BKH 10Q Q1 2015


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-Q
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
 
EXCHANGE ACT OF 1934
 
For the quarterly period ended March 31, 2015
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 April 30, 2015
Common stock, $1.00 par value
44,821,847

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 Months Ended March 31, 2015 and 2014
 
 
 
 
 
 
Condensed Consolidated Statements of Comprehensive Income (Loss) - unaudited
 
 
 
   Three Months Ended March 31, 2015 and 2014
 
 
 
 
 
 
Condensed Consolidated Balance Sheets - unaudited
 
 
 
   March 31, 2015, December 31, 2014 and March 31, 2014
 
 
 
 
 
 
Condensed Consolidated Statements of Cash Flows - unaudited
 
 
 
   Three Months Ended March 31, 2015 and 2014
 
 
 
 
 
 
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 is a 132 MW natural gas-fired generating facility jointly owned by Black Hills Power and Cheyenne Light in Cheyenne, Wyoming. Cheyenne Prairie was placed into commercial service on October 1, 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
CPCN
Certificate of Public Convenience and Necessity
CPUC
Colorado Public Utilities Commission
CVA
Credit Valuation Adjustment
Dodd-Frank
Dodd-Frank Wall Street Reform and Consumer Protection Act
Dth
Dekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu)
Energy West
Energy West Wyoming, Inc., a subsidiary of Gas Natural, Inc.
FASB
Financial Accounting Standards Board
Fitch
Fitch Ratings
GAAP
Accounting principles generally accepted in the United States of America
GHG
Greenhouse Gases
GCA
Gas Cost Adjustment -- adjustments that allow us to pass the prudently-incurred cost of natural gas and certain services through to customers.
Global Settlement
Settlement with a utilities commission where the dollar figure is agreed upon, but the specific adjustments used by each party to arrive at the figure are not specified in public rate orders.
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.
IFRS
International Financial Reporting Standards

3



Iowa Gas
Black Hills Iowa Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
IPP
Independent power producer
IRS
United States Internal Revenue Service
IUB
Iowa Utilities Board
Kansas Gas
Black Hills Kansas Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
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 (1 barrel equals 6 Mcfe)
NPSC
Nebraska Public Service Commission
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
March 31,
 
2015
2014
 
(in thousands, except per share amounts)
 
 
 
Revenue
$
441,987

$
460,169

 
 
 
Operating expenses:
 
 
Utilities -
 
 
Fuel, purchased power and cost of natural gas sold
205,327

230,468

Operations and maintenance
71,084

71,227

Non-regulated energy operations and maintenance
22,050

22,332

Depreciation, depletion and amortization
39,586

36,083

Taxes - property, production and severance
11,936

10,336

Other operating expenses
52

125

Total operating expenses
350,035

370,571

 
 
 
Operating income
91,952

89,598

 
 
 
Other income (expense):
 
 
Interest charges -
 
 
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts and realized settlements on interest rate swaps)
(19,910
)
(17,860
)
Allowance for funds used during construction - borrowed
158

270

Capitalized interest
276

257

Interest income
448

390

Allowance for funds used during construction - equity
56

238

Other income (expense), net
331

592

Total other income (expense), net
(18,641
)
(16,113
)
 
 
 
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes
73,311

73,485

Equity in earnings (loss) of unconsolidated subsidiaries
(297
)
(1
)
Income tax benefit (expense)
(25,120
)
(25,366
)
Net income (loss) available for common stock
$
47,894

$
48,118

 
 
 
Earnings (loss) per share of common stock:
 
 
Earnings (loss) per share, Basic
$
1.08

$
1.09

Earnings (loss) per share, Diluted
$
1.07

$
1.08

Weighted average common shares outstanding:
 
 
Basic
44,541

44,330

Diluted
44,660

44,554

 
 
 
Dividends declared per share of common stock
$
0.405

$
0.390


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
March 31,
 
2015
2014
 
(in thousands)
 
 
 
Net income (loss) available for common stock
$
47,894

$
48,118

 
 
 
Other comprehensive income (loss), net of tax:
 
 
Fair value adjustments on derivatives designated as cash flow hedges (net of tax (expense) benefit of $(1,042) and $1,307 for the three months ended 2015 and 2014, respectively)
1,836

(2,257
)
Reclassification adjustments for cash flow hedges settled and included in net income (loss) (net of tax (expense) benefit of $1,254 and $(425) for the three months ended 2015 and 2014, respectively)
(1,241
)
780

Benefit plan liability adjustments - net gain (loss) (net of tax (expense) benefit of $15 and $2 for the three months ended 2015 and 2014, respectively)
(27
)
(2
)
Benefit plan liability adjustments - prior service cost (net of tax (expense) benefit of $(90) for the three months ended 2014

164

Reclassification adjustments of benefit plan liability - prior service cost (net of tax (expense) benefit of $19 and $4 for the three months ended 2015 and 2014, respectively)
(36
)
(9
)
Reclassification adjustments of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(247) and $(85) for the three months ended 2015 and 2014, respectively)
458

157

Other comprehensive income (loss), net of tax
990

(1,167
)
 
 
 
Comprehensive income (loss) available for common stock
$
48,884

$
46,951


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
 
March 31,
2015
 
December 31, 2014
 
March 31,
2014
 
(in thousands)
ASSETS
 
 
 
 
 
Current assets:
 
 
 
 
 
Cash and cash equivalents
$
63,385

 
$
21,218

 
$
17,641

Restricted cash and equivalents
2,191

 
2,056

 
2

Accounts receivable, net
178,421

 
189,992

 
203,625

Materials, supplies and fuel
66,626

 
91,191

 
66,187

Derivative assets, current

 

 
1,846

Income tax receivable, net
159

 
2,053

 
1,826

Deferred income tax assets, net, current
23,913

 
48,288

 
25,780

Regulatory assets, current
56,542

 
74,396

 
62,946

Other current assets
47,448

 
24,842

 
24,563

Total current assets
438,685

 
454,036

 
404,416

 
 
 
 
 
 
Investments
17,210

 
17,294

 
16,916

 
 
 
 
 
 
Property, plant and equipment
4,652,058

 
4,563,400

 
4,318,194

Less: accumulated depreciation and depletion
(1,351,857
)
 
(1,324,025
)
 
(1,298,398
)
Total property, plant and equipment, net
3,300,201

 
3,239,375

 
3,019,796

 
 
 
 
 
 
Other assets:
 
 
 
 
 
Goodwill
353,396

 
353,396

 
353,396

Intangible assets, net
3,121

 
3,176

 
3,342

Regulatory assets, non-current
178,935

 
183,443

 
138,173

Other assets, non-current
28,280

 
29,086

 
28,925

Total other assets, non-current
563,732

 
569,101

 
523,836

 
 
 
 
 
 
TOTAL ASSETS
$
4,319,828

 
$
4,279,806

 
$
3,964,964


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
 
March 31,
2015
 
December 31, 2014
 
March 31,
2014
 
(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
 
 
Current liabilities:
 
 
 
 
 
Accounts payable
$
88,770

 
$
124,139

 
$
149,681

Accrued liabilities
166,781

 
170,115

 
145,973

Derivative liabilities, current
3,342

 
3,340

 
3,498

Regulatory liabilities, current
17,621

 
3,687

 
583

Notes payable
102,600

 
75,000

 
100,000

Current maturities of long-term debt

 
275,000

 

Total current liabilities
379,114

 
651,281

 
399,735

 
 
 
 
 
 
Long-term debt, net of current maturities
1,542,658

 
1,267,589

 
1,396,949

 
 
 
 
 
 
Deferred credits and other liabilities:
 
 
 
 
 
Deferred income tax liabilities, net, non-current
522,290

 
523,716

 
466,856

Derivative liabilities, non-current
2,143

 
2,680

 
4,805

Regulatory liabilities, non-current
148,918

 
145,144

 
116,793

Benefit plan liabilities
162,334

 
158,966

 
113,324

Other deferred credits and other liabilities
154,604

 
154,406

 
129,083

Total deferred credits and other liabilities
990,289

 
984,912

 
830,861

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


 

 

 
 
 
 
 
 
Stockholders’ equity:
 
 
 
 
 
Common stock equity —
 
 
 
 
 
Common stock $1 par value; 100,000,000 shares authorized; issued 44,856,790; 44,714,072; and 44,666,953 shares, respectively
44,857

 
44,714

 
44,667

Additional paid-in capital
749,517

 
748,840

 
742,016

Retained earnings
629,135

 
599,389

 
570,963

Treasury stock, at cost – 33,755; 42,226; and 37,038 shares, respectively
(1,688
)
 
(1,875
)
 
(1,638
)
Accumulated other comprehensive income (loss)
(14,054
)
 
(15,044
)
 
(18,589
)
Total stockholders’ equity
1,407,767

 
1,376,024

 
1,337,419

 
 
 
 
 
 
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
$
4,319,828

 
$
4,279,806

 
$
3,964,964


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)
Three Months Ended March 31,
 
2015
2014
Operating activities:
(in thousands)
Net income (loss) available for common stock
$
47,894

$
48,118

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
Depreciation, depletion and amortization
39,586

36,083

Deferred financing cost amortization
519

568

Stock compensation
2,083

3,716

Deferred income taxes
22,048

25,953

Employee benefit plans
5,283

3,703

Other adjustments, net
6,748

5,190

Changes in certain operating assets and liabilities:
 
 
Materials, supplies and fuel
25,689

22,291

Accounts receivable, unbilled revenues and other operating assets
47,947

(78,576
)
Accounts payable and other operating liabilities
(44,652
)
29,074

Other operating activities, net
(1,658
)
1,978

Net cash provided by (used in) operating activities
151,487

98,098

 
 
 
Investing activities:
 
 
Property, plant and equipment additions
(117,523
)
(83,609
)
Other investing activities
(348
)
(3,220
)
Net cash provided by (used in) investing activities
(117,871
)
(86,829
)
 
 
 
Financing activities:
 
 
Dividends paid on common stock
(18,148
)
(17,399
)
Common stock issued
999

881

Short-term borrowings - issuances
77,700

86,800

Short-term borrowings - repayments
(50,100
)
(69,300
)
Other financing activities
(1,900
)
(2,451
)
Net cash provided by (used in) financing activities
8,551

(1,469
)
Net change in cash and cash equivalents
42,167

9,800

Cash and cash equivalents, beginning of period
21,218

7,841

Cash and cash equivalents, end of period
$
63,385

$
17,641


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 2014 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 2014 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 March 31, 2015, December 31, 2014, and March 31, 2014 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 months ended March 31, 2015 and March 31, 2014, and our financial condition as of March 31, 2015, December 31, 2014, and March 31, 2014, 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. We are currently assessing the impact any other new accounting pronouncements that have been issued may have on our financial position, results of operations, or cash flows.

Simplifying the Presentation of Debt Issuance Costs, ASU 2015-03

In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. Debt issuance costs related to a recognized debt liability will be presented on the balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as an asset. Amortization of these costs will continue to be reported as interest expense. ASU 2015-03 is effective for annual and interim reporting periods beginning after December 15, 2015. Early adoption is permitted. We are currently evaluating the impact of adoption that ASU 2015-03 will have on our financial position, results of operations, or cash flows.


10



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. On April 1, 2015, FASB voted to propose to defer the effective date of ASU 2014-09 by one year. The proposed guidance would be effective for annual and interim reporting periods beginning after December 15, 2017 and early adoption is 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.


(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 March 31, 2015
 
External
Operating
Revenue
 
Inter-company
Operating
Revenue
 
Net Income (Loss)
Utilities:
 
 
 
 
 
 
   Electric
 
$
182,974

 
$
3,424

 
$
18,929

   Gas
 
237,651

 

 
22,212

Non-regulated Energy:
 
 
 
 
 
 
   Power Generation
 
1,953

 
20,721

 
8,145

   Coal Mining
 
8,142

 
7,792

 
3,010

   Oil and Gas
 
11,267

 

 
(5,071
)
Corporate activities
 

 

 
669

Inter-company eliminations
 

 
(31,937
)
 

Total
 
$
441,987

 
$

 
$
47,894


Three Months Ended March 31, 2014
 
External
Operating
Revenue
 
Inter-company
Operating
Revenue
 
Net Income (Loss)
Utilities:
 
 
 
 
 
 
   Electric
 
$
178,095

 
$
4,007

 
$
14,575

   Gas
 
259,337

 

 
24,698

Non-regulated Energy:
 
 
 
 
 
 
   Power Generation
 
1,269

 
21,079

 
8,073

   Coal Mining
 
6,618

 
8,880

 
2,464

   Oil and Gas
 
14,850

 

 
(2,022
)
Corporate activities
 

 

 
330

Inter-company eliminations
 

 
(33,966
)
 

Total
 
$
460,169

 
$

 
$
48,118


 
 
 
 
 
 
 
 
 
 
 
 
 
 


11



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:
March 31, 2015
 
December 31, 2014
 
March 31, 2014
Utilities:
 
 
 
 
 
   Electric (a)
$
2,817,423

 
$
2,748,680

 
$
2,572,616

   Gas
839,802

 
906,922

 
842,660

Non-regulated Energy:
 
 
 
 
 
   Power Generation (a)
75,945

 
76,945

 
90,643

   Coal Mining
77,399

 
74,407

 
74,523

   Oil and Gas
403,657

 
366,247

 
295,083

Corporate activities
105,602

 
106,605

 
89,439

Total assets
$
4,319,828

 
$
4,279,806

 
$
3,964,964

__________
(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.


(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
March 31, 2015
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
53,862

$
24,540

$
(834
)
$
77,568

Gas Utilities
63,252

28,785

(1,588
)
90,449

Power Generation
1,152



1,152

Coal Mining
3,638



3,638

Oil and Gas
4,646


(13
)
4,633

Corporate
981



981

Total
$
127,531

$
53,325

$
(2,435
)
$
178,421


 
Accounts
Unbilled
Less Allowance for
Accounts
December 31, 2014
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
59,714

$
26,474

$
(722
)
$
85,466

Gas Utilities
47,394

45,546

(781
)
92,159

Power Generation
1,369



1,369

Coal Mining
3,151



3,151

Oil and Gas
5,305


(13
)
5,292

Corporate
2,555



2,555

Total
$
119,488

$
72,020

$
(1,516
)
$
189,992



12



 
Accounts
Unbilled
Less Allowance for
Accounts
March 31, 2014
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
53,733

$
20,063

$
(690
)
$
73,106

Gas Utilities
77,982

35,791

(814
)
112,959

Power Generation
1,340



1,340

Coal Mining
2,616



2,616

Oil and Gas
10,920


(13
)
10,907

Corporate
2,697



2,697

Total
$
149,288

$
55,854

$
(1,517
)
$
203,625


(4)    REGULATORY ACCOUNTING

We had the following regulatory assets and liabilities (in thousands):
 
Maximum
As of
As of
As of
 
Amortization (in years)
March 31, 2015
December 31, 2014
March 31, 2014
Regulatory assets
 
 
 
 
Deferred energy and fuel cost adjustments - current (a) (d)
1
$
30,833

$
23,820

$
23,935

Deferred gas cost adjustments (a)(d)
2
6,138

37,471

38,505

Gas price derivatives (a)
7
21,606

18,740

4,420

AFUDC (b)
45
12,114

12,358

12,349

Employee benefit plans (c) (e)
12
97,700

97,126

65,833

Environmental (a)
subject to approval
1,240

1,314

1,317

Asset retirement obligations (a)
44
3,237

3,287

3,271

Bond issue cost (a)
23
3,240

3,276

3,383

Renewable energy standard adjustment (a)
5
5,590

9,622

16,088

Flow through accounting (c)
35
26,835

25,887

21,837

Decommissioning costs
10
13,702

12,484


Other regulatory assets (a)
15
13,242

12,454

10,181

 
 
$
235,477

$
257,839

$
201,119

 
 
 
 
 
Regulatory liabilities
 
 
 
 
Deferred energy and gas costs (a) (d)
1
$
18,094

$
6,496

$
6,485

Employee benefit plans (c) (e)
12
53,151

53,139

34,355

Cost of removal (a)
44
81,449

78,249

67,640

Other regulatory liabilities (c)
25
13,845

10,947

8,896

 
 
$
166,539

$
148,831

$
117,376

__________
(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. Fluctuations in deferred gas cost adjustments compared to the same period in the prior year are primarily due to higher natural gas prices driven by demand and market conditions from the peak winter heating season in the first part of 2014. 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.
(e)
Increase compared to March 31, 2014 is due to a decrease in the discount rate and a change in the mortality tables used in employee benefit plan estimates.

13




(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:
 
March 31, 2015
 
December 31, 2014
 
March 31, 2014
Materials and supplies
$
52,429

 
$
49,555

 
$
50,727

Fuel - Electric Utilities
6,780

 
6,637

 
7,218

Natural gas in storage held for distribution
7,417

 
34,999

 
8,242

Total materials, supplies and fuel
$
66,626

 
$
91,191

 
$
66,187



(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 March 31,
 
2015
2014
 
 
 
Net income (loss) available for common stock
$
47,894

$
48,118

 
 
 
Weighted average shares - basic
44,541

44,330

Dilutive effect of:
 
 
Equity compensation
119

224

Weighted average shares - diluted
44,660

44,554


The following outstanding securities were not included in the computation of diluted earnings per share as their effect would have been anti-dilutive (in thousands):
 
Three Months Ended March 31,
 
2015
2014
 
 
 
Equity compensation
107

46

Anti-dilutive shares
107

46



14




(7)    NOTES PAYABLE AND LONG-TERM DEBT

We had the following short-term debt outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
 
March 31, 2015
December 31, 2014
March 31, 2014
 
Balance Outstanding
Letters of Credit
Balance Outstanding
Letters of Credit
Balance Outstanding
Letters of Credit
Revolving Credit Facility
$
102,600

$
22,300

$
75,000

$
35,000

$
100,000

$
27,700


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 at March 31, 2015. A commitment fee is charged on the unused amount of the Revolving Credit Facility and was 0.175% based on our credit rating.

Replacement of Corporate Term Loan

On April 13, 2015, we entered into a new $300 million Corporate term loan expiring April 12, 2017. This new term loan replaced the $275 million Corporate term loan due on June 19, 2015. In accordance with the terms of the agreement, the $275 million Corporate term loan is classified as Long-Term Debt as of March 31, 2015. The additional $25 million, less interest and fees, will be used for general corporate purposes. The cost of the borrowing under the new term loan is LIBOR plus a margin of 0.9%. The covenants on the new term loan are substantially the same as the revolving credit facility.

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 March 31, 2015
 
Covenant Requirement
Recourse Leverage Ratio
55%
 
Less than
65%

As of March 31, 2015, 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 2014 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.


15



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.

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.

Oil and Gas

We produce natural gas, NGLs 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 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, net of balance sheet offsetting as permitted by GAAP. 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:
 
March 31, 2015
 
December 31, 2014
 
March 31, 2014
 
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)
305,000

5,367,500

 
334,500

6,582,500

 
442,500

8,296,250

Maximum terms in months (b)
1

1

 
1

1

 
1

1

Derivative assets, current
$

$

 
$

$

 
$

$

Derivative assets, non-current
$

$

 
$

$

 
$

$

Derivative liabilities, current
$

$

 
$

$

 
$

$

Derivative liabilities, non-current
$

$

 
$

$

 
$

$

__________
(a)
Crude oil in Bbls, natural gas in MMBtus.
(b)
Refers to the tenor of the derivative instrument. Assets and liabilities are classified as current/non-current based on the production month hedged and the corresponding settlement of the derivative instrument.
Based on March 31, 2015, prices a $9.9 million gain would be reclassified from AOCI over the next 12 months. Estimated and actual realized gains or losses will change during future periods as market prices fluctuate.


16



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), or the Condensed Consolidated Statements of Comprehensive Income (Loss).


The contract or notional amounts and terms of the natural gas derivative commodity instruments held at our Utilities were as follows, as of:
 
March 31, 2015
 
December 31, 2014
 
March 31, 2014
 
Notional
(MMBtus)
 
Maximum
Term
(months) (a)
 
Notional
(MMBtus)
 
Maximum
Term
(months) (a)
 
Notional
(MMBtus)
 
Maximum
Term
(months) (a)
Natural gas futures purchased
17,280,000

 
69
 
19,370,000

 
72
 
16,140,000

 
80
Natural gas options purchased
1,320,000

 
12
 
4,020,000

 
8
 
1,320,000

 
12
Natural gas basis swaps purchased
15,735,000

 
57
 
12,005,000

 
60
 
14,575,000

 
69
__________
(a) Term reflects the maximum forward period hedged.

We had the following derivative balances related to the hedges in our Utilities reflected in our Condensed Consolidated Balance Sheets as of (in thousands):
 
March 31, 2015
December 31, 2014
March 31, 2014
Derivative assets, current
$

$

$
1,846

Derivative assets, non-current
$

$

$

Derivative liabilities, non-current
$

$

$

Net unrealized (gain) loss included in Regulatory assets or Regulatory liabilities
$
21,606

$
18,740

$
4,420



17



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:
 
March 31, 2015
 
December 31, 2014
 
March 31, 2014
 
Interest Rate
Swaps (a)
 
Interest Rate
Swaps (a)
 
Interest Rate
Swaps (a)
Notional
$
75,000

 
$
75,000

 
$
75,000

Weighted average fixed interest rate
4.97
%
 
4.97
%
 
4.97
%
Maximum terms in years
1.75

 
2.00

 
2.75

Derivative liabilities, current
$
3,342

 
$
3,340

 
$
3,498

Derivative liabilities, non-current
$
2,143

 
$
2,680

 
$
4,805

__________
(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 borrowings.

Based on March 31, 2015, market interest rates and balances related to our interest rate swaps, a loss of approximately $3.3 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.

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 March 31, 2015
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
 
$
(886
)
 
Interest expense
 
$
1,437

 
 
 
$

Commodity derivatives
 
3,764

 
Revenue
 
(3,932
)
 
 
 

Total
 
$
2,878

 
 
 
$
(2,495
)
 
 
 
$


Three Months Ended March 31, 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
 
$
(91
)
 
Interest expense
 
$
(894
)
 
 
 
$

Commodity derivatives
 
(3,473
)
 
Revenue
 
(311
)
 
 
 

Total
 
$
(3,564
)
 
 
 
$
(1,205
)
 
 
 
$


 
 
 
 
 
 
 
 
 
 
 

 
 
 
 
 
 
 
 
 
 
 


18




(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, 9 and 10 to the Consolidated Financial Statements included in our 2014 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 contracts for our Oil and Gas segment are valued using the market approach and include exchange-traded futures and basis swaps. Fair value was derived using exchange quoted settlement 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.

Utilities Segments:

The commodity contracts for our Utilities Segments, valued using the market approach, include exchange-traded futures, options and basis swaps (Level 2) 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.

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.


19



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 March 31, 2015
 
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

8,096


 
(8,096
)

    Options -- Gas



 


    Basis Swaps -- Gas

6,526


 
(6,526
)

Commodity derivatives — Utilities

1,184


 
(1,184
)

Total
$

$
15,806

$

 
$
(15,806
)
$

 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
Commodity derivatives — Oil and Gas
 
 
 
 
 


Options -- Oil
$

$

$

 
$

$

Basis Swaps -- Oil

2


 
(2
)

Options -- Gas



 


Basis Swaps -- Gas

256


 
(256
)

Commodity derivatives — Utilities

22,002


 
(22,002
)

Interest rate swaps

5,485


 

5,485

Total
$

$
27,745

$

 
$
(22,260
)
$
5,485




20




 
As of December 31, 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

8,599


 
(8,599
)

Options -- Gas



 


Basis Swaps -- Gas

6,558


 
(6,558
)

Commodity derivatives —Utilities

2,389


 
(2,389
)

Total
$

$
17,546

$

 
$
(17,546
)
$

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

$

$

 
$

$

Basis Swaps -- Oil



 


Options -- Gas



 


Basis Swaps -- Gas

473


 
(473
)

Commodity derivatives — Utilities

19,303


 
(19,303
)

Interest rate swaps

6,020


 

6,020

Total
$

$
25,796

$

 
$
(19,776
)
$
6,020



 
As of March 31, 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

7


 
(7
)

Options -- Gas



 


Basis Swaps -- Gas

490


 
(490
)

Commodity derivatives — Utilities

3,226


 
(1,380
)
1,846

Total
$

$
3,723

$

 
$
(1,877
)
$
1,846

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

$

$

 
$

$

Basis Swaps -- Oil

1,983


 
(1,983
)

Options -- Gas



 


Basis Swaps -- Gas

2,114


 
(2,114
)

Commodity derivatives — Utilities

6,919


 
(6,919
)

Interest rate swaps

8,303


 

8,303

Total
$

$
19,319

$

 
$
(11,016
)
$
8,303



21




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 March 31, 2015, December 31, 2014, and March 31, 2014, 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 March 31, 2015
 
Balance Sheet Location
 
Fair Value
of Asset
Derivatives
Fair Value
of Liability
Derivatives
Derivatives designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
9,989

$

Commodity derivatives
Derivative assets — non-current
 
4,633


Commodity derivatives
Derivative liabilities — current
 

126

Commodity derivatives
Derivative liabilities — non-current
 

132

Interest rate swaps
Derivative liabilities — current
 

3,342

Interest rate swaps
Derivative liabilities — non-current
 

2,143

Total derivatives designated as hedges
 
 
$
14,622

$
5,743

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

$

Commodity derivatives
Derivative assets — non-current
 


Commodity derivatives
Derivative liabilities — current
 

7,530

Commodity derivatives
Derivative liabilities — non-current
 

13,288

Total derivatives not designated as hedges
 
 
$

$
20,818


As of December 31, 2014
 
Balance Sheet Location
 
Fair Value
of Asset
Derivatives
Fair Value
of Liability
Derivatives
Derivatives designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
10,391

$

Commodity derivatives
Derivative assets — non-current
 
4,766


Commodity derivatives
Derivative liabilities — current
 

185

Commodity derivatives
Derivative liabilities — non-current
 

288

Interest rate swaps
Derivative liabilities — current
 

3,340

Interest rate swaps
Derivative liabilities — non-current
 

2,680

Total derivatives designated as hedges
 
 
$
15,157

$
6,493

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

$

Commodity derivatives
Derivative assets — non-current
 


Commodity derivatives
Derivative liabilities — current
 

8,032

Commodity derivatives
Derivative liabilities — non-current
 

8,882

Total derivatives not designated as hedges
 
 
$

$
16,914



22



As of March 31, 2014
 
Balance Sheet Location
 
Fair Value
of Asset
Derivatives
Fair Value
of Liability
Derivatives
Derivatives designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
30

$

Commodity derivatives
Derivative assets — non-current
 
466


Commodity derivatives
Derivative liabilities — current
 

3,187

Commodity derivatives
Derivative liabilities — non-current
 

910

Interest rate swaps
Derivative liabilities — current
 

3,498

Interest rate swaps
Derivative liabilities — non-current
 

4,805

Total derivatives designated as hedges
 
 
$
496

$
12,400

 
 
 
 
 
Derivatives not designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
1,846

$

Commodity derivatives
Derivative assets — non-current
 


Commodity derivatives
Derivative liabilities — current
 


Commodity derivatives
Derivative liabilities — non-current
 

5,539

Interest rate swaps
Derivative liabilities — current
 


Interest rate swaps
Derivative liabilities — non-current
 


Total derivatives not designated as hedges
 
 
$
1,846

$
5,539

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 



23




(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:
 
March 31, 2015
 
December 31, 2014
 
March 31, 2014
 
Carrying
Amount
Fair Value
 
Carrying
Amount
Fair Value
 
Carrying
Amount
Fair Value
Cash and cash equivalents (a)
$
63,385

$
63,385

 
$
21,218

$
21,218

 
$
17,641

$
17,641

Restricted cash and equivalents (a)
$
2,191

$
2,191

 
$
2,056

$
2,056

 
$
2

$
2

Notes payable (a)
$
102,600

$
102,600

 
$
75,000

$
75,000

 
$
100,000

$
100,000

Long-term debt, including current maturities (b)
$
1,542,658

$
1,767,113

 
$
1,542,589

$
1,734,555

 
$
1,396,949

$
1,541,727

__________
(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
March 31, 2015
March 31, 2014
Gains (losses) on cash flow hedges:
 
 
 
Interest rate swaps
Interest expense
$
1,437

$
894

Commodity contracts
Revenue
(3,932
)
311

 
 
(2,495
)
1,205

Income tax
Income tax benefit (expense)
1,254

(425
)
Reclassification adjustments related to cash flow hedges, net of tax
 
$
(1,241
)
$
780

 
 
 
 
Amortization of defined benefit plans:
 
 
 
Prior service cost
Utilities - Operations and maintenance
$
(27
)
$
(25
)
 
Non-regulated energy operations and maintenance
(28
)
12

 
 
 
 
Actuarial gain (loss)
Utilities - Operations and maintenance
454

157

 
Non-regulated energy operations and maintenance
251

85

 
 
650

229

Income tax
Income tax benefit (expense)
(228
)
(81
)
Reclassification adjustments related to defined benefit plans, net of tax
 
$
422

$
148



24



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, 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
)
 
 
 
 
Balance as of December 31, 2014
$
5,093

$
(20,137
)
$
(15,044
)
Other comprehensive income (loss), net of tax
595

395

990

Balance as of March 31, 2015
$
5,688

$
(19,742
)
$
(14,054
)


(12)    SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

Three months ended
March 31, 2015
 
March 31, 2014
 
(in thousands)
Non-cash investing and financing activities from continuing operations—
 
 
 
Property, plant and equipment acquired with accrued liabilities
$
33,534

 
$
40,939

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)
$
(10,909
)
 
$
(11,452
)
Income taxes, net
$
(2
)
 
$
4



(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 March 31,
 
2015
2014
Service cost
$
1,494

$
1,362

Interest cost
3,880

3,963

Expected return on plan assets
(4,867
)
(4,516
)
Prior service cost
15

16

Net loss (gain)
2,759

1,201

Net periodic benefit cost
$
3,281

$
2,026



25



Defined Benefit Postretirement Healthcare Plans

The components of net periodic benefit cost for the Defined Benefit Postretirement Healthcare Plans were as follows (in thousands):
 
Three Months Ended March 31,
 
2015
2014
Service cost
$
464

$
425

Interest cost
450

479

Expected return on plan assets
(33
)
(21
)
Prior service cost (benefit)
(107
)
(107
)
Net loss (gain)
102

40

Net periodic benefit cost
$
876

$
816


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 March 31,
 
2015
2014
Service cost
$
491

$
374

Interest cost
364

362

Prior service cost
1

1

Net loss (gain)
270

124

Net periodic benefit cost
$
1,126

$
861


Contributions

We anticipate that we will make contributions to the benefit plans during 2015 and 2016. 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
Additional Contributions
Contributions
 
Three Months Ended March 31, 2015
Anticipated for 2015
Anticipated for 2016
Defined Benefit Pension Plans
$

$
10,200

$
10,200

Non-pension Defined Benefit Postretirement Healthcare Plans
$
939

$
2,816

$
4,026

Supplemental Non-qualified Defined Benefit and Defined Contribution Plans
$
372

$
1,115

$
1,544



26




(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 2014 Annual Report on Form 10-K except for those described below.

Oil Creek Fire

On June 29, 2012, a forest and grassland fire occurred in the western Black Hills of Wyoming. A fire investigator retained by the Weston County Fire Protection District 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 large group of private landowners filed suit in the United States District Court for the District of Wyoming. There are approximately 36 Plaintiff groups (including property jointly owned by multiple family members or entities), or approximately 73 individually named private plaintiffs. In addition, the State of Wyoming has intervened in the lawsuit. Both the private landowners and the State of Wyoming assert 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 compensatory damages, the lawsuit seeks recovery of punitive damages. We have denied and will vigorously defend all claims arising out of the fire. We cannot predict the outcome of expert investigation, the viability of alleged claims or the outcome of the litigation.

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, and we will pursue recoveries to the maximum extent available under the policies. The deductible applicable to some types of claims arising out of this fire is $1.0 million. Based upon information currently available, we believe that a loss associated with settlement of pending claims is probable. Accordingly, 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. We cannot reasonably estimate the amount of such possible loss because expert investigations and our review of damage claim documentation are ongoing, and there are significant factual and legal issues to be resolved. Further claims may be presented by these claimants and other parties. 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. Based on the legal standard for measuring damages that we believe applies to this matter, we estimate the current total claims to be approximately $55 million; however the actual amount of allowed claims and any loss will depend on the resolution of certain factual and legal issues. We are not yet able 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 March 31, 2015, we were in compliance with the debt 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 March 31, 2015:

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 March 31, 2015, the restricted net assets at our Utilities Group were approximately $338 million.


27



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 205,400 customers in South Dakota, Wyoming, Colorado and Montana; and also distributes natural gas to approximately 36,000 Cheyenne Light customers in Wyoming. Our Gas Utilities serve approximately 543,200 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 months ended March 31, 2015 and 2014, and our financial condition as of March 31, 2015, December 31, 2014 and March 31, 2014, 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 53.

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.


28



Results of Operations

Executive Summary, Significant Events and Overview

Three Months Ended March 31, 2015 Compared to Three Months Ended March 31, 2014. Net income (loss) for the three months ended March 31, 2015 was $48 million, or $1.07 per share, compared to Net income (loss) of $48 million, or $1.08 per share, reported for the same period in 2014.

The following table summarizes select financial results by operating segment and details significant items (in thousands):
 
Three Months Ended March 31,
 
2015
2014
Variance
Revenue
 
 
 
Utilities
$
424,049

$
441,439

$
(17,390
)
Non-regulated Energy
49,875

52,696

(2,821
)
Inter-company eliminations
(31,937
)
(33,966
)
2,029

 
$
441,987

$
460,169

$
(18,182
)
 
 
 
 
Net income (loss)
 
 
 
Electric Utilities
$
18,929

$
14,575

$
4,354

Gas Utilities
22,212

24,698

(2,486
)
Utilities
41,141

39,273

1,868

 
 
 
 
Power Generation
8,145

8,073

72

Coal Mining
3,010

2,464

546

Oil and Gas
(5,071
)
(2,022
)
(3,049
)
Non-regulated Energy
6,084

8,515

(2,431
)
 
 
 
 
Corporate activities and eliminations
669

330

339

 
 
 
 
Net income (loss)
$
47,894

$
48,118

$
(224
)

Overview of Business Segments and Corporate Activity

Utilities Group

Gas Utilities experienced milder weather during the three months ended March 31, 2015 compared to the three months ended March 31, 2014. Heating degree days were 9% lower for the three months ended March 31, 2015, compared to the same period in 2014. Heating degree days for the three months ended March 31, 2015 were 4% higher than normal, compared to 14% higher than normal for the same period in 2014.

On April 15, 2015, we filed a request for approval with the WPSC of our $17 million purchase agreement to acquire Energy West, Wyoming, a deal previously announced on October 14, 2014. Energy West is a gas utility serving approximately 6,700 customers, in Cody, Ralston, and Meeteetse, Wyoming. The purchase also includes a 30 mile gas transmission pipeline and a 42 mile gas gathering pipeline, both located near the utility service territory. A hearing is scheduled with the WPSC on May 14, 2015. We have requested approval from the WPSC to close on the acquisition on June 1, 2015.

On March 16, 2015, we announced plans to build a new corporate headquarters in Rapid City that will consolidate our approximately 500 employees in Rapid City from five locations into one. The investment in the new corporate headquarters will be approximately $70 million and will support all our businesses. The cost of the facility will replace existing expenses of our five facilities throughout Rapid City. Construction will begin in the second quarter of 2015 with completion expected in 2017.


29



On March 2, 2015, the SDPUC issued an order approving a rate stipulation and agreement authorizing an annual electric revenue increase for Black Hills Power of $6.9 million. The agreement was a Global Settlement and did not stipulate return on equity and capital structure. The SDPUC’s decision provides Black Hills Power a return on its investment in Cheyenne Prairie and associated infrastructure, and provides recovery of its share of operating expenses for this natural gas fired facility. Black Hills Power implemented interim rates on October 1, 2014, coinciding with Cheyenne Prairie’s commercial operation date. Final rates were approved on April 1, 2015, effective October 1, 2014.

In January 2015, Colorado Electric implemented new rates in accordance with the CPUC approval received on December 19, 2014 for an annual electric revenue increase of $3.1 million. The approval also allowed a 9.83% return on equity and a capital structure of 49.83% equity and 50.17% debt, as well as approving implementation of a construction financing rider. This approval allows Colorado Electric to recover increased operating expenses and infrastructure investments, including those for the Busch Ranch Wind Farm, placed in service late 2012. The implementation of the rider also allows Colorado Electric to recover a return on the construction costs for a $65 million natural gas-fired combustion turbine that will replace the retired W.N. Clark power plant.

In January 2015, Kansas Gas implemented new base rates in accordance with the rate request approval received on December 16, 2014 from the KCC to increase base rates by $5.2 million. This increase in base rates allows Kansas Gas to recover infrastructure and increased operating costs.

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. We are awaiting approval of the CPCN from the WPSC. Black Hills Power received approval on November 6, 2014 from the SDPUC for a permit to construct the South Dakota portion of this line. Assuming timely receipt of remaining approvals, Black Hills Power plans to commence construction in the third quarter of 2015.

On May 5, 2014, Colorado Electric issued an all-source generation request, including up to 60 megawatts of eligible renewable energy resources to serve its customers in southern Colorado. Our power generation segment submitted solar and wind bids in response to the request. An independent evaluator submitted a report to the CPUC confirming the ranking of the bids. On February 27, 2015 the Commission determined that none of the renewable bids were cost effective. Colorado Electric submitted a request for reconsideration on March 19, 2015. On April 16, 2015, the Commission deliberated these requests filed by the company and various parties to the initial decision.  The Commission declined to change its decision.  In their written order, the commission noted precedent allowing utilities to secure new bid pricing. Colorado Electric, at it’s discretion, has sixty days to renegotiate bids and submit a revised contract or contacts for approval. Colorado Electric is currently reviewing its options.

Non-regulated Energy Group

Our Oil and Gas segment was impacted by lower commodity prices for crude oil and natural gas for the three months ended March 31, 2015 compared to the same period in 2014. The average hedged price received for natural gas decreased by 34% for the three months ended March 31, 2015 compared to the same period in 2014. The average hedged price received for oil decreased by 26% for the three months ended March 31, 2015 compared to the same period in 2014. Oil and Gas production volumes increased 23% for the three months ended March 31, 2015 compared to the same period in 2014.

We review the carrying value of our natural gas and oil properties under the full cost accounting rules of the SEC on a quarterly basis, known as a ceiling test. We did not record a ceiling test impairment for the three months ended March 31, 2015. However, using our current reserves information, a ceiling impairment charge could occur in 2015 if commodity prices for crude oil and natural gas remain at current low levels.

Our southern Piceance Basin drilling program continued with three Mancos Shale wells placed on production (one in January 2015 and two in February 2015). Production results to date from these wells have been favorable, and exceeded our expectations.

Our Oil and Gas segment contracted for two additional drilling rigs to support drilling operations in the southern Piceance Basin. Drilling operations are ongoing for 10 additional horizontal wells on three separate surface pads. Due to the partial carryover of 2014 planned Mancos and other drilling capital to 2015, and the addition of one more Mancos well to the 2015 drilling plan, we have increased our planned 2015 capital expenditures to $167 million from $123 million.

30




Corporate Activities

On April 13, 2015, we entered into a new $300 million unsecured term loan. The loan has a two-year term with a maturity date of April 12, 2017. Proceeds of the term note were used to repay the existing $275 million term note due June 19, 2015.

Operating Results

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

Utilities Group

We report two segments within the Utilities Group: Electric Utilities and Gas Utilities. The Electric Utilities segment includes the regulated electric operations of Black Hills Power, Colorado Electric and the regulated 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 to the gas utility customers of Cheyenne Light. 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.


31



Electric Utilities
 
Three Months Ended March 31,
 
2015
2014
Variance
 
(in thousands)
Revenue — electric
$
169,917

$
168,365

$
1,552

Revenue — gas
16,481

13,737

2,744

Total revenue
186,398

182,102

4,296

 
 
 
 
Fuel, purchased power and cost of gas — electric
67,690

78,418

(10,728
)
Purchased gas — gas
10,098

8,274

1,824

Total fuel, purchased power and cost of gas
77,788

86,692

(8,904
)
 
 
 
 
Gross margin — electric
102,227

89,947

12,280

Gross margin — gas
6,383

5,463

920

Total gross margin
108,610

95,410

13,200

 
 
 
 
Operations and maintenance
43,984

42,601

1,383

Depreciation and amortization
21,044

19,086

1,958

Total operating expenses
65,028

61,687

3,341

 
 
 
 
Operating income
43,582

33,723

9,859

 
 
 
 
Interest expense, net
(13,833
)
(12,013
)
(1,820
)
Other income (expense), net
69

256

(187
)
Income tax benefit (expense)
(10,889
)
(7,391
)
(3,498
)
Net income (loss)
$
18,929

$
14,575

$
4,354



32



 
Three Months Ended March 31,
Revenue - Electric (in thousands)
2015
 
2014
Residential:
 
 
 
Black Hills Power
$
20,140

 
$
20,061

Cheyenne Light
10,265

 
9,673

Colorado Electric
24,570

 
24,679

Total Residential
54,975

 
54,413

 
 
 
 
Commercial:
 
 
 
Black Hills Power
24,741

 
21,528

Cheyenne Light
15,820

 
14,394

Colorado Electric
22,164

 
21,890

Total Commercial
62,725

 
57,812

 
 
 
 
Industrial:
 
 
 
Black Hills Power
8,299

 
7,335

Cheyenne Light
8,626

 
7,224

Colorado Electric
10,756

 
9,038

Total Industrial
27,681

 
23,597

 
 
 
 
Municipal:
 
 
 
Black Hills Power
858

 
792

Cheyenne Light
516

 
454

Colorado Electric
3,062

 
3,307

Total Municipal
4,436

 
4,553

 
 
 
 
Total Retail Revenue - Electric
149,817

 
140,375

 
 
 
 
Contract Wholesale:
 
 
 
Total Contract Wholesale - Black Hills Power
5,420

 
5,598

 
 
 
 
Off-system Wholesale:
 
 
 
Black Hills Power
6,635

 
9,075

Cheyenne Light
1,961

 
2,387

Colorado Electric
84

 
2,082

Total Off-system Wholesale
8,680

 
13,544

 
 
 
 
Other Revenue:
 
 
 
Black Hills Power
4,190

 
6,878

Cheyenne Light
475

 
753

Colorado Electric
1,335

 
1,217

Total Other Revenue
6,000

 
8,848

 
 
 
 
Total Revenue - Electric
$
169,917

 
$
168,365



33



 
Three Months Ended
March 31,
Quantities Generated and Purchased (in MWh)
2015
 
2014
Generated —
 
 
 
Coal-fired:
 
 
 
Black Hills Power (a)
376,834

 
417,248

Cheyenne Light (b)
194,716

 
169,789

Total Coal-fired
571,550

 
587,037

 
 
 
 
Natural Gas and Oil:
 
 
 
Black Hills Power
2,878

 
2,308

Cheyenne Light
2,839

 

Colorado Electric (c)
3,492

 
18,068

Total Natural Gas and Oil
9,209

 
20,376

 
 
 
 
Wind:
 
 
 
Colorado Electric
9,091

 
14,329

Total Wind
9,091

 
14,329

 
 
 
 
Total Generated:
 
 
 
Black Hills Power
379,712

 
419,556

Cheyenne Light
197,555

 
169,789

Colorado Electric
12,583

 
32,397

Total Generated
589,850

 
621,742

 
 
 
 
Purchased —
 
 
 
Black Hills Power
438,443

 
430,801

Cheyenne Light
187,779

 
207,318

Colorado Electric 
472,187

 
470,101

Total Purchased
1,098,409

 
1,108,220

 
 
 
 
Total Generated and Purchased:
 
 
 
Black Hills Power
818,155

 
850,357

Cheyenne Light
385,334

 
377,107

Colorado Electric
484,770

 
502,498

Total Generated and Purchased
1,688,259

 
1,729,962

__________
(a)
Decrease reflects the retirement of Neil Simpson I on March 21, 2014.
(b)
Increase is due to purchasing spinning reserve in the current year compared to carrying spinning reserve in the prior year.
(c)
Decrease in 2015 generation is primarily driven by commodity prices that impacted power marketing sales.

34




 
Three Months Ended March 31,
Quantity (in MWh)
2015
2014
Residential:
 
 
Black Hills Power
146,963

171,311

Cheyenne Light
67,499

70,656

Colorado Electric
157,214

153,632

Total Residential
371,676

395,599

 
 
 
Commercial:
 
 
Black Hills Power
195,078

184,448

Cheyenne Light
131,103

126,412

Colorado Electric
165,081

158,179

Total Commercial
491,262

469,039

 
 
 
Industrial:
 
 
Black Hills Power
111,859

100,851

Cheyenne Light
111,096

90,724

Colorado Electric
118,107

90,116

Total Industrial
341,062

281,691

 
 
 
Municipal:
 
 
Black Hills Power
7,700

7,686

Cheyenne Light
2,550

2,493

Colorado Electric
28,113

26,687

Total Municipal
38,363

36,866

 
 
 
Total Retail Quantity Sold
1,242,363

1,183,195

 
 
 
Contract Wholesale:
 
 
Total Contract Wholesale - Black Hills Power (a)
84,271

95,228

 
 
 
Off-system Wholesale:
 
 
Black Hills Power
245,638

254,796

Cheyenne Light
48,872

52,356

Colorado Electric (b)
2,469

30,746

Total Off-system Wholesale
296,979

337,898

 
 
 
Total Quantity Sold:
 
 
Black Hills Power
791,509

814,320

Cheyenne Light
361,120

342,641

Colorado Electric
470,984

459,360

Total Quantity Sold
1,623,613

1,616,321

 
 
 
Other Uses, Losses or Generation, net (c):
 
 
Black Hills Power
26,646

36,037

Cheyenne Light
24,214

34,466

Colorado Electric
13,786

43,138

Total Other Uses, Losses and Generation, net
64,646

113,641

 
 
 
Total Energy
1,688,259

1,729,962

__________
(a)
Decrease is driven by load requirements related to a Wygen III unit-contingent PPA.
(b)
Decrease in 2015 generation is primarily driven by commodity prices that impacted power marketing sales.
(c)
Includes company uses, line losses, and excess exchange production.

35




 
Three Months Ended March 31,
Degree Days
2015
 
 
 
2014
 
Actual
 
Variance from
30-Year Average
 
Actual Variance to Prior Year
 
Actual
 
Variance from
30-Year Average
Heating Degree Days:
 
 
 
 
 
 
 
 
 
Black Hills Power
2,873
 
(11)%
 
(16)%
 
3,410
 
6%
Cheyenne Light
2,651
 
(12)%
 
(17)%
 
3,206
 
6%
Colorado Electric
2,398
 
(8)%
 
(10)%
 
2,670
 
2%
Combined (a)
2,610
 
(10)%
 
(14)%
 
3,028
 
5%
__________
(a)
Combined actuals are calculated based on the weighted average number of total customers by state.

 
 
 
 
 
 
 
 

Electric Utilities Power Plant Availability
Three Months Ended March 31,
 
2015
2014
Coal-fired plants 
91.3
%
 
95.5
%
 
Other plants (a)
95.7
%
 
78.1
%
 
Total availability
94.1
%
 
86.6
%
 
__________
(a)
The three months ended March 31, 2014, reflects an unplanned outage due to a turbine bearing replacement and combustor upgrade at Pueblo Airport Generation Station.


36



Cheyenne Light Natural Gas Distribution

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

 
Three Months Ended March 31,
 
2015
 
2014
Revenue - Natural Gas (in thousands):
 
 
 
Residential
$
8,712

 
$
8,224

Commercial
4,954

 
3,977

Industrial
1,900

 
1,285

Other Sales Revenue
915

 
251

Total Revenue - Natural Gas
$
16,481

 
$
13,737

 
 
 
 
Gross Margin (in thousands):
 
 
 
Residential
$
3,778

 
$
3,605

Commercial
1,428

 
1,332

Industrial
262

 
275

Other Gross Margin
915

 
251

Total Gross Margin
$
6,383

 
$
5,463

 
 
 
 
Volumes Sold (Dth):
 
 
 
Residential
940,407

 
1,035,177

Commercial
670,589

 
564,394

Industrial
301,277

 
255,927

Total Volumes Sold
1,912,273

 
1,855,498


Results of Operations for the Electric Utilities for the Three Months Ended March 31, 2015 Compared to the Three Months Ended March 31, 2014: Net income for the Electric Utilities was $19 million for the three months ended March 31, 2015, compared to Net income of $15 million for the three months ended March 31, 2014, as a result of:

Gross margin increased primarily due to a return on additional investment in our generating facilities which increased electric gross margins by $9.4 million compared to the same period in the prior year. Electric margins were favorably impacted by higher retail load and demand that increased megawatt hours sold driving an increase of $2.5 million. Colorado Electric also received approval of a one-time settlement agreement from the CPUC on our renewable energy standard adjustment related to Busch Ranch, which increased margins by $2.1 million. Partially offsetting these increases was a negative weather impact on electric and gas residential retail margins of $3.2 million driven by a 14% decrease in heating degree days compared to the same period in the prior year.

Operations and maintenance increased primarily due to costs related to Cheyenne Prairie, which was placed into commercial service on Oct. 1, 2014, and an increase in allowance for uncollectible account expense.

Depreciation and amortization increased primarily due to a higher asset base driven by the addition of Cheyenne Prairie, which was placed into commercial service on Oct. 1, 2014.

Interest expense, net increased primarily due to interest costs from the $160 million of permanent financing placed during the fourth quarter of 2014 for Cheyenne Prairie.

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 2015 primarily due to the increase in liability with respect to uncertain tax positions related to research and development credits.

37




Gas Utilities
 
Three Months Ended March 31,
 
2015
2014
Variance
 
(in thousands)
Revenue:
 
 
 
Natural gas — regulated
$
229,148

$
251,232

$
(22,084
)
Other — non-regulated services
8,503

8,105

398

Total revenue
237,651

259,337

(21,686
)
 
 
 
 
Cost of sales
 
 
 
Natural gas — regulated
152,285

170,774

(18,489
)
Other — non-regulated services
3,913

3,722

191

Total cost of sales
156,198

174,496

(18,298
)
 
 
 
 
Gross margin
81,453

84,841

(3,388
)
 
 
 
 
Operations and maintenance
35,432

35,378

54

Depreciation and amortization
7,046

6,521

525

Total operating expenses
42,478

41,899

579

 
 
 
 
Operating income (loss)
38,975

42,942

(3,967
)
 
 
 
 
Interest expense, net
(3,809
)
(3,853
)
44

Other income (expense), net
(11
)
(17
)
6

Income tax benefit (expense)
(12,943
)
(14,374
)
1,431

Net income (loss)
$
22,212

$
24,698

$
(2,486
)


38



 
Three Months Ended March 31,
Revenue (in thousands)
2015
 
2014
Residential:
 
 
 
Colorado
$
25,736

 
$
23,687

Nebraska
56,444

 
62,892

Iowa
46,366

 
54,764

Kansas
29,328

 
33,277

Total Residential
157,874

 
174,620

 
 
 
 
Commercial:
 
 
 
Colorado
5,097

 
4,697

Nebraska
18,212

 
20,066

Iowa
21,629

 
25,914

Kansas
11,066

 
11,671

Total Commercial
56,004

 
62,348

 
 
 
 
Industrial:
 
 
 
Colorado
29

 
77

Nebraska
317

 
208

Iowa
1,255

 
1,172

Kansas
1,741

 
1,086

Total Industrial
3,342

 
2,543

 
 
 
 
Transportation:
 
 
 
Colorado
365

 
325

Nebraska
5,396

 
5,730

Iowa
1,662

 
1,761

Kansas
2,501

 
2,493

Total Transportation
9,924

 
10,309

 
 
 
 
Other Sales Revenue:
 
 
 
Colorado
43

 
31

Nebraska
657

 
703

Iowa
139

 
152

Kansas
1,165

 
526

Total Other Sales Revenue
2,004

 
1,412

 
 
 
 
Total Regulated Revenue
229,148

 
251,232

 
 
 
 
Non-regulated Services
8,503

 
8,105

 
 
 
 
Total Revenue
$
237,651

 
$
259,337



39



 
Three Months Ended March 31,
Gross Margin (in thousands)
2015
 
2014
Residential:
 
 
 
Colorado
$
6,337

 
$
6,372

Nebraska
18,990

 
20,889

Iowa
13,898

 
15,210

Kansas
11,478

 
11,584

Total Residential
50,703

 
54,055

 
 
 
 
Commercial:
 
 
 
Colorado
1,040

 
1,060

Nebraska
4,669

 
5,163

Iowa
4,636

 
5,225

Kansas
3,387

 
3,183

Total Commercial
13,732

 
14,631

 
 
 
 
Industrial:
 
 
 
Colorado
21

 
30

Nebraska
81

 
68

Iowa
81

 
85

Kansas
393

 
236

Total Industrial
576

 
419

 
 
 
 
Transportation:
 
 
 
Colorado
365

 
326

Nebraska
5,396

 
5,731

Iowa
1,662

 
1,761

Kansas
2,501

 
2,493

Total Transportation
9,924

 
10,311

 
 
 
 
Other Sales Margins:
 
 
 
Colorado
43

 
31

Nebraska
657

 
702

Iowa
139

 
152

Kansas
1,089

 
157

Total Other Sales Margins
1,928

 
1,042

 
 
 
 
Total Regulated Gross Margin
76,863

 
80,458

 
 
 
 
Non-regulated Services
4,590

 
4,383

 
 
 
 
Total Gross Margin
$
81,453

 
$
84,841



40



 
Three Months Ended March 31,
Distribution Quantities Sold and Transportation (in Dth)
2015
2014
Residential:
 
 
Colorado
2,946,805

3,021,434

Nebraska
5,958,956

6,986,293

Iowa
5,516,037

6,643,044

Kansas
3,353,814

3,881,555

Total Residential
17,775,612

20,532,326

 
 
 
Commercial:
 
 
Colorado
617,198

635,690

Nebraska
2,180,694

2,475,156

Iowa
2,880,091

3,485,692

Kansas
1,435,504

1,541,967

Total Commercial
7,113,487

8,138,505

 
 
 
Industrial:
 
 
Colorado
2,402

10,325

Nebraska
45,700

26,965

Iowa
191,005

193,863

Kansas (a) (b)
324,779

180,087

Total Industrial
563,886

411,240

 
 
 
Wholesale and Other:
 
 
Kansas (b)
13,975

68,633

Total Wholesale and Other
13,975

68,633

 
 
 
Total Distribution Quantities Sold
25,466,960

29,150,704

 
 
 
Transportation:
 
 
Colorado
380,049

330,344

Nebraska
9,049,775

9,963,219

Iowa
6,088,049

6,157,366

Kansas
4,297,352

4,827,137

Total Transportation
19,815,225

21,278,066

 
 
 
 
 
 
Total Distribution Quantities Sold and Transportation
45,282,185

50,428,770

__________
(a)
Increase is primarily due to a large customer’s sales volumes compared to the prior year and from a classification change in customer class.
(b)
Decrease from prior year is primarily due a change in customer class.

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.

41




 
Three Months Ended March 31,
 
2015
 
 
 
2014
Heating Degree Days:
Actual
 
Variance
from 30-Year
Average
 
Actual Variance to Prior Year
 
Actual
 
Variance
from 30-Year
Average
Colorado
2,535
 
(9)%
 
(11)%
 
2,859
 
2%
Nebraska
3,014
 
—%
 
(8)%
 
3,272
 
7%
Iowa
3,834
 
13%
 
(8)%
 
4,174
 
19%
Kansas (a)
2,322
 
(6)%
 
(14)%
 
2,689
 
8%
Combined (b) 
3,222
 
4%
 
(9)%
 
3,524
 
14%
__________
(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 March 31, 2015 Compared to the Three Months Ended March 31, 2014: Net income for the Gas Utilities was $22 million for the three months ended March 31, 2015, compared to Net income of $25 million for the three months ended March 31, 2014, as a result of:

Gross margin decreased primarily due to a $5.3 million impact from milder weather than in the same period in the prior year. Heating degree days were 9% lower for the three months ended March 31, 2015, compared to the same period in the prior year and 4% higher than normal in the current year, compared to 14% higher than normal in the prior year. Partially offsetting this weather impact was a $1.2 million increase from base rate adjustments at Kansas Gas which were effective January 1, 2015, and a $0.6 million increase from year-over-year customer growth.

Operations and maintenance was comparable to the prior year reflecting increases in property taxes and allowance for uncollectible account expense, offset by a decrease in employee costs.

Depreciation and amortization increased primarily due to a higher asset base than the same period in the prior year.

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

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

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



42




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
Black Hills Power (a)
Electric
3/2014
10/2014
$
14.6

$
6.9

Kansas Gas (b)
Gas
4/2014
1/2015
$
7.3

$
5.2

Colorado Electric (c)
Electric
4/2014
1/2015
$
4.0

$
3.1

__________
(a)
On March 2, 2015, the SDPUC issued an order approving a rate stipulation and agreement authorizing an increase for Black Hills Power of $6.9 million in annual electric revenue. The agreement was a Global Settlement and did not stipulate return on equity and capital structure. The SDPUC’s decision provides Black Hills Power a return on its investment in Cheyenne Prairie and associated infrastructure, and provides recovery of its share of operating expenses for this natural gas fired facility. Black Hills Power implemented interim rates on October 1, 2014, coinciding with Cheyenne Prairie’s commercial operation date. Final rates were approved on April 1, 2015, effective October 1, 2014.

(b)
On December 16, 2014, Kansas Gas received approval from the KCC to increase base rates by $5.2 million, effective January 2015. This increase in base rates allows Kansas Gas to recover a return on investments in infrastructure and recovery of increased operating costs.

(c)
On December 19, 2014, Colorado Electric received approval from the CPUC for an annual electric revenue increase of $3.1 million. The approval also allowed a 9.83% return on equity and a capital structure of 49.83% equity and 50.17% debt, as well as approving implementation of a construction financing rider. This approval allows Colorado Electric to recover increased operating expenses and a return on infrastructure investments, including those for the Busch Ranch Wind Farm, placed in service late 2012. The implementation of the rider allows Colorado Electric to recover a return on the construction costs for a $65 million natural gas-fired combustion turbine that will replace the retired W.N. Clark power plant.

Capital Investment Recovery Surcharge filings

 
Type of Service
Date Requested
Effective Date
Capital Surcharge Requested
Capital Surcharge Approved
Nebraska Gas (a)
Gas
4/2015
8/2015
$
1.5

$

Iowa Gas (b)
Gas
3/2015
6/2015
$
0.9

$

__________
(a)
On April 6, 2015, Nebraska Gas filed with the NPSC for a capital investment recovery surcharge increase of $1.5 million. Approval is expected in July, 2015.

(b)
On March 17, 2015, Iowa Gas filed with the IUB for a capital investment recovery surcharge increase of $0.9 million. Approval is expected in June 2015.




43




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 March 31,
 
2015
2014
Variance
 
(in thousands)
Revenue
$
22,674

$
22,348

$
326

 
 
 
 
Operations and maintenance
7,828

7,677

151

Depreciation and amortization
1,134

1,209

(75
)
Total operating expense
8,962

8,886

76

 
 
 
 
Operating income
13,712

13,462

250

 
 
 
 
Interest expense, net
(886
)
(928
)
42

Other (expense) income, net
(2
)
(9
)
7

Income tax (expense) benefit
(4,679
)
(4,452
)
(227
)
 
 
 
 
Net income (loss)
$
8,145

$
8,073

$
72

____________
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.

The following table summarizes MWh for our Power Generation segment:
 
Three Months Ended March 31,
 
2015
2014
Quantities Sold, Generated and Purchased (MWh) (a)
 
 Sold
 
 
Black Hills Colorado IPP
284,491

285,956

Black Hills Wyoming (b)
159,558

140,608

Total Sold
444,049

426,564

 
 
 
Generated
 
 
Black Hills Colorado IPP
284,491

285,956

Black Hills Wyoming
137,973

140,678

Total Generated
422,464

426,634

 
 
 
Purchased
 
 
Black Hills Wyoming (b)
24,392

989

Total Purchased
24,392

989

____________
(a) Company use and losses are not included in the quantities sold, generated, and purchased.
(b) Under the 20-year economy PPA with the City of Gillette, effective September 2014, Black Hills Wyoming purchases energy on behalf of the City of Gillette.

44




The following table provides certain operating statistics for our plants within the Power Generation segment:
 
Three Months Ended March 31,
 
2015
2014
Contracted power plant fleet availability:
 
 
Coal-fired plant
98.2
%
99.3
%
Natural gas-fired plants
98.9
%
97.9
%
Total availability
98.7
%
98.2
%

Results of Operations for Power Generation for the Three Months Ended March 31, 2015 Compared to the Three Months Ended March 31, 2014: Net income for the Power Generation segment was $8.1 million for the three months ended March 31, 2015, compared to Net income of $8.1 million for the same period in 2014 as a result of:

Revenue was comparable to the prior year reflecting an increase in PPA pricing, offset by the net effect of the expiration of the CTII PPA and subsequent economy energy PPA.

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 was comparable to the same period in the prior year.

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

Income tax (expense) benefit: The effective tax rate is higher in 2015 primarily due to the increase in liability with respect to uncertain tax positions related to research and development credits.

Coal Mining
 
Three Months Ended March 31,
 
2015
2014
Variance
 
(in thousands)
Revenue
$
15,934

$
15,498

$
436

 
 
 
 
Operations and maintenance
9,904

10,131

(227
)
Depreciation, depletion and amortization
2,503

2,690

(187
)
Total operating expenses
12,407

12,821

(414
)
 
 
 


Operating income (loss)
3,527

2,677

850

 
 
 
 
Interest (expense) income, net
(89
)
(103
)
14

Other income, net
585

603

(18
)
Income tax benefit (expense)
(1,013
)
(713
)
(300
)
 
 
 
 
Net income (loss)
$
3,010

$
2,464

$
546



45



The following table provides certain operating statistics for our Coal Mining segment (in thousands, except for Revenue per ton):

 
Three Months Ended March 31,
 
2015
2014
Tons of coal sold
1,019

1,087

Cubic yards of overburden moved
1,413

910

 
 
 
Revenue per ton
$
15.64

$
14.26


Results of Operations for Coal Mining for the Three Months Ended March 31, 2015 Compared to the Three Months Ended March 31, 2014: Net income for the Coal Mining segment was $3.0 million for the three months ended March 31, 2015, compared to Net income of $2.5 million for the same period in 2014 as a result of:

Revenue increased primarily due to a 10% increase in price per ton sold, partially offset by a 6% decrease in tons sold. The increase in pricing was driven by the price re-opener on our coal contract with the third-party operator of the Wyodak plant which became effective in the third quarter of 2014, partially offset by contract price adjustments based on actual mining costs. Tons of coal sold was negatively impacted by unplanned customer outages, and the closure of Neil Simpson 1 in March 2014. 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 decreased primarily due to mining efficiencies resulting in reduced major maintenance, blasting and lower fuel costs, partially offset by a higher overburden stripping ratio and a favorable coal tax adjustment recognized in 2014.

Depreciation, depletion and amortization decreased primarily due to lower depreciation on mine assets driven by a lower net asset base.

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 in 2015 is higher due primarily to the reduced impact of the tax benefit of percentage depletion.

Oil and Gas
 
Three Months Ended March 31,
 
2015
2014
Variance
 
(in thousands)
Revenue
$
11,267

$
14,850

$
(3,583
)
 
 
 
 
Operations and maintenance
10,917

11,139

(222
)
Depreciation, depletion and amortization
8,095

6,633

1,462

Total operating expenses
19,012

17,772

1,240

 
 
 
 
Operating income (loss)
(7,745
)
(2,922
)
(4,823
)
 
 
 
 
Interest income (expense), net
(384
)
(455
)
71

Other income (expense), net
(223
)
38

(261
)
Income tax benefit (expense)
3,281

1,317

1,964

 
 
 
 
Net income (loss)
$
(5,071
)
$
(2,022
)
$
(3,049
)


46



The following tables provide certain operating statistics for our Oil and Gas segment:
 
Three Months Ended March 31,
 
2015
2014
Production:
 
 
Bbls of oil sold
80,730

74,262

Mcf of natural gas sold
2,254,042

1,759,964

Bbls of NGL sold
28,770

27,041

Mcf equivalent sales
2,911,043

2,367,782


 
Three Months Ended March 31,
 
2015
2014
Average price received: (a) (b)
 
 
Oil/Bbl
$
66.86

$
90.75

Gas/Mcf  
$
2.20

$
3.35

NGL/Bbl
$
13.74

$
49.02

 
 
 
Depletion expense/Mcfe
$
2.40

$
2.25

__________
(a)
Net of hedge settlement gains and losses.
(b)
Based on our quarterly ceiling test under the full cost accounting rules of the SEC, no impairment charge was necessary as of March 31, 2015. If crude oil and natural gas prices remain at or near the current low levels, a ceiling test impairment charge could occur in 2015.

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

 
Three Months Ended March 31, 2015
 
Three Months Ended March 31, 2014
Producing Basin
LOE
Gathering,
 Compression,
  Processing and Transportation (a)
Production Taxes
Total
 
LOE
Gathering,
 Compression,
  Processing and Transportation (a)
Production Taxes
Total
San Juan
$
1.58

$
1.30

$
0.37

$
3.25

 
$
1.54

$
1.20

$
0.63

$
3.37

Piceance
0.33

2.48

0.20

3.01

 
(0.06
)
1.28

0.57

1.79

Powder River
2.89


0.56

3.45

 
2.36


1.34

3.70

Williston
0.24


0.09

0.33

 
0.67


1.90

2.57

All other properties
1.24


0.34

1.58

 
1.61


0.02

1.63

Total weighted average
$
1.19

$
1.35

$
0.31

$
2.85

 
$
1.19

$
0.81

$
0.74

$
2.74

__________
(a)
These costs include both third-party costs and operations costs.
 
 
 
 
 
 
 
 
 
 
In the Piceance and San Juan Basins, our natural gas is transported through our own and third-party gathering systems and pipelines, for which we incur processing, gathering, compression and transportation fees. The sales price for natural gas, condensate and NGLs is reduced for these third-party costs, and the cost of operating our own gathering systems is included in operations and maintenance. The gathering, compression, processing and transportation costs shown in the tables above include amounts paid to third parties, as well as costs incurred in operations associated with our own gas gathering, compression, processing and transportation.

We revised our presentation of these costs in 2014 to include both third-party costs and operations costs. A ten-year gas gathering and processing contract for natural gas production in our Piceance Basin became effective in March of 2014. This take or pay contract requires us to pay a fee on a minimum of 20,000 Mcf per day, regardless of the volume delivered. We did not meet the minimum requirements of this contract until mid-February 2015. Our gathering, compression and processing costs on a per Mcfe basis, as shown in the table above, will be higher in periods when we are not meeting the minimum contract requirements.  The higher costs for 2015 are due to lower volumes delivered to the plant for the first half of the quarter.

47




Results of Operations for Oil and Gas for the Three Months Ended March 31, 2015 Compared to the Three Months Ended March 31, 2014: Net loss for the Oil and Gas segment was $5.1 million for the three months ended March 31, 2015, compared to Net loss of $2.0 million for the same period in 2014 as a result of:

Revenue decreased primarily due to lower commodity market prices for both crude oil and natural gas resulting in a 26% decrease in the average hedged price received for crude oil sold, and a 34% decrease in the average hedged price received for natural gas sold. A production increase of 23%, driven primarily by three new Piceance Mancos Shale wells placed on production in the first quarter of 2015, partially offset the decrease in prices.

Operations and maintenance decreased primarily due to lower production taxes and ad valorem taxes on lower revenue and lower employee costs, partially offset by higher lease and field operation expenses from non-operated wells.

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

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

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

Income tax (expense) benefit: The effective tax rate in 2015 is comparable to the same period in the prior year.

Corporate Activity

Results of Operations for Corporate activities for the Three Months Ended March 31, 2015 Compared to the Three Months Ended March 31, 2014: Net income for Corporate was $0.7 million for the three months ended March 31, 2015, compared to Net income of $0.3 million for the three months ended March 31, 2014 as a result of:

The income for the three months ended March 31, 2015, included lower interest expense compared to the three months ended March 31, 2014, primarily driven by favorable margins on base rate borrowings on our Revolving Credit Facility. Our Revolving Credit Facility agreement was amended and extended on May 29, 2014 with improved margins on base rate borrowings of 0.25% compared to the agreement it replaced.

Critical Accounting Policies

There have been no material changes in our critical accounting policies from those reported in our 2014 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 2014 Annual Report on Form 10-K.

Liquidity and Capital Resources

OVERVIEW

BHC and its subsidiaries require significant 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 uses of cash are our capital expenditures, the purchase of natural gas for our Gas Utilities and our Power Generation segment, as well as the payment of dividends to our shareholders. We experience significant cash requirements during peak months of the winter heating season due to higher natural gas consumption and during periods of high natural gas prices.

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


48



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 and acquisitions, 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 three months ended March 31 (in thousands):

Cash provided by (used in):
2015
2014
Increase (Decrease)
Operating activities
$
151,487

$
98,098

$
53,389

Investing activities
$
(117,871
)
$
(86,829
)
$
(31,042
)
Financing activities
$
8,551

$
(1,469
)
$
10,020


Year-to-Date 2015 Compared to Year-to-Date 2014

Operating Activities

Net cash provided by operating activities was $151 million for the three months ended March 31, 2015, compared to net cash provided by operating activities of $98 million for the same period in 2014 for a variance of $53 million. The variance was primarily attributable to:

Cash earnings (net income plus non-cash adjustments) were comparable for the three months ended March 31, 2015 to the same period in the prior year.

Net inflows from operating assets and liabilities were $29 million for the three months ended March 31, 2015, compared to net cash outflows of $27 million in the same period in the prior year. This $56 million variance was primarily due to:

Cash inflows increased as a result of lower working capital requirements for the three months ended March 31, 2015 compared to the same period in the prior year. Colder weather and higher natural gas prices during the first quarter 2014 peak winter heating season drove a significant increase in natural gas volumes sold, and in natural gas volumes purchased and fuel cost adjustments recorded in regulatory assets. These fuel cost adjustments deferred in the prior year are recovered through their respective cost mechanisms as allowed by the state utility commissions; and
 
Accrued expenditures decreased primarily at our Oil and Gas segment related to drilling activity for the three months ended March 31, 2015 compared to the same period in the prior year.

Investing Activities

Net cash used in investing activities was $118 million for the three months ended March 31, 2015, compared to net cash used in investing activities of $87 million for the same period in 2014. The variance was primarily driven by:

Capital expenditures of approximately $118 million for the three months ended March 31, 2015, compared to $84 million for the three months ended March 31, 2014. The increase is related primarily to higher capital expenditures at our Oil and Gas segment driven by drilling activity in the Southern Piceance in the current year. The prior year Oil and Gas segment capital expenditures were affected by weather delays. Offsetting the oil and gas capital expenditure increase is the construction of Cheyenne Prairie at our Electric Utilities segment occurring in the prior year.

49




Financing Activities

Net cash provided by financing activities for the three months ended March 31, 2015 was $8.6 million, compared to $1.5 million net cash used in financing activities for the same period in 2014. The variance was primarily driven by:

Net short-term borrowings under the revolving credit facility for the three months ended March 31, 2015 increased primarily to fund the increase in overall capital expenditures.


Dividends

Dividends paid on our common stock totaled $18 million for the three months ended March 31, 2015, or $0.405 per share. On April 27, 2015, our board of directors declared a quarterly dividend of $0.405 per share payable June 1, 2015, which is equivalent to an annual dividend rate of $1.62 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 are 0.125%, 1.125% and 1.125%, respectively. A commitment fee is charged on the unused amount of the Revolving Credit Facility and is 0.175% based on our credit rating.

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
March 31, 2015
March 31, 2015
March 31, 2015
Revolving Credit Facility
May 29, 2019
$
500

$
103

$
22

$
375


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 March 31, 2015.

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.


50



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 1.75 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 $5.5 million at March 31, 2015.

Financing Activities

On April 13, 2015, we entered into a new $300 million Corporate term loan expiring April 12, 2017. This new term loan replaced the $275 million Corporate term loan due on June 19, 2015. The additional $25 million, less interest and fees, will be used for general corporate purposes. The cost of the borrowing under the new term loan will be LIBOR plus a margin of 0.9%. The covenants on the new term loan are substantially the same as the revolving credit facility.

On October 1, 2014, Black Hills Power and Cheyenne Light sold $160 million of first mortgage bonds in a private placement to provide permanent financing for Cheyenne Prairie. Black Hills Power issued $85 million of 4.43% coupon first mortgage bonds due October 20, 2044, and Cheyenne Light issued $75 million of 4.53% coupon first mortgage bonds due October 20, 2044.

Future Financing Plans

We anticipate the following financing activities:

Evaluate amending and extending our Revolving Credit Facility for an additional year.
Evaluate the conversion of our $300 million variable-rate Corporate term loan to fixed rate debt.

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 the 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 March 31, 2015, the restricted net assets at our Electric Utilities and Gas Utilities were approximately $338 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 March 31, 2015, 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 2014 Annual Report on Form 10-K filed with the SEC.


51



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, the Company’s credit ratings, cash flows from routine operations and the credit ratings of counterparties. After assessing the current operating performance, liquidity and the credit ratings of the Company, management believes that the Company will have access to the capital markets at prevailing market rates for companies with comparable credit ratings. BHC notes that credit ratings 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 March 31, 2015:
Rating Agency
Senior Unsecured Rating
Outlook
S&P
BBB
Stable
Moody’s
Baa1
Stable
Fitch
  BBB+
Stable

The following table represents the credit ratings of Black Hills Power at March 31, 2015:
Rating Agency
Senior Secured Rating
S&P
A-
Moody’s
A1
Fitch
A

Capital Requirements

Actual and forecasted capital requirements are as follows (in thousands):
 
Expenditures for the
 
Total
 
Total
 
Total
 
Three Months Ended March 31, 2015 (a)
 
2015 Planned
Expenditures (b)
 
2016 Planned
Expenditures
 
2017 Planned
Expenditures
Utilities:
 
 
 
 
 
 
 
Electric Utilities
$
29,376

 
$
229,300

 
$
225,400

 
$
135,600

Gas Utilities
12,006

 
83,600

 
60,100

 
71,800

Cost of Service Gas

 

 
40,000

 
50,000

Non-regulated Energy:
 
 
 
 
 
 
 
Power Generation
3,465

 
8,000

 
2,000

 
2,600

Coal Mining
4,287

 
7,000

 
6,000

 
6,600

Oil and Gas (c)
47,912

 
167,000

 
122,000

 
120,000

Corporate
1,433

 
6,100

 
1,500

 
3,600

 
$
98,479

 
$
501,000

 
$
457,000

 
$
390,200

__________
(a)    Expenditures for the three months ended March 31, 2015 include the impact of accruals for property, plant and equipment.
(b)    Includes actual expenditures for the three months ended March 31, 2015.
(c)
Our Oil and Gas segment contracted for two additional drilling rigs to support drilling operations in the southern Piceance Basin. Drilling operations are ongoing for 10 additional horizontal wells on three separate surface pads. Due to the partial carryover of 2014 planned Mancos and other drilling capital to 2015, and the addition of one more Mancos well to the 2015 drilling plan, we have increased our planned 2015 capital expenditures to $167 million from $123 million.

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.


52



Contractual Obligations

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 2014 Annual Report on Form 10-K.

Guarantees

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 2014 Annual Report on Form 10-K.

New Accounting Pronouncements

Other than the pronouncements reported in our 2014 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 2014 Annual Report on Form 10-K including statements contained within Item 1A - Risk Factors of our 2014 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.


53




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:
 
March 31, 2015
 
December 31, 2014
 
March 31, 2014
Net derivative (liabilities) assets
$
(20,818
)
 
$
(16,914
)
 
$
(3,693
)
Cash collateral offset in Derivatives
20,818

 
16,914

 
5,539

Cash Collateral included in Other current assets
3,818

 
3,093

 
1,917

Net asset (liability) position
$
3,818

 
$
3,093

 
$
3,763


Oil and Gas Activities

We have entered into agreements to hedge a portion of our estimated 2015 and 2016 natural gas and crude oil production from the Oil and Gas segment. The hedge agreements in place at March 31, 2015, were as follows:

Natural Gas
 
March 31,
June 30,
September 30,
December 31,
Total Year
2015
 
 
 
 
 
Swaps - MMBtu

1,180,000

955,000

1,000,000

3,135,000

Weighted Average Price per MMBtu
$

$
4.03

$
4.00

$
4.04

$
4.03

 
 
 
 
 
 
2016
 
 
 
 
 
Swaps - MMBtu
585,000

557,500

545,000

545,000

2,232,500

Weighted Average Price per MMBtu
$
3.87

$
3.87

$
3.91

$
3.90

$
3.89


Crude Oil
 
March 31,
June 30,
September 30,
December 31,
Total Year
2015
 
 
 
 
 
Swaps - Bbls

53,000

54,000

48,000

155,000

Weighted Average Price per Bbl
$

$
86.56

$
80.70

$
79.56

$
82.35

 
 
 
 
 
 
2016
 
 
 
 
 
Swaps - Bbls
39,000

39,000

36,000

36,000

150,000

Weighted Average Price per Bbl
$
84.55

$
84.55

$
84.55

$
84.55

$
84.55


The fair value of our Oil and Gas segment’s derivative contracts is summarized below (in thousands) as of:

 
March 31, 2015
 
December 31, 2014
 
March 31, 2014
Net derivative (liabilities) assets
$
14,364

 
$
14,684

 
$
(3,601
)
Cash collateral offset in Derivatives
(14,364
)
 
(14,684
)
 
3,601

Cash Collateral included in Other current assets
3,286

 
4,392

 
4,067

Net asset (liability) position
$
3,286

 
$
4,392

 
$
4,067



54



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 2014 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:
 
March 31, 2015
December 31, 2014
March 31, 2014
 
Designated 
Interest Rate
Swaps
(a)
Designated
Interest Rate
Swaps
 (a)
Designated
Interest Rate
Swaps
(a)
Notional
$
75,000

 
$
75,000

 
$
75,000

Weighted average fixed interest rate
4.97
%
 
4.97
%
 
4.97
%
Maximum terms in years
1.75

 
2.00

 
2.75

Derivative liabilities, current
$
3,342

 
$
3,340

 
$
3,498

Derivative liabilities, non-current
$
2,143

 
$
2,680

 
$
4,805

Pre-tax accumulated other comprehensive income (loss)
$
(5,485
)
 
$
(6,020
)
 
$
(8,303
)
__________
(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 borrowings.    

Based on March 31, 2015 market interest rates and balances related to our interest rate swaps, a loss of approximately $3.3 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 March 31, 2015. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective.

During the quarter ended March 31, 2015, 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.


55



BLACK HILLS CORPORATION

Part II — Other Information

ITEM 1.
Legal Proceedings

For information regarding legal proceedings, see Note 18 in Item 8 of our 2014 Annual Report on Form 10-K and Note 14 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 14 is incorporated by reference into this item.

ITEM 1A.
Risk Factors

There are no material changes to the risk factors previously disclosed in Item 1A of Part I in our 2014 Annual Report on Form 10-K.


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

There were no unregistered securities sold during the three months ended March 31, 2015.
 
 
 
 
 
 
 
 
 

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.


56



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)). Third Supplemental Indenture, dated as of October 1, 2014, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on October 2, 2014).
 
 
Exhibit 4.3*
Restated Indenture of Mortgage, Deed of Trust, Security Agreement and Financing Statement, amended and restated as of November 20, 2007, between Cheyenne Light, Fuel and Power Company and Wells Fargo Bank, National Association (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on October 2, 2014). First Supplemental Indenture, dated as of September 3, 2009, between Cheyenne Light, Fuel and Power Company and Wells Fargo Bank, National Association (filed as Exhibit 10.3 to the Registrant’s Form 8-K filed on October 2, 2014). Second Supplemental Indenture, dated as of October 1, 2014, between Cheyenne Light, Fuel and Power Company and Wells Fargo Bank, National Association (filed as Exhibit 10.4 to the Registrant’s Form 8-K filed on October 2, 2014).
 
 
Exhibit 4.4*
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 April 13, 2015 among Black Hills Corporation, as Borrower, JPMorgan Chase Bank, N. A., 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 April 14, 2015).
 
 
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.
 
 

57


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.



58



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/ Richard W. Kinzley
 
 
Richard W. Kinzley, Senior Vice President and
 
 
  Chief Financial Officer
 
 
 
Dated:
May 5, 2015
 


59



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)). Third Supplemental Indenture, dated as of October 1, 2014, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on October 2, 2014).
 
 
Exhibit 4.3*
Restated Indenture of Mortgage, Deed of Trust, Security Agreement and Financing Statement, amended and restated as of November 20, 2007, between Cheyenne Light, Fuel and Power Company and Wells Fargo Bank, National Association (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on October 2, 2014). First Supplemental Indenture, dated as of September 3, 2009, between Cheyenne Light, Fuel and Power Company and Wells Fargo Bank, National Association (filed as Exhibit 10.3 to the Registrant’s Form 8-K filed on October 2, 2014). Second Supplemental Indenture, dated as of October 1, 2014, between Cheyenne Light, Fuel and Power Company and Wells Fargo Bank, National Association (filed as Exhibit 10.4 to the Registrant’s Form 8-K filed on October 2, 2014).
 
 
Exhibit 4.4*
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 April 13, 2015 among Black Hills Corporation, as Borrower, JPMorgan Chase Bank, N. A., 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 April 14, 2015).
 
 
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.
 
 

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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.


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