% and a capital structure of approximately 53.3% equity and 46.7% debt.

Our Utilities Group continued its efforts to acquire small municipal gas distribution systems adjacent to our existing service territories. During the first quarter of 2014, we acquired an additional gas system, adding approximately 70 customers, and we announced the pending acquisition of assets serving approximately 400 customers.

Non-regulated Energy Group

Oil and Gas production volumes increased 15% and 5%, respectively, for the three and six months ended June 30, 2014. The average hedged price received increased for natural gas by 35% and 24% and decreased for oil by 18% and 8%, respectively for the three and six months ended June 30, 2014 compared to the same periods in 2013.

On July 14, 2014, Black Hills Wyoming received FERC approval for the sale of its 40 MW CTII natural gas-fired unit to the City of Gillette, Wyoming for approximately $22 million. The sale is expected to close on August 31, 2014 upon expiration of the PPA with Cheyenne Light.

Drilling commenced in June 2014 in the southern Piceance Basin on two of the six horizontal Mancos Shale wells planned for 2014.

Production continued from the two horizontal Mancos Shale wells placed on production during the first quarter of 2014. On March 6, 2014, the Summit Midstream cryogenic gas processing plant with a capacity of 20,000 Mcf per day started serving the company’s gas production in the southern Piceance Basin, including the two Mancos Shale wells placed on production during the first quarter.

Corporate Activities

On June 13, 2014, Fitch upgraded the BHC credit rating to BBB+ with a stable outlook.

On May 29, 2014, we amended our $500 million corporate Revolving Credit Facility agreement to extend the term through May 29, 2019. This facility is substantially similar to the former agreement, which includes 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 continue to be available under a base rate or various Eurodollar rate options for which the borrowing rates were reduced under the amended agreement.

On January 30, 2014, Moody’s upgraded our corporate credit rating to Baa1 from Baa2 with continued stable outlook.

Consolidated interest expense decreased by approximately $5.5 million and $11 million for the three and six months ended June 30, 2014, respectively, compared to the three and six months ended June 30, 2013, due primarily to the refinancing activities occurring during the fourth quarter of 2013.

Operating Results

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


33




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 natural gas sold. Gross margin for our Gas Utilities is calculated as operating revenues less cost of natural 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.


Electric Utilities
 
Three Months Ended June 30,
Six Months Ended June 30,
 
2014
2013
Variance
2014
2013
Variance
 
(in thousands)
Revenue — electric
$
154,544

$
151,775

$
2,769

$
322,909

$
302,148

$
20,761

Revenue — gas
7,340

6,257

1,083

21,077

18,514

2,563

Total revenue
161,884

158,032

3,852

343,986

320,662

23,324

 
 
 
 
 
 
 
Fuel, purchased power and cost of gas — electric
69,723

67,349

2,374

148,142

133,038

15,104

Purchased gas — gas
4,051

2,515

1,536

12,325

8,953

3,372

Total fuel, purchased power and cost of gas
73,774

69,864

3,910

160,467

141,991

18,476

 
 
 
 
 
 
 
Gross margin — electric
84,821

84,426

395

174,767

169,110

5,657

Gross margin — gas
3,289

3,742

(453
)
8,752

9,561

(809
)
Total gross margin
88,110

88,168

(58
)
183,519

178,671

4,848

 
 
 
 
 
 
 
Operations and maintenance
40,272

39,383

889

82,872

78,218

4,654

Depreciation and amortization
19,274

19,665

(391
)
38,361

38,826

(465
)
Total operating expenses
59,546

59,048

498

121,233

117,044

4,189

 
 
 
 
 
 
 
Operating income
28,564

29,120

(556
)
62,286

61,627

659

 
 
 
 
 
 
 
Interest expense, net
(11,829
)
(13,810
)
1,981

(23,841
)
(28,207
)
4,366

Other income (expense), net
352

173

179

608

458

150

Income tax benefit (expense)
(5,660
)
(4,873
)
(787
)
(13,051
)
(10,912
)
(2,139
)
Net income (loss)
$
11,427

$
10,610

$
817

$
26,002

$
22,966

$
3,036



34



 
Three Months Ended June 30,
 
Six Months Ended June 30,
Revenue - Electric (in thousands)
2014
 
2013
 
2014
 
2013
Residential:
 
 
 
 
 
 
 
Black Hills Power
$
14,332

 
$
13,535

 
$
34,392

 
$
29,977

Cheyenne Light
8,167

 
8,307

 
17,840

 
17,637

Colorado Electric
21,316

 
21,829

 
45,995

 
45,950

Total Residential
43,815

 
43,671

 
98,227

 
93,564

 
 
 
 
 
 
 
 
Commercial:
 
 
 
 
 
 
 
Black Hills Power
21,200

 
18,913

 
42,728

 
36,397

Cheyenne Light
15,238

 
14,476

 
29,631

 
27,243

Colorado Electric
23,101

 
21,663

 
44,991

 
42,814

Total Commercial
59,539

 
55,052

 
117,350

 
106,454

 
 
 
 
 
 
 
 
Industrial:
 
 
 
 
 
 
 
Black Hills Power
7,534

 
7,210

 
14,869

 
13,220

Cheyenne Light
7,304

 
5,344

 
14,528

 
10,199

Colorado Electric
9,535

 
9,647

 
18,573

 
19,284

Total Industrial
24,373

 
22,201

 
47,970

 
42,703

 
 
 
 
 
 
 
 
Municipal:
 
 
 
 
 
 
 
Black Hills Power
846

 
847

 
1,638

 
1,561

Cheyenne Light
514

 
490

 
968

 
948

Colorado Electric
3,277

 
3,492

 
6,584

 
6,039

Total Municipal
4,637

 
4,829

 
9,190

 
8,548

 
 
 
 
 
 
 
 
Total Retail Revenue - Electric
132,364

 
125,753

 
272,737

 
251,269

 
 
 
 
 
 
 
 
Contract Wholesale:
 
 
 
 
 
 
 
Total Contract Wholesale - Black Hills Power
4,473

 
4,926

 
10,071

 
10,693

 
 
 
 
 
 
 
 
Off-system Wholesale:
 
 
 
 
 
 
 
Black Hills Power
5,411

 
7,849

 
14,486

 
14,099

Cheyenne Light
1,787

 
2,094

 
4,174

 
4,776

Colorado Electric
1,912

 
2,133

 
3,995

 
3,240

Total Off-system Wholesale
9,110

 
12,076

 
22,655

 
22,115

 
 
 
 
 
 
 
 
Other Revenue:
 
 
 
 
 
 
 
Black Hills Power
6,945

 
7,552

 
13,823

 
14,702

Cheyenne Light
534

 
482

 
1,287

 
1,048

Colorado Electric
1,118

 
986

 
2,336

 
2,321

Total Other Revenue
8,597

 
9,020

 
17,446

 
18,071

 
 
 
 
 
 
 
 
Total Revenue - Electric
$
154,544

 
$
151,775

 
$
322,909

 
$
302,148



35



 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
Quantities Generated and Purchased (in MWh)
2014
 
2013
 
2014
 
2013
Generated —
 
 
 
 
 
 
 
Coal-fired:
 
 
 
 
 
 
 
Black Hills Power (a)
336,842

 
450,097

 
754,090

 
877,112

Cheyenne Light
162,847

 
155,384

 
332,636

 
327,696

Colorado Electric

 

 

 

Total Coal-fired
499,689

 
605,481

 
1,086,726

 
1,204,808

 
 
 
 
 
 
 
 
Natural Gas and Oil:
 
 
 
 
 
 
 
Black Hills Power
2,665

 
4,558

 
4,972

 
7,678

Cheyenne Light

 

 

 

Colorado Electric (b)
40,599

 
107,535

 
58,668

 
138,589

Total Natural Gas and Oil
43,264

 
112,093

 
63,640

 
146,267

 
 
 
 
 
 
 
 
Wind:
 
 
 
 
 
 
 
Colorado Electric
13,230

 
11,834

 
27,558

 
23,007

Total Wind
13,230

 
11,834

 
27,558

 
23,007

 
 
 
 
 
 
 
 
Total Generated:
 
 
 
 
 
 
 
Black Hills Power
339,507

 
454,655

 
759,062

 
884,790

Cheyenne Light
162,847

 
155,384

 
332,636

 
327,696

Colorado Electric
53,829

 
119,369

 
86,226

 
161,596

Total Generated
556,183

 
729,408

 
1,177,924

 
1,374,082

 
 
 
 
 
 
 
 
Purchased —
 
 
 
 
 
 
 
Black Hills Power
365,463

 
349,183

 
796,265

 
737,382

Cheyenne Light
197,225

 
205,027

 
404,543

 
406,872

Colorado Electric (b)
467,197

 
412,037

 
937,299

 
867,175

Total Purchased
1,029,885

 
966,247

 
2,138,107

 
2,011,429

 
 
 
 
 
 
 
 
Total Generated and Purchased:
 
 
 
 
 
 
 
Black Hills Power
704,970

 
803,838

 
1,555,327

 
1,622,172

Cheyenne Light
360,072

 
360,411

 
737,179

 
734,568

Colorado Electric
521,026

 
531,406

 
1,023,525

 
1,028,771

Total Generated and Purchased
1,586,068

 
1,695,655

 
3,316,031

 
3,385,511

__________
(a)
Decrease reflects the retirement of Neil Simpson I on March 21, 2014.
(b)
Decrease reflects a current year unplanned outage due to a turbine bearing replacement and combustor upgrade at Pueblo Airport Generation Station, and utilization of Pueblo Airport Generating Station Units #1 and #2 in place of purchased power from Colorado IPP during the six months ended June 30 2013.



36



 
Three Months Ended June 30,
 
Six Months Ended June 30,
Quantity (in MWh)
2014
2013
 
2014
2013
Residential:
 
 
 
 
 
Black Hills Power
107,394

113,525

 
278,704

274,495

Cheyenne Light
57,328

60,669

 
127,983

136,125

Colorado Electric
132,256

140,755

 
285,887

296,191

Total Residential
296,978

314,949

 
692,574

706,811

 
 
 
 
 
 
Commercial:
 
 
 
 
 
Black Hills Power
176,541

174,763

 
360,989

350,380

Cheyenne Light
129,688

132,214

 
256,100

261,643

Colorado Electric
174,239

180,340

 
332,418

351,045

Total Commercial
480,468

487,317

 
949,507

963,068

 
 
 
 
 
 
Industrial:
 
 
 
 
 
Black Hills Power
104,914

105,856

 
205,765

197,488

Cheyenne Light
94,861

65,716

 
185,586

135,668

Colorado Electric
111,090

92,867

 
201,207

171,416

Total Industrial
310,865

264,439

 
592,558

504,572

 
 
 
 
 
 
Municipal:
 
 
 
 
 
Black Hills Power
7,709

8,147

 
15,394

15,930

Cheyenne Light
2,131

2,143

 
4,624

4,738

Colorado Electric
31,385

29,049

 
58,073

47,095

Total Municipal
41,225

39,339

 
78,091

67,763

 
 
 
 
 
 
Total Retail Quantity Sold
1,129,536

1,106,044

 
2,312,730

2,242,214

 
 
 
 
 
 
Contract Wholesale:
 
 
 
 
 
Total Contract Wholesale - Black Hills Power
71,999

77,653

 
167,227

181,437

 
 
 
 
 
 
Off-system Wholesale:
 
 
 
 
 
Black Hills Power
169,498

277,840

 
424,294

516,287

Cheyenne Light
42,250

61,514

 
94,606

131,822

Colorado Electric
50,178

38,238

 
80,924

70,015

Total Off-system Wholesale
261,926

377,592

 
599,824

718,124

 
 
 
 
 
 
Total Quantity Sold:
 
 
 
 
 
Black Hills Power
638,055

757,784

 
1,452,373

1,536,017

Cheyenne Light
326,258

322,256

 
668,899

669,996

Colorado Electric
499,148

481,249

 
958,509

935,762

Total Quantity Sold
1,463,461

1,561,289

 
3,079,781

3,141,775

 
 
 
 
 
 
Other Uses, Losses or Generation, net (a):
 
 
 
 
 
Black Hills Power
66,915

46,054

 
102,954

86,155

Cheyenne Light
33,814

38,155

 
68,280

64,572

Colorado Electric
21,878

50,157

 
65,016

93,009

Total Other Uses, Losses and Generation, net
122,607

134,366

 
236,250

243,736

 
 
 
 
 
 
Total Energy
1,586,068

1,695,655

 
3,316,031

3,385,511

__________
(a)
Includes company uses, line losses, and excess exchange production.


37



 
Three Months Ended June 30,
Degree Days
2014
 
2013
 
Actual
 
Variance from
30-Year Average
 
Actual
 
Variance from
30-Year Average
Heating Degree Days:
 
 
 
 
 
 
 
Black Hills Power
1,025

 
2
 %
 
1,227

 
43
 %
Cheyenne Light
1,191

 
 %
 
1,321

 
11
 %
Colorado Electric
633

 
4
 %
 
752

 
(1
)%
Combined
877

 
2
 %
 
1,026

 
19
 %
 
 
 
 
 
 
 
 
Cooling Degree Days:
 
 
 
 
 
 
 
Black Hills Power
99

 
(7
)%
 
78

 
(27
)%
Cheyenne Light
50

 
(2
)%
 
123

 
141
 %
Colorado Electric
209

 
(8
)%
 
376

 
66
 %
Combined
140

 
(7
)%
 
225

 
48
 %

 
Six Months Ended June 30,
Degree Days
2014
 
2013
 
Actual
 
Variance from
30-Year Average
 
Actual
 
Variance from
30-Year Average
Heating Degree Days:
 
 
 
 
 
 
 
Black Hills Power
4,435

 
5
 %
 
4,437

 
9
 %
Cheyenne Light
4,397

 
4
 %
 
4,483

 
6
 %
Colorado Electric
3,303

 
3
 %
 
3,502

 
4
 %
Combined
3,905

 
4
 %
 
4,012

 
6
 %
 
 
 
 
 
 
 
 
Cooling Degree Days:
 
 
 
 
 
 
 
Black Hills Power
99

 
(7
)%
 
78

 
(27
)%
Cheyenne Light
50

 
(2
)%
 
123

 
141
 %
Colorado Electric
209

 
(9
)%
 
376

 
66
 %
Combined
140

 
(7
)%
 
225

 
49
 %
Electric Utilities Power Plant Availability
Three Months Ended June 30,
Six Months Ended June 30,
 
 
2014
2013
2014
 
2013
 
Coal-fired plants (a)
84.8
%
 
96.0
%
 
90.1
%
 
96.4
%
 
Other plants (b)(c)
89.9
%
 
95.5
%
 
84.0
%
 
97.1
%
 
Total availability
87.7
%
 
95.7
%
 
86.6
%
 
96.7
%
 
__________
(a)
The three months and six months ended June 30, 2014 reflect a planned annual outage at Neil Simpson II and an unplanned outage for a catalyst repair at Wygen III.
(b)
The three months and six months ended June 30, 2014 include a planned outage at Ben French CT's #1 and #2 for a controls upgrade.
(c)
The six months ended June 30, 2014, reflects an unplanned outage due to a turbine bearing replacement and combustor upgrade at Pueblo Airport Generation Station.

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:


38



 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2014
 
2013
 
2014
 
2013
Revenue - Natural Gas (in thousands):
 
 
 
 
 
 
 
Residential
$
4,519

 
$
4,033

 
$
12,743

 
$
11,565

Commercial
1,975

 
1,522

 
5,951

 
5,130

Industrial
616

 
505

 
1,903

 
1,403

Other Sales Revenue
230

 
197

 
480

 
416

Total Revenue - Natural Gas
$
7,340

 
$
6,257

 
$
21,077

 
$
18,514

 
 
 
 
 
 
 
 
Gross Margin (in thousands):
 
 
 
 
 
 
 
Residential
$
2,383

 
$
2,674

 
$
5,987

 
$
6,634

Commercial
631

 
748

 
1,962

 
2,240

Industrial
47

 
123

 
323

 
271

Other Gross Margin
228

 
197

 
480

 
416

Total Gross Margin
$
3,289

 
$
3,742

 
$
8,752

 
$
9,561

 
 
 
 
 
 
 
 
Volumes Sold (Dth):
 
 
 
 
 
 
 
Residential
450,715

 
492,261

 
1,485,892

 
1,585,261

Commercial
284,493

 
278,914

 
848,887

 
904,851

Industrial
120,558

 
137,212

 
376,485

 
364,159

Total Volumes Sold
855,766

 
908,387

 
2,711,264

 
2,854,271


39




Results of Operations for the Electric Utilities for the Three Months Ended June 30, 2014 Compared to the Three Months Ended June 30, 2013: Net income for the Electric Utilities was $11 million for the three months ended June 30, 2014, compared to $11 million for the three months ended June 30, 2013, as a result of:

Gross margin was comparable to the prior year, reflecting increased rider margins of $2.2 million due to a return on additional investment in our generating facilities. Industrial megawatt hours sold increased 18% compared to the same period in the prior year, primarily driven by load growth at Cheyenne Light. These increases were offset by a 38% decrease in cooling degree days compared to the same period in the prior year resulting in a $1.6 million decrease on lower residential and commercial megawatt hours sold, and a $0.6 million decrease in wholesale power volumes as a result of plant outages. Our Cheyenne Light gas utility experienced an 11% decrease in heating degree days, primarily from April, resulting in a $0.5 million decrease in retail natural gas sales.
 
Operations and maintenance increased primarily due to increases in employee costs, regulatory support, and property taxes.

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

Interest expense, net decreased primarily due to lower interest rates from refinancing higher cost debt in the fourth quarter of 2013.

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

Income tax benefit (expense): The effective tax rate is higher in 2014 primarily due to the research and development tax credit not being extended to 2014.

Results of Operations for the Electric Utilities for the Six Months Ended June 30, 2014 Compared to the Six Months Ended June 30, 2013: Net income for the Electric Utilities was $26 million for the six months ended June 30, 2014, compared to $23 million for the six months ended June 30, 2013, as a result of:

Gross margin increased primarily due to a return on additional investments which increased base electric margins by $4.0 million and increased rider margins by $5.8 million. Industrial megawatt hours sold increased by approximately 18 percent, primarily due to load growth at Cheyenne Light. These increases are partially offset by a $1.8 million decrease from lower residential and commercial megawatt hours sold driven by a 38% decrease in cooling degree days compared to the same period in the prior year, a $1.0 million decrease in wholesale volumes sold, a $0.9 million decrease from the TCA, and a $0.5 million decrease from a construction savings incentive recognized in the prior year. Our Cheyenne Light gas utility experienced a decrease in heating degree days, resulting in a $0.8 million decrease in retail natural gas sales.

Operations and maintenance increased primarily due to an increase in employee costs, generation maintenance, regulatory support and property taxes.

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

Interest expense, net decreased primarily due to refinancing higher cost debt in the fourth quarter of 2013.

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

Income tax benefit (expense): The effective tax rate is higher in 2014 primarily due to the research and development tax credit not being extended to 2014. The prior year reflected the entire year of the 2012 research and development tax credit due to retroactive reinstatement of the credit in January 2013 by the U.S. Congress.



40



Gas Utilities
 
Three Months Ended June 30,
Six Months Ended June 30,
 
2014
2013
Variance
2014
2013
Variance
 
(in thousands)
Natural gas — regulated
$
95,350

$
98,635

$
(3,285
)
$
346,582

$
290,586

$
55,996

Other — non-regulated services
7,149

7,201

(52
)
15,254

15,062

192

Total revenue
102,499

105,836

(3,337
)
361,836

305,648

56,188

 
 
 
 
 
 
 
Natural gas — regulated
52,266

53,143

(877
)
223,040

173,523

49,517

Other — non-regulated services
3,675

3,517

158

7,397

7,234

163

Total cost of sales
55,941

56,660

(719
)
230,437

180,757

49,680

 
 
 
 
 
 
 
Gross margin
46,558

49,176

(2,618
)
131,399

124,891

6,508

 
 
 
 
 
 
 
Operations and maintenance
33,454

31,852

1,602

68,832

65,078

3,754

Depreciation and amortization
6,538

6,583

(45
)
13,059

13,086

(27
)
Total operating expenses
39,992

38,435

1,557

81,891

78,164

3,727

 
 
 
 
 
 
 
Operating income (loss)
6,566

10,741

(4,175
)
49,508

46,727

2,781

 
 
 
 
 
 
 
Interest expense, net
(3,722
)
(5,907
)
2,185

(7,574
)
(12,184
)
4,610

Other income (expense), net
19

(5
)
24

1

7

(6
)
Income tax benefit (expense)
(869
)
(1,637
)
768

(15,243
)
(12,875
)
(2,368
)
Net income (loss)
$
1,994

$
3,192

$
(1,198
)
$
26,692

$
21,675

$
5,017



41



 
Three Months Ended June 30,
 
Six Months Ended June 30,
Revenue (in thousands)
2014
 
2013
 
2014
 
2013
Residential:
 
 
 
 
 
 
 
Colorado
$
9,435

 
$
9,850

 
$
33,122

 
$
29,644

Nebraska
17,519

 
22,932

 
80,411

 
71,784

Iowa
22,052

 
18,139

 
76,816

 
56,890

Kansas
10,348

 
12,620

 
43,625

 
38,385

Total Residential
59,354

 
63,541

 
233,974

 
196,703

 
 
 
 
 
 
 
 
Commercial:
 
 
 
 
 
 
 
Colorado
2,060

 
1,778

 
6,757

 
5,438

Nebraska
4,590

 
7,098

 
24,656

 
23,345

Iowa
11,202

 
8,442

 
37,116

 
26,217

Kansas
3,624

 
4,052

 
15,295

 
12,841

Total Commercial
21,476

 
21,370

 
83,824

 
67,841

 
 
 
 
 
 
 
 
Industrial:
 
 
 
 
 
 
 
Colorado
504

 
507

 
581

 
555

Nebraska
99

 
100

 
307

 
305

Iowa
1,141

 
709

 
2,313

 
1,454

Kansas
5,632

 
6,068

 
6,718

 
7,000

Total Industrial
7,376

 
7,384

 
9,919

 
9,314

 
 
 
 
 
 
 
 
Transportation:
 
 
 
 
 
 
 
Colorado
217

 
227

 
542

 
628

Nebraska
2,542

 
2,395

 
8,272

 
7,111

Iowa
983

 
999

 
2,744

 
2,538

Kansas
1,563

 
1,453

 
4,056

 
3,502

Total Transportation
5,305

 
5,074

 
15,614

 
13,779

 
 
 
 
 
 
 
 
Other Sales Revenue:
 
 
 
 
 
 
 
Colorado
36

 
22

 
67

 
(52
)
Nebraska
651

 
626

 
1,354

 
1,240

Iowa
262

 
190

 
414

 
302

Kansas
890

 
428

 
1,416

 
1,459

Total Other Sales Revenue
1,839

 
1,266

 
3,251

 
2,949

 
 
 
 
 
 
 
 
Total Regulated Revenue
95,350

 
98,635

 
346,582

 
290,586

 
 
 
 
 
 
 
 
Non-regulated Services
7,149

 
7,201

 
15,254

 
15,062

 
 
 
 
 
 
 
 
Total Revenue
$
102,499

 
$
105,836

 
$
361,836

 
$
305,648



42



 
Three Months Ended June 30,
 
Six Months Ended June 30,
Gross Margin (in thousands)
2014
 
2013
 
2014
 
2013
Residential:
 
 
 
 
 
 
 
Colorado
$
3,597

 
$
3,884

 
$
9,969

 
$
10,122

Nebraska
9,925

 
11,055

 
30,814

 
29,366

Iowa
8,993

 
9,397

 
24,203

 
22,986

Kansas
6,529

 
6,925

 
18,113

 
17,129

Total Residential
29,044

 
31,261

 
83,099

 
79,603

 
 
 
 
 
 
 
 
Commercial:
 
 
 
 
 
 
 
Colorado
607

 
579

 
1,667

 
1,568

Nebraska
1,772

 
2,292

 
6,935

 
6,927

Iowa
2,300

 
2,592

 
7,525

 
7,044

Kansas
1,495

 
1,519

 
4,678

 
4,163

Total Commercial
6,174

 
6,982

 
20,805

 
19,702

 
 
 
 
 
 
 
 
Industrial:
 
 
 
 
 
 
 
Colorado
130

 
158

 
160

 
188

Nebraska
33

 
31

 
101

 
85

Iowa
61

 
81

 
146

 
163

Kansas
696

 
750

 
932

 
974

Total Industrial
920

 
1,020

 
1,339

 
1,410

 
 
 
 
 
 
 
 
Transportation:
 
 
 
 
 
 
 
Colorado
216

 
227

 
542

 
628

Nebraska
2,541

 
2,395

 
8,272

 
7,111

Iowa
982

 
999

 
2,743

 
2,538

Kansas
1,563

 
1,453

 
4,056

 
3,502

Total Transportation
5,302

 
5,074

 
15,613

 
13,779

 
 
 
 
 
 
 
 
Other Sales Margins:
 
 
 
 
 
 
 
Colorado
37

 
22

 
68

 
(52
)
Nebraska
653

 
626

 
1,356

 
1,240

Iowa
263

 
190

 
414

 
302

Kansas
692

 
318

 
849

 
1,079

Total Other Sales Margins
1,645

 
1,156

 
2,687

 
2,569

 
 
 
 
 
 
 
 
Total Regulated Gross Margin
43,085

 
45,493

 
123,543

 
117,063

 
 
 
 
 
 
 
 
Non-regulated Services
3,473

 
3,683

 
7,856

 
7,828

 
 
 
 
 
 
 
 
Total Gross Margin
$
46,558

 
$
49,176

 
$
131,399

 
$
124,891



43



 
Three Months Ended June 30,
 
Six Months Ended June 30,
Distribution Quantities Sold and Transportation (in Dth)
2014
2013
 
2014
2013
Residential:
 
 
 
 
 
Colorado
1,018,966

1,268,892

 
4,040,400

4,190,227

Nebraska
1,278,283

2,056,892

 
8,264,576

7,794,565

Iowa
1,249,921

1,732,786

 
7,892,965

7,023,152

Kansas
715,890

1,044,593

 
4,597,445

4,260,899

Total Residential
4,263,060

6,103,163

 
24,795,386

23,268,843

 
 
 
 
 
 
Commercial:
 
 
 
 
 
Colorado
255,312

256,317

 
891,002

832,593

Nebraska
485,023

836,828

 
2,960,179

3,035,626

Iowa
884,997

1,164,878

 
4,370,689

3,970,551

Kansas
391,548

474,953

 
1,933,515

1,752,087

Total Commercial
2,016,880

2,732,976

 
10,155,385

9,590,857

 
 
 
 
 
 
Industrial:
 
 
 
 
 
Colorado
101,468

127,124

 
111,793

136,861

Nebraska
12,168

13,585

 
39,133

44,265

Iowa
119,710

129,772

 
313,573

272,096

Kansas
1,084,608

1,222,845

 
1,264,695

1,411,666

Total Industrial
1,317,954

1,493,326

 
1,729,194

1,864,888

 
 
 
 
 
 
Wholesale and Other:
 
 
 
 
 
Kansas
32,274

19,199

 
100,907

74,209

Total Wholesale and Other
32,274

19,199

 
100,907

74,209

 
 
 
 
 
 
Total Distribution Quantities Sold
7,630,168

10,348,664

 
36,780,872

34,798,797

 
 
 
 
 
 
Transportation:
 
 
 
 
 
Colorado
209,799

216,333

 
540,143

629,042

Nebraska
6,623,555

6,040,006

 
16,586,774

14,722,321

Iowa
4,319,339

4,790,583

 
10,476,705

10,469,740

Kansas
3,594,159

3,336,618

 
8,421,296

7,388,636

Total Transportation
14,746,852

14,383,540

 
36,024,918

33,209,739

 
 
 
 
 
 
 
 
 
 
 
 
Total Distribution Quantities Sold and Transportation
22,377,020

24,732,204

 
72,805,790

68,008,536


Our Gas Utilities are highly seasonal, and sales volumes vary considerably with weather and seasonal heating and industrial loads. Over 70% 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 November 1 and ends around March 31.


44



 
Three Months Ended June 30,
 
2014
 
2013
Heating Degree Days:
Actual
 
Variance
from 30-Year
Average
 
Actual
 
Variance
from 30-Year
Average
Colorado
924

 
%
 
972

 
5
%
Nebraska
580

 
1
%
 
769

 
33
%
Iowa
775

 
11
%
 
873

 
27
%
Kansas (a)
480

 
7
%
 
636

 
42
%
Combined (b) 
711

 
5
%
 
842

 
24
%

 
Six Months Ended June 30,
 
2014
 
2013
Heating Degree Days:
Actual
 
Variance
from 30-Year
Average
 
Actual
 
Variance
from 30-Year
Average
Colorado
3,783

 
2
%
 
3,844

 
4
%
Nebraska
3,852

 
6
%
 
3,898

 
8
%
Iowa
4,949

 
18
%
 
4,616

 
14
%
Kansas (a)
3,169

 
8
%
 
3,186

 
9
%
Combined (b) 
4,235

 
12
%
 
4,148

 
9
%
__________
(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.

Results of Operations for the Gas Utilities for the Three Months Ended June 30, 2014 Compared to the Three Months Ended June 30, 2013: Net income for the Gas Utilities was $2.0 million for the three months ended June 30, 2014, compared to Net income of $3.2 million for the three months ended June 30, 2013, as a result of:

Gross margin decreased primarily due to milder weather compared to the same period in the prior year resulting in lower residential and commercial volumes sold. Heating degree days were 16% lower for the three months ended June 30, 2014, compared to the same period in the prior year and 5% higher than normal.

Operations and maintenance increased primarily due to an increase in employee costs.

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

Interest expense, net decreased primarily due to lower interest rates from refinancing higher cost debt in the fourth quarter of 2013.

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

Income tax benefit (expense): The effective tax rate for 2014 was slightly lower than 2013 due primarily to an increase in an estimated flow-through tax adjustment.



45



Results of Operations for the Gas Utilities for the Six Months Ended June 30, 2014 Compared to the Six Months Ended June 30, 2013: Net income for the Gas Utilities was $26.7 million for the six months ended June 30, 2014, compared to Net income of $21.7 million for the six months ended June 30, 2013, as a result of:

Gross margin increased primarily due to higher residential and commercial consumption, and transport volumes sold driven primarily by a 7% increase in heating degree days experienced through the peak months of the winter heating season as compared to the same period last year. Heating degree days were 2% higher for the six months ended June 30, 2014, compared to the same period in the prior year and 12% higher than normal.

Operations and maintenance increased primarily due to an increase in employee costs and property taxes.

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

Interest expense, net decreased primarily due to refinancing higher cost debt in the fourth quarter of 2013.

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

Income tax benefit (expense): The effective tax rate for 2014 was slightly lower than 2013 due primarily to an increase in an estimated flow-through tax adjustment.


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
Cheyenne Light (a)
Electric/Gas
12/2013
10/2014
$
14.1

$
9.2

Black Hills Power (b)
Electric
1/2014
pending
$
2.8

pending

Black Hills Power (c)
Electric
3/2014
pending
$
14.6

pending

Iowa Gas (d)
Gas
2/2014
4/2014
$
0.5

$
0.5

Kansas Gas (e)
Gas
4/2014
pending
$
7.3

pending

Colorado Electric (f)
Electric
4/2014
pending
$
7.2

pending

__________
(a)
On July 31, 2014, the WPSC approved rate case settlement agreements authorizing an increase for Cheyenne Light of $8.4 million and $0.8 million for annual electric and natural gas revenue, respectively, effective October 1, 2014. The settlement also included a return on equity of 9.9%, and a capital structure of 54% equity and 46% debt. The WPSC’s decision provides Cheyenne Light a return on its investment in Cheyenne Prairie and associated infrastructure, and provides recovery of its share of operating expenses for the natural gas-fired facility.

(b)
On January 17, 2014, Black Hills Power filed a rate request with the WPSC for an annual revenue increase of $2.8 million to recover investments made in electric infrastructure, primarily for Cheyenne Prairie. The filing seeks a return on equity of 10.25% and a capital structure of approximately 53.3% equity and 46.7% debt. Black Hills Power is seeking to implement the new rates on October 1, 2014, to coincide with Cheyenne Prairie’s expected in-service date.

(c)
On March 31, 2014, Black Hills Power filed a rate request with the SDPUC to increase annual revenue by $14.6 million to recover operating expenses and infrastructure investments, primarily for Cheyenne Prairie. The filing seeks a return on equity of 10.25%, and a capital structure of approximately 53.3% equity and 46.7% debt. Black Hills Power is seeking to implement the new rates on October 1, 2014, to coincide with Cheyenne Prairie’s expected in-service date.

(d)
On April 15, 2014, the IUB approved a capital investment recovery surcharge increase of $0.5 million.

(e)
On April 29, 2014, Kansas Gas filed a rate request with the KCC to increase annual revenue by $7.3 million primarily to recover infrastructure and increased operating costs. The filing seeks a return on equity of 10.6%, and a capital structure of approximately 50.3% equity and 49.7% debt.

(f)
On April 30, 2014, Colorado Electric filed a rate request with the CPUC for an annual revenue increase of $8.0 million to recover operating expenses and infrastructure investments, including those for the Busch Ranch Wind Farm. Colorado Electric seeks approval of a new rider pursuant to the Clean Air-Clean Jobs Act Adjustment, to recover a return on the expenditures associated with the construction of a $65 million natural gas-fired combustion turbine unit, previously approved by the CPUC to replace the W.N. Clark retirement. The filing seeks a return on equity of 10.3% and a capital structure of approximately 50.5% equity and 49.5% debt. A subsequent filing on June 27, 2014 reduced our request to $7.2 million to reflect updated cost information.

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 June 30,
Six Months Ended June 30,
 
2014
2013
Variance
2014
2013
Variance
 
(in thousands)
Revenue
$
21,980

$
20,125

$
1,855

$
44,328

$
40,485

$
3,843

 
 
 
 
 
 
 
Operations and maintenance
8,733

8,161

572

16,410

15,952

458

Depreciation and amortization
1,154

1,313

(159
)
2,363

2,539

(176
)
Total operating expense
9,887

9,474

413

18,773

18,491

282

 
 
 
 
 
 
 
Operating income
12,093

10,651

1,442

25,555

21,994

3,561

 
 
 
 
 
 
 
Interest expense, net
(934
)
(2,706
)
1,772

(1,862
)
(5,380
)
3,518

Other (expense) income, net
2

(4
)
6

(7
)
(3
)
(4
)
Income tax (expense) benefit
(3,967
)
(2,910
)
(1,057
)
(8,419
)
(5,936
)
(2,483
)
 
 
 
 
 
 
 
Net income (loss)
$
7,194

$
5,031

$
2,163

$
15,267

$
10,675

$
4,592

____________
The generating facility located in Pueblo, Colorado is accounted for as a capital lease under GAAP; as such, revenue and depreciation expense are impacted by the accounting for this lease. Under the lease, the original cost of the facility is recorded at Colorado Electric and is being depreciated by Colorado Electric for segment reporting purposes.

46




The following table summarizes MWh for our Power Generation segment:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2014
2013
 
2014
2013
Quantities Sold, Generated and Purchased (MWh)
(in thousands)
 Sold
 
 
 
 
 
Black Hills Colorado IPP
273,200

186,921

 
559,156

421,117

Black Hills Wyoming
138,377

134,896

 
278,985

277,002

Total Sold
411,577

321,817

 
838,141

698,119

 


 
 
 
Generated
 
 
 
 
 
Black Hills Colorado IPP
273,200

186,921

 
559,156

421,117

Black Hills Wyoming
141,458

135,056

 
282,136

279,245

Total Generated
414,658

321,977

 
841,292

700,362

 


 
 
 
Purchased
 
 
 
 
 
Black Hills Colorado IPP


 


Black Hills Wyoming
16

721

 
1,005

721

Total Purchased
16

721

 
1,005

721


The following table provides certain operating statistics for our plants within the Power Generation segment:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2014
2013
 
2014
2013
Contracted power plant fleet availability:
 
 
 
 
 
Coal-fired plant
98.7
%
94.0
%
 
99.0
%
97.0
%
Natural gas-fired plants
99.2
%
99.2
%
 
98.5
%
98.9
%
Total availability
99.1
%
98.0
%
 
98.6
%
98.5
%

Results of Operations for Power Generation for the Three Months Ended June 30, 2014 Compared to the Three Months Ended June 30, 2013: Net income for the Power Generation segment was $7.2 million for the three months ended June 30, 2014, compared to Net income of $5.0 million for the same period in 2013 as a result of:

Revenue increased primarily due to an increase in megawatt hours delivered at higher prices and an increase in megawatt hours sold and pricing for off-system sales at Black Hills Wyoming.

Operations and maintenance increased primarily due to repairs and maintenance at Colorado IPP.

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

Interest expense, net decreased primarily due to refinancing higher cost project debt and settling associated interest rate swaps in the fourth quarter of 2013.
 
Other (expense) income, net was comparable to the same period in the prior year.

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


47



Results of Operations for Power Generation for the Six Months Ended June 30, 2014 Compared to the Six Months Ended June 30, 2013: Net income for the Power Generation segment was $15.3 million for the six months ended June 30, 2014, compared to Net income of $10.7 million for the same period in 2013 as a result of:

Revenue increased primarily due to an increase in megawatts delivered at higher prices, an increase in fired hours and an increase in off-system megawatt hour sales and pricing at Black Hills Wyoming.

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

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

Interest expense, net decreased primarily due to refinancing higher cost project debt and settling associated interest rate swaps in the fourth quarter of 2013.
 
Other (expense) income, net was comparable to the same period in the prior year.

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

Coal Mining
 
Three Months Ended June 30,
Six Months Ended June 30,
 
2014
2013
Variance
2014
2013
Variance
 
(in thousands)
Revenue
$
14,651

$
14,318

$
333

$
30,149

$
27,901

$
2,248

 
 
 
 
 
 
 
Operations and maintenance
10,023

9,251

772

20,154

19,402

752

Depreciation, depletion and amortization
2,570

2,964

(394
)
5,260

5,829

(569
)
Total operating expenses
12,593

12,215

378

25,414

25,231

183

 
 
 


 
 
 
Operating income (loss)
2,058

2,103

(45
)
4,735

2,670

2,065

 
 
 
 
 
 
 
Interest (expense) income, net
(113
)
(179
)
66

(216
)
(310
)
94

Other income, net
589

581

8

1,192

1,194

(2
)
Income tax benefit (expense)
(518
)
(532
)
14

(1,231
)
(516
)
(715
)
 
 
 
 
 
 
 
Net income (loss)
$
2,016

$
1,973

$
43

$
4,480

$
3,038

$
1,442


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

 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2014
2013
 
2014
2013
Tons of coal sold
1,063

1,079

 
2,150

2,132

Cubic yards of overburden moved
1,010

930

 
1,920

1,989

 
 
 
 
 
 
Revenue per ton
$
13.79

$
13.27

 
$
14.03

$
13.09


Results of Operations for Coal Mining for the Three Months Ended June 30, 2014 Compared to the Three Months Ended June 30, 2013: Net income for the Coal Mining segment was $2.0 million for the three months ended June 30, 2014, compared to Net income of $2.0 million for the same period in 2013 as a result of:

Revenue increased primarily due to a 4% increase in price per ton sold, partially offset by a 1% decrease in tons sold. Approximately 50% of our coal production is sold under contracts that include price adjustments based on actual mining costs, including income taxes.

Operations and maintenance increased primarily due to materials and outside services for major maintenance projects.


48



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

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 is comparable to the same period in the prior year.



49



Results of Operations for Coal Mining for the Six Months Ended June 30, 2014 Compared to the Six Months Ended June 30, 2013: Net income for the Coal Mining segment was $4.5 million for the six months ended June 30, 2014, compared to Net income of $3.0 million for the same period in 2013 as a result of:

Revenue increased primarily due to a 7% increase in price per ton sold and a 1% increase in tons sold. Approximately 50% of our coal production is sold under contracts that include price adjustments based on actual mining costs, including income taxes.

Operations and maintenance increased primarily due to materials and outside services on major maintenance projects, partially offset by lower overburden removal costs, lower employee costs, and a favorable coal tax adjustment of $0.7 million.

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

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 increase in the effective tax rate in 2014 is due primarily to the reduced impact of the tax benefit of percentage depletion.

Oil and Gas
 
Three Months Ended June 30,
Six Months Ended June 30,
 
2014
2013
Variance
2014
2013
Variance
 
(in thousands)
Revenue
$
15,148

$
11,814

$
3,334

$
29,998

$
27,158

$
2,840

 
 
 
 
 
 
 
Operations and maintenance
10,239

9,995

244

21,378

20,250

1,128

Depreciation, depletion and amortization
7,290

5,214

2,076

13,923

10,581

3,342

Total operating expenses
17,529

15,209

2,320

35,301

30,831

4,470

 
 
 
 
 
 
 
Operating income (loss)
(2,381
)
(3,395
)
1,014

(5,303
)
(3,673
)
(1,630
)
 
 
 
 
 
 
 
Interest income (expense), net
(442
)
(54
)
(388
)
(897
)
25

(922
)
Other income (expense), net
49

81

(32
)
87

4

83

Income tax benefit (expense)
1,114

1,404

(290
)
2,431

1,627

804

 
 
 
 
 
 
 
Net income (loss)
$
(1,660
)
$
(1,964
)
$
304

$
(3,682
)
$
(2,017
)
$
(1,665
)

The following tables provide certain operating statistics for our Oil and Gas segment:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2014
2013
 
2014
2013
Production:
 
 
 
 
 
Bbls of oil sold
92,228

65,304

 
166,490

162,107

Mcf of natural gas sold
1,840,826

1,784,389

 
3,600,790

3,517,339

Gallons of NGL sold
1,764,111

895,720

 
2,899,832

1,841,534

Mcf equivalent sales
2,646,210

2,304,173

 
5,013,992

4,753,057



50



 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2014
2013
 
2014
2013
Average price received: (a)
 
 
 
 
 
Oil/Bbl
$
78.18

$
95.15

 
$
84.56

$
91.71

Gas/Mcf  
$
3.17

$
2.35

 
$
3.25

$
2.63

NGL/gallon
$
0.80

$
0.73

 
$
0.95

$
0.84

 
 
 
 
 
 
Depletion expense/Mcfe
$
2.36

$
1.82

 
$
2.31

$
1.80

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

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

 
Three Months Ended June 30, 2014
 
Three Months Ended June 30, 2013
Producing Basin
LOE
Gathering,
 Compression
 and Processing
Production Taxes
Total
 
LOE
Gathering,
 Compression
and Processing
Production Taxes
Total
San Juan
$
1.39

$
0.46

$
0.59

$
2.44

 
$
1.39

$
0.40

$
0.52

$
2.31

Piceance
0.26

0.23

0.35

0.84

 
0.80

0.52

0.27

1.59

Powder River
1.55


1.15

2.70

 
2.00


1.23

3.23

Williston
1.31


1.41

2.72

 
1.43


2.52

3.95

All other properties
1.30


0.77

2.07

 
0.65


(0.48
)
0.17

Total weighted average
$
1.08

$
0.23

$
0.72

$
2.03

 
$
1.32

$
0.27

$
0.55

$
2.14


 
Six Months Ended June 30, 2014
 
Six Months Ended June 30, 2013
Producing Basin
LOE
Gathering,
 Compression
 and Processing
Production Taxes
Total
 
LOE
Gathering,
 Compression
and Processing
Production Taxes
Total
San Juan
$
1.46

$
0.45

$
0.61

$
2.52

 
$
1.34

$
0.37

$
0.47

$
2.18

Piceance
0.11

0.23

0.45

0.79

 
0.73

0.58

0.30

1.61

Powder River
1.90


1.23

3.13

 
1.62


1.24

2.86

Williston
1.08


1.59

2.67

 
0.94


1.34

2.28

All other properties
1.47


0.36

1.83

 
0.67


(0.08
)
0.59

Total weighted average
$
1.13

$
0.23

$
0.73

$
2.09

 
$
1.19

$
0.25

$
0.60

$
2.04



51



Results of Operations for Oil and Gas for the Three Months Ended June 30, 2014 Compared to the Three Months Ended June 30, 2013: Net loss for the Oil and Gas segment was $1.7 million for the three months ended June 30, 2014, compared to Net loss of $2.0 million for the same period in 2013 as a result of:

Revenue increased primarily due to a 15% increase in volumes sold driven by production from two new Piceance Mancos Shale wells and an increase in non-operated Bakken crude oil volumes sold, and a 35% increase in the average hedged price received for natural gas sold. These increases were partially offset by an 18% decrease in the average price received for crude oil sold.

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

Depreciation, depletion and amortization increased primarily due to a higher depletion rate, applied to greater production.

Interest income (expense), net was comparable to prior year.

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

Income tax (expense) benefit: The effective tax rate is higher in 2014 primarily due to the research and development tax credit not being extended to 2014.

Results of Operations for Oil and Gas for the Six Months Ended June 30, 2014 Compared to the Six Months Ended June 30, 2013: Net loss for the Oil and Gas segment was $3.7 million for the six months ended June 30, 2014, compared to Net loss of $2.0 million for the same period in 2013 as a result of:

Revenue increased primarily due to a 5% increase in volumes sold driven by increased gallons of NGL sales from production on the two new Mancos Shale wells, and a 24% increase in the average hedged price received for natural gas sold, partially offset by an 8% decrease in the average price received for crude oil sold.

Operations and maintenance increased primarily due to higher non-operated well costs, higher production taxes and ad valorem taxes on higher natural gas revenue.

Depreciation, depletion and amortization increased primarily due to a higher depletion rate, applied to greater production.

Interest income (expense), net increased primarily due to interest received on third-party non-operated well revenue in the prior year that offset interest expense.

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

Income tax (expense) benefit: The effective tax rate is higher in 2014 primarily due to the research and development tax credit not being extended to 2014. The prior year reflected the entire year of the 2012 research and development tax credit due to retroactive reinstatement of the credit in January 2013 by the U.S. Congress.



52




Corporate Activity

Results of Operations for Corporate activities for the Three Months Ended June 30, 2014 Compared to the Three Months Ended June 30, 2013: Net loss for Corporate was $1.2 million for the three months ended June 30, 2014, compared to Net income of $11.7 million for the three months ended June 30, 2013 as a result of:

The settlement of the de-designated interest rate swaps in the fourth quarter of 2013, resulted in no activity for the three months ended June 30, 2014, compared to the recognition of an unrealized, non-cash mark-to-market gain of $18.8 million during the three months ended June 30, 2013.

The income for the three months ended June 30, 2014 included lower interest expense as compared to the three months ended June 30, 2013, as a result of lower interest rate debt from refinancing activities in fourth quarter 2013 and the settlement of the de-designated interest rate swaps.

Results of Operations for Corporate activities for the Six Months Ended June 30, 2014 Compared to the Six Months Ended June 30, 2013: Net loss for Corporate was $0.8 million for the six months ended June 30, 2014, compared to Net income of $17.4 million for the six months ended June 30, 2013 as a result of:

The settlement of the de-designated interest rate swaps in the fourth quarter of 2013, resulted in no activity for the six months ended June 30, 2014, compared to the recognition of an unrealized, non-cash mark-to-market gain of $26.2 million during the six months ended June 30, 2013.

The income for the six months ended June 30, 2014 included lower interest expense as compared to the six months ended June 30, 2013, as a result of lower interest rate debt from refinancing activities in fourth quarter 2013 and the settlement of the de-designated interest rate swaps.


Critical Accounting Policies

There have been no material changes in our critical accounting policies from those reported in our 2013 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 2013 Annual Report on Form 10-K.


Liquidity and Capital Resources

OVERVIEW

BHC and its subsidiaries require significant amounts of 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. Generally, we experience significant cash requirements during peak months of the winter heating season due to higher natural gas consumption.

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.


53



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 six months ended June 30, 2014 and 2013 (in thousands):

Cash provided by (used in):
2014
2013
Increase (Decrease)
Operating activities
$
173,835

$
197,385

$
(23,550
)
Investing activities
$
(180,296
)
$
(145,224
)
$
(35,072
)
Financing activities
$
13,317

$
(36,990
)
$
50,307


Year-to-Date 2014 Compared to Year-to-Date 2013

Operating Activities

Net cash provided by operating activities was $24 million lower for the six months ended June 30, 2014, than for the same period in 2013 primarily attributable to:

Cash earnings (net income plus non-cash adjustments) were $4.1 million higher for the six months ended June 30, 2014 than for the same period in the prior year.

Net outflows from operating assets and liabilities were $24 million for the six months ended June 30, 2014, compared to net cash outflows of $11 million in the same period in the prior year. Changes are primarily due to:

Increased working capital requirements resulting from higher natural gas volumes sold during our peak winter heating season months driven by cold weather and higher natural gas prices creating an increase in fuel cost adjustments recorded in regulatory assets in our Utility Group; and

Receipt in 2013 of approximately $8.4 million from a government grant relating to the Busch Ranch wind project.

Investing Activities

Net cash used in investing activities was $180 million for the six months ended June 30, 2014, compared to net cash used in investing activities of $145 million for the same period in 2013 for a variance of $35 million. The variance was primarily driven by:

Capital expenditures of approximately $177 million for the six months ended June 30, 2014, compared to $147 million for the six months ended June 30, 2013. The increase is related primarily to the construction of Cheyenne Prairie at our Electric Utilities segment.

54




Financing Activities

Net cash provided by financing activities for the six months ended June 30, 2014, was $13.3 million, compared to net cash used in financing activities for the same period in 2013 of $37 million for a variance of $50 million. The variance was primarily driven by:

Net short-term borrowings under the revolving credit facility for the six months ended June 30, 2014 were used primarily to fund additional working capital requirements due to colder weather during the peak winter heating season and the increase in overall capital expenditures. The prior period reflected the refinancing of the $275 million term loan, proceeds of which, replaced a short term loan of $150 million, a short term loan of $100 million, and $25 million used to pay off short-term borrowings under the Revolving Credit Facility.


Dividends

Dividends paid on our common stock totaled $34.8 million for the six months ended June 30, 2014, or $0.78 per share. On July 30, 2014, our board of directors declared a quarterly dividend of $0.39 per share payable September 1, 2014, which is equivalent to an annual dividend rate of $1.56 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.


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

On May 29, 2014, we amended our $500 million corporate Revolving Credit Facility agreement to extend the term through May 29, 2019. This facility is substantially similar to the former agreement, which includes 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 continue to be 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 our most favorable Corporate credit rating from S&P and Moody’s for our unsecured debt. Based on our credit ratings, the margins for base rate borrowings, Eurodollar borrowings and letters of credit were 0.125%, 1.125% and 1.125%, respectively, from May 29, 2014 through June 30, 2014; a reduction of 0.250% for each method of borrowing. A commitment fee is charged on the unused amount of the Revolving Credit Facility and is 0.175% based on our credit rating, a reduction of 0.025% compared to the prior arrangement.

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
June 30, 2014
June 30, 2014
June 30, 2014
Revolving Credit Facility
May 29, 2019
$
500

$
133

$
20

$
347


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 recourse leverage ratio. Under the Revolving Credit Facility, our recourse leverage ratio is calculated by dividing the sum of our recourse debt, letters of credit and certain guarantees issued, 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 June 30, 2014.


55



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.

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 $75 million notional amount floating-to-fixed interest rate swaps with a maximum remaining term of approximately 2.5 years. These swaps have been designated as cash flow hedges for the Revolving Credit Facility, 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 $7.7 million at June 30, 2014.

Financing Activities

On June 30, 2014, Black Hills Power and Cheyenne Light entered into Bond Purchase Agreements, to authorize the sale of $160 million of first mortgage bonds in a private placement to finance Cheyenne Prairie. Black Hills Power will issue $85 million of 4.43% first mortgage bonds due October 20, 2044. Cheyenne Light will issue $75 million of 4.53% first mortgage bonds due October 20, 2044. The closing date for the sale of the first mortgage bonds for both utilities is anticipated to be October 1, 2014, subject to satisfaction of customary closing conditions.


On November 19, 2013, we entered into a $525 million, 4.25% senior unsecured note expiring on November 30, 2023. The proceeds of this debt were used to:

Redeem our $250 million senior unsecured 9.0% notes originally due on May 15, 2014. This repayment occurred on December 19, 2013, for approximately $261 million which included a make-whole provision of approximately $8.5 million and accrued interest.

Repay our variable interest rate Black Hills Wyoming project financing with a remaining balance of $87 million originally due on December 9, 2016, and settle the interest rate swaps designated to this project financing of $8.5 million.

Settle the $250 million notional de-designated interest rate swaps for approximately $64 million.

Pay down $55 million of the Revolving Credit Facility.

Remainder was used for general corporate purposes.

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 long-term corporate term loan due on September 30, 2013, and $25 million in short-term borrowing under our Revolving Credit Facility. At June 30, 2014, the cost of borrowing under this new term loan was 1.3125% (LIBOR plus a margin of 1.125%).

Future Financing Plans

We anticipate the following financing activities:

Closing on the delayed-draw private placement bonds Black Hills Power and Cheyenne Light executed on June 30, 2014 to finance Cheyenne Prairie. It’s anticipated that Black Hills Power and Cheyenne Light will execute the draw of $85 million and $75 million, respectively, on October 1, 2014; and

Evaluate options for the $275 million term loan expiring on June 19, 2015.


56



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% 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 June 30, 2014, the restricted net assets at our Electric Utilities and Gas Utilities were approximately $141 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 only financial covenant under 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 June 30, 2014, we were in compliance with this covenant.

There have been no other material changes in our financing transactions and short-term liquidity from those reported in Item 7 of our 2013 Annual Report on Form 10-K filed with the SEC.

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 June 30, 2014:
Rating Agency
Senior Unsecured Rating
Outlook
S&P
BBB
Stable
Moody’s (a)
Baa1
Stable
Fitch (b)
  BBB+
Stable
__________
(a)
On January 30, 2014, Moody’s upgraded the BHC credit rating to Baa1 with a Stable outlook.
(b) On June 13, 2014, Fitch upgraded the BHC credit rating to BBB+ with a Stable outlook.


57



The following table represents the credit ratings of Black Hills Power’s Senior Secured Mortgage Bonds at June 30, 2014:
Rating Agency
Senior Secured Rating
S&P
A-
Moody’s *
A1
Fitch **
A
___________
*
On January 30, 2014, Moody’s upgraded the BHP credit rating to A1 with a Stable outlook.
** On June 13, 2014, Fitch upgraded the BHP credit rating to A with a Stable outlook.


Capital Requirements

Actual and forecasted capital requirements are as follows (in thousands):
 
Expenditures for the
 
Total
 
Total
 
Total
 
Six Months Ended June 30, 2014 (a)
 
2014 Planned
Expenditures (b)
 
2015 Planned
Expenditures
 
2016 Planned
Expenditures
Utilities:
 
 
 
 
 
 
 
Electric Utilities
$
96,249

 
$
250,700

 
$
189,300

 
$
160,500

Gas Utilities
22,176

 
63,000

 
62,000

 
47,600

Non-regulated Energy:
 
 
 
 
 
 
 
Power Generation
48

 
2,500

 
5,200

 
3,200

Coal Mining
2,755

 
6,600

 
6,200

 
7,300

Oil and Gas
27,859

 
117,800

 
122,700

 
122,200

Corporate
9,013

 
8,700

 
5,900

 
6,100

 
$
158,100

 
$
449,300

 
$
391,300

 
$
346,900

__________    
(a)    Expenditures for the six months ended June 30, 2014 include the impact of accruals for property, plant and equipment.
(b)    Includes actual expenditures for the six months ended June 30, 2014.

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 18 of our Notes to the Consolidated Financial Statements in our 2013 Annual Report on Form 10-K.

Natural Gas Delivery Agreement

In 2012, we entered into a ten-year gas gathering and processing contract for natural gas production from our properties in the Piceance Basin in Colorado, under which we pay a gathering fee per Mcf. The contract requires us to deliver a minimum of 20,000 Mcf per day. This agreement became effective in first quarter of 2014 upon completion of the processing infrastructure capable of handling the committed volumes. We believe that our reserves dedicated to the gathering system, and the projected volumes are adequate to materially satisfy our delivery commitments under this agreement.

Construction Commitments

Construction of Cheyenne Prairie, a 132 MW 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 September 30, 2014. As of June 30, 2014, contracts for equipment purchases and for construction were 100% and 98% committed, respectively.


58



Bond Purchase Agreements

On June 30, 2014, Black Hills Power and Cheyenne Light entered into agreements to issue $160 million of first mortgage bonds to finance Cheyenne Prairie. Black Hills Power will issue $85 million of 4.43% coupon first mortgage bonds due October 20, 2044, and Cheyenne Light will issue $75 million of 4.53% coupon first mortgage bonds due October 20, 2044. The closing date for the sale of the first mortgage bonds for both utilities is anticipated October 1, 2014.

Guarantees

Except as noted below, there have been no significant changes to guarantees from those previously disclosed in Note 19 of the Notes to the Consolidated Financial Statements in our 2013 Annual Report on Form 10-K.

During the second quarter, guarantees of payment obligations arising from commodity transactions of BHUH for natural gas supply were reduced by $70 million and no longer exist, primarily due to improvement of the corporate credit rating, as well as the conversion of certain guarantees to letters of credit.


New Accounting Pronouncements

Other than the pronouncements reported in our 2013 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 position, results of operations, or cash flows.


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 2013 Annual Report on Form 10-K including statements contained within Item 1A - Risk Factors of our 2013 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.


59




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:
 
June 30, 2014
 
December 31, 2013
 
June 30, 2013
Net derivative (liabilities) assets
$
(1,647
)
 
$
(6,071
)
 
$
(7,203
)
Cash collateral offset in Derivatives
3,384

 
6,733

 
7,203

Cash Collateral included in Other current assets
2,767

 
3,390

 
2,938

Net receivable (liability) position
$
4,504

 
$
4,052

 
$
2,938



Oil and Gas Activities

We have entered into agreements to hedge a portion of our estimated 2014, 2015 and 2016 natural gas and crude oil production from the Oil and Gas segment. The hedge agreements in place at June 30, 2014, were as follows:

Natural Gas
 
March 31,
June 30,
September 30,
December 31,
Total Year
2014
 
 
 
 
 
Swaps - MMBtu


1,335,000

1,305,000

2,640,000

Weighted Average Price per MMBtu
$

$

$
4.03

$
4.04

$
4.03

 
 
 
 
 
 
2015
 
 
 
 
 
Swaps - MMBtu
1,217,500

1,180,000

955,000

1,000,000

4,352,500

Weighted Average Price per MMBtu
$
4.24

$
4.03

$
4.00

$
4.04

$
4.08

 
 
 
 
 
 
2016
 
 
 
 
 
Swaps - MMBtu
587,500

572,500

567,500

545,000

2,272,500

Weighted Average Price per MMBtu
$
3.91

$
3.98

$
4.08

$
3.90

$
3.97


Crude Oil
 
March 31,
June 30,
September 30,
December 31,
Total Year
2014
 
 
 
 
 
Swaps - Bbls


57,000

57,000

114,000

Weighted Average Price per Bbl
$

$

$
90.55

$
90.66

$
90.60

 
 
 
 
 
 
2015
 
 
 
 
 
Swaps - Bbls
55,500

51,000

42,000

36,000

184,500

Weighted Average Price per Bbl
$
89.98

$
87.84

$
88.18

$
87.92

$
88.48

 
 
 
 
 
 
2016
 
 
 
 
 
Swaps - Bbls
33,000

33,000

30,000

30,000

126,000

Weighted Average Price per Bbl
$
83.45

$
83.45

$
83.33

$
83.33

$
83.39



60



Financing Activities

We engage in activities to manage risks associated with changes in interest rates. We have entered into floating-to-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations associated with our floating rate debt obligations. Further details of the swap agreements are set forth in Note 8 of the Notes to Consolidated Financial Statements in our 2013 Annual Report on Form 10-K and in Note 8 of the Notes to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

The contract or notional amounts, terms of our interest rate swaps and the interest rate swaps balances reflected on the Condensed Consolidated Balance Sheets were as follows (dollars in thousands) as of:
 
June 30, 2014
December 31, 2013
June 30, 2013
 
Designated 
Interest Rate
Swaps
(a)
 
Designated
Interest Rate
Swaps
 (a)
 
Designated
Interest Rate
Swaps
(b)
 
De-designated
Interest Rate
Swaps
(c)
Notional
$
75,000

 
$
75,000

 
$
150,000

 
$
250,000

Weighted average fixed interest rate
4.97
%
 
4.97
%
 
5.04
%
 
5.67
%
Maximum terms in years
2.5

 
3.0

 
3.5

 
0.5

Derivative liabilities, current
$
3,480

 
$
3,474

 
$
6,965

 
$
61,899

Derivative liabilities, non-current
$
4,251

 
$
5,614

 
$
12,384

 
$

Pre-tax accumulated other comprehensive income (loss)
$
(7,731
)
 
$
(9,088
)
 
$
(19,349
)
 
$

__________
(a)
These swaps are designated to borrowings on our Revolving Credit Facility, and are priced using three-month LIBOR, matching the floating portion of the related debt.
(b)
At June 30, 2013, $75 million of these interest rate swaps were designated to borrowings on our Revolving Credit Facility and $75 million were designated to borrowings on our project financing debt at Black Hills Wyoming. These swaps are priced using three-month LIBOR, matching the floating portion of the related swaps. The portion of the swaps that were designated to Black Hills Wyoming were settled during the fourth quarter of 2013 upon repayment of the Black Hills Wyoming project financing.
(c)
These swaps were settled during the fourth quarter of 2013.

Based on June 30, 2014 market interest rates and balances related to our interest rate swaps, a loss of approximately $3.5 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 June 30, 2014. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective.

During the quarter ended June 30, 2014, 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.


61



BLACK HILLS CORPORATION

Part II — Other Information

ITEM 1.
Legal Proceedings

For information regarding legal proceedings, see Note 18 in Item 8 of our 2013 Annual Report on Form 10-K and Note 14 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 14 is incorporated by reference into this item.

ITEM 1A.
Risk Factors

Except as noted below, there are no material changes to the risk factors previously disclosed in Item 1A of Part I in our 2013 Annual Report on Form 10-K.

ENVIRONMENTAL RISKS

Federal and state laws concerning greenhouse gas regulations and air emissions may materially increase our generation and production costs and could render some of our generating units uneconomical to operate and maintain.

We own and operate regulated and non-regulated fossil-fuel generating plants in South Dakota, Wyoming, and Colorado. Recent developments under federal and state laws and regulations governing air emissions from fossil-fuel generating plants will likely result in more stringent emission limitations, which could have a material impact on our costs of operations. In addition to the environmental matters identified in Item 1A of our Annual Report on    Form 10-K under the caption “Environmental Matters”, the following recently proposed regulations could negatively impact our operations.

On June 2, 2014, the EPA proposed the Clean Power Plan to cut carbon emissions from existing electric generating units. The design of the Clean Power Plan is to decrease existing coal-fired generation, and increase the utilization of existing gas generation, increase renewable energy, and demand side management. This rule could have a significant impact on our coal and natural gas generating fleet. The rule calls for states to develop plans to meet their assigned emission rate targets by 2030. The rule also allows states to formulate a regional approach whereby they would join with other states and be assigned a new single target for the group. We are currently evaluating this proposal, but cannot predict the impact on operations as this rule is expected to be final in June 2015, and state plans are expected to be due at the earliest in June 2016, with extensions possible to 2017 and 2018. We expect any impact to us to be mitigated through the recent Osage, Ben French, Neil Simpson I and W.N. Clark plant closures.
 
The Clean Power Plan could have a significant impact on our WRDC coal mine. Coal competes with other energy sources, such as natural gas, wind, solar and hydropower. If the Clean Power Plan Rule regulations were to have an adverse effect on coal as a domestic energy source, this rule could have a significant impact on our coal mining operations.

New or more stringent regulations or other energy efficiency requirements could require us to incur significant additional costs relating to, among other things, the installation of additional emission control equipment, the acceleration of capital expenditures, the purchase of additional emissions allowances or offsets, the acquisition or development of additional energy supply from renewable resources, and the closure of certain generating facilities. To the extent our regulated fossil-fuel generating plants are included in rate base we will attempt to recover costs associated with complying with emission standards or other requirements. We will also attempt to recover the emission compliance costs of our non-regulated fossil-fuel generating plants from utility and other purchasers of the power generated by those non-regulated power plants. Any unrecovered costs could have a material impact on our results of operations and financial condition. In addition, future changes in environmental regulations governing air emissions could render some of our power generating units more expensive or uneconomical to operate and maintain.




62



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

There were no unregistered securities sold during the six months ended June 30, 2014.
 
 
 
 
 
 
 
 
 


ITEM 4.
Mine Safety Disclosures

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

ITEM 5.
Other Information

None.


ITEM 6.
Exhibits

Exhibit Number
Description
 
 
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 Registrant’s Form 8-K filed on July 15, 2010). Fourth Supplemental Indenture dated as of November 19, 2013 (filed as Exhibit 4 to the Registrant’s Form 8-K filed on November 18, 2013).
 
 
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).
 
 
Exhibit 10.1*
Credit Agreement dated May 29, 2014 among Black Hills Corporation, as Borrower, U.S. Bank, National Association, in its capacity as administrative agent for the Banks under the Credit Agreement, and as a Bank, and the other Banks party thereto (filed as Exhibit 10 to the Registrant’s Form 8-K filed on May 30, 2014.)
 
 
Exhibit 10.2*
Bond Purchase Agreement dated as of June 30, 2014 by and among Black Hills Power, Inc., New York Life Insurance Company, New York Life Insurance and Annuity Corporation, Teachers Insurance and Annuity Association of America, John Hancock Life Insurance Company (U.S.A.), John Hancock Life & Health Insurance Company, John Hancock Life Insurance Company of New York and United of Omaha Life Insurance Company (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on July 2, 2014.)
 
 

63


Exhibit 10.3*
Bond Purchase Agreement dated as of June 30, 2014 by and among Cheyenne Light, Fuel and Power Company, New York Life Insurance Company, New York Life Insurance and Annuity Corporation, Teachers Insurance and Annuity Association of America, John Hancock Life Insurance Company (U.S.A.), John Hancock Life & Health Insurance Company, John Hancock Life Insurance Company of New York, Mutual of Omaha Insurance Company, United of Omaha Life Insurance Company and American Equity Investment Life Insurance Company (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on July 2, 2014.)
 
 
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.



64



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:
August 6, 2014
 


65



INDEX TO EXHIBITS

Exhibit Number
Description
 
 
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). Fourth Supplemental Indenture dated as of November 19, 2013 (filed as Exhibit 4 to the Registrants’ Form 8-K filed on November 18, 2013).
 
 
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).
 
 
Exhibit 10.1*
Credit Agreement dated May 29, 2014 among Black Hills Corporation, as Borrower, U.S. Bank, National Association, in its capacity as administrative agent for the Banks under the Credit Agreement, and as a Bank, and the other Banks party thereto (filed as Exhibit 10 to the Registrant’s Form 8-K filed on May 30, 2014.)
 
 
Exhibit 10.2*
Bond Purchase Agreement dated as of June 30, 2014 by and among Black Hills Power, Inc., New York Life Insurance Company, New York Life Insurance and Annuity Corporation, Teachers Insurance and Annuity Association of America, John Hancock Life Insurance Company (U.S.A.), John Hancock Life & Health Insurance Company, John Hancock Life Insurance Company of New York and United of Omaha Life Insurance Company (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on July 2, 2014.)
 
 
Exhibit 10.3*
Bond Purchase Agreement dated as of June 30, 2014 by and among Cheyenne Light, Fuel and Power Company, New York Life Insurance Company, New York Life Insurance and Annuity Corporation, Teachers Insurance and Annuity Association of America, John Hancock Life Insurance Company (U.S.A.), John Hancock Life & Health Insurance Company, John Hancock Life Insurance Company of New York, Mutual of Omaha Insurance Company, United of Omaha Life Insurance Company and American Equity Investment Life Insurance Company (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on July 2, 2014.)
 
 
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.
 
 

66



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.


67