Document


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

Form 10-Q
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
 
EXCHANGE ACT OF 1934
 
For the quarterly period ended September 30, 2016
OR
 
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
 
EXCHANGE ACT OF 1934
 
For the transition period from __________ to __________.
 
 
 
Commission File Number 001-31303
Black Hills Corporation
Incorporated in South Dakota
IRS Identification Number 46-0458824
625 Ninth Street
Rapid City, South Dakota 57701
Registrant’s telephone number (605) 721-1700
Former name, former address, and former fiscal year if changed since last report
NONE
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
 
Yes x
 
No o
 

Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files).
 
Yes x
 
No o
 

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as defined in Rule 12b-2 of the Exchange Act).
 
Large accelerated filer x
 
Accelerated filer o
 
 
Non-accelerated filer o
 
Smaller reporting company o
 

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
 
Yes o
 
No x
 

Indicate the number of shares outstanding of each of the issuer’s classes of common stock as of the latest practicable date.
Class
Outstanding at October 31, 2016
Common stock, $1.00 par value
53,147,805

shares





TABLE OF CONTENTS
 
 
 
Page
 
Glossary of Terms and Abbreviations
 
 
 
 
 
PART I.
FINANCIAL INFORMATION
 
 
 
 
 
Item 1.
Financial Statements
 
 
 
 
 
 
Condensed Consolidated Statements of Income (Loss) - unaudited
 
 
 
   Three and Nine Months Ended September 30, 2016 and 2015
 
 
 
 
 
 
Condensed Consolidated Statements of Comprehensive Income (Loss) - unaudited
 
 
 
   Three and Nine Months Ended September 30, 2016 and 2015
 
 
 
 
 
 
Condensed Consolidated Balance Sheets - unaudited
 
 
 
   September 30, 2016, December 31, 2015 and September 30, 2015
 
 
 
 
 
 
Condensed Consolidated Statements of Cash Flows - unaudited
 
 
 
   Nine Months Ended September 30, 2016 and 2015
 
 
 
 
 
 
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)
APSC
Arkansas Public Service Commission
ASC
Accounting Standards Codification
ASU
Accounting Standards Update issued by the FASB
ATM
At-the-market equity offering program
Bbl
Barrel
BHC
Black Hills Corporation; the Company
Black Hills Gas
Black Hills Gas, LLC, a subsidiary of Black Hills Gas Holdings, which was previously named SourceGas LLC.
Black Hills Gas Holdings
Black Hills Gas Holdings, LLC, a subsidiary of Black Hills Utility Holdings, which was previously named SourceGas Holdings LLC
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 our utility companies
Black Hills Energy Arkansas Gas
Includes the acquired SourceGas utility Black Hills Energy Arkansas, Inc. utility operations
Black Hills Energy Colorado Electric
Includes Colorado Electric’s utility operations
Black Hills Energy Colorado Gas
Includes Black Hills Energy Colorado Gas utility operations, as well as the acquired SourceGas utility Black Hills Gas Distribution’s Colorado gas operations and RMNG
Black Hills Energy Iowa Gas
Includes Black Hills Energy Iowa gas utility operations
Black Hills Energy Kansas Gas
Includes Black Hills Energy Kansas gas utility operations
Black Hills Energy Nebraska Gas
Includes Black Hills Energy Nebraska gas utility operations, as well as the acquired SourceGas utility Black Hills Gas Distribution’s Nebraska gas operations
Black Hills Energy South Dakota Electric
Includes Black Hills Power operations in South Dakota, Wyoming and Montana
Black Hills Energy Wyoming Electric
Includes Cheyenne Light’s electric utility operations
Black Hills Energy Wyoming Gas
Includes Cheyenne Light’s natural gas utility operations, as well as the acquired SourceGas utility Black Hills Gas Distribution’s Wyoming gas operations
Black Hills Gas Distribution
Black Hills Gas Distribution, LLC, a company acquired in the SourceGas Acquisition that conducts the gas distribution operations in Colorado, Nebraska and Wyoming. It was formerly named SourceGas Distribution LLC.
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 (doing business as Black Hills Energy)
Black Hills Utility Holdings
Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
Black Hills Wyoming
Black Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Generation
Btu
British thermal unit
Consolidated Indebtedness to Capitalization Ratio
Any Indebtedness outstanding at such time, divided by Capital at such time. Capital being Consolidated Net-Worth (excluding noncontrolling interest) plus Consolidated Indebtedness as defined within the current Credit Agreement.
Ceiling Test
Related to our Oil and Gas subsidiary, capitalized costs, less accumulated amortization and related deferred income taxes, are subject to a ceiling test which limits the pooled costs to the aggregate of the discounted value of future net revenue attributable to proved natural gas and crude oil reserves using a discount rate defined by the SEC plus the lower of cost or market value of unevaluated properties.
Cheyenne Light
Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)

3


Cheyenne Prairie
Cheyenne Prairie Generating Station is a 132 MW natural gas-fired generating facility jointly owned by Black Hills Power, Inc. and Cheyenne Light, Fuel and Power Company. Cheyenne Prairie was placed into commercial service on October 1, 2014.
CIAC
Contribution In Aid of Construction
City of Gillette
Gillette, Wyoming
Colorado Electric
Black Hills Colorado Electric Utility Company, LP, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy)
Colorado Gas
Black Hills Colorado Gas Utility Company, LP, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy)
Colorado Interstate Gas
Colorado Interstate Natural Gas Pricing Index
Colorado IPP
Black Hills Colorado IPP, LLC a 50.1% owned subsidiary of Black Hills Electric Generation
Cooling degree day
A cooling degree day is equivalent to each degree that the average of the high and low temperature for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30-year average.
Cost of Service Gas Program (COSG)
Proposed Cost of Service Gas Program designed to provide long-term natural gas price stability for the Company’s utility customers, along with a reasonable expectation of customer savings over the life of the program.
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)
El Paso San Juan
El Paso San Juan Natural Gas Pricing Index
Equity Unit
Each Equity Unit has a stated amount of $50, consisting of a purchase contract issued by BHC to purchase shares of BHC common stock and a 1/20, or 5% undivided beneficial ownership interest in $1,000 principal amount of BHC RSNs due 2028.
FASB
Financial Accounting Standards Board
FERC
United States Federal Energy Regulatory Commission
Fitch
Fitch Ratings
GAAP
Accounting principles generally accepted in the United States of America
Heating Degree Day
A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30-year average.
Iowa Gas
Black Hills Iowa Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy)
IPP
Independent power producer
IRS
United States Internal Revenue Service
Kansas Gas
Black Hills Kansas Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy)
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

4


Nebraska Gas
Black Hills Nebraska Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy)
NGL
Natural Gas Liquids (1 barrel equals 6 Mcfe)
Northwest Wyoming Pool
Northwest Wyoming Natural Gas Pricing index
NPSC
Nebraska Public Service Commission
NYMEX
New York Mercantile Exchange
NYSE
New York Stock Exchange
Panhandle Eastern Pipeline
Panhandle Eastern Pipeline Natural Gas Pricing Index
Peak View Wind Project
$109 million 60 MW wind generating project for Colorado Electric, adjacent to Busch Ranch wind farm
PPA
Power Purchase Agreement
Revolving Credit Facility
Our $750 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, which matures in 2021.
RMNG
Rocky Mountain Natural Gas, a regulated gas utility acquired in the SourceGas Acquisition that provides regulated transmission and wholesale natural gas service to Black Hills Gas in western Colorado (doing business as Black Hills Energy)
RSNs
Remarketable junior subordinated notes, issued on November 23, 2015
SEC
U. S. Securities and Exchange Commission
SourceGas
SourceGas Holdings LLC and its subsidiaries, a gas utility owned by funds managed by Alinda Capital Partners and GE Energy Financial Services, a unit of General Electric Co. (NYSE:GE) that was acquired on February 12, 2016, and is now named Black Hills Gas Holdings, LLC (doing business as Black Hills Energy)
SourceGas Acquisition
On February 12, 2016, Black Hills Utility Holdings acquired SourceGas pursuant to a purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion, which included the assumption of $760 million in debt at closing.
S&P
Standard and Poor’s, a division of The McGraw-Hill Companies, Inc.
SSIR
System Safety and Integrity
TCA
Transmission Cost Adjustment -- adjustments passed through to the customer based on transmission costs that are higher or lower than the costs approved in the rate case.
VIE
Variable interest entity
WPSC
Wyoming Public Service Commission
WRDC
Wyodak Resources Development Corp., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
Wyodak Plant
Wyodak, a 362 MW mine-mouth coal-fired plant in Gillette, Wyoming, is owned 80% by Pacificorp and 20% by Black Hills Energy South Dakota. Our WRDC mine supplies all of the fuel for the plant.

5




BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS)
(unaudited)
Three Months Ended
September 30,
Nine Months Ended
September 30,
 
2016
2015
2016
2015
 
(in thousands, except per share amounts)
 
 
 
 
 
Revenue
$
333,786

$
272,105

$
1,109,186

$
986,346

 
 
 
 
 
Operating expenses:
 
 
 
 
Fuel, purchased power and cost of natural gas sold
80,194

71,627

336,539

350,778

Operations and maintenance
115,103

89,830

334,706

273,374

Depreciation, depletion and amortization
48,925

37,768

140,637

116,821

Taxes - property, production and severance
12,114

10,675

36,991

33,988

Impairment of long-lived assets
12,293

61,875

52,286

178,395

Other operating expenses
6,748

2,374

40,730

3,392

Total operating expenses
275,377

274,149

941,889

956,748

 
 
 
 
 
Operating income (loss)
58,409

(2,044
)
167,297

29,598

 
 
 
 
 
Other income (expense):
 
 
 
 
Interest charges -
 
 
 
 
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts)
(37,306
)
(22,378
)
(103,989
)
(61,833
)
Allowance for funds used during construction - borrowed
860

478

2,115

843

Capitalized interest
282

280

785

1,037

Interest income
912

414

2,513

1,163

Allowance for funds used during construction - equity
1,211

430

2,900

563

Other income (expense), net
160

842

801

1,568

Total other income (expense), net
(33,881
)
(19,934
)
(94,875
)
(56,659
)
 
 
 
 
 
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes
24,528

(21,978
)
72,422

(27,061
)
Equity in earnings (loss) of unconsolidated subsidiaries
—

—

—

(344
)
Impairment of equity investments
—

—

—

(5,170
)
Income tax benefit (expense)
(6,644
)
12,035

(11,205
)
14,640

Net income (loss)
17,884

(9,943
)
61,217

(17,935
)
Net income attributable to noncontrolling interest
(3,753
)
—

(6,415
)
—

Net income (loss) available for common stock
$
14,131

$
(9,943
)
$
54,802

$
(17,935
)
 
 
 
 
 
Earnings (loss) per share of common stock:
 
 
 
 
Earnings (loss) per share, Basic
$
0.27

$
(0.22
)
$
1.06

$
(0.40
)
Earnings (loss) per share, Diluted
$
0.26

$
(0.22
)
$
1.04

$
(0.40
)
Weighted average common shares outstanding:
 
 
 
 
Basic
52,184

44,635

51,583

44,598

Diluted
53,733

44,635

52,893

44,598

 
 
 
 
 
Dividends declared per share of common stock
$
0.420

$
0.405

$
1.260

$
1.215


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

6




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


(unaudited)
Three Months Ended
September 30,
Nine Months Ended
September 30,
 
2016
2015
2016
2015
 
(in thousands)
 
 
 
 
 
Net income (loss)
$
17,884

$
(9,943
)
$
61,217

$
(17,935
)
 
 
 
 
 
Other comprehensive income (loss), net of tax:
 
 
 
 
Fair value adjustments on derivatives designated as cash flow hedges (net of tax (expense) benefit of $(260) and $(1,609) for the three months ended 2016 and 2015 and $10,605 and $(1,482) for the nine months ended 2016 and 2015, respectively)
(551
)
2,773

(20,617
)
2,644

Reclassification adjustments for cash flow hedges settled and included in net income (loss) (net of tax (expense) benefit of $566 and $558 for the three months ended 2016 and 2015 and $2,450 and $2,548 for the nine months ended 2016 and 2015, respectively)
(923
)
(948
)
(4,137
)
(3,450
)
Benefit plan liability adjustments - net gain (loss) (net of tax (expense) benefit of $0 and $0 for the three months ended 2016 and 2015 and $0 and $16 for the nine months ended 2016 and 2015, respectively)
—

—

—

(27
)
Reclassification adjustments of benefit plan liability - prior service cost (net of tax (expense) benefit of $19 and $19 for the three months ended 2016 and 2015 and $58 and $58 for the nine months ended 2016 and 2015, respectively)
(36
)
(36
)
(108
)
(108
)
Reclassification adjustments of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(171) and $(247) for the three months ended 2016 and 2015 and $(516) and $(742) for the nine months ended 2016 and 2015, respectively)
323

459

966

1,374

Other comprehensive income (loss), net of tax
(1,187
)
2,248

(23,896
)
433

 
 
 
 
 
Comprehensive income (loss)
16,697

(7,695
)
37,321

(17,502
)
Less: comprehensive income attributable to noncontrolling interest
(3,753
)
—

(6,415
)
—

Comprehensive income (loss) available for common stock
$
12,944

$
(7,695
)
$
30,906

$
(17,502
)

See Note 16 for additional disclosures.

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

7


BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)
As of
 
September 30,
2016
 
December 31, 2015
 
September 30,
2015
 
(in thousands)
ASSETS
 
 
 
 
 
Current assets:
 
 
 
 
 
Cash and cash equivalents
$
62,964

 
$
456,535

 
$
38,841

Restricted cash and equivalents
2,140

 
1,697

 
2,462

Accounts receivable, net
154,617

 
147,486

 
115,502

Materials, supplies and fuel
113,475

 
86,943

 
90,349

Derivative assets, current
4,382

 
—

 
—

Income tax receivable, net
—

 
368

 
—

Deferred income tax assets, net, current
—

 
—

 
47,783

Regulatory assets, current
50,561

 
57,359

 
51,962

Other current assets
30,032

 
71,763

 
55,383

Total current assets
418,171

 
822,151

 
402,282

 
 
 
 
 
 
Investments
12,416

 
11,985

 
12,148

 
 
 
 
 
 
Property, plant and equipment
6,306,119

 
4,976,778

 
4,882,420

Less: accumulated depreciation and depletion
(1,841,116
)
 
(1,717,684
)
 
(1,617,723
)
Total property, plant and equipment, net
4,465,003

 
3,259,094

 
3,264,697

 
 
 
 
 
 
Other assets:
 
 
 
 
 
Goodwill
1,300,379

 
359,759

 
359,527

Intangible assets, net
8,944

 
3,380

 
3,440

Regulatory assets, non-current
234,240

 
175,125

 
182,337

Derivative assets, non-current
183

 
3,441

 
—

Other assets, non-current
12,800

 
7,382

 
7,501

Total other assets, non-current
1,556,546

 
549,087

 
552,805

 
 
 
 
 
 
TOTAL ASSETS
$
6,452,136

 
$
4,642,317

 
$
4,231,932


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

8


BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Continued)
(unaudited)
As of
 
September 30,
2016
 
December 31, 2015
 
September 30,
2015
 
(in thousands, except share amounts)
LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND TOTAL EQUITY
 
 
 
 
 
Current liabilities:
 
 
 
 
 
Accounts payable
$
141,780

 
$
105,468

 
$
91,633

Accrued liabilities
228,522

 
232,061

 
229,889

Derivative liabilities, current
1,941

 
2,835

 
3,312

Accrued income taxes, net
10,909

 
—

 
308

Regulatory liabilities, current
16,925

 
4,865

 
5,647

Notes payable
75,000

 
76,800

 
117,900

Current maturities of long-term debt
5,743

 
—

 
—

Total current liabilities
480,820

 
422,029

 
448,689

 
 
 
 
 
 
Long-term debt
3,211,768

 
1,853,682

 
1,553,167

 
 
 
 
 
 
Deferred credits and other liabilities:
 
 
 
 
 
Deferred income tax liabilities, net, non-current
533,865

 
450,579

 
494,834

Derivative liabilities, non-current
317

 
156

 
722

Regulatory liabilities, non-current
186,496

 
148,176

 
152,164

Benefit plan liabilities
171,633

 
146,459

 
158,682

Other deferred credits and other liabilities
141,007

 
155,369

 
136,462

Total deferred credits and other liabilities
1,033,318

 
900,739

 
942,864

 
 
 
 
 
 
Commitments and contingencies (See Notes 10, 11, 12, 18, 19)


 

 

 
 
 
 
 
 
Redeemable noncontrolling interest
4,206

 
—

 
—

 
 
 
 
 
 
Equity:
 
 
 
 
 
Stockholders’ equity —
 
 
 
 
 
Common stock $1 par value; 100,000,000 shares authorized; issued 53,131,469; 51,231,861; and 44,891,626 shares, respectively
53,131

 
51,232

 
44,892

Additional paid-in capital
1,123,527

 
953,044

 
753,856

Retained earnings
462,090

 
472,534

 
504,864

Treasury stock, at cost – 22,368; 39,720; and 36,711 shares, respectively
(1,155
)
 
(1,888
)
 
(1,789
)
Accumulated other comprehensive income (loss)
(32,951
)
 
(9,055
)
 
(14,611
)
Total stockholders’ equity
1,604,642

 
1,465,867

 
1,287,212

Noncontrolling interest
117,382

 
—

 
—

Total equity
1,722,024

 
1,465,867

 
1,287,212

 
 
 
 
 
 
TOTAL LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND TOTAL EQUITY
$
6,452,136

 
$
4,642,317

 
$
4,231,932


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

9


BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
Nine Months Ended September 30,
 
2016
2015
Operating activities:
(in thousands)
Net income (loss) available for common stock
$
54,802

$
(17,935
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
Depreciation, depletion and amortization
140,637

116,821

Deferred financing cost amortization
4,002

3,074

Impairment of long-lived assets
52,286

183,565

Derivative fair value adjustments
(7,308
)
(8,851
)
Stock compensation
9,124

2,868

Deferred income taxes
38,578

(20,808
)
Employee benefit plans
11,830

15,175

Other adjustments, net
(2,076
)
4,013

Changes in certain operating assets and liabilities:
 
 
Materials, supplies and fuel
(5,166
)
3,618

Accounts receivable, unbilled revenues and other operating assets
78,869

75,966

Accounts payable and other operating liabilities
(102,155
)
(5,255
)
Regulatory assets - current
8,453

27,768

Regulatory liabilities - current
(8,181
)
2,457

Contributions to defined benefit pension plans
(14,200
)
(10,200
)
Interest rate swap settlement
(28,820
)
—

Other operating activities, net
(5,998
)
(6,403
)
Net cash provided by (used in) operating activities
224,677

365,873

 
 
 
Investing activities:
 
 
Property, plant and equipment additions
(334,098
)
(349,471
)
Acquisition, net of long term debt assumed
(1,124,238
)
—

Other investing activities
(860
)
(7,189
)
Net cash provided by (used in) investing activities
(1,459,196
)
(356,660
)
 
 
 
Financing activities:
 
 
Dividends paid on common stock
(65,247
)
(54,450
)
Common stock issued
107,690

2,484

Sale of noncontrolling interest
216,370

—

Short-term borrowings - issuances
208,100

287,910

Short-term borrowings - repayments
(209,900
)
(245,010
)
Long-term debt - issuances
1,767,608

300,000

Long-term debt - repayments
(1,162,872
)
(275,000
)
Distributions to noncontrolling interest
(4,516
)
—

Other financing activities
(16,285
)
(7,524
)
Net cash provided by (used in) financing activities
840,948

8,410

Net change in cash and cash equivalents
(393,571
)
17,623

Cash and cash equivalents, beginning of period
456,535

21,218

Cash and cash equivalents, end of period
$
62,964

$
38,841


See Note 17 for supplemental disclosure of cash flow information.

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

10


BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Reference is made to Notes to Consolidated Financial Statements
included in the Company’s 2015 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 2015 Annual Report on Form 10-K filed with the SEC.

Segment Reporting

We conduct our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation, Mining and Oil and Gas. Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States. Prior to March 31, 2016, our segments were reported within two business groups, our Utilities Group, containing the Electric Utilities and Gas Utilities segments, and our Non-regulated Energy Group, containing the Power Generation, Coal Mining and Oil and Gas segments. We have continued to report our operations consistently through our reportable segments; however we will no longer separate the segments by business group. We are a customer-focused, growth-oriented, vertically-integrated utility company. All of our non-utility business segments support our electric utilities, other than the Oil and Gas segment. In our oil and gas business, we are divesting non-core assets while retaining those best suited for a cost of service gas program and we have refocused our professional staff on assisting our utilities with the implementation of a cost of service gas program.
The following changes have been made to our Condensed Consolidated Statements of Income (Loss) to reflect combined operations and maintenance expenses, rather than by business group as previously reported, for the three and nine months ended September 30, 2015, respectively:

 
For the Three Months Ended September 30, 2015
 
For the Nine Months Ended September 30, 2015
(in thousands)
As Previously Reported
Presentation Reclassification
As Currently Reported
 
As Previously Reported
Presentation Reclassification
As Currently Reported
Utilities - operations and maintenance
$
67,282

$
(67,282
)
$
—

 
$
205,630

$
(205,630
)
$
—

Non-regulated energy operations and maintenance
$
22,548

$
(22,548
)
$
—

 
$
67,744

$
(67,744
)
$
—

Operations and maintenance
$
—

$
89,830

$
89,830

 
$
—

$
273,374

$
273,374


This presentation reclassification did not impact our consolidated financial position, results of operations or cash flows.

Segment Reporting Transition of Cheyenne Light’s Natural Gas Distribution

Effective January 1, 2016, the natural gas operations of Cheyenne Light have been included in our Gas Utilities Segment. Through December 31, 2015, Cheyenne Light’s natural gas operations were included in our Electric Utilities Segment as these natural gas operations were consolidated within Cheyenne Light since its acquisition. This change is a result of our business segment reorganization to, among other things, integrate all regulated natural gas operations, including the SourceGas Acquisition, into our Gas Utilities Segment which is led by the Group Vice President, Natural Gas Utilities. Likewise, all regulated electric utility operations, including Cheyenne Light’s electric utility operations, are reported in our Electric Utilities Segment, which is led by the Group Vice President, Electric Utilities. The prior period has been reclassified to reflect this change in presentation between the Electric Utilities and Gas Utilities segments. See Note 3 for Revenues, Net Income and Segment Assets reclassified from the Electric Utilities segment to the Gas Utilities segment for the three and nine months ending September 30, 2015. This segment reclassification did not impact our consolidated financial position, results of operations or cash flows.

11


Use of Estimates and Basis of Presentation

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 September 30, 2016, December 31, 2015, and September 30, 2015 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 prices. In particular, the normal peak usage season for electric utilities is June through August while the normal peak usage season for gas utilities is November through March. Significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three and nine months ended September 30, 2016 and September 30, 2015, and our financial condition as of September 30, 2016, December 31, 2015, and September 30, 2015, 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.

Significant Accounting Policies

Business Combinations

We record acquisitions in accordance with ASC 805, Business Combinations, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition date. The excess of the purchase price over the estimated fair values of the net tangible and net intangible assets acquired is recorded as goodwill. The application of ASC 805, Business Combinations requires management to make significant estimates and assumptions in the determination of the fair value of assets acquired and liabilities assumed in order to properly allocate purchase price consideration between goodwill and assets that are depreciated and amortized. Our estimates are based on historical experience, information obtained from the management of the acquired companies and, when appropriate, include assistance from independent third-party appraisal firms. These estimates are inherently uncertain and unpredictable. In addition, unanticipated events or circumstances may occur which may affect the accuracy or validity of such estimates. See Note 2 for additional detail on the accounting for our acquisition.

Noncontrolling Interest

We account for changes in our controlling interests of subsidiaries according to ASC 810, Consolidations. ASC 810 requires that the Company record such changes as equity transactions, recording no gain or loss on such a sale. GAAP requires that noncontrolling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. In addition, the amounts attributable to the noncontrolling interest net income (loss) of those subsidiaries are reported separately in the consolidated statements of income and comprehensive income. See Note 12 for additional detail on Noncontrolling Interests.

Share-Based Compensation

We account for our share-based compensation arrangements in accordance with ASC 718, Compensation-Stock Compensation, by recognizing compensation costs for all share-based awards over the respective service period for employee services received in exchange for an award of equity or equity-based compensation. Awards that will be settled in stock are accounted for as equity and the compensation expense is based on the grant date fair value. Awards that are settled in cash are accounted for as liabilities and the compensation expense is re-measured each period based on the current market price and performance achievement measures.


12


Recently Issued and Adopted Accounting Standards

Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, ASU 2016-15

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). This ASU requires changes in the presentation of certain items including but not limited to debt prepayment or debt extinguishment costs; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. The ASU will be effective for fiscal years beginning after December 15, 2017. We are currently assessing the impact that adoption of ASU 2016-15 will have on our consolidated financial position, results of operations and cash flows.

Improvements to Employee Share-Based Payment Accounting, ASU 2016-09

In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting. This ASU simplifies several aspects of the accounting for employee share-based payment transactions, including the accounting for forfeitures, income taxes, and statutory tax withholding requirements. The ASU will be effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption permitted. Certain amendments of this guidance are to be applied retrospectively and others prospectively. We are currently assessing the impact that adoption of ASU 2016-09 will have on our consolidated financial position, results of operations and cash flows.

Leases, ASU 2016-02

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases. This ASU requires lessees to recognize a right-of-use asset and lease liability for all leases with terms of more than 12 months. Lessees are permitted to make an accounting policy election to not recognize the asset and liability for leases with a term of 12 months or less. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASC is largely unchanged from the previous accounting standard. In addition, the ASU expands the disclosure requirements of lease arrangements. Lessees and lessors will use a modified retrospective transition approach, which includes a number of practical expedients. The guidance is effective for the Company beginning after December 15, 2018. Early adoption is permitted. We are currently assessing the impact that adoption of ASU 2016-02 will have on our financial position, results of operations and cash flows.

Revenue from Contracts with Customers, ASU 2014-09

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The standard provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer, as opposed to recognizing revenue when the risks and rewards transfer to the customer under the existing revenue guidance. On July 9, 2015, FASB voted to defer the effective date of ASU 2014-09 by one year. The guidance is effective for annual and interim reporting periods beginning after December 15, 2017 and early adoption is permitted. Entities will have the option of using either a full retrospective or modified retrospective approach to adopting this guidance. Under the modified approach, an entity would recognize the cumulative effect of initially applying the guidance with an adjustment to the opening balance of retained earnings in the period of adoption. As of September 30, 2016, we were actively evaluating all of our sources of revenue to determine the impact that adoption of ASU 2014-09 will have on our financial position, results of operations and cash flows.

Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent), ASU 2015-07

On May 1, 2015, the FASB issued ASU 2015-07, Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent). The ASU removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient and also removes certain disclosure requirements. The new requirements were effective for us beginning January 1, 2016 and will be applied retrospectively to all periods presented, in our 2016 Form 10-K. This ASU will not materially affect our financial statements and disclosures, but will change certain presentation and disclosure of the fair value of certain plan assets in our pension and other postretirement benefit plan disclosures in our 2016 Form 10-K, for all periods presented.


13


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 are 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. We adopted ASU 2015-03 in the first quarter of 2016 on a retrospective basis. As of September 30, 2016, we presented the debt issuance costs, previously reported in other assets, as direct deductions from the carrying amount of long-term debt. The implementation of this standard resulted in reductions of other assets, non-current and long-term debt of $13 million and $15 million in the Condensed Consolidated Balance Sheets as of December 31, 2015, and September 30, 2015, respectively. Adoption of ASU 2015-03 did not have a material impact on our financial position.

Simplifying the Accounting for Measurement-Period Adjustments, ASU 2015-16

In September 2015, the FASB issued ASU 2015-16, Simplifying the Accounting for Measurement-Period Adjustments. This ASU eliminates the requirement to retrospectively account for changes to provisional amounts recognized at the acquisition date in a business combination. ASU 2015-16 requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustments are determined, including the effect of the change in the provisional amount as if the accounting had been completed at the acquisition date. The provisions of this ASU are effective for fiscal years beginning after December 31, 2015, including interim periods within those fiscal years and should be applied prospectively to adjustments to provisional amounts that occur after the effective date. We have implemented ASU 2015-16 as of January 1, 2016. Adoption of this standard did not have a material impact on our financial position, results of operations and cash flows.

(2)    ACQUISITION

Acquisition of SourceGas

On February 12, 2016, Black Hills Corporation acquired SourceGas, pursuant to the purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion, including the assumption of $760 million in debt at closing. The purchase price was subject to post-closing adjustments for capital expenditures, indebtedness and working capital. Post-closing adjustments of approximately $11 million were agreed to and received from the sellers in June 2016.  SourceGas is a 99.5% owned subsidiary of Black Hills Utility Holdings, Inc., a wholly-owned subsidiary of Black Hills Corporation and has been renamed Black Hills Gas Holdings, LLC. Black Hills Gas Holdings primarily operates four regulated natural gas utilities serving approximately 429,000 customers in Arkansas, Colorado, Nebraska and Wyoming, and a 512-mile regulated intrastate natural gas transmission pipeline in Colorado.

Cash consideration of $1.135 billion paid on February 12, 2016 to close the SourceGas Acquisition included net proceeds of approximately $536 million from the November 23, 2015 issuance of 6.325 million shares of our common stock and 5.98 million equity units, and $546 million in net proceeds from our debt offerings on January 13, 2016. We funded the cash consideration and out-of-pocket expenses payable with the SourceGas Acquisition using the proceeds listed above, cash on hand, and draws under our revolving credit facility.

In connection with the acquisition, the Company recorded pre-tax, incremental acquisition costs of approximately $5.2 million and $36 million, respectively, in the three and nine months ended September 30, 2016. These costs consisted of transaction costs, professional fees, employee-related expenses and other miscellaneous costs. The costs are recorded primarily in Other operating expenses on the Condensed Consolidating Income Statements. There were $4.3 million and $5.0 million of incremental acquisition costs recorded in the three and nine months ended September 30, 2015, respectively.

Our consolidated operating results for the three and nine months ended September 30, 2016 include revenues of $72 million and $217 million, respectively, and net income (loss) of $(3.8) million and $0.8 million, respectively, attributable to SourceGas for the period from February 12 through September 30, 2016. The SourceGas operating results are reported in our Gas Utilities segment. We believe the SourceGas Acquisition enhances Black Hills Corporation’s utility growth strategy, providing greater operating scale, driving more efficient delivery of services and benefiting customers.


14


We accounted for the SourceGas Acquisition in accordance with ASC 805, Business Combinations, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition date. Substantially all of SourceGas’ operations are subject to the rate-setting authority of state regulatory commissions, and are accounted for in accordance with GAAP for regulated operations. SourceGas’ assets and liabilities subject to rate setting provisions provide revenues derived from costs, including a return on investment of assets and liabilities included in rate base. As such, the fair value of these assets and liabilities equal their historical net book values.

We are still determining the purchase price allocation for SourceGas. A preliminary purchase price allocation of the fair value of the assets acquired and liabilities assumed is included in the table below. The cash consideration paid of $1.124 billion, net of long-term debt assumed of $760 million and a working capital adjustment received of approximately $11 million, resulted in a preliminary estimate of goodwill totaling $941 million. This estimate is subject to change and will likely result in an increase or decrease in goodwill, which could be material. We have up to one year from the acquisition date to finalize the purchase price allocation. From the time of acquisition through September 30, 2016, we decreased goodwill by $5.8 million, reflecting the working capital adjustment received of $11 million and changes in valuation estimates for long-term debt, intangible assets, accrued liabilities and deferred taxes. Approximately $251 million of the goodwill balance is amortizable for tax purposes, relating to the partnership interests that were directly acquired in the transaction. The remainder of the goodwill balance is not amortizable for tax purposes. Goodwill generated from the acquisition reflects the benefits of increased operating scale and organic growth opportunities.
 
(in thousands)
 
 
 
 
Preliminary Purchase Price
 
 
$
1,894,882

Less: Long-term debt assumed
 
 
(760,000
)
Less: Working capital adjustment received
 
 
(10,644
)
 Consideration Paid, net of working capital adjustment received
 
 
$
1,124,238

 
 
 
 
Preliminary Allocation of Purchase Price:
 
 
 
Current Assets
 
 
$
111,893

Property, plant & equipment, net
 
 
1,058,093

Goodwill
 
 
940,620

Deferred charges and other assets, excluding goodwill
 
 
133,215

Current liabilities
 
 
(166,807
)
Long-term debt
 
 
(764,337
)
Deferred credits and other liabilities
 
 
(188,439
)
Total preliminary consideration paid, net of working-capital adjustment received
 
 
$
1,124,238


Conditions of SourceGas Acquisition Regulatory Approval

The acquisition was subject to regulatory approvals from the public utility commissions in Arkansas (APSC), Colorado (CPUC), Nebraska (NPSC), and Wyoming (WPSC). Approvals were obtained from all commissions, subject to various conditions as set forth below:

The APSC order includes a 12 month base rate moratorium, an annual $0.25 million customer credit for a term of up to five-years or until we file the next rate case, whichever comes first, and provides the Company recovery of a portion of specific labor synergies at the time of the next base rate case, as well as various other terms and reporting requirements.

The CPUC order includes a two-year base rate moratorium for our regulated transmission and wholesale natural gas provider, a three-year base rate moratorium for our regulated gas distribution utility, an annual $0.2 million customer credit for a term of up to five-years or until we file the next rate case, whichever comes first, and provides the Company recovery of a portion of specific labor synergies at the time of the next base rate case, as well as various other terms and reporting requirements.

The NPSC order includes a three-year base rate moratorium, a three-year continuation of the Choice Gas program, and provides the Company recovery of a portion of specific labor synergies at the time of the next base rate case, as well as various other terms and reporting requirements.


15


The WPSC order includes a three-year continuation of the Choice Gas program, as well as various other terms and reporting requirements.

All four orders also disallowed recovery of goodwill and transaction costs. Recovery of transition costs is disallowed in Arkansas, Colorado and Nebraska, however Wyoming allows for request of recovery of transition costs. Transition costs are those non-recurring costs related to the transition and integration of SourceGas. In the conditions mentioned above, the orders that include base rate moratoriums over a specified period of time do not impact our ability to adjust rates through riders or gas supply cost recovery mechanisms as allowed under the current enacted state tariffs. In certain cases, we may file for leave to increase general base rates and/or cost of sales recovery limited to material adverse changes, but only if there are changes in law or regulations or the occurrence of other extraordinary events outside of our control which result in a material adverse change in revenues, revenue requirement and/or increase in operating costs.

Settlement of Gas Supply Contract

On April 29, 2016, we settled for $40 million, a former SourceGas contract that required the company to purchase all of the natural gas produced over the productive life of specific leaseholds in the Bowdoin Field in Montana. This contract’s intangible negative fair value is included with Current liabilities of the preliminary purchase price allocation. Approximately 75% of these purchases were committed to distribution customers in Nebraska, Colorado and Wyoming, which are subject to cost recovery mechanisms, while the remaining 25% was not subject to regulatory recovery. The prices to be paid under this contract varied, ranging from $6 to $8 per MMBtu at the time of acquisition and exceeded market prices. We applied for and were granted approval to terminate this agreement from the NPSC, CPUC and WPSC, on the basis that the agreement was not beneficial to customers in the long term. We received written orders allowing recovery of the net buyout costs associated with the contract termination that were allocated to regulated subsidiaries. These costs were recorded as a regulatory asset of approximately $30 million that is being recovered over a five-year period.

Pro Forma Results

We calculated the pro forma impact of the SourceGas Acquisition and the associated debt and equity financings on our operating results for the three and nine months ended September 30, 2016 and 2015. The following pro forma results give effect to the acquisition, assuming the transaction closed on January 1, 2015:
 
 
Pro Forma Results
 
 
Three Months Ended September 30,
Nine Months Ended September 30,
 
 
2016
2015
2016
2015
 
 
(in thousands, except per share amounts)
Revenue
 
$
333,786

$
344,498

$
1,188,148

$
1,320,047

Net income (loss) available for common stock
 
$
17,376

$
(14,189
)
$
89,973

$
(13,884
)
Earnings (loss) per share, Basic
 
$
0.33

$
(0.28
)
$
1.74

$
(0.27
)
Earnings (loss) per share, Diluted
 
$
0.32

$
(0.28
)
$
1.70

$
(0.27
)

We derived the pro forma results for the SourceGas Acquisition based on historical financial information obtained from the sellers and certain management assumptions. Our pro forma adjustments relate to incremental interest expense associated with the financings to effect the transaction, and for the three and nine months ended September 30, 2015, also include adjustments to shares outstanding to reflect the equity issuances as if they had occurred on January 1, 2015, and to reflect pro forma dilutive effects of the equity units issued. The pro forma results do not reflect any cost savings, (or associated costs to achieve such savings) from operating efficiencies or restructuring that could result from the acquisition, and exclude any unique one-time items resulting from the acquisition that are not expected to have a continuing impact on the combined consolidated results. Pro forma results for the three and nine months ended September 30, 2016 reflect unfavorable weather impacts resulting in lower gas usage by our customers than in the same periods of the prior year. In addition, we calculated the tax impact of these adjustments at an estimated combined federal and state income tax rate of 37%.

These pro forma results are for illustrative purposes only and do not purport to be indicative of the results that would have been obtained had the SourceGas Acquisition been completed on January 1, 2015, or that may be obtained in the future.


16


Seller’s noncontrolling interest

One of the sellers retained 0.5% of the outstanding equity interests of SourceGas under the terms of the purchase agreement. As part of the transaction, we entered into an associated option agreement with that holder of the retained interest. The terms of this agreement provide us a call option to purchase the remaining interest beginning 366 days after the initial close of the SourceGas transaction. If we choose not to exercise this option during a ninety-day period, the seller may exercise the put option to sell us the retained interest. The value of this 0.5% equity interest is shown as Redeemable noncontrolling interest on the accompanying condensed consolidated balance sheets.

(3)    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 September 30, 2016
 
External
Operating
Revenue
 
Inter-company
Operating
Revenue
 
Net Income (Loss) Available for Common Stock
Segment:
 
 
 
 
 
 
Electric
 
$
171,754

 
$
2,747

 
$
24,181

Gas (f)
 
141,445

 
—

 
(2,939
)
Power Generation (e)
 
1,906

 
21,431

 
5,642

Mining
 
9,042

 
7,778

 
3,307

Oil and Gas (a)
 
9,639

 
—

 
(8,828
)
Corporate activities (c)
 
—

 
—

 
(7,232
)
Inter-company eliminations
 
—

 
(31,956
)
 
—

Total
 
$
333,786

 
$
—

 
$
14,131


Three Months Ended September 30, 2015
 
External
Operating
Revenue
 
Inter-company
Operating
Revenue
 
Net Income (Loss) Available for Common Stock
Segment:
 
 
 
 
 
 
Electric (d)
 
$
176,042

 
$
2,548

 
$
22,659

Gas (d)
 
75,155

 
—

 
652

Power Generation
 
2,123

 
21,128

 
9,067

Mining
 
8,890

 
8,076

 
3,047

Oil and Gas (a) (b)
 
9,895

 
—

 
(39,769
)
Corporate activities (c)
 
—

 
—

 
(5,599
)
Inter-company eliminations
 
—

 
(31,752
)
 
—

Total
 
$
272,105

 
$
—

 
$
(9,943
)

17


 
 
 
 
 
 
 
Nine Months Ended September 30, 2016
 
External
Operating
Revenue
 
Inter-company
Operating
Revenue
 
Net Income (Loss) Available for Common Stock
Segment:
 
 
 
 
 
 
Electric
 
$
493,845

 
$
9,413

 
$
62,625

Gas (f)
 
563,879

 
—

 
29,975

Power Generation (e)
 
5,304

 
63,055

 
19,907

Mining
 
20,498

 
23,651

 
6,969

Oil and Gas (a)
 
25,660

 
—

 
(35,277
)
Corporate activities (c)
 
—

 
—

 
(29,397
)
Inter-company eliminations
 
—

 
(96,119
)
 
—

Total
 
$
1,109,186

 
$
—

 
$
54,802

 
 
 
 
 
 
 
Nine Months Ended September 30, 2015
 
External
Operating
Revenue
 
Inter-company
Operating
Revenue
 
Net Income (Loss) Available for Common Stock
Segment:
 
 
 
 
 
 
Electric (d)
 
$
504,049

 
$
8,481

 
$
57,844

Gas (d)
 
416,950

 
—

 
27,475

Power Generation
 
5,782

 
62,452

 
24,761

Mining
 
26,084

 
23,541

 
9,106

Oil and Gas (a) (b)
 
33,481

 
—

 
(130,079
)
Corporate activities (c)
 
—

 
—

 
(7,042
)
Inter-company eliminations
 
—

 
(94,474
)
 
—

Total
 
$
986,346

 
$
—

 
$
(17,935
)
___________
(a)
Net income (loss) available for common stock for the three and nine months ended September 30, 2016 and September 30, 2015 includes non-cash after-tax impairments of oil and gas properties of $7.9 million and $33 million and $36 million and $113 million, respectively. See Note 20 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.
(b)
Net income (loss) available for common stock for the nine months ended September 30, 2015 included a non-cash after-tax impairment to equity investments of $3.4 million. See Note 20 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.
(c)
Net income (loss) available for common stock for the three and nine months ended September 30, 2016 and September 30, 2015 included incremental, non-recurring acquisition costs, net of tax of $4.0 million and $24 million; and $2.8 million and $3.0 million respectively, and after-tax internal labor costs attributable to the acquisition of $1.7 million and $7.4 million; and $1.2 million and $1.8 million respectively. See Note 2 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.
(d)
Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utility segment. Cheyenne Light’s gas utility results for the three and nine months ended September 30, 2015 have been reclassified from the Electric Utility segment to the Gas Utility segment. Revenue of $6.2 million and $31 million, respectively, and Net loss of $1.0 million and Net income of $0.5 million, respectively, previously reported in the Electric Utility segment in 2015 are now included in the Gas Utility segment.
(e)
Net income (loss) available for common stock is net of net income attributable to noncontrolling interests of $3.8 million and $6.4 million for the three and nine months ended September 30, 2016.
(f)
Gas Utility revenue increased for the three and nine months ended September 30, 2016 compared to the same periods in the prior year primarily due to the addition of the SourceGas utilities on February 12, 2016.


18


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:
September 30, 2016
 
December 31, 2015
 
September 30, 2015
Segment:
 
 
 
 
 
Electric (a) (b)
$
2,824,145

 
$
2,720,004

 
$
2,706,654

Gas (b) (e)
3,182,852

 
999,778

 
967,225

Power Generation (a)
77,570

 
60,864

 
78,666

Mining
66,804

 
76,357

 
78,000

Oil and Gas (c)
158,970

 
208,956

 
280,842

Corporate activities (d)
141,795

 
576,358

 
120,545

Total assets
$
6,452,136

 
$
4,642,317

 
$
4,231,932

__________
(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.
(b)
Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utility segment. Cheyenne Light’s gas utility assets as of the nine months ended September 30, 2015 have been reclassified from the Electric Utility segment to the Gas Utility segment. Assets of $135 million and $136 million, respectively, previously reported in the Electric Utility segment in 2015 are now presented in the Gas Utility segment as of December 31, 2015 and September 30, 2015.
(c)
As a result of continued low commodity prices and our decision to divest non-core oil and gas assets, we recorded non-cash impairments of $52 million for the nine months ended September 30, 2016, $250 million for the year ended December 31, 2015, and $178 million for the nine months ended September 30, 2015. See Note 20 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.
(d)
Corporate assets at December 31, 2015 included approximately $440 million of cash from the November 23, 2015 equity offerings, which was used to partially fund the SourceGas acquisition on February 12, 2016.
(e)
Includes the assets acquired in the SourceGas acquisition on February 12, 2016.


(4)    ACCOUNTS RECEIVABLE

Following is a summary of Accounts receivable, net included in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
 
Accounts
Unbilled
Less Allowance for
Accounts
September 30, 2016
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
44,747

$
30,970

$
(580
)
$
75,137

Gas Utilities
48,057

23,582

(1,923
)
69,716

Power Generation
1,165

—

—

1,165

Mining
3,612

—

—

3,612

Oil and Gas
3,341

—

(13
)
3,328

Corporate
1,659

—

—

1,659

Total
$
102,581

$
54,552

$
(2,516
)
$
154,617


 
Accounts
Unbilled
Less Allowance for
Accounts
December 31, 2015
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities (a)
$
41,679

$
35,874

$
(727
)
$
76,826

Gas Utilities (a)
30,331

32,869

(1,001
)
62,199

Power Generation
1,187

—

—

1,187

Mining
2,760

—

—

2,760

Oil and Gas
3,502

—

(13
)
3,489

Corporate
1,025

—

—

1,025

Total
$
80,484

$
68,743

$
(1,741
)
$
147,486


 
Accounts
Unbilled
Less Allowance for
Accounts
September 30, 2015
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities (a)
$
41,655

$
33,979

$
(811
)
$
74,823

Gas Utilities (a)
20,031

11,230

(527
)
30,734

Power Generation
1,186

—

—

1,186

Mining
2,684

—

—

2,684

Oil and Gas
4,522

—

(13
)
4,509

Corporate
1,566

—

—

1,566

Total
$
71,644

$
45,209

$
(1,351
)
$
115,502

___________
(a)
Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utility segment. Cheyenne Light’s gas utility accounts receivable has been reclassified from the Electric Utility segment to the Gas Utility segment. Accounts receivable of $6.8 million and $2.9 million as of December 31, 2015 and September 30, 2015, respectively, previously reported in the Electric Utility segment is now presented in the Gas Utility segment.

19


(5)    REGULATORY ACCOUNTING

We had the following regulatory assets and liabilities (in thousands):
 
Maximum
As of
As of
As of
 
Amortization
(in years)
September 30, 2016
December 31, 2015
September 30, 2015
Regulatory assets
 
 
 
 
Deferred energy and fuel cost adjustments - current (a) (d)
1
$
16,525

$
24,751

$
25,354

Deferred gas cost adjustments (a)(d)
1
12,172

15,521

9,358

Gas price derivatives (a)
7
14,405

23,583

23,681

AFUDC (b)
45
14,093

12,870

12,580

Employee benefit plans (c) (e)
12
107,578

83,986

95,779

Environmental (a)
subject to approval
1,126

1,180

1,209

Asset retirement obligations (a)
44
507

457

675

Loss on reacquired debt (a)
30
15,918

3,133

3,169

Renewable energy standard adjustment (b)
5
1,694

5,068

5,102

Flow through accounting (c)
35
33,136

29,722

28,585

Decommissioning costs (f)
10
17,271

18,310

16,353

Gas supply contract termination
5
28,164

—

—

Other regulatory assets (a)
15
22,212

13,903

12,454

 
 
$
284,801

$
232,484

$
234,299

 
 
 
 
 
Regulatory liabilities
 
 
 
 
Deferred energy and gas costs (a) (d)
1
$
15,033

$
7,814

$
9,899

Employee benefit plans (c) (e)
12
65,575

47,218

53,140

Cost of removal (a)
44
114,616

90,045

86,946

Other regulatory liabilities (c)
25
8,197

7,964

7,826

 
 
$
203,421

$
153,041

$
157,811

__________
(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.
(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. 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 December 31, 2015 was driven by addition of the SourceGas employee benefit plans.
(f)
South Dakota Electric has approximately $12 million of decommissioning costs associated with the retirements of the Neil Simpson I and Ben French power plants that are allowed a rate of return, in addition to recovery of costs.

Loss on reacquired debt - The increase from the prior periods is the loss on the early retirement of debt assumed in the SourceGas Acquisition. These costs are being amortized to interest expense over a maximum period of 30 years.

Gas Supply Contract Termination - Black Hills Gas Holdings had agreements under the previous ownership that required the company to purchase all of the natural gas produced over the productive life of specific leaseholds in the Bowdoin Field in Montana. The majority of these purchases were committed to distribution customers in Nebraska, Colorado, and Wyoming, which are subject to cost recovery mechanisms. The prices to be paid under these agreements varied, ranging from $6 to $8 per MMBtu at the time of acquisition, and exceeded market prices. We recorded a liability for this contract in our purchase price allocation. We were granted approval to terminate these agreements from the NPSC, CPUC and WPSC, on the basis that these agreements are not beneficial to customers over the long term. We received written orders allowing us to create a regulatory asset for the net buyout costs associated with the contract termination, and recover the majority of costs from customers over a five year period. We terminated the contract and settled the liability on April 29, 2016.


20


Cost of Removal - Cost of Removal represents the estimated cumulative net provisions for future removal costs included in depreciation expense. The increase from the prior periods is primarily due to cost of removal recorded with the SourceGas purchase price allocation.


(6)    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:
 
September 30, 2016
 
December 31, 2015
 
September 30, 2015
Materials and supplies
$
67,257

 
$
55,726

 
$
53,838

Fuel - Electric Utilities
4,282

 
5,567

 
6,139

Natural gas in storage held for distribution
41,936

 
25,650

 
30,372

Total materials, supplies and fuel
$
113,475

 
$
86,943

 
$
90,349


(7)    GOODWILL & INTANGIBLE ASSETS

Following is a summary of Goodwill included in the accompanying Condensed Consolidated Balance Sheets (in thousands):
 
Electric Utilities (b)
Gas Utilities (b)
Power Generation
Total
Ending balance at December 31, 2015
$
256,850

$
94,144

$
8,765

$
359,759

Acquisition of SourceGas (a)
—

940,620

—

940,620

Ending balance at September 30, 2016
$
256,850

$
1,034,764

$
8,765

$
1,300,379

__________
(a)
Represents preliminary goodwill recorded with the acquisition of SourceGas. See Note 2 for more information.
(b)
Goodwill of $6.3 million is now presented in the Gas Utilities segment as a result of the inclusion of Cheyenne Light’s Gas operations in the Gas Utility segment, previously reported in the Electric Utilities segment. See Note 1 for additional details.

Following is a summary of Intangible assets included in the accompanying Condensed Consolidated Balance Sheets (in thousands):

Intangible assets, net beginning balance at December 31, 2015
$
3,380

Additions/amortization, net (a)
5,564

Intangible assets, net, ending balance at September 30, 2016
$
8,944

__________
(a)
Intangible assets, net acquired from SourceGas are primarily non-regulated customer relationships, and are amortized over their 10-year estimated useful lives. See Note 2 for more information.


21


(8)    ASSET RETIREMENT OBLIGATIONS

The following table presents the details of asset retirement obligations which are included on the accompanying Condensed Consolidated Balance Sheets in Other deferred credits and other liabilities (in thousands):
 
December 31, 2015
Liabilities Incurred
Liabilities Settled
Accretion
Liabilities Acquired (a)
Revisions to Prior Estimates (b) (c)
September 30, 2016
Electric Utilities
$
4,462

$
—

$
—

$
143

$
—

$
11

$
4,616

Gas Utilities
136

—

—

478

22,412

6,436

29,462

Mining
18,633

—

(15
)
653

—

(5,603
)
13,668

Oil and Gas
21,504

—

(814
)
1,047

—

57

21,794

Total
$
44,735

$
—

$
(829
)
$
2,321

$
22,412

$
901

$
69,540

__________
(a)
Represents our legal liability for retirement of gas pipelines, specifically to purge and cap these lines in accordance with Federal regulations. Approximately $22 million was recorded with the purchase price allocation of SourceGas.
(b)
The Gas Utilities Revision to Prior Estimates represents our legal liability for retirement of gas pipelines, specifically to purge and cap these lines in accordance with Federal regulations.
(c)
The Mining Revision to Prior Estimates reflects an approximately 33% reduction in equipment costs as promulgated by the State of Wyoming.


(9)    EARNINGS PER SHARE

A reconciliation of share amounts used to compute Earnings (loss) per share in the accompanying Condensed Consolidated Statements of Income (Loss) was as follows (in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2016
2015
 
2016
2015
 
 
 
 
 
 
Net income (loss) available for common stock
$
14,131

$
(9,943
)
 
$
54,802

$
(17,935
)
 
 
 
 
 
 
Weighted average shares - basic
52,184

44,635

 
51,583

44,598

Dilutive effect of:
 
 
 
 
 
Equity Units (a)
1,414

—

 
1,191

—

Equity compensation
135

—

 
119

—

Weighted average shares - diluted (b)
53,733

44,635

 
52,893

44,598

__________
(a)
Calculated using the treasury stock method.
(b)
Due to our net loss for the three and nine months ended September 30, 2015, potentially dilutive securities were excluded from the diluted loss per share calculation due to their anti-dilutive effect. In computing dilutive net loss per share, 58,380 and 82,130 equity compensation shares were excluded from the computations for the three and nine months ended September 30, 2015, respectively.

The following outstanding securities were excluded in the computation of diluted net income (loss) per share as their inclusion would have been anti-dilutive (in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2016
2015
 
2016
2015
 
 
 
 
 
 
Equity compensation
2

121

 
4

114

Anti-dilutive shares
2

121

 
4

114



22


(10)    NOTES PAYABLE

We had the following notes payable outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
 
September 30, 2016
December 31, 2015
September 30, 2015
 
Balance Outstanding
Letters of Credit
Balance Outstanding
Letters of Credit
Balance Outstanding
Letters of Credit
Revolving Credit Facility
$
75,000

$
30,500

$
76,800

$
33,399

$
117,900

$
30,600


Revolving Credit Facility

On August 9, 2016, we amended and restated our corporate Revolving Credit Facility to increase total commitments to $750 million from $500 million and extend the term through August 9, 2021 with two one-year extension options. This facility is 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 total commitments of the facility up to $1 billion. 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 either S&P or 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 September 30, 2016. A 0.175% commitment fee is charged on the unused amount of the Revolving Credit Facility.

Debt Financial Covenants

On February 12, 2016, in connection with the SourceGas Acquisition discussed in Note 2, our Revolving Credit Facility and Term Loan credit agreements were amended to permit the assumption of certain indebtedness of SourceGas and to increase the Recourse Leverage Ratio. We also amended and restated SourceGas’s $340 million term loan due June 30, 2017. On February 12, 2016, the maximum Recourse Leverage Ratio increased to 0.75 to 1.00 until March 31, 2017, a period of four fiscal quarters following the SourceGas acquisition; it was previously 0.65 to 1.00. On August 9, 2016, in conjunction with the amendment and restatement of the Revolving Credit Facility and Term Loan, the Recourse Leverage Ratio was amended and replaced with the Consolidated Indebtedness to Capitalization Ratio. Under the amended and restated Revolving Credit Facility and Term Loan, we are required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.70 to 1.00 at the end of fiscal quarters ending September 30, 2016 and December 31, 2016 and not to exceed 0.65 to 1.00 at the end of any fiscal quarter thereafter.

Except as provided above, our Revolving Credit Facility and our Term Loans require compliance with the following financial covenant at the end of each quarter:
 
As of September 30, 2016
 
Covenant Requirement
Consolidated Indebtedness to Capitalization Ratio
68%
 
Less than
70%

As of September 30, 2016, we were in compliance with this covenant.


23



(11)    LONG-TERM DEBT AND CURRENT MATURITIES OF LONG-TERM DEBT

Long-term debt was as follows (dollars in thousands):

 
Interest Rate at
 
 
 
 
September 30, 2016
September 30, 2016
December 31, 2015
September 30, 2015
Corporate
 
 
 
 
Remarketable junior subordinated notes due November 1, 2028
3.50%
$
299,000

$
299,000

$
—

Senior unsecured notes due January 15, 2026
3.95%
300,000

—

—

Unamortized discount on Senior unsecured notes due 2026
 
(842
)
—

—

Senior unsecured notes due November 30, 2023
4.25%
525,000

525,000

525,000

Unamortized discount on Senior unsecured notes due 2023
 
(1,685
)
(1,890
)
(1,959
)
Senior unsecured notes due July 15, 2020
5.88%
200,000

200,000

200,000

Senior unsecured notes due January 11, 2019
2.50%
250,000

—

—

Unamortized discount on Senior unsecured notes due 2019
 
(205
)
—

—

Senior unsecured notes due January 15, 2027
3.15%
400,000

—

—

Unamortized discount on Senior unsecured notes due 2027
 
(202
)
—

—

Senior unsecured notes, due September 15, 2046
4.20%
300,000

—

—

Unamortized discount on Senior unsecured notes due 2046
 
(1,630
)
—

—

Corporate term loan due August 9, 2019 (a)
1.46%
400,000

—

—

Corporate term loan due April 12, 2017 (a)

—

300,000

300,000

Corporate term loan due June 7, 2021
2.32%
25,842

—

—

Total Corporate Debt
 
2,695,278

1,322,110

1,023,041

 
 
 
 
 
Electric Utilities
 
 
 
 
First Mortgage Bonds due October 20, 2044
4.43%
85,000

85,000

85,000

First Mortgage Bonds due October 20, 2044
4.53%
75,000

75,000

75,000

First Mortgage Bonds due August 15, 2032
7.23%
75,000

75,000

75,000

First Mortgage Bonds due November 1, 2039
6.13%
180,000

180,000

180,000

Unamortized discount on First Mortgage Bonds due 2039
 
(96
)
(99
)
(99
)
First Mortgage Bonds due November 20, 2037
6.67%
110,000

110,000

110,000

Industrial development revenue bonds due September 1, 2021 (b)
0.86%
7,000

7,000

7,000

Industrial development revenue bonds due March 1, 2027 (b)
0.86%
10,000

10,000

10,000

Series 94A Debt, variable rate due June 1, 2024 (b)
1.01%
2,855

2,855

2,855

Total Electric Utilities Debt
 
544,759

544,756

544,756

 
 
 
 
 
Total long-term debt
 
3,240,037

1,866,866

1,567,797

Less current maturities
 
5,743

—

—

Less deferred financing costs (c)
 
22,526

13,184

14,630

Long-term debt, net of current maturities
 
$
3,211,768

$
1,853,682

$
1,553,167

_______________
(a)
Variable interest rate, based on LIBOR plus a spread.
(b)
Variable interest rate.
(c)
Includes deferred financing costs associated with our Revolving Credit Facility of $2.5 million, $1.7 million and $1.9 million as of September 30, 2016, December 31, 2015 and September 30, 2015, respectively.

24


Scheduled future maturities of debt, excluding amortization of premiums or discounts are (in thousands):

Year Ended:
 
2016
$
1,436

2017
$
5,743

2018
$
5,743

2019
$
655,743

2020
$
205,742

Thereafter
$
2,370,290


Our debt securities contain certain restrictive financial covenants, all of which the Company and its subsidiaries were in compliance with at September 30, 2016.

Current Maturities of Long-Term Debt

As of September 30, 2016, we have the following classified as Current maturities of long-term debt:
Loan
Interest Rate
 
Current Maturities at September 30, 2016
 
 
 
 
Corporate
 
 
 
Corporate term loan due June 7, 2021 (a)
2.32%
 
5,743

Current Maturities of Long-Term Debt
 
 
$
5,743

_______________
(a)
Principal payments of $1.4 million are due quarterly.

Debt Transactions

On August 19, 2016, we completed a public debt offering of $700 million principal amount of senior unsecured notes. The debt offering consisted of $400 million of 3.15% ten-year senior notes due January 15, 2027 and $300 million of 4.20% 30-year senior notes due September 15, 2046 (together the “Notes”). The proceeds of the Notes were used for the following:

•
Repay the $325 million 5.9% senior unsecured notes assumed in the SourceGas Acquisition;

•
Repay the $95 million, 3.98% senior secured notes assumed in the SourceGas Acquisition;

•
Repay the remaining $100 million on the $340 million unsecured term loan assumed in the SourceGas Acquisition;

•
Pay down $100 million of the $500 million three-year unsecured term loan discussed below;

•
Payment of $29 million for the settlement of $400 million notional interest rate swap; and

•
Remainder was used for general corporate purposes.

On August 9, 2016, we entered into a $500 million, three-year, unsecured term loan expiring on August 9, 2019. The proceeds of this term loan was used to pay down $240 million of the $340 million unsecured term loan assumed in the SourceGas Acquisition and the $260 million term loan expiring on April 12, 2017. This new term loan has substantially similar terms and covenants as the amended and restated Revolving Credit Facility.

In accordance with regulatory orders related to the early termination and settlement of the gas supply contract described in Note 5, on June 7, 2016, we entered into a 2.32%, $29 million term loan, due June 7, 2021. Proceeds from this term loan were used to finance the early termination of the gas supply contract, resulting in a regulatory asset. Principal and interest are payable quarterly at approximately $1.6 million, the first of which were paid on June 30, 2016.


25


On January 13, 2016, we completed a public debt offering of $550 million principal amount of senior unsecured notes. The debt offering consisted of $300 million of 3.95%, ten-year senior notes due 2026, and $250 million of 2.50%, three-year senior notes due 2019. After discounts and underwriter fees, net proceeds from the offering totaled $546 million and were used as funding for the SourceGas Acquisition. The discounts are amortized over the life of each respective note.

Assumption of Long-Term Debt

At the closing of the SourceGas Acquisition on February 12, 2016, we assumed $760 million in long-term debt, consisting of the following:

•
$325 million, 5.9% senior unsecured notes with an original issue date of April 16, 2007, due April 1, 2017.

•
$95 million, 3.98% senior secured notes with an original issue date of September 29, 2014, due September 29, 2019.

•
$340 million unsecured corporate term loan due June 30, 2017. Interest under this term loan was LIBOR plus a margin of 0.875%.

As of September 30, 2016, the $760 million in long-term debt assumed in the SourceGas Acquisition was repaid.

(12)    EQUITY

A summary of the changes in equity is as follows:

Nine Months Ended September 30, 2016
Total Stockholders’ Equity
Noncontrolling Interest
Total Equity
 
 
(in thousands)
 
Balance at December 31, 2015
$
1,465,867

$
—

$
1,465,867

Net income (loss)
54,802

6,402

61,204

Other comprehensive income (loss)
(23,896
)
—

(23,896
)
Dividends on common stock
(65,247
)
—

(65,247
)
Share-based compensation
3,822

—

3,822

Issuance of common stock
105,238

—

105,238

Dividend reinvestment and stock purchase plan
2,242

—

2,242

Other stock transactions
(24
)
—

(24
)
Sale of noncontrolling interest
61,838

115,496

177,334

Distribution to noncontrolling interest
—

(4,516
)
$
(4,516
)
Balance at September 30, 2016
$
1,604,642

$
117,382

$
1,722,024


Nine Months Ended September 30, 2015
Total Stockholders’ Equity
Noncontrolling Interest
Total Equity
 
 
(in thousands)
 
Balance at December 31, 2014
$
1,353,884

$
—

$
1,353,884

Net income (loss)
(17,935
)
—

(17,935
)
Other comprehensive income (loss)
433

—

433

Dividends on common stock
(54,450
)
—

(54,450
)
Share-based compensation
2,998

—

2,998

Issuance of common stock
—

—

—

Dividend reinvestment and stock purchase plan
2,298

—

2,298

Other stock transactions
(16
)
—

(16
)
Balance at September 30, 2015
$
1,287,212

$
—

$
1,287,212


26


At-the-Market Equity Offering Program

On March 18, 2016, we implemented an ATM equity offering program allowing us to sell shares of our common stock with an aggregate value of up to $200 million. The shares may be offered from time to time pursuant to a sales agreement dated March 18, 2016. Shares of common stock are offered pursuant to our shelf registration statement filed with the SEC. During the three months ended September 30, 2016, we issued 819,442 common shares for $49 million, net of $0.5 million in commissions under the ATM equity offering program. Through September 30, 2016, we have sold and issued an aggregate of 1,750,091 shares of common stock under the ATM equity offering program for $106 million, net of $1.1 million in commissions. Additionally, 38,781 shares for net proceeds of $2.4 million have been sold, but were not settled and are not considered issued and outstanding as of September 30, 2016.

Sale of Noncontrolling Interest in Subsidiary

Black Hills Colorado IPP owns and operates a 200 MW, combined-cycle natural gas generating facility located in Pueblo, Colorado. On April 14, 2016, Black Hills Electric Generation sold a 49.9%, noncontrolling interest in Black Hills Colorado IPP for $216 million to a third party buyer. FERC approval of the sale was received on March 29, 2016. Black Hills Electric Generation is the operator of the facility, which is contracted to provide capacity and energy through 2031 to Black Hills Colorado Electric. Proceeds from the sale were used to pay down short-term debt and for other general corporate purposes.

ASC 810 requires the accounting for a partial sale of a subsidiary in which control is maintained and the subsidiary continues to be consolidated. The partial sale is required to be recorded as an equity transaction with no resulting gain or loss on the sale. GAAP requires that noncontrolling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. Distributions of net income attributable to noncontrolling interests are due within 30 days following the end of a quarter, but may be withheld as necessary by Black Hills Electric Generation.

Black Hills Colorado IPP has been determined to be a variable interest entity (VIE) in which the Company has a variable interest. Black Hills Electric Generation has been determined to be the primary beneficiary of the VIE as Black Hills Electric Generation is the operator and manager of the generation facility and, as such, has the power to direct the activities that most significantly impact Black Hills Colorado IPP’s economic performance. Black Hills Electric Generation, as the primary beneficiary, continues to consolidate Black Hills Colorado IPP. Black Hills Colorado IPP has not received financial or other support from the Company outside of pre-existing contractual arrangements during the reporting period. Black Hills Colorado IPP does not have any debt and its cash flows from operations are sufficient to support its ongoing operations.

We have recorded the following assets and liabilities on our consolidated balance sheets related to the VIE described above as of:
 
September 30, 2016
 
December 31, 2015
 
September 30, 2015
 
(in thousands)
Assets
 
 
 
 
 
Current assets
$
14,191

 
$
—

 
$
—

Property, plant and equipment of variable interest entities, net
$
220,818

 
$
—

 
$
—