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 June 30, 2017
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, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
 
Large accelerated filer x
 
Accelerated filer o
 
 
 
 
 
 
 
Non-accelerated filer o
(Do not check if a smaller reporting company)
 
 
 
 
 
 
 
 
Smaller reporting company o
 
 
 
 
 
 
 
 
 
Emerging growth company o
 

If an emerging growth company, indicate by check mark if the Registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock as of the latest practicable date.
Class
Outstanding at July 31, 2017
Common stock, $1.00 par value
53,475,190

shares






TABLE OF CONTENTS
 
 
 
Page
 
Glossary of Terms and Abbreviations
 
 
 
 
 
PART I.
FINANCIAL INFORMATION
 
 
 
 
 
Item 1.
Financial Statements
 
 
 
 
 
 
Condensed Consolidated Statements of Income - unaudited
 
 
 
   Three and Six Months Ended June 30, 2017 and 2016
 
 
 
 
 
 
Condensed Consolidated Statements of Comprehensive Income - unaudited
 
 
 
   Three and Six Months Ended June 30, 2017 and 2016
 
 
 
 
 
 
Condensed Consolidated Balance Sheets - unaudited
 
 
 
   June 30, 2017, December 31, 2016 and June 30, 2016
 
 
 
 
 
 
Condensed Consolidated Statements of Cash Flows - unaudited
 
 
 
   Six Months Ended June 30, 2017 and 2016
 
 
 
 
 
 
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
Arkansas Gas
Black Hills Energy Arkansas, Inc., a direct, wholly-owned subsidiary of Black Hills Gas Inc.
Stockton Storage
Arkansas Gas storage facility
ARMRP
At-Risk Meter Relocation Program
ASC
Accounting Standards Codification
ASU
Accounting Standards Update issued by the FASB
ATM
At-the-market equity offering program
Availability
The availability factor of a power plant is the percentage of the time that it is available to provide energy.
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
CAPP
Customer Appliance Protection Plan

3



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 prices and 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)
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 IPP
Black Hills Colorado IPP, LLC a 50.1% owned subsidiary of Black Hills Electric Generation
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 and including the aggregate outstanding amount of RSNs) plus Consolidated Indebtedness (including letters of credit, certain guarantees issued and excluding RSNs) as defined within the current Credit Agreement.
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.
CP Program
Commercial Paper Program
CPUC
Colorado Public Utilities Commission
CVA
Credit Valuation Adjustment
Dodd-Frank
Dodd-Frank Wall Street Reform and Consumer Protection Act
DSM
Demand Side Management
Dth
Dekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu)
ECA
Energy Cost Adjustment - adjustments that allow us to pass the prudently-incurred cost of fuel and purchased energy through to customers.
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
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.
GSRS
Gas System Reliability Surcharge
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

4



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)
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.
MRP
Meter Relocation Program
MW
Megawatts
MWh
Megawatt-hours
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)
NOL
Net Operating Loss
NPSC
Nebraska Public Service Commission
NYMEX
New York Mercantile Exchange
NYSE
New York Stock Exchange
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
SDPUC
South Dakota Public Utilities Commission
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
The acquisition of SourceGas Holdings, LLC by Black Hills Utility Holdings
SourceGas Transaction
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.
South Dakota Electric
Includes Black Hills Power operations in South Dakota, Wyoming and Montana
SSIR
System Safety and Integrity Rider
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
Winter Storm Atlas
An October 2013 blizzard that impacted South Dakota Electric. It was the second most severe blizzard in Rapid City’s history.
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.
Wyoming Electric
Includes Cheyenne Light’s electric utility operations

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

5





BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
Three Months Ended
June 30,
Six Months Ended
June 30,
 
2017
2016
2017
2016
 
(in thousands, except per share amounts)
 
 
 
 
 
Revenue
$
347,978

$
325,441

$
901,981

$
775,400

 
 
 
 
 
Operating expenses:
 
 
 
 
Fuel, purchased power and cost of natural gas sold
98,164

84,489

317,941

256,345

Operations and maintenance
117,374

112,541

239,504

219,603

Depreciation, depletion and amortization
48,663

47,305

97,310

91,712

Taxes - property, production and severance
13,743

12,760

27,712

24,877

Impairment of long-lived assets

25,497


39,993

Other operating expenses
1,168

7,551

3,137

33,982

Total operating expenses
279,112

290,143

685,604

666,512

 
 
 
 
 
Operating income
68,866

35,298

216,377

108,888

 
 
 
 
 
Other income (expense):
 
 
 
 
Interest charges -
 
 
 
 
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts)
(35,098
)
(34,609
)
(70,194
)
(66,683
)
Allowance for funds used during construction - borrowed
822

754

1,308

1,255

Capitalized interest
130

268

299

503

Interest income
257

946

298

1,601

Allowance for funds used during construction - equity
794

982

1,286

1,689

Other income (expense), net
(58
)
(47
)
(160
)
641

Total other income (expense), net
(33,153
)
(31,706
)
(67,163
)
(60,994
)
 
 
 
 
 
Income before income taxes
35,713

3,592

149,214

47,894

Income tax benefit (expense)
(10,402
)
(309
)
(43,757
)
(4,561
)
Net income
25,311

3,283

105,457

43,333

Net income attributable to noncontrolling interest
(3,116
)
(2,614
)
(6,739
)
(2,662
)
Net income available for common stock
$
22,195

$
669

$
98,718

$
40,671

 
 
 
 
 
Earnings per share of common stock:
 
 
 
 
Earnings per share, Basic
$
0.42

$
0.01

$
1.86

$
0.79

Earnings per share, Diluted
$
0.40

$
0.01

$
1.79

$
0.78

Weighted average common shares outstanding:
 
 
 
 
Basic
53,229

51,514

53,191

51,279

Diluted
55,384

52,986

55,179

52,454

 
 
 
 
 
Dividends declared per share of common stock
$
0.445

$
0.420

$
0.890

$
0.840


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
June 30,
Six Months Ended
June 30,
 
2017
2016
2017
2016
 
(in thousands)
 
 
 
 
 
Net income (loss)
$
25,311

$
3,283

$
105,457

$
43,333

 
 
 
 
 
Other comprehensive income (loss), net of tax:
 
 
 
 
Reclassification adjustments of benefit plan liability - prior service cost (net of tax (expense) benefit of $18 and $19 for the three months ended June 30, 2017 and 2016 and $35 and $38 for the six months ended June 30, 2017 and 2016, respectively)
(31
)
(36
)
(62
)
(72
)
Reclassification adjustments of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(146) and $(173) for the three months ended June 30, 2017 and 2016 and $(300) and $(346) for the six months ended June 30, 2017 and 2016, respectively)
268

321

528

643

Derivative instruments designated as cash flow hedges:
 
 
 
 
Net unrealized gains (losses) on interest rate swaps (net of tax of $0 and $4,440 for the three months ended June 30, 2017 and 2016 and $0 and $10,767 for the six months ended June 30, 2017 and 2016, respectively)

(8,174
)

(19,898
)
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(249) and $(294) for the three months ended June 30, 2017 and 2016 and $(530) and $(592) for the six months ended June 30, 2017 and 2016, respectively)
464

546

985

1,098

Net unrealized gains (losses) on commodity derivatives (net of tax of $(194) and $906 for the three months ended June 30, 2017 and 2016 and $(536) and $98 for the six months ended June 30, 2017 and 2016, respectively)
331

(1,546
)
915

(168
)
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $143 and $1,176 for the three months ended June 30, 2017 and 2016 and $249 and $2,476 for the six months ended June 30, 2017 and 2016, respectively)
(243
)
(2,050
)
(424
)
(4,312
)
Other comprehensive income (loss), net of tax
789

(10,939
)
1,942

(22,709
)
 
 
 
 
 
Comprehensive income (loss)
26,100

(7,656
)
107,399

20,624

Less: comprehensive income attributable to noncontrolling interest
(3,116
)
(2,614
)
(6,739
)
(2,662
)
Comprehensive income (loss) available for common stock
$
22,984

$
(10,270
)
$
100,660

$
17,962


See Note 13 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
 
June 30,
2017
 
December 31, 2016
 
June 30,
2016
 
(in thousands)
ASSETS
 
 
 
 
 
Current assets:
 
 
 
 
 
Cash and cash equivalents
$
11,590

 
$
13,580

 
$
61,859

Restricted cash and equivalents
2,534

 
2,274

 
1,975

Accounts receivable, net
169,957

 
263,289

 
150,227

Materials, supplies and fuel
99,126

 
107,210

 
85,189

Derivative assets, current
1,148

 
4,138

 
4,030

Regulatory assets, current
53,061

 
49,260

 
54,856

Other current assets
21,840

 
27,063

 
30,652

Total current assets
359,256

 
466,814

 
388,788

 
 
 
 
 
 
Investments
12,761

 
12,561

 
12,363

 
 
 
 
 
 
Property, plant and equipment
6,533,581

 
6,412,223

 
6,209,816

Less: accumulated depreciation and depletion
(1,981,880
)
 
(1,943,234
)
 
(1,819,886
)
Total property, plant and equipment, net
4,551,701

 
4,468,989

 
4,389,930

 
 
 
 
 
 
Other assets:
 
 
 
 
 
Goodwill
1,299,454

 
1,299,454

 
1,303,453

Intangible assets, net
7,972

 
8,392

 
9,164

Regulatory assets, non-current
244,099

 
246,882

 
220,556

Derivative assets, non-current
37

 
222

 
226

Other assets, non-current
13,812

 
12,130

 
15,438

Total other assets, non-current
1,565,374

 
1,567,080

 
1,548,837

 
 
 
 
 
 
TOTAL ASSETS
$
6,489,092

 
$
6,515,444

 
$
6,339,918


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
 
June 30,
2017
 
December 31, 2016
 
June 30,
2016
 
(in thousands, except share amounts)
LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND TOTAL EQUITY
 
 
 
 
 
Current liabilities:
 
 
 
 
 
Accounts payable
$
99,970

 
$
153,477

 
$
115,203

Accrued liabilities
201,993

 
244,034

 
218,250

Derivative liabilities, current
719

 
2,459

 
28,855

Accrued income taxes, net
5,160

 
12,552

 
10,624

Regulatory liabilities, current
17,305

 
13,067

 
34,275

Notes payable
107,975

 
96,600

 
75,000

Current maturities of long-term debt
5,743

 
5,743

 
930,743

Total current liabilities
438,865

 
527,932

 
1,412,950

 
 
 
 
 
 
Long-term debt
3,160,302

 
3,211,189

 
2,221,347

 
 
 
 
 
 
Deferred credits and other liabilities:
 
 
 
 
 
Deferred income tax liabilities, net, non-current
589,189

 
535,606

 
530,746

Derivative liabilities, non-current
88

 
274

 
231

Regulatory liabilities, non-current
199,005

 
193,689

 
195,166

Benefit plan liabilities
176,102

 
173,682

 
173,347

Other deferred credits and other liabilities
135,510

 
138,643

 
122,015

Total deferred credits and other liabilities
1,099,894

 
1,041,894

 
1,021,505

 
 
 
 
 
 
Commitments and contingencies (See Notes 8, 10, 15, 16)


 

 

 
 
 
 
 
 
Redeemable noncontrolling interest

 
4,295

 
4,171

 
 
 
 
 
 
Equity:
 
 
 
 
 
Stockholders’ equity —
 
 
 
 
 
Common stock $1 par value; 100,000,000 shares authorized; issued 53,513,521; 53,397,467; and 52,299,075 shares, respectively
53,514

 
53,397

 
52,299

Additional paid-in capital
1,145,493

 
1,138,982

 
1,072,927

Retained earnings
512,498

 
457,934

 
469,940

Treasury stock, at cost – 39,329; 15,258; and 18,900 shares, respectively
(2,325
)
 
(791
)
 
(975
)
Accumulated other comprehensive income (loss)
(32,941
)
 
(34,883
)
 
(31,764
)
Total stockholders’ equity
1,676,239

 
1,614,639

 
1,562,427

Noncontrolling interest
113,792

 
115,495

 
117,518

Total equity
1,790,031

 
1,730,134

 
1,679,945

 
 
 
 
 
 
TOTAL LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND TOTAL EQUITY
$
6,489,092

 
$
6,515,444

 
$
6,339,918


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)
Six Months Ended June 30,
 
2017
2016
Operating activities:
(in thousands)
Net income (loss)
$
105,457

$
40,671

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
Depreciation, depletion and amortization
97,310

91,712

Deferred financing cost amortization
4,138

2,857

Impairment of long-lived assets

39,993

Stock compensation
6,589

7,054

Deferred income taxes
51,153

32,606

Employee benefit plans
5,717

7,782

Other adjustments, net
(6,515
)
(6,332
)
Changes in certain operating assets and liabilities:
 
 
Materials, supplies and fuel
7,720

17,722

Accounts receivable, unbilled revenues and other operating assets
97,902

82,361

Accounts payable and other operating liabilities
(113,541
)
(124,695
)
Regulatory assets - current
3,086

1,862

Regulatory liabilities - current
5,908

2,994

Contributions to defined benefit pension plans

(10,200
)
Other operating activities, net
(2,055
)
(2,884
)
Net cash provided by (used in) operating activities
262,869

183,503

 
 
 
Investing activities:
 
 
Property, plant and equipment additions
(163,768
)
(199,854
)
Acquisition, net of long term debt assumed

(1,124,238
)
Other investing activities
(22
)
(649
)
Net cash provided by (used in) investing activities
(163,790
)
(1,324,741
)
 
 
 
Financing activities:
 
 
Dividends paid on common stock
(47,544
)
(43,265
)
Common stock issued
2,965

57,490

Sale of noncontrolling interest

216,370

Net (payments) borrowings of short-term debt
11,375

(1,800
)
Long-term debt - issuances

574,672

Long-term debt - repayments
(52,871
)
(41,436
)
Distributions to noncontrolling interest
(8,335
)

Other financing activities
(6,659
)
205

Net cash provided by (used in) financing activities
(101,069
)
762,236

Net change in cash and cash equivalents
(1,990
)
(379,002
)
Cash and cash equivalents, beginning of period
13,580

440,861

Cash and cash equivalents, end of period
$
11,590

$
61,859


See Note 14 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 2016 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 2016 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.

Use of Estimates and Basis of Presentation

The information furnished in the accompanying Condensed Consolidated Financial Statements reflects certain estimates required and all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the June 30, 2017, December 31, 2016, and June 30, 2016 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 six months ended June 30, 2017 and June 30, 2016, and our financial condition as of June 30, 2017, December 31, 2016, and June 30, 2016, are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period. June 30, 2017 reflects a full six months of activity from the SourceGas Acquisition on February 12, 2016, as compared to the six months ended June 30, 2016 which reflects a partial period of approximately 4.5 months. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted.

Revisions

Certain revisions have been made to prior years’ financial information to conform to the current year presentation.
The Company revised its presentation of cash as of December 31, 2016.  The Company has banking arrangements at certain financial institutions whereby if required, payments of one account are cleared with cash from other accounts at the same financial institution; therefore, book overdrafts are presented on a combined basis by bank as cash and cash equivalents. Prior year amounts were corrected to conform with the current year presentation, which decreased cash and cash equivalents and accounts payable by $55 million as of June 30, 2016, and decreased net cash flows provided by operations by $39 million for the six months ended June 30, 2016. We assessed the materiality of these changes, taking into account quantitative and qualitative factors, and determined them to be immaterial to the condensed consolidated balance sheet as of June 30, 2016 and to the Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2016. There is no impact to the Condensed Consolidated Statements of Income or the Condensed Consolidated Statements of Comprehensive Income for any period reported.

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Recently Issued and Adopted Accounting Standards

Compensation - Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost, ASU 2017-07

In March 2017, the FASB issued ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost. The changes to the standard require employers to report the service cost component in the same line item(s) as other compensation costs, and require the other components of net periodic pension and post-retirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component may be eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. This ASU will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and post-retirement benefit costs in the income statement. The capitalization of the service cost component of net period pension and post-retirement benefit costs in assets will be applied on a prospective basis. This new guidance is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. We continue to assess the impact of this new standard on our financial statements and disclosures, and we monitor regulated utility industry implementation discussions and guidance. The presentation changes required for net periodic pension and post-retirement costs will result in offsetting changes to Operating income and Other income and are not expected to be material. We will implement this standard effective January 1, 2018.

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 will use the retrospective transition method to adopt this standard with fiscal years beginning after December 15, 2017. This standard will not have a material impact on our financial position, results of operations or 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 was 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 implemented this ASU effective January 1, 2017, recording a cumulative-effect adjustment to retained earnings as of the date of adoption of $3.2 million in the Condensed Consolidated Balance Sheets, representing previously recorded forfeitures and excess tax benefits generated in years prior to 2017 that were previously not recognized in stockholders’ equity due to NOLs in those years. Adoption of this ASU did not have a material impact on our consolidated financial position, results of operations or 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 on the balance sheet for all leases with a term greater than 12 months, whereas today only financing type lease liabilities (capital leases) are recognized on the balance sheet. In addition, the definition of a lease has been revised in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement which may result in changes to the classification of an arrangement as a lease. 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 ASU is largely unchanged from the previous accounting standard. The ASU expands the disclosure requirements of lease arrangements. Lessees and lessors will use a modified retrospective transition approach, which requires application of the new guidance at the beginning of the earliest comparative period presented in the year of adoption. The guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted.


12



We currently expect to adopt this standard on January 1, 2019. We continue to evaluate the impact of this new standard on our financial position, results of operations and cash flows as well as monitor emerging guidance on such topics as easements and right of ways, pipeline laterals, purchase power agreements, pole attachments and other industry-related areas. We also expect to implement changes to systems, processes and procedures in order to recognize and measure leases recorded on the balance sheet that are currently classified as operating leases.

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. The new disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows from revenue contracts with customers. The guidance is effective for annual and interim reporting periods beginning after December 15, 2017 with early adoption on January 1, 2017 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.

We currently expect to implement the standard on a modified retrospective basis effective January 1, 2018. We continue to actively assess all of our sources of revenue to determine the impact that adoption of the new standard will have on our financial position, results of operations and cash flows. Our evaluation includes identifying revenue streams by like contracts to allow for ease of implementation. A majority of our revenues are from regulated tariff offerings that provide natural gas or electricity with a defined contractual term. For such arrangements, we expect that revenue from contracts with the customer will be equivalent to the electricity or gas delivered in that period. Therefore, we do not expect there will be a significant shift in the timing or pattern of revenue recognition for regulated tariff based sales. The evaluation of other revenue streams is ongoing, including our non-regulated revenues and those tied to longer term contractual commitments. We also continue to monitor outstanding industry implementation issues and assess the impacts to our current accounting policies and/or patterns of revenue recognition.

(2)    ACQUISITION

2016 Acquisition of SourceGas

On February 12, 2016, Black Hills Corporation acquired SourceGas (now referred to as Black Hills Gas Holdings). We acquired SourceGas for $1.1 billion of cash plus the assumption of $760 million of long-term debt. We finalized our purchase price allocation at December 31, 2016. See Note 2 of our Notes to the Consolidated Financial Statements in our 2016 Annual Report on Form 10-K for more details.

Pro Forma Results

The following unaudited pro forma financial information reflects the consolidated results of operations as if the SourceGas Acquisition had taken place on January 1, 2015. The unaudited pro forma financial information is presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or our future consolidated results.


13



The pro forma financial information does not reflect any potential cost savings from operating efficiencies resulting from the acquisition and does not include certain acquisition-related costs that are not expected to have a continuing impact on the combined consolidated results. Pro forma results for the three and six months ended June 30, 2016 exclude approximately $4.0 million and $20 million, respectively, of after-tax transaction costs, professional fees, employee related expenses and other miscellaneous costs.

 
Three Months Ended June 30, 2016
Six Months Ended June 30, 2016
 
(in thousands, except per share amounts)
Revenue
$
325,441

$
854,362

Net income (loss) available for common stock
$
4,658

$
72,978

Earnings (loss) per share, Basic
$
0.09

$
1.42

Earnings (loss) per share, Diluted
$
0.09

$
1.39


Redemption of seller’s noncontrolling interest

As part of the SourceGas Transaction, a seller retained a 0.5% noncontrolling interest and we entered into an associated option agreement with the holder of the 0.5% retained interest. The terms of the agreement provided us a call option to purchase the remaining interest beginning 366 days after the initial close of the SourceGas Transaction. In March 2017, we exercised our call option and purchased the remaining 0.5% equity interest in SourceGas for $5.6 million.

(3)    BUSINESS SEGMENT INFORMATION

Segment information and Corporate activities included in the accompanying Condensed Consolidated Statements of Income were as follows (in thousands):
Three Months Ended June 30, 2017
 
External
Operating
Revenue
 
Inter-company
Operating
Revenue
 
Net Income (Loss) Available for Common Stock
Segment:
 
 
 
 
 
 
Electric
 
$
165,517

 
$
2,936

 
$
18,832

Gas
 
166,439

 
8

 
(272
)
Power Generation (b)
 
1,470

 
20,325

 
5,332

Mining
 
8,403

 
6,543

 
2,681

Oil and Gas
 
6,149

 

 
(1,946
)
Corporate activities (c)
 

 

 
(2,432
)
Inter-company eliminations
 

 
(29,812
)
 

Total
 
$
347,978

 
$

 
$
22,195


Three Months Ended June 30, 2016
 
External
Operating
Revenue
 
Inter-company
Operating
Revenue
 
Net Income (Loss) Available for Common Stock
Segment:
 
 
 
 
 
 
Electric.
 
$
158,560

 
$
2,921

 
$
19,229

Gas
 
153,767

 
(1,806
)
 
987

Power Generation (b)
 
1,546

 
20,168

 
5,683

Mining
 
3,922

 
7,125

 
724

Oil and Gas (e)
 
7,646

 

 
(19,424
)
Corporate activities (c)
 

 

 
(6,530
)
Inter-company eliminations
 

 
(28,408
)
 

Total
 
$
325,441

 
$

 
$
669


14



 
 
 
 
 
 
 
Six Months Ended June 30, 2017
 
External
Operating
Revenue
 
Inter-company
Operating
Revenue
 
Net Income (Loss) Available for Common Stock
Segment:
 
 
 
 
 
 
Electric
 
$
337,687

 
$
6,790

 
$
41,062

Gas (a)
 
531,340

 
17

 
45,738

Power Generation (b)
 
3,572

 
41,790

 
11,862

Mining
 
16,758

 
14,734

 
5,571

Oil and Gas
 
12,624

 

 
(4,897
)
Corporate activities (c)(d)
 

 

 
(618
)
Inter-company eliminations
 

 
(63,331
)
 

Total
 
$
901,981

 
$

 
$
98,718

 
 
 
 
 
 
 
Six Months Ended June 30, 2016
 
External
Operating
Revenue
 
Inter-company
Operating
Revenue
 
Net Income (Loss) Available for Common Stock
Segment:
 
 
 
 
 
 
Electric
 
$
322,091

 
$
6,666

 
$
38,444

Gas (a)
 
422,434

 

 
32,914

Power Generation (b)
 
3,398

 
41,624

 
14,265

Mining
 
11,456

 
15,873

 
3,662

Oil and Gas (e)
 
16,021

 

 
(26,448
)
Corporate activities (c)(d)
 

 

 
(22,166
)
Inter-company eliminations
 

 
(64,163
)
 

Total
 
$
775,400

 
$

 
$
40,671

___________
(a)
Gas Utility revenue increased for the six months ended June 30, 2017 compared to the same periods in the prior year primarily due to the addition of the SourceGas utilities on February 12, 2016.
(b)
Net income (loss) available for common stock for the three and six months ended June 30, 2017 was net of net income attributable to noncontrolling interests of $3.1 million and $6.6 million, respectively, and $2.6 million for both the three and six months ended June 30, 2016.
(c)
Net income (loss) available for common stock for the three and six months ended June 30, 2017 and June 30, 2016 included incremental, non-recurring acquisition costs, net of tax of $0.3 million and $1.2 million, and $4.1 million and $20 million respectively. The three and six months ended June 30, 2016 also included $2.0 million and $5.7 million, respectively, of after-tax internal labor costs attributable to the acquisition.
(d)
Net income (loss) available for common stock for the six months ended June 30, 2017 included a $1.4 million tax benefit recognized from carryback claims for specified liability losses involving prior tax years. Net income (loss) available for common stock for the six months ended June 30, 2016 included tax benefits of approximately $4.4 million as a result of the re-measurement of the liability for uncertain tax positions predicated on an agreement reached with IRS Appeals in early 2016. See Note 18.
(e)
Net income (loss) available for common stock for the three and six months ended June 30, 2016 included non-cash after-tax impairments of oil and gas properties of $16 million and $25 million. See Note 17 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.


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Segment information and Corporate balances included in the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands):
Total Assets (net of inter-company eliminations) as of:
June 30, 2017
 
December 31, 2016
 
June 30, 2016
Segment:
 
 
 
 
 
Electric (a)
$
2,901,570

 
$
2,859,559

 
$
2,755,695

Gas
3,242,461

 
3,307,967

 
3,118,626

Power Generation (a)
66,292

 
73,445

 
80,360

Mining
67,365

 
67,347

 
71,319

Oil and Gas (b)
103,044

 
96,435

 
171,239

Corporate activities
108,360

 
110,691

 
142,679

Total assets
$
6,489,092

 
$
6,515,444

 
$
6,339,918

__________
(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)
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 $107 million for the year ended December 31, 2016 and $40 million for the six months ended June 30, 2016. See Note 17 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.



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(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
June 30, 2017
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
41,635

$
33,686

$
(466
)
$
74,855

Gas Utilities
62,908

26,584

(2,535
)
86,957

Power Generation
877



877

Mining
2,904



2,904

Oil and Gas
3,280


(83
)
3,197

Corporate
1,167



1,167

Total
$
112,771

$
60,270

$
(3,084
)
$
169,957


 
Accounts
Unbilled
Less Allowance for
Accounts
December 31, 2016
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
41,730

$
36,463

$
(353
)
$
77,840

Gas Utilities
88,168

88,329

(2,026
)
174,471

Power Generation
1,420



1,420

Mining
3,352



3,352

Oil and Gas
3,991


(13
)
3,978

Corporate
2,228



2,228

Total
$
140,889

$
124,792

$
(2,392
)
$
263,289


 
Accounts
Unbilled
Less Allowance for
Accounts
June 30, 2016
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
40,991

$
34,174

$
(716
)
$
74,449

Gas Utilities
47,600

23,124

(2,997
)
67,727

Power Generation
1,229



1,229

Mining
1,114



1,114

Oil and Gas
3,094


(13
)
3,081

Corporate
2,627



2,627

Total
$
96,655

$
57,298

$
(3,726
)
$
150,227



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(5)    REGULATORY ACCOUNTING

We had the following regulatory assets and liabilities (in thousands):
 
Maximum
As of
As of
As of
 
Amortization
June 30, 2017
December 31, 2016
June 30, 2016
 
(in years)
 
 
 
Regulatory assets
 
 
 
 
Deferred energy and fuel cost adjustments - current (a)(d)
1
$
20,761

$
17,491

$
20,603

Deferred gas cost adjustments (a)(d)
1
9,060

15,329

12,122

Gas price derivatives (a)
3.5
11,159

8,843

11,515

Deferred taxes on AFUDC (b)
45
15,322

15,227

13,879

Employee benefit plans (c)
12
107,419

108,556

109,522

Environmental (a)
subject to approval
1,070

1,108

1,144

Asset retirement obligations (a)
44
510

505

505

Loss on reacquired debt (a)
30
21,466

22,266

3,061

Renewable energy standard adjustment (b)
5
768

1,605

2,679

Deferred taxes on flow through accounting (c)
35
40,586

37,498

31,554

Decommissioning costs (e)
6
14,681

16,859

18,399

Gas supply contract termination
5
22,793

26,666

28,385

Other regulatory assets (a) (e)
15
31,565

24,189

22,044

 
 
$
297,160

$
296,142

$
275,412

 
 
 
 
 
Regulatory liabilities
 
 
 
 
Deferred energy and gas costs (a) (d)
1
$
16,767

$
10,368

$
32,868

Employee benefit plan costs and related deferred taxes (c)
12
67,297

68,654

62,712

Cost of removal (a)
44
125,247

118,410

126,002

Revenue subject to refund
1
1,518

2,485

1,616

Other regulatory liabilities (c)
25
5,481

6,839

6,243

 
 
$
216,310

$
206,756

$
229,441

__________
(a)
We are allowed 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)
In accordance with a settlement agreement approved by the SDPUC on June 16, 2017, the amortization of South Dakota Electric’s decommissioning costs of approximately $11 million, vegetation management costs of approximately $14 million, and Winter Storm Atlas costs of approximately $2.0 million will be amortized over 6 years, effective July 1, 2017. Decommissioning costs and Winter Storm Atlas costs were previously amortized over a 10 year period ending September 30, 2024. The vegetation management costs were previously unamortized. The change in amortization periods for these costs will increase annual amortization expense by approximately $2.7 million.


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(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:
 
June 30, 2017
 
December 31, 2016
 
June 30, 2016
Materials and supplies
$
72,397

 
$
68,456

 
$
67,440

Fuel - Electric Utilities
3,106

 
3,667

 
4,659

Natural gas in storage held for distribution
23,623

 
35,087

 
13,090

Total materials, supplies and fuel
$
99,126

 
$
107,210

 
$
85,189



(7)    EARNINGS PER SHARE

A reconciliation of share amounts used to compute Earnings (loss) per share in the accompanying Condensed Consolidated Statements of Income was as follows (in thousands):
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2017
2016
 
2017
2016
 
 
 
 
 
 
Net income (loss) available for common stock
$
22,195

$
669

 
$
98,718

$
40,671

 
 
 
 
 
 
Weighted average shares - basic
53,229

51,514

 
53,191

51,279

Dilutive effect of:
 
 
 
 
 
Equity Units (a)
1,977

1,362

 
1,796

1,068

Equity compensation
178

110

 
192

107

Weighted average shares - diluted
55,384

52,986

 
55,179

52,454

__________
(a)
Calculated using the treasury stock method.

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 June 30,
 
Six Months Ended June 30,
 
2017
2016
 
2017
2016
 
 
 
 
 
 
Equity compensation

4

 

10

Anti-dilutive shares

4

 

10



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(8)    NOTES PAYABLE AND LONG-TERM DEBT

We had the following notes payable outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
 
June 30, 2017
December 31, 2016
June 30, 2016
 
Balance Outstanding
Letters of Credit
Balance Outstanding
Letters of Credit
Balance Outstanding
Letters of Credit
Revolving Credit Facility
$

$
24,540

$
96,600

$
36,000

$
75,000

$
24,700

CP Program
107,975






Total
$
107,975

$
24,540

$
96,600

$
36,000

$
75,000

$
24,700


Revolving Credit Facility and CP Program

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 (subject to consent from lenders). 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 $1.0 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 0.250%, 1.250%, and 1.250%, respectively, at June 30, 2017. A 0.200% commitment fee is charged on the unused amount of the Revolving Credit Facility.

On December 22, 2016, we implemented a $750 million, unsecured CP Program that is backstopped by the Revolving Credit Facility. Amounts outstanding under the Revolving Credit Facility and the CP Program, either individually or in the aggregate, cannot exceed $750 million. The notes issued under the CP Program may have maturities not to exceed 397 days from the date of issuance and bear interest (or are sold at par less a discount representing an interest factor) based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings. Under the CP Program, any borrowings rank equally with our unsecured debt. Notes under the CP Program are not registered and are offered and issued pursuant to a registration exemption. Our net amount borrowed under the CP Program during the six months ended June 30, 2017 and our notes outstanding as of June 30, 2017 were $108 million. As of June 30, 2017, the weighted average interest rate on CP Program borrowings was 1.41%.

Debt Covenants

On December 7, 2016, we amended our Revolving Credit Facility and term loan agreements, allowing the exclusion of the Remarketable Junior Subordinated Notes (RSNs) from our Consolidated Indebtedness to Capitalization Ratio covenant calculation. Under the amended and restated Revolving Credit Facility and term loan agreements, we are required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00. Our Consolidated Indebtedness to Capitalization Ratio is calculated by dividing (i) Consolidated Indebtedness, which includes letters of credit and certain guarantees issued and excludes RSNs by (ii) Capital, which includes Consolidated Indebtedness plus Net Worth, which excludes noncontrolling interests in subsidiaries and includes the aggregate outstanding amount of the RSNs.

Our Revolving Credit Facility and our Term Loans require compliance with the following financial covenant at the end of each quarter:
 
As of June 30, 2017
 
Covenant Requirement
Consolidated Indebtedness to Capitalization Ratio
61%
 
Less than
65%

As of June 30, 2017, we were in compliance with this covenant.

Long-Term Debt

On May 16, 2017, we paid down $50 million on our Corporate term loan due August 9, 2019. On July 17, 2017, we paid down an additional $50 million on the same term loan. Short-term borrowings from our CP program were used to fund the payments on the Corporate term loan.

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(9)    EQUITY

A summary of the changes in equity is as follows:

Six Months Ended June 30, 2017
Total Stockholders’ Equity
Noncontrolling Interest
Total Equity
 
 
(in thousands)
 
Balance at December 31, 2016
$
1,614,639

$
115,495

$
1,730,134

Net income (loss)
98,718

6,632

105,350

Other comprehensive income (loss)
1,942


1,942

Dividends on common stock
(47,544
)

(47,544
)
Share-based compensation
4,133


4,133

Issuance of common stock



Dividend reinvestment and stock purchase plan
1,530


1,530

Redeemable noncontrolling interest
(886
)

(886
)
Cumulative effect of ASU 2016-09 implementation
3,714


3,714

Other stock transactions
(7
)

(7
)
Distribution to noncontrolling interest

(8,335
)
(8,335
)
Balance at June 30, 2017
$
1,676,239

$
113,792

$
1,790,031


Six Months Ended June 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)
40,671

2,632

43,303

Other comprehensive income (loss)
(22,709
)

(22,709
)
Dividends on common stock
(43,270
)

(43,270
)
Share-based compensation
2,192


2,192

Issuance of common stock
55,802


55,802

Dividend reinvestment and stock purchase plan
1,478


1,478

Other stock transactions
(20
)

(20
)
Sale of noncontrolling interest
62,416

114,886

177,302

Balance at June 30, 2016
$
1,562,427

$
117,518

$
1,679,945



21



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. We did not issue any common shares during the six months ended June 30, 2017. During the three months ended June 30, 2016, we sold 809,649 common shares for $49 million, net of $0.5 million in commissions, under the ATM equity offering program. During the six months ended June 30, 2016, we sold and issued an aggregate of 930,649 shares of common stock under the ATM equity offering program for $56 million, net of $0.6 million in commissions with settlement dates through June 30, 2016. On August 4, 2017, the Company plans to file for renewal of the ATM equity offering program initiated in 2016 which resets the size of the ATM equity offering program to an aggregate sales price of up to $300 million.

Sale of Noncontrolling Interest in Subsidiary

Black Hills Colorado IPP owns 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.

This partial sale was required to be recorded as an equity transaction with no resulting gain or loss on the sale. Further, 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:
 
June 30, 2017
 
December 31, 2016
 
June 30, 2016
 
(in thousands)
Assets
 
 
 
 
 
Current assets
$
12,042

 
$
12,627

 
$
12,681

Property, plant and equipment of variable interest entities, net
$
214,239

 
$
218,798

 
$
224,128

 
 
 
 
 
 
Liabilities
 
 
 
 
 
Current liabilities
$
2,651

 
$
4,342

 
$
4,174



22



(10)    RISK MANAGEMENT ACTIVITIES

Our activities in the regulated and non-regulated energy sectors expose us to a number of risks in the normal operation of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and credit risk. To manage and mitigate these identified risks, we have adopted the Black Hills Corporation Risk Policies and Procedures as discussed in our 2016 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, our retail natural gas marketing activities, and our fuel procurement for certain of our gas-fired generation assets.

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 on 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 and Condensed Consolidated Statements of Comprehensive Income are detailed below and in Note 11.

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, swaps and options to hedge portions of our crude oil and natural gas production. We elect hedge accounting on our futures and swaps. 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.


23



The contract or notional amounts and terms of the crude oil futures and natural gas futures and swaps held at our Oil and Gas segment are composed of short positions. We had the following short positions as of:

 
June 30, 2017
 
December 31, 2016
 
June 30, 2016
 
Crude Oil Futures
Crude Oil Options
Natural Gas Futures and Swaps
 
Crude Oil Futures
Crude Oil Options
Natural Gas Futures and Swaps
 
Crude Oil Futures
Natural Gas Futures and Swaps
Notional (a)
72,000

18,000

1,080,000

 
108,000

36,000

2,700,000

 
210,000

2,530,000

Maximum terms in months (b)
18

6

6

 
24

12

12

 
30

18

__________
(a)
Crude oil futures and call options in Bbls, natural gas in MMBtus.
(b)
Term reflects the maximum forward period hedged.
Based on June 30, 2017 prices, a $0.5 million gain would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods.

Utilities

The operations of our utilities, including natural gas sold by our Gas Utilities and natural gas used by our Electric Utilities’ 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, fixed to float swaps 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.

For our regulated utilities’ hedging plans, 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, or the Condensed Consolidated Statements of Comprehensive Income.

We buy, sell and deliver natural gas at competitive prices by managing commodity price risk. As a result of these activities, this area of our business is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risks using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and/or sales during time frames ranging from July 2017 through December 2020. A portion of our over-the-counter swaps have been designated as cash flow hedges to mitigate the commodity price risk associated with forward contracts to deliver gas to our Choice Gas Program customers. The effective portion of the gain or loss on these designated derivatives is reported in AOCI in the accompanying Condensed Consolidated Balance Sheets and the ineffective portion, if any, is reported in Fuel, purchased power and cost of natural gas sold in the accompanying Condensed Consolidated Statements of Income. Effectiveness of our hedging position is evaluated at least quarterly.


24



The contract or notional amounts and terms of the natural gas derivative commodity instruments held at our Utilities are composed of both long and short positions. We were in a net long position as of:
 
June 30, 2017
 
December 31, 2016
 
June 30, 2016
 
Notional
(MMBtus)
 
Maximum
Term
(months) (a)
 
Notional
(MMBtus)
 
Maximum
Term
(months) (a)
 
Notional
(MMBtus)
 
Maximum
Term
(months) (a)
Natural gas futures purchased
11,060,000

 
42
 
14,770,000

 
48
 
18,080,000

 
54
Natural gas options purchased, net
1,640,000

 
20
 
3,020,000

 
5
 
3,770,000

 
20
Natural gas basis swaps purchased
10,070,000

 
42
 
12,250,000

 
48
 
15,320,000

 
54
Natural gas over-the-counter swaps, net (b)
5,200,000

 
23
 
4,622,302

 
28
 
5,029,500

 
23
Natural gas physical contracts, net
8,427,119

 
10
 
21,504,378

 
10
 
1,666,800

 
9
__________
(a)
Term reflects the maximum forward period hedged.
(b)
2,480,000 MMBtus were designated as cash flow hedges for the natural gas fixed for float swaps purchased.

Based on June 30, 2017 prices, a $0.2 million loss would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods.

Financing Activities

In October 2015 and January 2016, we entered into forward starting interest rate swaps with a notional value totaling $400 million to reduce the interest rate risk associated with the anticipated issuance of senior notes. These swaps were settled at a loss of $29 million in connection with the issuance of our $400 million of unsecured ten-year senior notes on August 10, 2016. The effective portion of the loss in the amount of $28 million was recognized as a component of AOCI and will be recognized as a component of interest expense over the ten-year life of the $400 million unsecured senior note issued on August 19, 2016. Amortization of approximately $2.9 million, which includes the amortization of the $28 million loss currently deferred in AOCI will be recognized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. The ineffective portion of $1.0 million, related to the timing of the debt issuance, was recognized in earnings as a component of interest expense in 2016. The contract or notional amounts, terms of our interest rate swaps and the interest rate swaps balances reflected on the Condensed Consolidated Balance Sheets were as follows (dollars in thousands) as of:
 
June 30, 2017
 
December 31, 2016
 
June 30, 2016
 
Designated 
Interest Rate
Swaps
 
Designated
Interest Rate
Swap
 (a)
 
Designated
Interest Rate
Swap
(b)
Designated
Interest Rate
Swap
(b)
Designated
Interest Rate
Swaps
(a)
Notional
$

 
$
50,000

 
$
150,000

$
250,000

$
75,000

Weighted average fixed interest rate
%
 
4.94
%
 
2.09
%
2.29
%
4.97
%
Maximum terms in months
0

 
1

 
10

10

6

Derivative liabilities, current
$

 
$
90

 
$
8,553

$
18,500

$
1,505

__________
(a)
The $25 million in swaps expired in October 2016 and the $50 million in swaps expired in January 2017. These swaps were designated to borrowings on our Revolving Credit Facility and were priced using three-month LIBOR, matching the floating portion of the related borrowings.
(b)
These swaps were settled and terminated in August 2016 in conjunction with the refinancing of acquired SourceGas debt.


25



Cash Flow Hedges

The impacts of cash flow hedges on our Condensed Consolidated Statements of Income is presented below for the three and six months ended June 30, 2017 and 2016 (in thousands). Note that this presentation does not reflect gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.
Three Months Ended June 30, 2017
Derivatives in Cash Flow Hedging Relationships
 
Location of
Reclassifications from AOCI into Income
 
Amount of
Gain/(Loss) Reclassified
from AOCI
into Income
(Settlements)
 
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
 
Interest expense
 
$
(713
)
 
Interest expense
 
$

Commodity derivatives
 
Revenue
 
430

 
Revenue
 

Commodity derivatives
 
Fuel, purchased power and cost of natural gas sold
 
(44
)
 
Fuel, purchased power and cost of natural gas sold
 

Total
 
 
 
$
(327
)
 
 
 
$


Three Months Ended June 30, 2016
Derivatives in Cash Flow Hedging Relationships
 
Location of
Reclassifications from AOCI into Income
 
Amount of
Gain/(Loss) Reclassified
from AOCI
into Income
(Settlements)
 
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
 
Interest expense
 
$
(840
)
 
Interest expense
 
$

Commodity derivatives
 
Revenue
 
3,287

 
Revenue
 

Commodity derivatives
 
Fuel, purchased power and cost of natural gas sold
 
(61
)
 
Fuel, purchased power and cost of natural gas sold
 

Total
 
 
 
$
2,386

 
 
 
$


 
 
 
 
 
 
 
 
 
Six Months Ended June 30, 2017
Derivatives in Cash Flow Hedging Relationships
 
Location of
Reclassifications from AOCI into Income
 
Amount of
Gain/(Loss) Reclassified
from AOCI
into Income
(Settlements)
 
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
 
Interest expense
 
$
(1,515
)
 
Interest expense
 
$

Commodity derivatives
 
Revenue
 
659

 
Revenue
 

Commodity derivatives
 
Fuel, purchased power and cost of natural gas sold
 
14

 
Fuel, purchased power and cost of natural gas sold
 

Total
 
 
 
$
(842
)
 
 
 
$

 
 
 
 
 
 
 
 
 


26



 
 
 
 
 
 
 
 
 
Six Months Ended June 30, 2016
Derivatives in Cash Flow Hedging Relationships
 
Location of
Reclassifications from AOCI into Income
 
Amount of
Gain/(Loss) Reclassified
from AOCI
into Income
(Settlements)
 
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
 
Interest expense
 
$
(1,690
)
 
Interest expense
 
$

Commodity derivatives
 
Revenue
 
6,939

 
Revenue
 

Commodity derivatives
 
Fuel, purchased power and cost of natural gas sold
 
(151
)
 
Fuel, purchased power and cost of natural gas sold
 

Total
 
 
 
$
5,098

 
 
 
$


The following table summarizes the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss) for the three and six months ended June 30, 2017 and 2016. The amounts included in the table below exclude gains and losses arising from ineffectiveness because these amounts are immediately recognized in the Consolidated Statements of Net Income as incurred.
 
Three Months Ended June 30,
 
2017
 
2016
 
(In thousands)
Increase (decrease) in fair value:
 
 
 
Interest rate swaps
$

 
$
(12,614
)
Forward commodity contracts
525

 
(2,452
)
Recognition of (gains) losses in earnings due to settlements:
 
 
 
Interest rate swaps
713

 
840

Forward commodity contracts
(386
)
 
(3,226
)
Total other comprehensive income (loss) from hedging
$
852

 
$
(17,452
)

 
Six Months Ended June 30,
 
2017
 
2016
 
(In thousands)
Increase (decrease) in fair value:
 
 
 
Interest rate swaps
$

 
$
(30,665
)
Forward commodity contracts
1,451

 
(266
)
Recognition of (gains) losses in earnings due to settlements:
 
 
 
Interest rate swaps
1,515

 
1,690

Forward commodity contracts
(673
)
 
6,788

Total other comprehensive income (loss) from hedging
$
2,293

 
$
(22,453
)


27



Derivatives Not Designated as Hedge Instruments

The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Consolidated Statements of Income for the three and six months ended June 30, 2017 and 2016 (in thousands). Note that this presentation does not reflect gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.
 
 
Three Months Ended June 30,
 
 
2017
 
2016
Derivatives Not Designated as Hedging Instruments
Location of Gain/(Loss) on Derivatives Recognized in Income
Amount of Gain/(Loss) on Derivatives Recognized in Income
 
Amount of Gain/(Loss) on Derivatives Recognized in Income
 
 
 
 
 
Commodity derivatives
Revenue
$
26

 
$

Commodity derivatives
Fuel, purchased power and cost of natural gas sold
(691
)
 
2,201

 
 
$
(665
)
 
$
2,201


 
 
Six Months Ended June 30,
 
 
2017
 
2016
Derivatives Not Designated as Hedging Instruments
Location of Gain/(Loss) on Derivatives Recognized in Income
Amount of Gain/(Loss) on Derivatives Recognized in Income
 
Amount of Gain/(Loss) on Derivatives Recognized in Income
 
 
 
 
 
Commodity derivatives
Revenue
$
143

 
$

Commodity derivatives
Fuel, purchased power and cost of natural gas sold
(1,500
)
 
2,835

 
 
$
(1,357
)
 
$
2,835


As discussed above, financial instruments used in our regulated utilities are not designated as cash flow hedges. However, there is no earnings impact because the unrealized gains and losses arising from the use of these financial instruments are recorded as Regulatory assets. The net unrealized losses included in our Regulatory assets related to the hedges in our Utilities were $11 million, $8.8 million and $12 million at June 30, 2017, December