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, 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 October 31, 2017
Common stock, $1.00 par value
53,484,560

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 Nine Months Ended September 30, 2017 and 2016
 
 
 
 
 
 
Condensed Consolidated Statements of Comprehensive Income - unaudited
 
 
 
   Three and Nine Months Ended September 30, 2017 and 2016
 
 
 
 
 
 
Condensed Consolidated Balance Sheets - unaudited
 
 
 
   September 30, 2017, December 31, 2016 and September 30, 2016
 
 
 
 
 
 
Condensed Consolidated Statements of Cash Flows - unaudited
 
 
 
   Nine Months Ended September 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
 


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
September 30,
Nine Months Ended
September 30,
 
2017
2016
2017
2016
 
(in thousands, except per share amounts)
 
 
 
 
 
Revenue
$
342,138

$
333,786

$
1,244,119

$
1,109,186

 
 
 
 
 
Operating expenses:
 
 
 
 
Fuel, purchased power and cost of natural gas sold
86,281

80,194

404,222

336,539

Operations and maintenance
114,648

115,103

354,152

334,706

Depreciation, depletion and amortization
49,434

48,925

146,744

140,637

Taxes - property, production and severance
13,092

12,114

40,804

36,991

Impairment of long-lived assets

12,293


52,286

Other operating expenses
164

6,748

3,301

40,730

Total operating expenses
263,619

275,377

949,223

941,889

 
 
 
 
 
Operating income
78,519

58,409

294,896

167,297

 
 
 
 
 
Other income (expense):
 
 
 
 
Interest charges -
 
 
 
 
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts)
(35,305
)
(37,306
)
(105,499
)
(103,989
)
Allowance for funds used during construction - borrowed
753

860

2,061

2,115

Capitalized interest
149

282

448

785

Interest income
402

912

700

2,513

Allowance for funds used during construction - equity
696

1,211

1,982

2,900

Other income (expense), net
189

160

29

801

Total other income (expense), net
(33,116
)
(33,881
)
(100,279
)
(94,875
)
 
 
 
 
 
Income before income taxes
45,403

24,528

194,617

72,422

Income tax benefit (expense)
(13,805
)
(6,644
)
(57,562
)
(11,205
)
Net income
31,598

17,884

137,055

61,217

Net income attributable to noncontrolling interest
(3,935
)
(3,753
)
(10,674
)
(6,415
)
Net income available for common stock
$
27,663

$
14,131

$
126,381

$
54,802

 
 
 
 
 
Earnings per share of common stock:
 
 
 
 
Earnings per share, Basic
$
0.52

$
0.27

$
2.38

$
1.06

Earnings per share, Diluted
$
0.50

$
0.26

$
2.29

$
1.04

Weighted average common shares outstanding:
 
 
 
 
Basic
53,243

52,184

53,208

51,583

Diluted
55,432

53,733

55,254

52,893

 
 
 
 
 
Dividends declared per share of common stock
$
0.445

$
0.420

$
1.335

$
1.260


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,
 
2017
2016
2017
2016
 
(in thousands)
 
 
 
 
 
Net income
$
31,598

$
17,884

$
137,055

$
61,217

 
 
 
 
 
Other comprehensive income (loss), net of tax:
 
 
 
 
Reclassification adjustments of benefit plan liability - prior service cost (net of tax (expense) benefit of $17 and $19 for the three months ended September 30, 2017 and 2016 and $52 and $57 for the nine months ended September 30, 2017 and 2016, respectively)
(32
)
(36
)
(94
)
(108
)
Reclassification adjustments of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(145) and $(171) for the three months ended September 30, 2017 and 2016 and $(445) and $(517) for the nine months ended September 30, 2017 and 2016, respectively)
269

323

797

966

Derivative instruments designated as cash flow hedges:
 
 
 
 
Net unrealized gains (losses) on interest rate swaps (net of tax of $0 and $163 for the three months ended September 30, 2017 and 2016 and $0 and $10,930 for the nine months ended September 30, 2017 and 2016, respectively)

(302
)

(20,200
)
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(249) and $(294) for the three months ended September 30, 2017 and 2016 and $(779) and $(886) for the nine months ended September 30, 2017 and 2016, respectively)
464

546

1,449

1,644

Net unrealized gains (losses) on commodity derivatives (net of tax of $94 and $(423) for the three months ended September 30, 2017 and 2016 and $(442) and $(324) for the nine months ended September 30, 2017 and 2016, respectively)
(160
)
(249
)
755

(417
)
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $95 and $860 for the three months ended September 30, 2017 and 2016 and $344 and $3,337 for the nine months ended September 30, 2017 and 2016, respectively)
(166
)
(1,469
)
(590
)
(5,781
)
Other comprehensive income (loss), net of tax
375

(1,187
)
2,317

(23,896
)
 
 
 
 
 
Comprehensive income
31,973

16,697

139,372

37,321

Less: comprehensive income attributable to noncontrolling interest
(3,935
)
(3,753
)
(10,674
)
(6,415
)
Comprehensive income available for common stock
$
28,038

$
12,944

$
128,698

$
30,906


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
 
September 30,
2017
 
December 31, 2016
 
September 30,
2016
 
(in thousands)
ASSETS
 
 
 
 
 
Current assets:
 
 
 
 
 
Cash and cash equivalents
$
13,510

 
$
13,580

 
$
31,814

Restricted cash and equivalents
2,683

 
2,274

 
2,140

Accounts receivable, net
153,832

 
263,289

 
154,617

Materials, supplies and fuel
126,520

 
107,210

 
113,475

Derivative assets, current
657

 
4,138

 
4,382

Regulatory assets, current
61,023

 
49,260

 
50,561

Other current assets
26,793

 
27,063

 
30,032

Total current assets
385,018

 
466,814

 
387,021

 
 
 
 
 
 
Investments
12,947

 
12,561

 
12,416

 
 
 
 
 
 
Property, plant and equipment
6,615,098

 
6,412,223

 
6,306,119

Less: accumulated depreciation and depletion
(2,020,331
)
 
(1,943,234
)
 
(1,841,116
)
Total property, plant and equipment, net
4,594,767

 
4,468,989

 
4,465,003

 
 
 
 
 
 
Other assets:
 
 
 
 
 
Goodwill
1,299,454

 
1,299,454

 
1,300,379

Intangible assets, net
7,765

 
8,392

 
8,944

Regulatory assets, non-current
239,571

 
246,882

 
234,240

Derivative assets, non-current

 
222

 
183

Other assets, non-current
11,655

 
12,130

 
12,800

Total other assets, non-current
1,558,445

 
1,567,080

 
1,556,546

 
 
 
 
 
 
TOTAL ASSETS
$
6,551,177

 
$
6,515,444

 
$
6,420,986


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,
2017
 
December 31, 2016
 
September 30,
2016
 
(in thousands, except share amounts)
LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND TOTAL EQUITY
 
 
 
 
 
Current liabilities:
 
 
 
 
 
Accounts payable
$
95,595

 
$
153,477

 
$
110,630

Accrued liabilities
213,571

 
244,034

 
228,522

Derivative liabilities, current
1,562

 
2,459

 
1,941

Accrued income taxes, net
5,587

 
12,552

 
10,909

Regulatory liabilities, current
7,042

 
13,067

 
16,925

Notes payable
225,170

 
96,600

 
75,000

Current maturities of long-term debt
5,743

 
5,743

 
5,743

Total current liabilities
554,270

 
527,932

 
449,670

 
 
 
 
 
 
Long-term debt
3,109,864

 
3,211,189

 
3,211,768

 
 
 
 
 
 
Deferred credits and other liabilities:
 
 
 
 
 
Deferred income tax liabilities, net, non-current
605,744

 
535,606

 
533,865

Derivative liabilities, non-current
74

 
274

 
317

Regulatory liabilities, non-current
198,189

 
193,689

 
186,496

Benefit plan liabilities
149,803

 
173,682

 
171,633

Other deferred credits and other liabilities
137,251

 
138,643

 
141,007

Total deferred credits and other liabilities
1,091,061

 
1,041,894

 
1,033,318

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


 

 

 
 
 
 
 
 
Redeemable noncontrolling interest

 
4,295

 
4,206

 
 
 
 
 
 
Equity:
 
 
 
 
 
Stockholders’ equity —
 
 
 
 
 
Common stock $1 par value; 100,000,000 shares authorized; issued 53,524,529; 53,397,467; and 53,131,469 shares, respectively
53,525

 
53,397

 
53,131

Additional paid-in capital
1,147,922

 
1,138,982

 
1,123,527

Retained earnings
516,371

 
457,934

 
462,090

Treasury stock, at cost – 41,457; 15,258; and 22,368 shares, respectively
(2,448
)
 
(791
)
 
(1,155
)
Accumulated other comprehensive income (loss)
(32,566
)
 
(34,883
)
 
(32,951
)
Total stockholders’ equity
1,682,804

 
1,614,639

 
1,604,642

Noncontrolling interest
113,178

 
115,495

 
117,382

Total equity
1,795,982

 
1,730,134

 
1,722,024

 
 
 
 
 
 
TOTAL LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND TOTAL EQUITY
$
6,551,177

 
$
6,515,444

 
$
6,420,986


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,
 
2017
2016
Operating activities:
(in thousands)
Net income
$
137,055

$
54,802

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation, depletion and amortization
146,744

140,637

Deferred financing cost amortization
6,212

4,002

Impairment of long-lived assets

52,286

Derivative fair value adjustments
1,931

(7,308
)
Stock compensation
7,594

9,124

Deferred income taxes
64,672

38,578

Employee benefit plans
8,470

11,830

Other adjustments, net
(5,550
)
(2,076
)
Changes in certain operating assets and liabilities:
 
 
Materials, supplies and fuel
(19,560
)
(5,166
)
Accounts receivable, unbilled revenues and other operating assets
107,026

78,869

Accounts payable and other operating liabilities
(101,471
)
(117,631
)
Regulatory assets - current
1,287

8,453

Regulatory liabilities - current
(4,328
)
(8,181
)
Contributions to defined benefit pension plans
(27,700
)
(14,200
)
Interest rate swap settlement

(28,820
)
Other operating activities, net
(2,952
)
(5,998
)
Net cash provided by (used in) operating activities
319,430

209,201

 
 
 
Investing activities:
 
 
Property, plant and equipment additions
(256,138
)
(334,098
)
Acquisition, net of long term debt assumed

(1,124,238
)
Other investing activities
(250
)
(860
)
Net cash provided by (used in) investing activities
(256,388
)
(1,459,196
)
 
 
 
Financing activities:
 
 
Dividends paid on common stock
(71,334
)
(65,247
)
Common stock issued
3,562

107,690

Sale of noncontrolling interest

216,370

Net (payments) borrowings of short-term debt
128,570

(1,800
)
Long-term debt - issuances

1,767,608

Long-term debt - repayments
(104,307
)
(1,162,872
)
Distributions to noncontrolling interest
(12,884
)
(4,516
)
Other financing activities
(6,719
)
(16,285
)
Net cash provided by (used in) financing activities
(63,112
)
840,948

Net change in cash and cash equivalents
(70
)
(409,047
)
Cash and cash equivalents, beginning of period
13,580

440,861

Cash and cash equivalents, end of period
$
13,510

$
31,814


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.

On November 1, 2017, the BHC board of directors approved a complete divestiture of our Oil and Gas segment. We have initiated the process of divesting all Oil and Gas segment assets in order to fully exit the oil and gas business. We anticipate selling or otherwise disposing of all remaining oil and gas properties and assets by year-end 2018 and have retained advisors to accelerate the marketing and sales process. The Company’s Condensed Consolidated Financial Statements and accompanying Notes as of and for the three and nine months ended September 30, 2017 include the Oil and Gas segment’s assets and liabilities, results of operations and cash flows within continuing operations, as we did not meet the criteria for classifying assets as held for sale and presenting the segment’s activities as discontinued operations during the quarter. See Note 20.

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 September 30, 2017, December 31, 2016, and September 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 nine months ended September 30, 2017 and September 30, 2016, and our financial condition as of September 30, 2017, December 31, 2016, and September 30, 2016, are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period. September 30, 2017 reflects a full nine months of activity from the SourceGas Acquisition on February 12, 2016, as compared to the nine months ended September 30, 2016 which reflects a partial period of approximately 7.5 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 $31 million as of September 30, 2016, and decreased net cash flows provided by operations by $15 million for the nine months ended September 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 September

11



30, 2016 and to the Condensed Consolidated Statements of Cash Flows for the nine months ended September 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.

Recently Issued Accounting Standards

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 have substantially completed our assessment of all sources of revenue and are currently determining the impact that adoption of the new standard will have on our financial position, results of operations and cash flows. 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 during that period. Therefore, we do not expect to have a significant shift in the timing or pattern of revenue recognition for regulated tariff based sales. We also continue to monitor outstanding industry implementation issues and assess the impacts to our current accounting policies and/or patterns of revenue recognition.

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 periodic 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. For our rate-regulated entities, we currently expect to capitalize the other components of net periodic benefit costs into regulatory assets or regulatory liabilities. The presentation changes required for net periodic pension and post-retirement costs will result in offsetting changes to Operating income and Other income which 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 implement this standard effective January 1, 2018. This standard will not have a material impact on our financial position, results of operations or cash flows.




12



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.

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 rights of way, pipeline laterals, purchase power agreements, and other industry-related areas. We have begun the process of identifying and categorizing our lease contracts and evaluating our current business processes.

Derivatives and Hedging: Targeted Improvement to Accounting for Hedging Activities, 2017-12

In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvement to Accounting for Hedging Activities. This standard better aligns risk management activities and financial reporting for hedging relationships, simplifies hedge accounting requirements and improves disclosures of hedging arrangements. This ASU is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. We are currently reviewing this standard to assess the impact on our financial position, results of operations and cash flows.

Recently Adopted Accounting Standards

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.


(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.

The pro forma financial information does not reflect any potential cost savings from operating efficiencies resulting from the

13



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 nine months ended September 30, 2016 exclude approximately $3.8 million and $23 million, respectively, of after-tax transaction costs, including professional fees, employee related expenses and other miscellaneous costs.

 
Three Months Ended September 30, 2016
Nine Months Ended September 30, 2016
 
(in thousands, except per share amounts)
Revenue
$
333,786

$
1,188,148

Net income available for common stock
$
17,376

$
89,973

Earnings per share, Basic
$
0.33

$
1.74

Earnings per share, Diluted
$
0.32

$
1.70


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 for 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 September 30, 2017
 
External
Operating
Revenue
 
Inter-company
Operating
Revenue
 
Net Income (Loss) Available for Common Stock
Segment:
 
 
 
 
 
 
Electric
 
$
181,238

 
$
2,333

 
$
27,324

Gas
 
142,821

 
73

 
(4,329
)
Power Generation (b)
 
1,810

 
21,117

 
6,155

Mining
 
9,742

 
7,751

 
3,477

Oil and Gas
 
6,527

 

 
(2,712
)
Corporate activities (c)
 

 

 
(2,252
)
Inter-company eliminations
 

 
(31,274
)
 

Total
 
$
342,138

 
$

 
$
27,663


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
 
141,445

 

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

 
21,431

 
5,642

Mining
 
9,042

 
7,778

 
3,307

Oil and Gas (e)
 
9,639

 

 
(8,828
)
Corporate activities (c)
 

 

 
(7,232
)
Inter-company eliminations
 

 
(31,956
)
 

Total
 
$
333,786

 
$

 
$
14,131


14



 
 
 
 
 
 
 
Nine Months Ended September 30, 2017
 
External
Operating
Revenue
 
Inter-company
Operating
Revenue
 
Net Income (Loss) Available for Common Stock
Segment:
 
 
 
 
 
 
Electric
 
$
518,925

 
$
9,123

 
$
68,386

Gas (a)
 
674,161

 
90

 
41,409

Power Generation (b)
 
5,382

 
62,907

 
18,017

Mining
 
26,500

 
22,485

 
9,048

Oil and Gas
 
19,151

 

 
(7,609
)
Corporate activities (c)(d)
 

 

 
(2,870
)
Inter-company eliminations
 

 
(94,605
)
 

Total
 
$
1,244,119

 
$

 
$
126,381

 
 
 
 
 
 
 
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 (a)
 
563,879

 

 
29,975

Power Generation (b)
 
5,304

 
63,055

 
19,907

Mining
 
20,498

 
23,651

 
6,969

Oil and Gas (e)
 
25,660

 

 
(35,277
)
Corporate activities (c)(d)
 

 

 
(29,397
)
Inter-company eliminations
 

 
(96,119
)
 

Total
 
$
1,109,186

 
$

 
$
54,802

___________
(a)
Gas Utility revenue increased for the nine months ended September 30, 2017 compared to the same period 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 nine months ended September 30, 2017 and September 30, 2016 was net of net income attributable to noncontrolling interests of $3.9 million and $11 million, and $3.8 million and $6.4 million, respectively.
(c)
Net income (loss) available for common stock for the three and nine months ended September 30, 2017 and September 30, 2016 included incremental, non-recurring acquisition costs, net of tax of $0.2 million and $1.5 million, and $4.0 million and $24 million respectively. The nine months ended September 30, 2017 and the three and nine months ended September 30, 2016 included $0.4 million, $1.7 million and $7.4 million, respectively, of after-tax internal labor costs attributable to the acquisition.
(d)
Net income (loss) available for common stock for the nine months ended September 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 nine months ended September 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 nine months ended September 30, 2016 included non-cash after-tax impairments of oil and gas properties of $7.9 million and $33 million, respectively. See Note 17 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.


15



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, 2017
 
December 31, 2016
 
September 30, 2016
Segment:
 
 
 
 
 
Electric (a)
$
2,911,919

 
$
2,859,559

 
$
2,814,408

Gas
3,288,104

 
3,307,967

 
3,170,571

Power Generation (a)
64,357

 
73,445

 
77,570

Mining
66,700

 
67,347

 
66,804

Oil and Gas (b)
105,963

 
96,435

 
158,981

Corporate activities
114,134

 
110,691

 
132,652

Total assets
$
6,551,177

 
$
6,515,444

 
$
6,420,986

__________
(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 $52 million for the nine months ended September 30, 2016. See Note 17 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.


(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, 2017
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
42,716

$
29,762

$
(494
)
$
71,984

Gas Utilities
49,842

24,516

(1,190
)
73,168

Power Generation
1,010



1,010

Mining
3,534



3,534

Oil and Gas
3,590


(83
)
3,507

Corporate
629



629

Total
$
101,321

$
54,278

$
(1,767
)
$
153,832


 
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



16



 
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


(5)    REGULATORY ACCOUNTING

We had the following regulatory assets and liabilities (in thousands) as of:
 
Maximum Amortization
(in years)
September 30, 2017
December 31, 2016
September 30, 2016
Regulatory assets
 
 
 
 
Deferred energy and fuel cost adjustments -
current (a)(d)
1
$
20,559

$
17,491

$
16,525

Deferred gas cost adjustments (a) (d)
1
12,833

15,329

12,172

Gas price derivatives (a)
3
11,297

8,843

14,405

Deferred taxes on AFUDC (b)
45
15,645

15,227

14,093

Employee benefit plans (c)
12
105,671

108,556

107,578

Environmental (a)
subject to approval
1,051

1,108

1,126

Asset retirement obligations (a)
44
514

505

507

Loss on reacquired debt (a)
30
21,067

22,266

18,077

Renewable energy standard adjustment (b)
5
1,956

1,605

1,694

Deferred taxes on flow through accounting (c)
35
41,900

37,498

33,136

Decommissioning costs (e)
6
13,989

16,859

17,271

Gas supply contract termination
5
21,402

26,666

28,164

Other regulatory assets (a) (e)
30
32,710

24,189

20,053

 
 
$
300,594

$
296,142

$
284,801

 
 
 
 
 
Regulatory liabilities
 
 
 
 
Deferred energy and gas costs (a) (d)
1
$
3,780

$
10,368

$
15,033

Employee benefit plan costs and related deferred taxes (c)
12
66,620

68,654

65,575

Cost of removal (a)
44
125,360

118,410

114,616

Revenue subject to refund
1
1,386

2,485

1,892

Other regulatory liabilities (c)
25
8,085

6,839

6,305

 
 
$
205,231

$
206,756

$
203,421

__________
(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, 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 are being 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

17



unamortized. The change in amortization periods for these costs will increase annual amortization expense by approximately $2.7 million.


(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, 2017
 
December 31, 2016
 
September 30, 2016
Materials and supplies
$
73,938

 
$
68,456

 
$
67,257

Fuel - Electric Utilities
2,993

 
3,667

 
4,282

Natural gas in storage held for distribution
49,589

 
35,087

 
41,936

Total materials, supplies and fuel
$
126,520

 
$
107,210

 
$
113,475



(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 September 30,
 
Nine Months Ended September 30,
 
2017
2016
 
2017
2016
 
 
 
 
 
 
Net income available for common stock
$
27,663

$
14,131

 
$
126,381

$
54,802

 
 
 
 
 
 
Weighted average shares - basic
53,243

52,184

 
53,208

51,583

Dilutive effect of:
 
 
 
 
 
Equity Units (a)
2,015

1,414

 
1,872

1,191

Equity compensation
174

135

 
174

119

Weighted average shares - diluted
55,432

53,733

 
55,254

52,893

__________
(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 September 30,
 
Nine Months Ended September 30,
 
2017
2016
 
2017
2016
 
 
 
 
 
 
Equity compensation

2

 

4

Anti-dilutive shares

2

 

4



18



(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:
 
September 30, 2017
December 31, 2016
September 30, 2016
 
Balance Outstanding
Letters of Credit
Balance Outstanding
Letters of Credit
Balance Outstanding
Letters of Credit
Revolving Credit Facility
$

$
25,391

$
96,600

$
36,000

$
75,000

$
30,500

CP Program
225,170






Total
$
225,170

$
25,391

$
96,600

$
36,000

$
75,000

$
30,500


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 September 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 nine months ended September 30, 2017 and our notes outstanding as of September 30, 2017 were $225 million. As of September 30, 2017, the weighted average interest rate on CP Program borrowings was 1.46%.

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 September 30, 2017
 
Covenant Requirement
Consolidated Indebtedness to Capitalization Ratio
61%
 
Less than
65%

As of September 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.

19



(9)    EQUITY

A summary of the changes in equity is as follows:

Nine Months Ended September 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)
126,381

10,567

136,948

Other comprehensive income (loss)
2,317


2,317

Dividends on common stock
(71,334
)

(71,334
)
Share-based compensation
5,853


5,853

Issuance of common stock



Dividend reinvestment and stock purchase plan
2,300


2,300

Redeemable noncontrolling interest
(886
)

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


3,714

Other stock transactions
(180
)

(180
)
Distribution to noncontrolling interest

(12,884
)
(12,884
)
Balance at September 30, 2017
$
1,682,804

$
113,178

$
1,795,982


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



20



At-the-Market Equity Offering Program

On August 4, 2017, we renewed the ATM equity offering program initiated in March 2016 which reset the size of the ATM equity offering program to an aggregate value of up to $300 million. The renewed program, which allows us to sell shares of our common stock, is the same as the prior year program other than the aggregate value increased from $200 million to $300 million. The shares may be offered from time to time pursuant to a sales agreement dated August 4, 2017. 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 nine months ended September 30, 2017 under the ATM equity offering program. During the three months ended September 30, 2016, we sold 819,442 shares of common stock for $49 million, net of $0.5 million in commissions, under the ATM equity offering program. During the nine months ended September 30, 2016, we sold and issued under the ATM equity offering program an aggregate of 1,750,091 shares of common stock, with settlement dates through September 30, 2016, for $106 million, net of $1.1 million in commissions.

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 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 the noncontrolling interest 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, 2017
 
December 31, 2016
 
September 30, 2016
 
(in thousands)
Assets
 
 
 
 
 
Current assets
$
14,732

 
$
12,627

 
$
14,191

Property, plant and equipment of variable interest entities, net
$
211,380

 
$
218,798

 
$
220,818

 
 
 
 
 
 
Liabilities
 
 
 
 
 
Current liabilities
$
3,275

 
$
4,342

 
$
3,353



21



(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.


22



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:

 
September 30, 2017
 
December 31, 2016
 
September 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
Crude Oil Options
Natural Gas Futures and Swaps
Notional (a)
54,000

9,000

540,000

 
108,000

36,000

2,700,000

 
159,000

36,000

1,625,000

Maximum terms in
months (b)
15

3

3

 
24

12

12

 
27

15

15

__________
(a)
Crude oil futures and call options in Bbls, natural gas in MMBtus.
(b)
Term reflects the maximum forward period hedged.
Based on September 30, 2017 prices, a $0.1 million gain would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. Concurrent with the divestiture of our Oil and Gas Business, our existing oil and gas derivative contracts are expected to be unwound within the next six months. Accordingly, we have de-designated our hedge positions in our Oil and Gas Business effective November 1, 2017. See Note 20.

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, and 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.

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 October 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 inception of the hedge, upon occurrence of a triggering event and as of the end of each quarter.


23



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:
 
September 30, 2017
 
December 31, 2016
 
September 30, 2016
 
Notional
(MMBtus)
 
Maximum
Term
(months) (a)
 
Notional
(MMBtus)
 
Maximum
Term
(months) (a)
 
Notional
(MMBtus)
 
Maximum
Term
(months) (a)
Natural gas futures purchased
10,250,000

 
39
 
14,770,000

 
48
 
17,740,000

 
51
Natural gas options purchased, net
7,360,000

 
17
 
3,020,000

 
5
 
6,540,000

 
17
Natural gas basis swaps purchased
9,170,000

 
39
 
12,250,000

 
48
 
13,650,000

 
51
Natural gas over-the-counter swaps, net (b)
4,600,000

 
20
 
4,622,302

 
28
 
4,749,000

 
20
Natural gas physical contracts, net
21,071,714

 
38
 
21,504,378

 
10
 
15,666,202

 
13
__________
(a)
Term reflects the maximum forward period hedged.
(b)
2,260,000 MMBtus were designated as cash flow hedges for the natural gas fixed for float swaps purchased.

Based on September 30, 2017 prices, a $0.3 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:
 
September 30, 2017
 
December 31, 2016
 
September 30, 2016
 
Designated 
Interest Rate
Swaps
 
Designated
Interest Rate
Swap
 (a)
 
Designated
Interest Rate
Swaps
(a)
Notional
$

 
$
50,000

 
$
75,000

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

 
1

 
4

Derivative liabilities, current
$

 
$
90

 
$
654

__________
(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.



24



Cash Flow Hedges

The impacts of cash flow hedges on our Condensed Consolidated Statements of Income is presented below for the three and nine months ended September 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 September 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
 
295

 
Revenue
 

Commodity derivatives
 
Fuel, purchased power and cost of natural gas sold
 
(34
)
 
Fuel, purchased power and cost of natural gas sold
 

Total
 
 
 
$
(452
)
 
 
 
$


Three Months Ended September 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
 
2,201

 
Revenue
 

Commodity derivatives
 
Fuel, purchased power and cost of natural gas sold
 
128

 
Fuel, purchased power and cost of natural gas sold
 

Total
 
 
 
$
1,489

 
 
 
$


 
 
 
 
 
 
 
 
 
Nine Months Ended September 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
 
$
(2,228
)
 
Interest expense
 
$

Commodity derivatives
 
Revenue
 
954

 
Revenue
 

Commodity derivatives
 
Fuel, purchased power and cost of natural gas sold
 
(20
)
 
Fuel, purchased power and cost of natural gas sold
 

Total
 
 
 
$
(1,294
)
 
 
 
$

 
 
 
 
 
 
 
 
 


25



 
 
 
 
 
 
 
 
 
Nine Months Ended September 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
 
$
(2,530
)
 
Interest expense
 
$

Commodity derivatives
 
Revenue
 
9,140

 
Revenue
 

Commodity derivatives
 
Fuel, purchased power and cost of natural gas sold
 
(23
)
 
Fuel, purchased power and cost of natural gas sold
 

Total
 
 
 
$
6,587

 
 
 
$


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 nine months ended September 30, 2017 and 2016. The amounts included in the table below exclude gains and losses arising from ineffectiveness because these amounts, if any, are immediately recognized in the Consolidated Statements of Income as incurred.
 
Three Months Ended September 30,
 
2017
 
2016
 
(In thousands)
Increase (decrease) in fair value:
 
 
 
Interest rate swaps
$

 
$
(787
)
Forward commodity contracts
(254
)
 
174

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

 
1,162

Forward commodity contracts
(261
)
 
(2,329
)
Total other comprehensive income (loss) from hedging
$
198

 
$
(1,780
)

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

 
$
(31,452
)
Forward commodity contracts
1,197

 
(92
)
Recognition of (gains) losses in earnings due to settlements:
 
 
 
Interest rate swaps
2,228

 
2,852

Forward commodity contracts
(934
)
 
4,459

Total other comprehensive income (loss) from hedging
$
2,491

 
$
(24,233
)


26



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 nine months ended September 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 September 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
$
(53
)
 
$

Commodity derivatives
Fuel, purchased power and cost of natural gas sold
(322
)
 
(342
)
 
 
$
(375
)
 
$
(342
)

 
 
Nine Months Ended September 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
$
90

 
$

Commodity derivatives
Fuel, purchased power and cost of natural gas sold
(1,822
)
 
2,492

 
 
$
(1,732
)
 
$
2,492


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 $14 million at September 30, 2017, December 31, 2016 and September 30, 2016, respectively.



27




(11)    FAIR VALUE MEASUREMENTS

Derivative Financial Instruments

The accounting guidance for fair value measurements requires certain disclosures about assets and liabilities measured at fair value. This guidance establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments. For additional information, see Notes 1, 9, 10 and 11 to the Consolidated Financial Statements included in our 2016 Annual Report on Form 10-K filed with the SEC.

Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs.

Valuation Methodologies for Derivatives

Oil and Gas Segment:

The commodity contracts for our Oil and Gas segment are valued using the market approach and include exchange-traded futures, basis swaps and call options. Fair value was derived using exchange quoted settlement prices from third party brokers for similar instruments as to quantity and timing. The prices are then validated through third-party sources and therefore support Level 2 disclosure.

Utilities Segments:

The commodity contracts for our Utilities Segments, are valued using the market approach and include exchange-traded futures, options, basis swaps and over-the-counter swaps and options (Level 2) for natural gas contracts. For exchange-traded futures, options and basis swap assets and liabilities, fair value was derived using broker quotes validated by the exchange settlement pricing for the applicable contract. For over-the-counter instruments, the fair value is obtained by utilizing a nationally recognized service that obtains observable inputs to compute the fair value, which we validate by comparing our valuation with the counterparty. The fair value of these swaps includes a CVA component based on the credit spreads of the counterparties when we are in an unrealized gain position or on our own credit spread when we are in an unrealized loss position.

Corporate Activities:

As of September 30, 2017, we no longer have derivatives within our corporate activities as our interest rate swaps matured in January 2017. The interest rate swaps that were in place prior to January 2017 were valued using the market approach. We established fair value by obtaining price quotes directly from the counterparty which were based on the floating three-month LIBOR curve for the term of the contract. The fair value obtained from the counterparty was validated by utilizing a nationally recognized service that obtains observable inputs to compute fair value for the same instrument. In addition, the fair value for the interest rate swap derivatives included a CVA component. The CVA considered the fair value of the interest rate swap and the probability of default based on the life of the contract. For the probability of a default component, we utilized observable inputs supporting a Level 2 disclosure by using the credit default spread of the obligor, if available, or a generic credit default spread curve that took into account our credit ratings, and the credit rating of our counterparty.


28



Recurring Fair Value Measurements

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

The following tables set forth by level within the fair value hierarchy are gross assets and gross liabilities and related offsetting cash collateral and counterparty netting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments.

 
As of September 30, 2017
 
Level 1
Level 2
Level 3
 
Cash Collateral and Counterparty
Netting
Total
 
(in thousands)
Assets:
 
 
 
 
 
 
Commodity derivatives — Oil and Gas
$

$
769

$

 
$
(544
)
$
225

Commodity derivatives — Utilities

2,880


 
(2,448
)
432

Total
$

$
3,649

$

 
$
(2,992
)
$
657

 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
Commodity derivatives — Oil and Gas
$

$
114

$

 
$

$
114

Commodity derivatives — Utilities

12,647


 
(11,125
)
1,522

Total
$

$
12,761

$

 
$
(11,125
)
$
1,636


 
As of December 31, 2016
 
Level 1
Level 2
Level 3
 
Cash Collateral and Counterparty
Netting
Total
 
(in thousands)
Assets:
 
 
 
 
 
 
Commodity derivatives — Oil and Gas
$

$
2,886

$

 
$
(2,733
)
$
153

Commodity derivatives —Utilities

7,469


 
(3,262
)
4,207

Total
$

$
10,355

$

 
$
(5,995
)
$
4,360

 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
Commodity derivatives — Oil and Gas
$

$
1,586

$

 
$

$
1,586

Commodity derivatives — Utilities

12,201


 
(11,144
)
1,057

Interest rate swaps

90


 

90

Total
$

$
13,877

$

 
$
(11,144
)
$
2,733



29



 
As of September 30, 2016
 
Level 1
Level 2
Level 3
 
Cash Collateral and Counterparty
Netting
Total
 
(in thousands)
Assets:
 
 
 
 
 
 
Commodity derivatives — Oil and Gas
$

$
2,882

$

 
$

$
2,882

Commodity derivatives — Utilities

5,330


 
(3,647
)
1,683

Total
$

$
8,212

$

 
$
(3,647
)
$
4,565

 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
Commodity derivatives — Oil and Gas
$

$
705

$

 
$

$
705

Commodity derivatives — Utilities

16,130


 
(15,231
)
899

Interest rate swaps

654


 

654

Total
$

$
17,489

$

 
$
(15,231
)
$
2,258


Fair Value Measures by Balance Sheet Classification

As required by accounting standards for derivatives and hedges, fair values within the following tables are presented on a gross basis aside from the netting of asset and liability positions permitted in accordance with accounting standards for offsetting and under terms of our master netting agreements and the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions.

The following tables present the fair value and balance sheet classification of our derivative instruments (in thousands):
As of September 30, 2017
 
Balance Sheet Location
 
Fair Value
of Asset
Derivatives
Fair Value
of Liability
Derivatives
Derivatives designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
227

$

Commodity derivatives
Derivative assets — non-current
 


Commodity derivatives
Derivative liabilities — current
 

511

Commodity derivatives
Derivative liabilities — non-current
 

59

Total derivatives designated as hedges
 
 
$
227

$
570

 
 
 
 
 
Derivatives not designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
430

$

Commodity derivatives
Derivative assets — non-current
 


Commodity derivatives
Derivative liabilities — current
 

1,051

Commodity derivatives
Derivative liabilities — non-current
 

15

Total derivatives not designated as hedges
 
 
$
430

$
1,066



30



As of December 31, 2016
 
Balance Sheet Location
 
Fair Value
of Asset
Derivatives
Fair Value
of Liability
Derivatives
Derivatives designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
1,161

$

Commodity derivatives
Derivative assets — non-current
 
124


Commodity derivatives
Derivative liabilities — current
 

1,090

Commodity derivatives
Derivative liabilities — non-current
 

238

Interest rate swaps
Derivative liabilities — current
 

90

Total derivatives designated as hedges
 
 
$
1,285

$
1,418

 
 
 
 
 
Derivatives not designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
2,977

$

Commodity derivatives
Derivative assets — non-current
 
98


Commodity derivatives
Derivative liabilities — current
 

1,279

Commodity derivatives
Derivative liabilities — non-current
 

36

Total derivatives not designated as hedges
 
 
$
3,075

$
1,315


As of September 30, 2016
 
Balance Sheet Location
 
Fair Value
of Asset
Derivatives
Fair Value
of Liability
Derivatives
Derivatives designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
2,919

$

Commodity derivatives
Derivative assets — non-current
 
66


Commodity derivatives
Derivative liabilities — current
 

479

Commodity derivatives
Derivative liabilities — non-current
 

256

Interest rate swaps
Derivative liabilities — current
 

654

Total derivatives designated as hedges
 
 
$
2,985

$
1,389

 
 
 
 
 
Derivatives not designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
1,463

$

Commodity derivatives
Derivative assets — non-current
 
117


Commodity derivatives
Derivative liabilities — current
 

808

Commodity derivatives
Derivative liabilities — non-current
 

61

Total derivatives not designated as hedges
 
 
$
1,580

$
869


Fair value measurements also apply to the valuation of our pension and postretirement plan assets. Current accounting guidance requires employers to annually disclose information about the fair value measurements of their assets of a defined benefit pension or other postretirement plan. The fair value of these assets is presented in Note 18 to the Consolidated Financial Statements included in our 2016 Annual Report on Form 10-K.


31



(12)    FAIR VALUE OF FINANCIAL INSTRUMENTS

The estimated fair values of our financial instruments, excluding derivatives which are presented in Note 11, were as follows (in thousands) as of:
 
September 30, 2017
 
December 31, 2016
 
September 30, 2016
 
Carrying
Amount
Fair Value
 
Carrying
Amount
Fair Value
 
Carrying
Amount
Fair Value
Cash and cash equivalents (a)
$
13,510

$
13,510

 
$
13,580

$
13,580

 
$
31,814

$
31,814

Restricted cash and equivalents (a)
$
2,683

$
2,683

 
$
2,274

$
2,274

 
$
2,140

$
2,140

Notes payable (b)
$
225,170

$
225,170

 
$
96,600

$
96,600

 
$
75,000

$
75,000

Long-term debt, including current maturities (c) (d)
$
3,115,607

$
3,362,971

 
$
3,216,932

$
3,351,305

 
$
3,217,511

$
3,525,362

__________
(a)
Carrying value approximates fair value due to either the short-term length of maturity or variable interest rates that approximate prevailing market rates, and therefore is classified in Level 1 in the fair value hierarchy.
(b)
Notes payable consist of commercial paper borrowings and borrowings on our Revolving Credit Facility. Carrying value approximates fair value due to the short-term length of maturity; since these borrowings are not traded on an exchange, they are classified in Level 2 in the fair value hierarchy.
(c)
Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy.
(d)
Carrying amount of long-term debt is net of deferred financing costs.


32



(13)
OTHER COMPREHENSIVE INCOME (LOSS)

We record deferred gains (losses) in AOCI related to interest rate swaps designated as cash flow hedges, commodity contracts designated as cash flow hedges and the amortization of components of our defined benefit plans. Deferred gains (losses) for our commodity contracts designated as cash flow hedges are recognized in earnings upon settlement, while deferred gains (losses) related to our interest rate swaps are recognized in earnings as they are amortized.

The following table details reclassifications out of AOCI and into net income. The amounts in parentheses below indicate decreases to net income in the Consolidated Statements of Income for the period, net of tax (in thousands):
 
Location on the Condensed Consolidated Statements of Income
Amount Reclassified from AOCI
Three Months Ended
 
Nine Months Ended
September 30, 2017
September 30, 2016
 
September 30, 2017
September 30, 2016
Gains and (losses) on cash flow hedges:
 
 
 
 
 
 
Interest rate swaps
Interest expense
$
(713
)
$
(840
)
 
$
(2,228
)
$
(2,530
)
Commodity contracts
Revenue
295

2,201

 
954

9,140

Commodity contracts
Fuel, purchased power and cost of natural gas sold

(34
)
128

 
(20
)
(23
)
 
 
(452
)
1,489

 
(1,294
)
6,587

Income tax
Income tax benefit (expense)
154

(566
)
 
435

(2,450
)
Total reclassification adjustments related to cash flow hedges, net of tax
 
$
(298
)
$
923

 
$
(859
)
$
4,137

 
 
 
 
 
 
 
Amortization of components of defined benefit plans:
 
 
 
 
 
 
Prior service cost
Operations and maintenance
$
49

$
55

 
$
146

$
165

Actuarial gain (loss)
Operations and maintenance
(414
)
(494
)
 
(1,242
)
(1,483
)
 
 
(365
)
(439
)
 
(1,096
)
(1,318
)
Income tax
Income tax benefit (expense)
128

152

 
393

460

Total reclassification adjustments related to defined benefit plans, net of tax
 
$
(237
)
$
(287
)
 
$
(703
)
$
(858
)
Total reclassifications
 
$
(535
)
$
636

 
$
(1,562
)
$
3,279



33



Balances by classification included within AOCI, net of tax on the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands):
 
Derivatives Designated as Cash Flow Hedges
 
 
 
Interest Rate Swaps
Commodity Derivatives
Employee Benefit Plans
Total
As of December 31, 2016
$
(18,109
)
$
(233
)
$
(16,541
)
$
(34,883
)
Other comprehensive income (loss)
 
 
 
 
before reclassifications

755


755

Amounts reclassified from AOCI
1,449

(590
)
703

1,562

Ending Balance September 30, 2017
$
(16,660
)
$
(68
)
$
(15,838
)
$
(32,566
)
 
 
 
 
 
 
 
 
 
 
 
Derivatives Designated as Cash Flow Hedges
 
 
 
Interest Rate Swaps
Commodity Derivatives
Employee Benefit Plans
Total
Balance as of December 31, 2015
$
(341
)
$
7,066

$
(15,780
)
$
(9,055
)
Other comprehensive income (loss)
 
 
 
 
before reclassifications
(20,200
)
(417
)

(20,617
)
Amounts reclassified from AOCI
1,644

(5,781
)
858

(3,279
)
Ending Balance September 30, 2016
$
(18,897
)
$
868

$
(14,922
)
$
(32,951
)


(14)    SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

Nine Months Ended
September 30, 2017
 
September 30, 2016
 
(in thousands)
Non-cash investing and financing activities—
 
 
 
Property, plant and equipment acquired with accrued liabilities
$
35,065

 
$
44,140

Increase (decrease) in capitalized assets associated with asset retirement obligations
$
1,362

 
$
(2,285
)
 
 
 
 
Cash (paid) refunded during the period —
 
 
 
Interest (net of amounts capitalized)
$
(101,840
)
 
$
(82,639
)
Income taxes, net
$
1

 
$
(1,168
)



34



(15)    EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plans

The components of net periodic benefit cost for the Defined Benefit Pension Plans were as follows (in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2017
2016
 
2017
2016
Service cost
$
1,759

$
2,078

 
$
5,276

$
6,234

Interest cost
3,880

3,936

 
11,640

11,808

Expected return on plan assets
(6,130
)
(5,766
)
 
(18,388
)
(17,297
)
Prior service cost
15

15

 
44

45

Net loss (gain)
1,002

1,793

 
3,005

5,379

Net periodic benefit cost
$
526

$
2,056

 
$
1,577

$
6,169



Defined Benefit Postretirement Healthcare Plans

The components of net periodic benefit cost for the Defined Benefit Postretirement Healthcare Plans were as follows (in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2017
2016
 
2017
2016
Service cost
$
575

$
467

 
$
1,725

$
1,401

Interest cost
533

485

 
1,600

1,455

Expected return on plan assets
(79
)
(70
)
 
(237
)
(210
)
Prior service cost (benefit)
(109
)
(107
)
 
(327
)
(321
)
Net loss (gain)
125

84

 
375

252

Net periodic benefit cost
$
1,045

$
859

 
$
3,136

$
2,577


Supplemental Non-qualified Defined Benefit and Defined Contribution Plans

The components of net periodic benefit cost for the Supplemental Non-qualified Defined Benefit and Defined Contribution Plans were as follows (in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2017
2016
 
2017
2016
Service cost
$
612

$
623

 
$
2,048

$
1,530

Interest cost
319

314

 
957

943

Prior service cost

1

 
1

2

Net loss (gain)
251

207

 
751

621

Net periodic benefit cost
$
1,182

$
1,145

 
$
3,757

$
3,096



35



Contributions

Contributions to the Defined Benefit Pension Plan are cash contributions made directly to the Pension Plan Trust account. On July 24, 2017, we made contributions to the Defined Benefit Pension Plan in the amount of approximately $13 million. On September 15, 2017, we made an additional contribution of $15 million to reduce our Pension Benefit Guaranty Corporation premiums and offset the forecasted increase in pension expense due to low bond yields which impact the pension discount rate. Contributions to the Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions made in 2017 and anticipated contributions for 2017 and 2018 are as follows (in thousands):
 
Contributions Made
Contributions Made
Additional Contributions
Contributions
 
Three Months Ended September 30, 2017
Nine Months Ended September 30, 2017
Anticipated for 2017
Anticipated for 2018
Defined Benefit Pension Plan
$
27,700

$
27,700

$

$
12,700

Non-pension Defined Benefit Postretirement Healthcare Plans
$
1,270

$
3,810

$
1,270

$
5,115

Supplemental Non-qualified Defined Benefit and Defined Contribution Plans
$
395

$
1,187

$
396

$
1,682


(16)    COMMITMENTS AND CONTINGENCIES

There have been no significant changes to commitments and contingencies from those previously disclosed in Note 19 of our Notes to the Consolidated Financial Statements in our 2016 Annual Report on Form 10-K.

Dividend Restrictions

Our Revolving Credit Facility and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. As of September 30, 2017, we were in compliance with the debt covenants.

Due to our holding company structure, substantially all of our operating cash flows are provided by dividends paid or distributions made by our subsidiaries. The cash to pay dividends to our stockholders is derived from these cash flows. As a result, certain statutory limitations or regulatory or financing agreements could affect the levels of distributions allowed to be made by our subsidiaries.

Our utilities are generally limited to the amount of dividends allowed to be paid to us as a utility holding company under the Federal Power Act and settlement agreements with state regulatory jurisdictions and financing agreements. As of September 30, 2017, the restricted net assets at our Electric Utilities and Gas Utilities were approximately $257 million.

(17)    IMPAIRMENT OF ASSETS

Long-lived Assets

Our Oil and Gas segment accounts for oil and gas activities under the full cost method of accounting. Under the full cost method, all productive and non-productive costs related to acquisition, exploration, development, abandonment and reclamation activities are capitalized. These 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. Any costs in excess of the ceiling are written off as a non-cash charge.

There were no impairments for the nine months ended September 30, 2017. In determining the ceiling value of our assets under the full cost accounting rules of the SEC, we utilized the average of the quoted prices from the first day of each month from the previous 12 months. At September 30, 2017, the average NYMEX natural gas price was $3.00 per Mcf, adjusted to $2.66 per Mcf at the wellhead; the average NYMEX crude oil price was $49.81 per barrel, adjusted to $45.58 per barrel at the wellhead. At September 30, 2016, the average NYMEX natural gas price was $2.28 per Mcf, adjusted to $1.03 per Mcf at the wellhead; the average NYMEX crude oil price was $41.68 per barrel, adjusted to $35.88 per barrel at the wellhead. During the three and nine months ended September 30, 2016, we recorded pre-tax non-cash impairments of oil and gas assets included in our Oil and Gas segment of $12 million and $38 million, respectively.


36



During the second quarter of 2016, certain non-core assets were identified that were not suitable for inclusion in a possible Cost of Service Gas program. We assessed these assets for impairment in accordance with ASC 360. We valued the assets applying a market method approach utilizing assumptions consistent with similar known and measurable transactions and determined that the carrying amount exceeded the fair value. As a result, we recorded a pre-tax impairment of depreciable properties at June 30, 2016 of $14 million, in addition to the impairments noted above.

(18)    INCOME TAXES

The effective tax rate differs from the federal statutory rate as follows:
 
Three Months Ended September 30,
Tax (benefit) expense
2017
2016
Federal statutory rate
35.0
 %
35.0
 %
State income tax (net of federal tax effect) (a)
(1.0
)
(4.0
)
Percentage depletion in excess of cost
(1.1
)
(2.3
)
Accounting for uncertain tax positions adjustment
(0.9
)
(2.4
)
Noncontrolling interest (b)
(3.0
)
(3.7
)
Tax credits (c)
(1.5
)

Effective tax rate adjustment (d)
3.9

7.2

Flow-through adjustments 
(1.7
)
(2.2
)
AFUDC equity
(0.4
)
(0.6
)
Other tax differences
1.1

0.1

 
30.4
 %
27.1
 %
__________
(a)
In the three months ending September 30, 2017 and 2016, the state income tax benefit is primarily attributable to favorable flow-through adjustments and a pretax net loss at state tax accruing companies. Under flow-through accounting the income tax effects of certain tax items are reflected in our cost of service for the customer in the year in which the tax benefits are realized and result in lower utility rates.
(b)
The adjustment reflects the noncontrolling interest attributable to the sale of 49.9% of the membership interests of Colorado IPP in April 2016.
(c)
The increase in tax credits is due to the production tax credits for the Peak View wind farm and marginal gas well tax credit for the oil and gas segment.
(d)
Adjustment to reflect the projected annual effective tax rate, pursuant to ASC 740-270.





37



 
 
 
 
Nine Months Ended September 30,
Tax (benefit) expense
2017
2016
Federal statutory rate
35.0
 %
35.0
 %
State income tax (net of federal tax effect) (a)
0.5

1.7

Percentage depletion in excess of cost (b)
(0.7
)
(9.7
)
Accounting for uncertain tax positions adjustment (c)
(0.2
)
(7.7
)
Noncontrolling interest (d)
(1.9
)
(2.5
)
IRC 172(f) carryback claim (e)
(1.0
)

Tax credits (f)
(1.7
)

Effective tax rate adjustment (g)
0.3

0.1

Flow-through adjustments (h)
(1.2
)
(1.9
)
Transaction costs

1.4

Other tax differences
0.5

(0.9
)
 
29.6
 %
15.5
 %
__________
(a)
The lower state income tax expense in 2017 is lower primarily attributable to favorable flow-through adjustments. Under flow-through accounting the income tax effects of certain tax items are reflected in our cost of service for the customer in the year in which the tax benefits are realized and result in lower utility rates.
(b)
The tax benefit for the nine months ended September 30, 2016 relates to additional percentage depletion deductions that are being claimed with respect to the oil and gas properties involving prior tax years. Such deductions are primarily the result of a change in the application of the maximum daily limitation of 1,000 barrels of oil equivalent as allowed under the Internal Revenue Code.
(c)
The tax benefit for the nine months ended September 30, 2016 relates to the release of after-tax interest expense that was previously accrued with respect to the liability for uncertain tax positions involving the like-kind exchange transaction effectuated in connection with the IPP Transaction and Aquila Transaction that occurred in 2008. In addition, the tax benefit includes the release of reserves involving research and development credits and deductions. Both adjustments are the result of a re-measurement of the liability for uncertain tax positions predicated on an agreement reached with IRS Appeals in early 2016.
(d)
Black Hills Colorado IPP went from a single member LLC, wholly-owned by Black Hills Electric Generation, to a partnership as a result of the sale of 49.9% of its membership interest in April 2016. The effective tax rate reflects the income attributable to the noncontrolling interest for which a tax provision is not recorded.
(e)
In Q1 2017, the Company filed amended income tax returns for the years 2006 through 2008 to carryback specified liability losses in accordance with IRC172(f). As a result of filing the amended returns, the Company's accrued tax liability interest decreased, certain valuation allowances increased and the previously recorded domestic production activities deduction decreased.
(f)
The tax credits for the nine months ended September 30, 2017 are the result of Colorado Electric placing the Peak View Wind Project into service in November 2016.   The Peak View Wind Project began generating production tax credits during the fourth quarter of 2016. 
(g)
Adjustment to reflect our 2017 and 2016 annual projected effective tax rate, pursuant to ASC 740-270.
(h)
The flow-through adjustments related primarily to an accounting method change for tax purposes that allows us to take a current tax deduction for repair costs that continue to be capitalized for book purposes. In addition, flow-through adjustments were recorded related to an accounting method change for tax purposes that allows us to take a current tax deduction for certain indirect costs that continue to be capitalized for book purposes. We recorded a deferred income tax liability in recognition of the temporary difference created between book and tax treatment and flowed the tax benefit through to tax expense. A regulatory asset was established to reflect the recovery of future increases in taxes payable from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record tax benefits consistent with the flow-through method.

In the first quarter of 2016, we reached an agreement in principle with IRS Appeals in regards to the like-kind exchange transaction associated with the gain deferred from the tax treatment related to the 2008 IPP Transaction and the Aquila Transaction.  An agreement in principle was also reached with respect to research and development credits and deductions.  Both issues were the subject of an IRS Appeals process involving the 2007 to 2009 tax years. We reversed approximately $35 million of the liability for unrecognized tax benefits, including interest, during the first quarter of 2016.  The vast majority of such reversal was to restore accumulated deferred income taxes. We reversed accrued after-tax interest expense and tax credits of approximately $5.1 million associated with these liabilities in the first quarter of 2016. The cash taxes due as a result of the agreement in principle with IRS Appeals is estimated to be $8.0 million excluding interest.


38



(19)    ACCRUED LIABILITIES

The following amounts by major classification are included in Accrued liabilities in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:

 
September 30, 2017
December 31, 2016
September 30, 2016
Accrued employee compensation, benefits and withholdings
$
54,134

$
56,926

$
57,203

Accrued property taxes
39,564

40,004

37,156

Customer deposits and prepayments
45,711

51,628

51,137

Accrued interest and contract adjustment payments
30,977

45,503

42,612

CIAC current portion
1,575


5,465

Other (none of which is individually significant)
41,610

49,973

34,949

Total accrued liabilities
$
213,571

$
244,034

$
228,522



(20)    SUBSEQUENT EVENTS

Divestiture of Oil and Gas Business

On November 1, 2017, the BHC Board of Directors approved a complete divestiture of our Oil and Gas segment. We have initiated the process of divesting all Oil and Gas segment assets in order to fully exit the oil and gas business. We anticipate selling or otherwise disposing of all remaining oil and gas properties and assets by year-end 2018 and have retained advisors to accelerate the marketing and sales process. The Company’s Condensed Consolidated Financial Statements and accompanying Notes as of and for the three and nine months ended September 30, 2017 include the Oil and Gas segment’s assets and liabilities, results of operations and cash flows within continuing operations, as we did not meet the criteria for classifying assets as held for sale and presenting the segment’s activities as discontinued operations. Effective in the fourth quarter of 2017, our Oil and Gas segment assets and liabilities will be classified as held for sale, and the Oil and Gas results of operations and cash flows will be presented as discontinued operations. When these assets are classified as held for sale, they will be reviewed for impairment which could result in further impairment charges in the future.

Revenue and net loss for our Oil and Gas segment for the three and nine months ended September 30, 2017 and 2016 were as follows:
 
Three Months Ended
 
Nine Months Ended
(in thousands)
September 30, 2017
September 30, 2016
 
September 30, 2017
September 30, 2016
Revenue
$
6,527

$
9,639

 
$
19,151

$
25,660

Net (loss) available for common stock
$
(2,712
)
$
(8,828
)
 
$
(7,609
)
$
(35,277
)



39



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

We are a customer-focused, growth-oriented utility company operating in the United States. We report our operations and results in the following financial segments:

Electric Utilities: Our Electric Utilities segment generates, transmits and distributes electricity to approximately 208,500 customers in South Dakota, Wyoming, Colorado and Montana. Our electric generating facilities and power purchase agreements provide for the supply of electricity principally to our own distribution systems. Additionally, we sell excess power to other utilities and marketing companies, including our affiliates.

Gas Utilities: Our Gas Utilities conduct natural gas utility operations through our Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming subsidiaries. Our Gas Utilities distribute and transport natural gas through our pipeline network to approximately 1,030,800 natural gas customers. Additionally, we sell temporarily-available, contractual pipeline capacity and gas commodities to other utilities and marketing companies, including our affiliates.

We also provide non-regulated services through Black Hills Energy Services. Black Hills Energy Services provides approximately 55,000 retail distribution customers in Nebraska and Wyoming with unbundled natural gas commodity offerings under the regulatory-approved Choice Gas Program. We also sell, install and service air, heating and water-heating equipment, and provide associated repair service and protection plans under various trade names. Service Guard and CAPP primarily provide appliance repair services to approximately 61,000 and 33,000 residential customers, respectively, through Company technicians and third-party service providers, typically through on-going monthly service agreements. Tech Services primarily serves gas transportation customers throughout our service territory by constructing and maintaining customer-owned gas infrastructure facilities, typically through one-time contracts.

Power Generation: Our Power Generation segment produces electric power from its generating plants and sells the electric capacity and energy principally to our utilities under long-term contracts.

Mining: Our Mining segment produces coal at our coal mine near Gillette, Wyoming and sells the coal primarily to on-site, mine-mouth power generation facilities.

Oil and Gas: Our Oil and Gas segment engages in the production of crude oil and natural gas, primarily in the Rocky Mountain region. In the fourth quarter of 2017, we initiated the process of divesting of all remaining Oil and Gas segment assets in order to fully exit the oil and gas business. We anticipate the divestiture process will be complete by year-end 2018. The Company’s Condensed Consolidated Financial Statements and accompanying Notes as of and for the three and nine months ended September 30, 2017 include the Oil and Gas segment’s assets and liabilities, results of operations and cash flows within continuing operations, as we did not meet the criteria for classifying assets as held for sale and presenting the segment’s activities as discontinued operations during the quarter. See Note 20 of the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q for more information.

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 our electric utilities is June through August while the normal peak usage season for our 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, 2017 and 2016, and our financial condition as of September 30, 2017, December 31, 2016 and September 30, 2016, are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period or for the entire year.

See Forward-Looking Information in the Liquidity and Capital Resources section of this Item 2, beginning on Page 73.

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


40



Results of Operations

Executive Summary, Significant Events and Overview

Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016. Net income available for common stock for the three months ended September 30, 2017 was $28 million, or $0.50 per share, compared to Net income available for common stock of $14 million, or $0.26 per share, reported for the same period in 2016. The Net income available for common stock for the three months ended September 30, 2017 increased over the same period in the prior year primarily due to a decrease in after-tax impairment charges on our oil and gas properties, lower after-tax corporate expenses, and higher earnings at our Electric Utilities. These are partially offset by lower earnings at our Gas Utilities. The variance to the prior year included the following:

A decrease in non-cash after-tax impairment charges of approximately $7.9 million on our oil and gas properties;
Corporate expenses decreased primarily due to a reduction of $3.8 million of after-tax acquisition and transition costs;
Electric Utilities’ earnings increased $3.1 million driven primarily by returns on prior year generation investments; and
Gas Utilities’ earnings decreased $1.4 million primarily due to the impact of cooler summer temperatures and higher precipitation on summer irrigation load delivered to agricultural customers.

Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. Net income available for common stock for the nine months ended September 30, 2017 was $126 million, or $2.29 per share, compared to Net income available for common stock of $55 million, or $1.04 per share, reported for the same period in 2016. The Net income available for common stock for the nine months ended September 30, 2017 increased over the same period in the prior year primarily due to higher earnings at our Gas Utilities, Electric Utilities and Mining segments, lower corporate expenses, and a decrease in impairment charges on our oil and gas properties, partially offset by lower earnings at our Power Generation segment and by tax benefits realized during the same period in the prior year. The variance to the prior year included the following:

Earnings at our Oil and Gas segment increased $28 million primarily due to prior year non-cash after-tax impairments on our oil and gas properties of approximately $33 million, partially offset by a prior year $5.8 million tax benefit recognized from additional percentage depletion deductions claimed with respect to our oil and gas properties;
Corporate expenses decreased $27 million compared to the same period in the prior year driven primarily by a $23 million reduction of after-tax acquisition and transition costs;
Gas Utilities’ earnings increased $11 million with a full nine months of earnings from our acquired SourceGas utilities compared to approximately 7.5 months in the same period of the prior year;
Electric Utilities’ earnings increased $5.8 million driven primarily by returns on prior year generation investments;
Earnings at our Mining segment increased $2.1 million due to an increase in tons sold as a result of an extended outage in the prior year; and
Earnings at our Power Generation segment decreased $1.9 million primarily due to an increase in net income attributable to noncontrolling interests, reflecting a full nine months in 2017 compared to approximately 5.5 months in the same period of the prior year.





41



The following table summarizes select financial results by operating segment and details significant items (in thousands):
 
Three Months Ended September 30,
Nine Months Ended September 30,
 
2017
2016
Variance
2017
2016
Variance
Revenue
 
 
 
 
 
 
Revenue
$
373,412

$
365,742

$
7,670

$
1,338,724

$
1,205,305

$
133,419

Inter-company eliminations
(31,274
)
(31,956
)
682

(94,605
)
(96,119
)
1,514

 
$
342,138

$
333,786

$
8,352

$
1,244,119

$
1,109,186

$
134,933

 
 
 
 
 
 
 
Net income (loss) available for common stock
 
 
 
 
 
 
Electric Utilities
$
27,324

$
24,181

$
3,143

$
68,386

$
62,625

$
5,761

Gas Utilities
(4,329
)
(2,939
)
(1,390
)
41,409

29,975

11,434

Power Generation (a)
6,155

5,642

513

18,017

19,907

(1,890
)
Mining
3,477

3,307

170

9,048

6,969

2,079

Oil and Gas (b) (c)
(2,712
)
(8,828
)
6,116

(7,609
)
(35,277
)
27,668

 
29,915

21,363

8,552

129,251

84,199

45,052

 
 
 
 
 
 
 
Corporate activities and eliminations (d) (e)
(2,252
)
(7,232
)
4,980

(2,870
)
(29,397
)
26,527

 
 
 
 
 
 
 
Net income available for common stock
$
27,663

$
14,131

$
13,532

$
126,381

$
54,802

$
71,579

__________
(a)
Net income available for common stock for the three and nine months ended September 30, 2017 is net of net income attributable to noncontrolling interest of $3.9 million and $11 million, respectively, and $3.8 million and $6.4 million for the three and nine months ended September 30, 2016, respectively.
(b)
Net (loss) available for common stock for the three and nine months ended September 30, 2016 included non-cash after-tax impairments of our oil and gas properties of $7.9 million and $33 million, respectively. See Note 17 of the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.
(c)
Net (loss) available for common stock for the nine months ended September 30, 2016 included a tax benefit of approximately $5.8 million recognized from additional percentage depletion deductions that are being claimed with respect to our oil and gas properties involving prior tax years.
(d)
Net (loss) available for common stock for the three and nine months ended September 30, 2017 included incremental, non-recurring acquisition costs, after-tax of $0.2 million and $1.5 million, respectively, as compared to $4.0 million and $24 million for the same periods in the prior year. The three and nine months ended September 30, 2016 also included after-tax internal labor costs attributable to the acquisition of $1.7 million and $7.4 million, respectively.
(e)
Net (loss) available for common stock for the nine months ended September 30, 2017 included a net tax benefit of approximately $1.4 million from a carryback claim for specified liability losses involving prior tax years. Net (loss) available for common stock for the nine months ended September 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 of the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.


42



Overview of Business Segments and Corporate Activity

Electric Utilities Segment

Electric Utilities experienced milder summer weather during the three and nine months ended September 30, 2017 compared to the three and nine months ended September 30, 2016. Cooling degree days for the three and nine months ended September 30, 2017 were both 15% higher than normal, compared to 15% and 26% higher than normal for the same periods in 2016. Compared to the same periods in the prior year, cooling degree days were 5% and 14% lower, respectively. Heating degree days for the three and nine months ended September 30, 2017 were 8% and 11% lower than normal, respectively, compared to 34% and 13% lower than normal for the same periods in 2016.

On January 17, 2017, Colorado Electric received approval from the CPUC on a settlement agreement for its electric resource plan which provides for the addition of 60 megawatts of renewable energy to be in service by 2019. The resource plan was filed June 3, 2016, to meet requirements under the Colorado Renewable Energy Standard. In the second quarter of 2017, Colorado Electric issued a request for proposals to construct new generation and plans to present the results to the CPUC by year-end.

On January 9, 2017, we filed an application with the CPUC for rehearing, reargument or reconsideration of the Commission’s December 19, 2016 decision to increase annual revenue by $1.2 million. This application was denied by the CPUC on June 9, 2017. We subsequently filed an appeal of this decision with Denver County District Court on July 10, 2017. The briefing schedule runs through November 2017. The timing of a ruling is uncertain.

Construction was completed on the 144 mile transmission line connecting the Teckla Substation in northeast Wyoming to the Lange Substation near Rapid City, South Dakota. The first segment of this project connecting Teckla to Osage, WY was placed in service on August 31, 2016. The second segment connecting Osage to Lange was placed in service on May 30, 2017.

On July 19, 2017, Wyoming Electric set a new summer load peak of 249 MW, exceeding the previous summer peak of 236 MW set in July 2016.

Gas Utilities Segment

On October 3, 2017, RMNG filed a rate review application with the CPUC requesting an annual increase in revenue of $2.2 million and an extension of SSIR to recover costs from 2018 through 2022. The annual increase is based on a return on equity of 12.25% and a capital structure of 53.37% debt and 46.63% equity. This rate review was driven by the impending expiration of the SSIR on May 31, 2018; this application requests a continuation of the SSIR through 2022.

Gas Utilities experienced milder weather during the non-peak three months ended September 30, 2017 compared to the three months ended September 30, 2016. Heating degree days for the three months ended September 30, 2017 were 22% lower than normal compared to 2% lower than normal for the same period in 2016. For the nine months ended September 30, 2017, Gas Utilities experienced slightly colder weather compared to the nine months ended September 30, 2016. Heating degree days were 12% lower than normal for the nine months ended September 30, 2017 compared to 20% lower than normal for the same period in 2016.

The Gas Utilities also experienced cooler summer temperatures and higher precipitation levels during the three months ended September 30, 2017 than the same period in 2016, which reduced the irrigation load delivered to agricultural customers, primarily in our Nebraska service territory.

Oil and Gas Segment

On November 1, 2017, our board of directors authorized the sale of all remaining oil and gas assets and the exit of the business. The segment will be reported as discontinued operations beginning with fourth quarter results. The company has retained advisors to support its ongoing property sales efforts and plans to divest all remaining properties by year-end 2018.

We recently signed agreements to sell our San Juan Basin assets in New Mexico and certain Powder River Basin assets in Wyoming for a combined $28 million. The San Juan Basin transaction is subject to final approval from the

43



U.S. Bureau of Indian Affairs and U.S. Bureau of Land Management. Both transactions are expected to close by year-end.

Oil and Gas production volumes decreased 9% and 17% for the three and nine months ended September 30, 2017 compared to the same periods in 2016, respectively. The decrease in production was due to the 2016 sales of non-core properties, and limiting natural gas production to meet minimum daily quantity contractual gas processing commitments in the Piceance. Crude oil production also decreased due to non-core property sales in the fourth quarter of 2016. The average hedged price received for natural gas decreased 15% for the three months ended September 30, 2017 and increased 21% for the nine months ended September 30, 2017 compared to the same periods in 2016, respectively. The average hedged price received for oil decreased 11% and 14% for the three and nine months ended September 30, 2017 compared to the same periods in 2016, respectively.

Corporate Activities

On August 4, 2017, we renewed the ATM equity offering program initiated in March 2016 which reset the size of the ATM equity offering program to an aggregate value of up to $300 million. The renewed program, which allows us to sell shares of our common stock, is the same as the prior year program with the exception that the aggregate value increased $100 million.

We utilized favorable short-term borrowings from our CP program to pay down $100 million on a Corporate term loan due in 2019 with principal payments of $50 million paid in May and an additional $50 million paid in July.

On July 21, 2017, S&P affirmed Black Hills’ credit rating at BBB rating and maintained a Stable outlook.

On October 4, 2017, Fitch affirmed Black Hills’ credit rating at BBB+ rating and changed its outlook from Negative to Stable, citing successful integration of SourceGas, a low business risk profile focused on utility operations and expected improvement of credit metrics.

Tax Matters - Potential Corporate Tax Reform

President Trump and Congressional Republicans have stated that one of their top priorities is enactment of comprehensive tax reform.  On November 2, 2017, the House Ways and Means Committee released its tax reform bill. Significant uncertainty exists as to the ultimate legislation that will be enacted into law.  We are evaluating the proposed legislation; any impact on our future results of operations, financial position and cash flows as a result of the potential changes cannot yet be determined and such changes could be material.

Operating Results

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

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

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

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


44



Electric Utilities
 
Three Months Ended September 30,
Nine Months Ended September 30,
 
2017
2016
Variance
2017
2016
Variance
 
(in thousands)
Revenue
$
183,571

$
174,501

$
9,070

$
528,048

$
503,258

$
24,790

 
 
 
 
 
 
 
Total fuel and purchased power
68,733

66,953

1,780

199,398

194,477

4,921

 
 
 
 
 
 
 
Gross margin
114,838

107,548

7,290

328,650

308,781

19,869

 
 
 
 
 
 
 
Operations and maintenance
40,204

38,108

2,096

125,302

116,312

8,990

Depreciation and amortization
23,446

21,063

2,383

69,427

62,794

6,633

Total operating expenses
63,650

59,171

4,479

194,729

179,106

15,623

 
 
 
 
 
 
 
Operating income
51,188

48,377

2,811

133,921

129,675

4,246

 
 
 
 
 
 
 
Interest expense, net
(12,744
)
(12,046
)
(698
)
(39,049
)
(36,676
)
(2,373
)
Other income (expense), net
649

1,335

(686
)
1,579

2,828

(1,249
)
Income tax benefit (expense)
(11,769
)
(13,485
)
1,716

(28,065
)
(33,202
)
5,137

Net income
$
27,324

$
24,181

$
3,143

$
68,386

$
62,625

$
5,761


Results of Operations for the Electric Utilities for the Three Months Ended September 30, 2017 Compared to the Three Months Ended September 30, 2016: Net income available for common stock for the Electric Utilities was $27 million for the three months ended September 30, 2017, compared to Net income available for common stock of $24 million for the three months ended September 30, 2016, as a result of:

Gross margin increased due primarily to a $3.3 million increase in rider revenues primarily related to transmission investment recovery and a $3.0 million return on investment from the Peak View Wind Project.

Operations and maintenance increased primarily due to $1.4 million of higher generation outage and major maintenance expenses for turbine, generator, pulverizer and boiler work as compared to the prior year. Employee costs increased $0.9 million as a result of prior year integration activities and transition expenses charged to the Corporate segment. In addition, operating expenses increased $0.4 million from the addition of the Peak View Wind Project and the 40-megawatt gas turbine at the Pueblo Airport Generating Station.

Depreciation and amortization increased primarily due to a higher asset base driven by the addition of the Peak View Wind Project and the 40-megawatt gas turbine at the Pueblo Airport Generating Station.

Interest expense, net increased primarily due to higher intercompany debt resulting from additional investments as compared to the prior year.

Other income (expense), net decreased due to reduced AFUDC with lower current year capital spend.

Income tax benefit (expense): The effective tax rate was lower than the prior year due primarily to wind production tax credits related to the Peak View Wind Project.


45





Results of Operations for the Electric Utilities for the Nine Months Ended September 30, 2017 Compared to the Nine Months Ended September 30, 2016: Net income available for common stock for the Electric Utilities was $68 million for the nine months ended September 30, 2017, compared to Net income available for common stock of $63 million for the nine months ended September 30, 2016, as a result of:

Gross margin increased over the prior year reflecting a $7.5 million return on investment from the Peak View Wind Project, a $6.4 million increase in rider revenues primarily related to transmission investment recovery and a $3.3 million increase in commercial and industrial margins driven by increased demand largely associated with data centers in Cheyenne, Wyoming. A variety of smaller items contribute to the remainder of the increase.

Operations and maintenance increased primarily due to $4.2 million of higher employee costs as a result of prior year integration activities and transition expenses charged to the Corporate segment, $2.0 million increase in generation outage and major maintenance expenses with increased scope of work, $1.9 million of higher property taxes with an increased asset base, and $1.3 million of higher operating expenses from the Peak View Wind Project and 40-megawatt gas turbine at the Pueblo Airport Generating Station.

Depreciation and amortization increased primarily due to a higher asset base driven by the addition of the Peak View Wind Project and the 40-megawatt gas turbine at the Pueblo Airport Generating Station.

Interest expense, net increased primarily due to higher intercompany debt resulting from additional investments as compared to prior year.

Other income (expense), net decreased due to reduced AFUDC with lower current year capital spend.

Income tax benefit (expense): The effective tax rate was lower than the prior year due primarily to wind production tax credits related to the Peak View Wind Project.


46



 
Three Months Ended September 30,
 
Nine Months Ended September 30,
Revenue - Electric (in thousands)
2017
 
2016
 
2017
 
2016
Residential:
 
 
 
 
 
 
 
South Dakota Electric
$
18,020

 
$
17,501

 
$
53,724

 
$
53,057

Wyoming Electric
10,083

 
9,585

 
29,571

 
29,283

Colorado Electric
27,763

 
27,460

 
74,722

 
73,721

Total Residential
55,866

 
54,546

 
158,017

 
156,061

 
 
 
 
 
 
 
 
Commercial:
 
 
 
 
 
 
 
South Dakota Electric
25,459

 
25,714

 
72,608

 
73,026

Wyoming Electric
16,389

 
16,306

 
48,565

 
47,818

Colorado Electric
26,196

 
25,907

 
74,322

 
72,782

Total Commercial
68,044

 
67,927

 
195,495

 
193,626

 
 
 
 
 
 
 
 
Industrial:
 
 
 
 
 
 
 
South Dakota Electric
8,149

 
8,275

 
24,774

 
24,540

Wyoming Electric
12,104

 
11,904

 
37,737

 
32,353

Colorado Electric
10,311

 
9,870

 
29,072

 
28,917

Total Industrial
30,564

 
30,049

 
91,583

 
85,810

 
 
 
 
 
 
 
 
Municipal:
 
 
 
 
 
 
 
South Dakota Electric
1,071

 
1,053

 
2,849

 
2,844

Wyoming Electric
542

 
543

 
1,588

 
1,606

Colorado Electric
3,345

 
3,299

 
9,497

 
8,879

Total Municipal
4,958

 
4,895

 
13,934

 
13,329

 
 
 
 
 
 
 
 
Total Retail Revenue - Electric
159,432

 
157,417

 
459,029

 
448,826

 
 
 
 
 
 
 
 
Contract Wholesale:
 
 
 
 
 
 
 
Total Contract Wholesale - South Dakota Electric (a)
8,048

 
4,596

 
22,593

 
12,717

 
 
 
 
 
 
 
 
Off-system Wholesale:
 
 
 
 
 
 
 
South Dakota Electric
4,787

 
3,984

 
11,044

 
11,304

Wyoming Electric
758

 
924

 
3,505

 
3,777

Colorado Electric
387

 
522

 
561

 
1,229

Total Off-system Wholesale
5,932

 
5,430

 
15,110

 
16,310

 
 
 
 
 
 
 
 
Other Revenue:
 
 
 
 
 
 
 
South Dakota Electric
8,404

 
5,605

 
26,193

 
19,901

Wyoming Electric
794

 
325

 
2,333

 
1,435

Colorado Electric
961

 
1,128

 
2,790

 
4,069

Total Other Revenue
10,159

 
7,058

 
31,316

 
25,405

 
 
 
 
 
 
 
 
Total Revenue - Electric
$
183,571

 
$
174,501

 
$
528,048

 
$
503,258

__________
(a)
Increase for the three and nine months ended September 30, 2017 was primarily due to a new 50 MW power sales agreement effective January 1, 2017.

47




 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
Quantities Generated and Purchased (in MWh)
2017
 
2016
 
2017
 
2016
Generated —
 
 
 
 
 
 
 
Coal-fired:
 
 
 
 
 
 
 
South Dakota Electric
423,766

 
401,231

 
1,101,291

 
1,054,264

Wyoming Electric (d)
201,824

 
188,739

 
562,644

 
548,513

Total Coal-fired
625,590

 
589,970

 
1,663,935

 
1,602,777

 
 
 
 
 
 
 
 
Natural Gas and Oil:
 
 
 
 
 
 
 
South Dakota Electric (a)
54,466

 
41,654

 
75,840

 
96,649

Wyoming Electric (a)
25,567

 
23,874

 
39,136

 
58,944

Colorado Electric
76,432

 
64,507

 
134,089

 
128,397

Total Natural Gas and Oil
156,465

 
130,035

 
249,065

 
283,990

 
 
 
 
 
 
 
 
Wind:
 
 
 
 
 
 
 
Colorado Electric (b)
38,773

 
10,676

 
167,429

 
34,325

Total Wind
38,773

 
10,676

 
167,429

 
34,325

 
 
 
 
 
 
 
 
Total Generated:
 
 
 
 
 
 
 
South Dakota Electric
478,232

 
442,885

 
1,177,131

 
1,150,913

Wyoming Electric (a)
227,391

 
212,613

 
601,780

 
607,457

Colorado Electric (b)
115,205

 
75,183

 
301,518

 
162,722

Total Generated
820,828

 
730,681

 
2,080,429

 
1,921,092

 
 
 
 
 
 
 
 
Purchased —
 
 
 
 
 
 
 
South Dakota Electric (c)
357,053

 
247,097

 
1,222,864

 
902,166

Wyoming Electric (d)
207,554

 
215,257

 
696,229

 
624,137

Colorado Electric (b)
476,084

 
527,947

 
1,273,125

 
1,473,195

Total Purchased
1,040,691

 
990,301

 
3,192,218

 
2,999,498

 
 
 
 
 
 
 
 
Total Generated and Purchased:
 
 
 
 
 
 
 
South Dakota Electric (c)
835,285

 
689,982

 
2,399,995

 
2,053,079

Wyoming Electric
434,945

 
427,870

 
1,298,009

 
1,231,594

Colorado Electric
591,289

 
603,130

 
1,574,643

 
1,635,917

Total Generated and Purchased
1,861,519

 
1,720,982

 
5,272,647

 
4,920,590

__________
(a)
Variances for the three and nine months ended September 30, 2017 compared to the same periods in the prior year are driven primarily by the ability to purchase excess generation in the open market at a lower or higher cost than to generate.
(b)
Increase in generation in 2017 is due to the addition of the Peak View Wind Project in November 2016. This generation replaced resources provided by PPAs in 2016, reducing the quantities purchased.
(c)
Increase in 2017 is primarily driven by resource needs from a new 50 MW power sales agreement effective January 1, 2017.
(d)
Year over year increase for nine months ended September 30, 2017 is primarily driven by new load supporting data centers in Cheyenne, Wyoming.

48




 
Three Months Ended September 30,
 
Nine Months Ended September 30,
Quantity Sold (in MWh)
2017
2016
 
2017
2016
Residential:
 
 
 
 
 
South Dakota Electric
129,616

124,012

 
386,709

381,616

Wyoming Electric
65,723

63,505

 
190,087

191,405

Colorado Electric
174,127

176,900

 
461,641

470,246

Total Residential
369,466

364,417

 
1,038,437

1,043,267

 
 
 
 
 
 
Commercial:
 
 
 
 
 
South Dakota Electric
212,773

213,276

 
582,899

592,371

Wyoming Electric
137,169

137,534

 
398,178

398,414

Colorado Electric
208,033

211,716

 
566,177

572,062

Total Commercial
557,975

562,526

 
1,547,254

1,562,847

 
 
 
 
 
 
Industrial:
 
 
 
 
 
South Dakota Electric
109,745

110,220

 
323,038

320,861

Wyoming Electric  (a)
182,844

175,188

 
545,640

468,262

Colorado Electric
114,357

116,073

 
323,638

329,016

Total Industrial
406,946

401,481

 
1,192,316

1,118,139

 
 
 
 
 
 
Municipal:
 
 
 
 
 
South Dakota Electric
10,156

9,927

 
25,865

25,855

Wyoming Electric
2,154

2,201

 
6,643

6,848

Colorado Electric
35,079

34,507

 
92,557

91,116

Total Municipal
47,389

46,635

 
125,065

123,819

 
 
 
 
 
 
Total Retail Quantity Sold
1,381,776

1,375,059

 
3,903,072

3,848,072

 
 
 
 
 
 
Contract Wholesale:
 
 
 
 
 
Total Contract Wholesale-South Dakota Electric (b)
185,723

62,547

 
537,720

182,087

 
 
 
 
 
 
Off-system Wholesale:
 
 
 
 
 
South Dakota Electric (c)
130,825

128,415

 
388,287

438,852

Wyoming Electric
17,981

18,788

 
72,517

77,534

Colorado Electric (c)
10,619

17,949

 
16,479

53,644

Total Off-system Wholesale
159,425

165,152

 
477,283

570,030

 
 
 
 
 
 
Total Quantity Sold:
 
 
 
 
 
South Dakota Electric
778,838

648,397

 
2,244,518

1,941,642

Wyoming Electric
405,871

397,216

 
1,213,065

1,142,463

Colorado Electric
542,215

557,145

 
1,460,492

1,516,084

Total Quantity Sold
1,726,924

1,602,758

 
4,918,075

4,600,189

 
 
 
 
 
 
Other Uses, Losses or Generation, net (d):
 
 
 
 
 
South Dakota Electric
56,447

41,585

 
155,477

111,437

Wyoming Electric
29,074

30,654

 
84,944

89,131

Colorado Electric
49,074

45,985

 
114,151

119,833

Total Other Uses, Losses and Generation, net
134,595

118,224

 
354,572

320,401

 
 
 
 
 
 
Total Energy
1,861,519

1,720,982

 
5,272,647

4,920,590

__________
(a) Year over year increases are driven by new load supporting data centers in Cheyenne, Wyoming.
(b)
Increase for the three and nine months ended September 30, 2017 was primarily due to a new 50 MW power sales agreement effective January 1, 2017.
(c)
Decrease in 2017 was primarily driven by commodity prices that impacted power marketing sales.
(d)
Includes company uses, line losses, and excess exchange production.

49




 
Three Months Ended September 30,
Degree Days
 
 
2017
 
 
 
2016
 
Actual
 
Variance from
30-Year Average
 
Actual Variance to Prior Year
 
Actual
 
Variance from
30-Year Average
Heating Degree Days:
 
 
 
 
 
 
 
 
 
South Dakota Electric
202

 
(10
)%
 
25%
 
161

 
(23
)%
Wyoming Electric
292

 
(4
)%
 
39%
 
210

 
(19
)%
Colorado Electric
87

 
(11
)%
 
335%
 
20

 
(77
)%
Combined (a)
168

 
(8
)%
 
57%
 
107

 
(34
)%
 
 
 
 
 
 
 
 
 
 
Cooling Degree Days:
 
 
 
 
 
 
 
 
 
South Dakota Electric
595

 
11
 %
 
29%
 
460

 
(18
)%
Wyoming Electric
388

 
30
 %
 
8%
 
358

 
19
 %
Colorado Electric
784

 
14
 %
 
(19)%
 
968

 
33
 %
Combined (a)
640

 
15
 %
 
(5)%
 
673

 
15
 %


 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30,
Degree Days
2017
 
 
 
2016
 
Actual
 
Variance from
30-Year Average
 
Actual Variance to Prior Year
 
Actual
 
Variance from
30-Year Average
Heating Degree Days:
 
 
 
 
 
 
 
 
 
South Dakota Electric
4,242

 
(5
)%
 
10%
 
3,844

 
(13
)%
Wyoming Electric
4,186

 
(11
)%
 
2%
 
4,120

 
(12
)%
Colorado Electric
2,773

 
(17
)%
 
(2)%
 
2,821

 
(15
)%
Combined (a)
3,559

 
(11
)%
 
4%
 
3,430

 
(13
)%
 
 
 
 
 
 
 
 
 
 
Cooling Degree Days:
 
 
 
 
 
 
 
 
 
South Dakota Electric
709

 
12
 %
 
10%
 
646

 
(3
)%
Wyoming Electric
429

 
23
 %
 
(7)%
 
460

 
31
 %
Colorado Electric
1,027

 
15
 %
 
(23)%
 
1,337

 
40
 %
Combined (a)
798

 
15
 %
 
(14)%
 
926

 
26
 %
__________
(a)
Combined actuals are calculated based on the weighted average number of total customers by state.

Electric Utilities Power Plant Availability
Three Months Ended September 30,
Nine Months Ended September 30,
 
2017
2016
2017
 
2016
 
Coal-fired plants (a)
98.3
%
 
94.8
%
 
88.1
%
 
88.0
%
 
Natural gas fired plants and Other plants
94.6
%
 
98.4
%
 
95.8
%
 
97.0
%
 
Wind (b)
91.0
%
 
99.1
%
 
92.0
%
 
99.2
%
 
Total availability
95.5
%
 
97.1
%
 
93.0
%
 
93.7
%
 
 
 
 
 
 
 
 
 
 
Wind capacity factor
23.6
%
 
33.5
%
 
34.3
%
 
36.1
%
 
__________
(a)
Both the nine months ended September 30, 2017 and 2016 included outages. 2017 included planned outages at Neil Simpson II, Wyodak and Wygen II, and 2016 included a planned outage at Wygen III and an extended planned outage at Wyodak.
(b)
2017 is lower than the prior year primarily due to the addition of the Peak View Wind Project for which 2017 is the first year of commercial operation.

50




Gas Utilities
 
Three Months Ended September 30,
Nine Months Ended September 30,
 
2017
2016
Variance
2017
2016
Variance
 
(in thousands)
Revenue:
 
 
 
 
 
 
Natural gas — regulated
$
126,865

$
123,699

$
3,166

$
618,924

$
515,963

$
102,961

Other — non-regulated services
16,029

17,746

(1,717
)
55,327

47,916

7,411

Total revenue
142,894

141,445

1,449

674,251

563,879

110,372

 
 
 
 
 
 
 
Cost of sales
 
 
 
 
 
 
Natural gas — regulated
33,376

29,330

4,046

255,410

202,244

53,166

Other — non-regulated services
11,917

12,400

(483
)
33,615

25,755

7,860

Total cost of sales
45,293

41,730

3,563

289,025

227,999

61,026

 
 
 
 
 
 
 
Gross margin
97,601

99,715

(2,114
)
385,226

335,880

49,346

 
 
 
 
 
 
 
Operations and maintenance
65,390

64,921

469

201,105

179,845

21,260

Depreciation and amortization
20,937

21,193

(256
)
62,658

57,096

5,562

Total operating expenses
86,327

86,114

213

263,763

236,941

26,822

 
 
 
 
 
 
 
Operating income
11,274

13,601

(2,327
)
121,463

98,939

22,524

 
 
 
 
 
 
 
Interest expense, net
(19,527
)
(21,267
)
1,740

(58,919
)
(53,858
)
(5,061
)
Other income (expense), net
(294
)
(418
)
124

(342
)
(28
)
(314
)
Income tax benefit (expense)
4,218

5,128

(910
)
(20,686
)
(15,065
)
(5,621
)
Net income (loss)
(4,329
)
(2,956
)
(1,373
)
41,516

29,988

11,528

Net (income) loss attributable to noncontrolling interest

17

(17
)
(107
)
(13
)
(94
)
Net income (loss) available for common stock
$
(4,329
)
$
(2,939
)
$
(1,390
)
$
41,409

$
29,975

$
11,434



51



Results of Operations for the Gas Utilities for the Three Months Ended September 30, 2017 Compared to the Three Months Ended September 30, 2016: Net loss available for common stock for the Gas Utilities was $(4.3) million for the three months ended September 30, 2017, compared to Net loss available for common stock of $(3.0) million for the three months ended September 30, 2016, as a result of:

Gross margin decreased primarily due to a $3.4 million weather impact from cooler summer temperatures and higher precipitation driving lower irrigation load to agriculture customers in our Nebraska Gas service territory as compared to the same period in the prior year. This is partially offset by gas utilities' customer growth and higher rider revenue.

Operations and maintenance increased primarily due to $1.2 million higher employee related expenses as a result of prior year integration activities and transition expenses charged to the Corporate segment, partially offset by lower pension expenses.

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

Interest expense, net decreased primarily due to the August 2016 refinancing of the debt assumed in the SourceGas Acquisition.

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

Income tax benefit (expense): The 2017 effective tax rate is lower than 2016 due to increased flow-through benefits and no changes to uncertain tax positions as compared to 2016.

Results of Operations for the Gas Utilities for the Nine Months Ended September 30, 2017 Compared to the Nine Months Ended September 30, 2016: Net income available for common stock for the Gas Utilities was $41 million for the nine months ended September 30, 2017, compared to Net income available for common stock of $30 million for the nine months ended September 30, 2016, as a result of:

Gross margin increased primarily due to additional margins of approximately $51 million contributed by the SourceGas utilities in the first quarter of 2017 compared to the first quarter of 2016 which included approximately 1.5 months of SourceGas results. 2017 reflects a full nine months of SourceGas results as compared to approximately 7.5 months in 2016. This is partially offset by lower irrigation loads delivered to agriculture customers primarily in the Nebraska service territory due to cooler summer temperatures and higher precipitation in the third quarter of 2017.

Operations and maintenance increased primarily due to additional operating costs of approximately $19 million for the acquired SourceGas utilities, reflecting a full nine months of results in 2017 as compared to approximately 7.5 months in 2016. In addition, employee related expenses increased $5.2 million for the Black Hills legacy gas utilities as a result of prior year integration activities and transition expenses charged to the Corporate segment. A variety of smaller items contribute to the partially offsetting decrease in operations and maintenance expenses.

Depreciation and amortization increased primarily due to additional depreciation from the acquired SourceGas utilities.

Interest expense, net increased primarily due to additional interest expense from the acquired SourceGas utilities.

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

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


52



 
Three Months Ended September 30,
 
Nine Months Ended September 30,
Revenue (in thousands) (a)
2017
 
2016
 
2017
 
2016
Residential:
 
 
 
 
 
 
 
Arkansas
$
9,085

 
$
8,201

 
$
57,992

 
$
33,778

Colorado
12,911

 
12,144

 
80,351

 
65,285

Nebraska (b)
12,622

 
12,259

 
72,965

 
69,132

Iowa
10,314

 
9,694

 
60,618

 
57,328

Kansas
8,128

 
7,760

 
44,309

 
39,428

Wyoming (b)
4,744

 
4,895

 
28,172

 
23,663

Total Residential
$
57,804

 
$
54,953

 
$
344,407

 
$
288,614

 
 
 
 
 
 
 
 
Commercial:
 
 
 
 
 
 
 
Arkansas
$
5,281

 
$
4,123

 
$
30,465

 
$
16,652

Colorado
4,893

 
4,971

 
29,967

 
23,107

Nebraska
2,994

 
3,123

 
20,567

 
19,462

Iowa
3,425

 
3,144

 
24,522

 
22,617

Kansas
2,672

 
2,298

 
14,695

 
12,558

Wyoming
2,101

 
2,315

 
13,940

 
11,495

Total Commercial
$
21,366

 
$
19,974

 
$
134,156

 
$
105,891

 
 
 
 
 
 
 
 
Industrial:
 
 
 
 
 
 
 
Arkansas
$
1,801

 
$
1,463

 
$
5,382

 
$
3,071

Colorado
906

 
808

 
1,588

 
1,340

Nebraska
158

 
143

 
363

 
330

Iowa
119

 
189

 
1,158

 
1,014

Kansas
5,734

 
5,204

 
7,716

 
7,793

Wyoming
754

 
692

 
2,492

 
2,349

Total Industrial
$
9,472

 
$
8,499

 
$
18,699

 
$
15,897

 
 
 
 
 
 
 
 
Transportation:
 
 
 
 
 
 
 
Arkansas
$
2,335

 
$
1,997

 
$
7,750

 
$
5,730

Colorado
738

 
766

 
2,940

 
2,531

Nebraska (b) (c)
20,343

 
23,222

 
54,202

 
49,147

Iowa
967

 
970

 
3,557

 
3,525

Kansas
1,598

 
1,736

 
4,851

 
5,134

Wyoming (b)
4,387

 
4,245

 
18,849

 
14,382

Total Transportation
$
30,368

 
$
32,936

 
$
92,149

 
$
80,449


53




 
Three Months Ended September 30,
 
Nine Months Ended September 30,
Revenue (in thousands) (continued)
2017
 
2016
 
2017
 
2016
Transmission:
 
 
 
 
 
 
 
Arkansas
$
448

 
$
19

 
$
1,660

 
$
44

Colorado
4,014

 
3,572

 
17,778

 
12,334

Wyoming
1,211

 
1,209

 
3,712

 
3,386

Total Transmission
$
5,673

 
$
4,800

 
$
23,150

 
$
15,764

 
 
 
 
 
 
 
 
Other Sales Revenue:
 
 
 
 
 
 
 
Arkansas
$
218

 
$
398

 
$
880

 
$
1,687

Colorado
208

 
315

 
687

 
770

Nebraska
937

 
912

 
2,724

 
2,587

Iowa
96

 
96

 
357

 
409

Kansas
494

 
582

 
936

 
3,215

Wyoming
229

 
234

 
779

 
680

Total Other Sales Revenue
$
2,182

 
$
2,537

 
$
6,363

 
$
9,348

 
 
 
 
 
 
 
 
Total Regulated Revenue
$
126,865

 
$
123,699

 
$
618,924

 
$
515,963

 
 
 
 
 
 
 
 
Non-regulated Services
16,029

 
17,746

 
55,327

 
47,916

 
 
 
 
 
 
 
 
Total Revenue
$
142,894

 
$
141,445

 
$
674,251

 
$
563,879

__________
(a)
Certain prior year revenue classes have been revised to conform to current year presentation; total revenue did not change.
(b)
Change in prior year due to reclassification of Residential Choice customers from Residential to Transportation class.
(c) Decrease for the three months ended September 30, 2017 is primarily driven by lower irrigation load in 2017 compared to the prior year.
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
Gross Margin (in thousands) (a)
2017
 
2016
 
2017
 
2016
Residential:
 
 
 
 
 
 
 
Arkansas
$
6,934

 
$
6,735

 
$
38,020

 
$
24,116

Colorado
7,533

 
7,235

 
33,784

 
28,531

Nebraska (b)
9,333

 
9,214

 
38,383

 
37,634

Iowa
8,430

 
8,252

 
31,442

 
30,848

Kansas
6,033

 
5,872

 
24,031

 
22,401

Wyoming (b)
3,749

 
3,863

 
16,596

 
15,164

Total Residential
$
42,012

 
$
41,171

 
$
182,256

 
$
158,694

 
 
 
 
 
 
 
 
Commercial:
 
 
 
 
 
 
 
Arkansas
$
2,904

 
$
2,551

 
$
16,053

 
$
9,595

Colorado
2,198

 
2,385

 
10,660

 
8,612

Nebraska
1,606

 
1,652

 
7,952

 
7,865

Iowa
1,930

 
1,894

 
8,504

 
8,351

Kansas
1,371

 
1,289

 
5,846

 
5,300

Wyoming
1,088

 
1,217

 
5,916

 
5,596

Total Commercial
$
11,097

 
$
10,988

 
$
54,931

 
$
45,319


54



 
Three Months Ended September 30,
 
Nine Months Ended September 30,
Gross Margin (in thousands) (continued)
2017
 
2016
 
2017
 
2016
Industrial:
 
 
 
 
 
 
 
Arkansas
$
566

 
$
582

 
$
1,727

 
$
1,268

Colorado
292

 
326

 
513

 
594

Nebraska
57

 
54

 
134

 
149

Iowa
33

 
40

 
169

 
127

Kansas
1,052

 
986

 
1,638

 
1,754

Wyoming
157

 
163

 
484

 
513

Total Industrial
$
2,157

 
$
2,151

 
$
4,665

 
$
4,405

 
 
 
 
 
 
 
 
Transportation:
 
 
 
 
 
 
 
Arkansas
$
2,335

 
$
1,997

 
$
7,750

 
$
5,730

Colorado
738

 
539

 
2,940

 
2,293

Nebraska (b) (c)
20,343

 
23,222

 
54,202

 
49,147

Iowa
967

 
970

 
3,557

 
3,525

Kansas
1,598

 
1,736

 
4,851

 
5,134

Wyoming (b)
4,387

 
4,245

 
18,849

 
14,382

Total Transportation
$
30,368

 
$
32,709

 
$
92,149

 
$
80,211

 
 
 
 
 
 
 
 
Transmission:
 
 
 
 
 
 
 
Arkansas
$
448

 
$
19

 
$
1,660

 
$
44

Colorado
4,014

 
3,572

 
17,778

 
12,334

Wyoming
1,211

 
1,209

 
3,712

 
3,362

Total Transmission
$
5,673

 
$
4,800

 
$
23,150

 
$
15,740

 
 
 
 
 
 
 
 
Other Sales Margins:
 
 
 
 
 
 
 
Arkansas
$
218

 
$
398

 
$
880

 
$
1,688

Colorado
208

 
315

 
687

 
770

Nebraska
937

 
912

 
2,724

 
2,586

Iowa
96

 
96

 
357

 
409

Kansas
494

 
595

 
936

 
3,217

Wyoming
229

 
234

 
779

 
680

Total Other Sales Margins
$
2,182

 
$
2,550

 
$
6,363

 
$
9,350

 
 
 
 
 
 
 
 
Total Regulated Gross Margin
$
93,489

 
$
94,369

 
$
363,514

 
$
313,719

 
 
 
 
 
 
 
 
Non-regulated Services
4,112

 
5,346

 
21,712

 
22,161

 
 
 
 
 
 
 
 
Total Gross Margin
$
97,601

 
$
99,715

 
$
385,226

 
$
335,880

__________
(a)
Certain prior year revenue classes have been revised to conform to current year presentation.
(b)
Change in prior year due to reclassification of Residential Choice customers from Residential to Transportation class.
(c) Decrease for the three months ended September 30, 2017 is primarily driven by lower irrigation load in 2017 compared to the prior year.


55



 
Three Months Ended September 30,
 
Nine Months Ended September 30,
Gas Utilities Quantities Sold and Transportation
(in Dth) (a)
2017
2016
 
2017
2016
Residential:
 
 
 
 
 
Arkansas
530,573

531,564

 
5,058,717

3,277,167

Colorado
1,114,728

1,067,081

 
9,385,555

8,012,982

Nebraska
747,053

719,880

 
7,496,171

7,375,926

Iowa
544,429

478,158

 
6,691,008

6,744,086

Kansas
431,594

416,971

 
4,066,531

4,071,723

Wyoming
314,567

335,772

 
3,354,432

2,951,579

Total Residential
3,682,944

3,549,426

 
36,052,414

32,433,463

 
 
 
 
 
 
Commercial:
 
 
 
 
 
Arkansas
586,224

526,937

 
3,630,598

2,377,038

Colorado
479,409

539,304

 
3,700,032

2,973,962

Nebraska
317,867

384,546

 
2,764,350

2,800,616

Iowa
438,185

423,084

 
3,729,944

3,725,512

Kansas
284,647

220,650

 
1,831,946

1,771,050

Wyoming
339,515

382,503

 
2,454,248

2,194,570

Total Commercial
2,445,847

2,477,024

 
18,111,118

15,842,748

 
 
 
 
 
 
Industrial:
 
 
 
 
 
Arkansas
304,556

305,910

 
914,235

651,815

Colorado
234,770

212,997

 
357,806

345,126

Nebraska
33,050

29,531

 
64,960

62,243

Iowa
30,136

52,092

 
225,464

243,902

Kansas
1,931,919

1,645,891

 
2,483,575

2,575,314

Wyoming
187,742

185,299

 
644,052

673,366

Total Industrial
2,722,173

2,431,720

 
4,690,092

4,551,766

 
 
 
 
 
 
Total Quantities Sold
8,850,964

8,458,170

 
58,853,624

52,827,977

 
 
 
 
 
 
Transportation:
 
 
 
 
 
Arkansas
2,528,754

2,225,478

 
8,628,581

5,774,791

Colorado
1,282,746

668,591

 
5,713,315

2,267,404

Nebraska (b)
13,522,759

15,123,440

 
42,476,603

38,723,621

Iowa
4,333,161

4,394,260

 
14,826,265

14,860,343

Kansas
4,622,069

4,598,060

 
12,593,545

11,646,066

Wyoming
4,287,998

4,707,013

 
18,076,356

17,194,446

Total Transportation
30,577,487

31,716,842

 
102,314,665

90,466,671

 
 
 
 
 
 
Total Quantities Sold and Transportation
39,428,451

40,175,012

 
161,168,289

143,294,648

__________
(a)
Certain prior year revenue classes have been revised to conform to current year presentation.
(b)
Decrease for the three months ended September 30, 2017 is primarily driven by lower irrigation load in 2017 compared to the prior year.


Our Gas Utilities are highly seasonal, and sales volumes vary considerably with weather and seasonal heating and industrial loads. Approximately 70% of our Gas Utilities’ revenue and margins are expected in the first and fourth quarters of each year. Therefore, revenue for, and certain expenses of, these operations fluctuate significantly among quarters. Depending upon the geographic location in which our Gas Utilities operate, the winter heating season begins around November 1 and ends around March 31.


56



 
Three Months Ended September 30,
Degree Days
2017
 
 
 
2016
Heating Degree Days:
Actual
 
Variance
from 30-Year
Average
 
Actual Variance to Prior Year
 
Actual
 
Variance
from 30-Year
Average
Arkansas (a) (d)
15
 
(66)%
 
67%
 
9
 
(79)%
Colorado
187
 
(13)%
 
22%
 
153
 
(29)%
Nebraska
66
 
(40)%
 
(65)%
 
191
 
74%
Iowa
90
 
(35)%
 
32%
 
68
 
(51)%
Kansas (a)
37
 
(32)%
 
42%
 
26
 
(54)%
Wyoming
307
 
1%
 
(2)%
 
314
 
3%
Combined (b) (d)
117
 
(22)%
 
(20)%
 
146
 
(2)%
 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30,
Degree Days
2017
 
 
 
2016
Heating Degree Days:
Actual
 
Variance
from 30-Year
Average
 
Actual Variance to Prior Year (c)
 
Actual
 
Variance
from 30-Year
Average
Arkansas (a) (d)
1,826

 
(26
)%
 
52%
 
1,198

 
(52
)%
Colorado
3,541

 
(14
)%
 
(4)%
 
3,670

 
(6
)%
Nebraska
3,280

 
(13
)%
 
(1)%
 
3,312

 
(13
)%
Iowa
3,641

 
(13
)%
 
(4)%
 
3,783

 
(11
)%
Kansas (a)
2,584

 
(13
)%
 
—%
 
2,596

 
(13
)%
Wyoming
4,468

 
(5
)%
 
3%
 
4,334

 
(7
)%
Combined (b) (d)
3,521

 
(12
)%
 
10%
 
3,215

 
(20
)%
__________
(a)
Arkansas has a weather normalization mechanism in effect during the months of November through April for customers with residential and business rate schedules. Kansas Gas has an approved weather normalization mechanism within its residential and business rate structure, which minimizes weather impact on gross margins. The weather normalization mechanism in Arkansas differs from that in Kansas in that it only uses one location to calculate the weather, compared to Kansas, which uses multiple locations. The weather normalization mechanism in Arkansas minimizes weather impact, but does not eliminate the impact.
(b)
The combined heating degree days are calculated based on a weighted average of total customers by state excluding Kansas Gas due to its weather normalization mechanism. Arkansas Gas Distribution is partially excluded based on the weather normalization mechanism in effect from November through April.
(c)
The actual variance in heating degree days for the nine months ended September 30, 2017 compared to prior year is not a reasonable measurement of weather impacts due to the exclusion of the pre-acquisition heating degree days for the SourceGas utilities in Arkansas, Colorado, Nebraska and Wyoming. These utilities were acquired on February 12, 2016.
(d)
In 2016, the 30-year weather average for Arkansas was calculated on average actual daily temperatures. To conform to current year comparisons to normal, the 2016 variances for Arkansas compared to normal and the 2016 combined variance compared to normal have been updated for both the three and nine months ended September 30, 2016.



57



Regulatory Matters

For more information on enacted regulatory provisions with respect to the states in which our Utilities operate, see Part I, Items 1 and 2 of our 2016 Annual Report on Form 10-K filed with the SEC.

Electric Utilities Rates and Rate Activity

South Dakota Electric Settlement

On June 16, 2017, South Dakota Electric received approval from the SDPUC on a settlement reached with the SDPUC staff agreeing to a six-year moratorium period effective July 1, 2017. As part of this agreement, South Dakota Electric will not increase base rates, absent an extraordinary event. The moratorium period also includes suspension of both the Transmission Facility Adjustment and the Environmental Improvement Adjustment, and a $1.0 million increase to the annual power marketing margin guarantee during this period. Additionally, existing regulatory asset balances of approximately $13 million related to decommissioning and Winter Storm Atlas are being amortized over the moratorium period. These balances were previously being amortized over a 10-year period ending September 30, 2024. The vegetation management regulatory asset of $14 million, previously unamortized, will also be amortized over the moratorium period. The change in amortization periods for these costs will increase annual amortization expense by approximately $2.7 million.

The June 16, 2017 settlement had no impact to base rates. The following table illustrates information about certain enacted regulatory provisions with respect to South Dakota Electric:
Subsidiary
Jurisdiction
Authorized Rate of Return on Equity
Authorized Return on Rate Base
Authorized Capital Structure Debt/Equity
Authorized Rate Base (in millions)
Effective Date
Tariff and Rate Matters
Percentage of Power Marketing Profit Shared with Customers
South Dakota Electric
SD
Global Settlement
7.76%
Global Settlement
$543.9
10/2014
ECA, TCA, Energy Efficiency Cost Recovery/DSM
70%

Colorado Electric Rate Case filing

On December 19, 2016, Colorado Electric received approval from the CPUC to increase its annual revenues by $1.2 million to recover investments in a $63 million, 40 MW natural gas-fired combustion turbine and normal increases in operating expenses. This increase is in addition to approximately $5.9 million in annualized revenue being recovered under the Clean Air-Clean Jobs Act construction financing rider. The turbine was completed in the fourth quarter of 2016, achieving commercial operation on December 29, 2016. The approval allowed a return on rate base of 6.02% for this turbine, with a 9.37% return on equity and a capital structure of 67.34% debt and 32.66% equity. An authorized return on rate base of 7.4% was received for the remaining system investments, with a return on equity of 9.37% and an approved capital structure of 47.6% debt and 52.4% equity.

On January 9, 2017, we filed an application with the CPUC for rehearing, reargument or reconsideration of the Commission’s December 19, 2016 decision which reduced our proposed $8.9 million annual revenue increase to $1.2 million. This application was denied by the CPUC on June 9, 2017. We subsequently filed an appeal of this decision with Denver District Court on July 10, 2017. The briefing schedule runs through November 2017. The timing of a ruling is uncertain.
 
We believe the CPUC made errors in their December decision by demonstrating bias, making decisions not supported by evidence, making findings inconsistent with cost-recovery provisions of the Colorado Clean Air-Clean Jobs Act and the Commission’s own prior decisions, and treating Colorado Electric differently than other regulated utilities in Colorado have been treated in similar situations.

Gas Utilities Rates and Rate Activity

RMNG Rate Review

On October 3, 2017, RMNG filed a rate review application with the CPUC requesting an annual increase in revenue of $2.2 million and an extension of SSIR to recover costs from 2018 through 2022. The annual increase is based on a return on equity of 12.25% and a capital structure of 53.37% debt and 46.63% equity. This rate review was driven by the impending expiration of the SSIR on May 31, 2018; this application requests a continuation of the SSIR through 2022.

58




The following table summarizes recent activity of certain state and federal rate reviews, riders and surcharges (dollars in millions):
 
Type of Service
Date Requested
Effective Date
Revenue Amount Requested
Revenue Amount Approved
Arkansas Stockton Storage (a)
Gas - storage
11/2016
1/2017
$
2.6

$
2.6

Arkansas MRP/ARMRP (b)
Gas
9/2017
9/2017
$
2.7

$
2.7

Kansas Gas (c)
Gas
5/2017
6/2017
$
1.4

$
1.4

RMNG (d)
Gas - transmission and storage
11/2016
1/2017
$
2.9

$
2.9

Nebraska Gas Dist. (e)
Gas
10/2016
2/2017
$
6.5

$
6.5

____________________
(a)
On November 15, 2016, Arkansas Gas filed for the recovery of the Stockton Storage revenue requirement through the Stockton Storage Acquisition Rates regulatory mechanism with the rider effective January 1, 2017. This recovery mechanism was initially approved on October 15, 2015 for the Stockton Storage acquisition.
(b)
On September 1, 2017, Arkansas Gas filed for recovery of $2.2 million related to projects for the replacement of eligible mains (MRP) and the recovery of $0.5 million related to projects for the relocation of certain at risk meters (ARMRP). Pursuant to the Arkansas Gas Tariff, the filed rates went into effect on the date of the filing.
(c)
On February 21, 2017, Kansas Gas filed with the KCC requesting recovery of $1.4 million, which includes $0.6 million of new revenue related to the Gas System Reliability Surcharge rider (“GSRS”). This GSRS filing was approved by the KCC on May 23, 2017 and went into effect on June 1, 2017.
(d)
On November 3, 2016, RMNG filed with the CPUC requesting recovery of $2.9 million, which includes $1.2 million of new revenue related to system safety and integrity expenditures on projects for the period of 2014 through 2017. This SSIR request was approved by the CPUC in December 2016, and went into effect on January 1, 2017.
(e)
On October 3, 2016, Nebraska Gas Dist. filed with the NPSC requesting recovery of $6.5 million, which includes $1.7 million of new revenue related to system safety and integrity expenditures on projects for the period of 2012 through 2017. This SSIR tariff was approved by the NPSC in January 2017, and went into effect on February 1, 2017.

Power Generation
 
Three Months Ended September 30,
Nine Months Ended September 30,
 
2017
2016
Variance
2017
2016
Variance
 
(in thousands)
Revenue (a)
$
22,927

$
23,337

$
(410
)
$
68,289

$
68,359

$
(70
)
 
 
 
 
 
 
 
Operations and maintenance
7,646

7,465

181

24,228

24,155

73

Depreciation and amortization (a)
1,036

996

40

3,312

3,080

232

Total operating expense
8,682

8,461

221

27,540

27,235

305

 
 
 
 
 
 
 
Operating income
14,245

14,876

(631
)
40,749

41,124

(375
)
 
 
 
 
 
 
 
Interest expense, net
(724
)
(409
)
(315
)
(2,015
)
(1,343
)
(672
)
Other (expense) income, net
(5
)
(9
)
4

(36
)
(5
)
(31
)
Income tax (expense) benefit
(3,426
)
(5,046
)
1,620

(10,114
)
(13,467
)
3,353

 
 
 
 
 
 
 
Net income
10,090

9,412

678

28,584

26,309

2,275

Net income attributable to noncontrolling interest
(3,935
)
(3,770
)
(165
)
(10,567
)
(6,402
)
(4,165
)
Net income available for common stock
$
6,155

$
5,642

$
513

$
18,017

$
19,907

$
(1,890
)
____________
(a)
The generating facility located in Pueblo, Colorado is accounted for as a capital lease under GAAP; as such, revenue and depreciation expense are impacted by the accounting for this lease. Under the lease, the original cost of the facility is recorded at Colorado Electric and is being depreciated by Colorado Electric for segment reporting purposes.


59



On April 14, 2016, Black Hills Electric Generation sold a 49.9%, noncontrolling interest in Black Hills Colorado IPP for $216 million. Black Hills Electric Generation continues to be the majority owner and operator of the facility, which is contracted to provide capacity and energy through 2031 to Black Hills Colorado Electric. Net income available for common stock for the three and nine months ended September 30, 2017, was reduced by $3.9 million and $11 million, respectively, and reduced by $3.8 million and $6.4 million for the three and nine months ended September 30, 2016, respectively, attributable to this noncontrolling interest.

Results of Operations for Power Generation for the Three Months Ended September 30, 2017 Compared to the Three Months Ended September 30, 2016: Net income available for common stock for the Power Generation segment was $6.2 million for the three months ended September 30, 2017, compared to Net income available for common stock of $5.6 million for the same period in 2016. Revenue and operating expenses were comparable to the same period in the prior year. The variance to the prior year was driven by a lower 2017 effective tax rate compared to 2016 due to the greater impact of minority interest and higher 2016 adjustments to the filed tax return.

Results of Operations for Power Generation for the Nine Months Ended September 30, 2017 Compared to the Nine Months Ended September 30, 2016: Net income available for common stock for the Power Generation segment was $18 million for the nine months ended September 30, 2017, compared to Net income available for common stock of $20 million for the same period in 2016. Revenue and operating expenses were comparable to the same period in the prior year. The variance to the prior year was due to Black Hills Colorado IPP going from a single member LLC, wholly owned by Black Hills Electric Generation, to a partnership as a result of the sale of 49.9% of its membership interest in April 2016. The effective tax rate reflects the income attributable to the noncontrolling interest for which a tax provision is not recorded. Net income attributable to noncontrolling interest also increased by $4.2 million as a result of the noncontrolling interest sale in April 2016.

The following table summarizes MWh for our Power Generation segment:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2017
2016
 
2017
2016
Quantities Sold, Generated and Purchased
(MWh) (a)
 
 
 
 
 
Sold
 
 
 
 
 
Black Hills Colorado IPP (b)
256,895

327,793

 
725,919

972,113

Black Hills Wyoming (c)
163,690

167,670

 
476,659

476,677

Total Sold
420,585

495,463

 
1,202,578

1,448,790

 
 
 
 
 
 
Generated
 
 
 
 
 
Black Hills Colorado IPP (b)
256,895

327,793

 
725,919

972,113

Black Hills Wyoming (c)
140,081

142,388

 
407,775

401,292

Total Generated
396,976

470,181

 
1,133,694

1,373,405

 
 
 
 
 
 
Purchased
 
 
 
 
 
Black Hills Colorado IPP


 


Black Hills Wyoming (c)
20,246

23,558

 
52,463

68,797

Total Purchased
20,246

23,558

 
52,463

68,797

____________
(a)
Company uses and losses are not included in the quantities sold, generated, and purchased.
(b)
Decrease from the prior year is a result of the 2017 impact of Colorado Electric’s wind generation replacing natural-gas generation.
(c)
Under the 20-year economy energy PPA with the City of Gillette effective September 2014, Black Hills Wyoming purchases energy on behalf of the City of Gillette and sells that energy to the City of Gillette. MWh sold may not equal MWh generated and purchased due to a dispatch agreement Black Hills Wyoming has with South Dakota Electric to cover energy imbalances.


60



The following table provides certain operating statistics for our plants within the Power Generation segment:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2017
2016
 
2017
2016
Contracted power plant fleet availability:
 
 
 
 
 
Coal-fired plant
97.1
%
98.7
%
 
95.8
%
94.1
%
Natural gas-fired plants
99.2
%
99.1
%
 
99.1
%
99.2
%
Total availability
98.7
%
99.0
%
 
98.3
%
97.9
%

Mining
 
Three Months Ended September 30,
Nine Months Ended September 30,
 
2017
2016
Variance
2017
2016
Variance
 
(in thousands)
Revenue
$
17,493

$
16,820

$
673

$
48,985

$
44,149

$
4,836

 
 
 
 
 
 
 
Operations and maintenance
11,235

10,465

770

32,162

29,186

2,976

Depreciation, depletion and amortization
2,004

2,342

(338
)
6,231

7,269

(1,038
)
Total operating expenses
13,239

12,807

432

38,393

36,455

1,938

 
 
 
 
 
 
 
Operating income
4,254

4,013

241

10,592

7,694

2,898

 
 
 
 
 
 
 
Interest (expense) income, net
(47
)
(100
)
53

(146
)
(283
)
137

Other income, net
567

559

8

1,644

1,625

19

Income tax benefit (expense)
(1,297
)
(1,165
)
(132
)
(3,042
)
(2,067
)
(975
)
 
 
 
 
 
 
 
Net income
$
3,477

$
3,307

$
170

$
9,048

$
6,969

$
2,079


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

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2017
2016
 
2017
2016
Tons of coal sold
1,151

1,106

 
3,127

2,722

Cubic yards of overburden moved (a)
2,316

2,065

 
6,381

5,516

 
 
 
 
 
 
Revenue per ton
$
15.20

$
15.20

 
$
15.67

$
16.21

____________
(a)
Increase is driven by mining in areas with more overburden than in the prior year as well as higher production.


61



Results of Operations for Mining for the Three Months Ended September 30, 2017 Compared to the Three Months Ended September 30, 2016: Net income available for common stock for the Mining segment was $3.5 million for the three months ended September 30, 2017, compared to Net income available for common stock of $3.3 million for the same period in 2016 as a result of:

Revenue increased due to a 4% increase in tons sold, with comparable pricing to the same period last year. The increased tons sold were driven primarily by Wyodak plant generating requirements. During the current period, approximately 47% of the mine’s production was sold under contracts that include price adjustments based on actual mining costs, including income taxes.

Operations and maintenance increased primarily due to increased overburden removal and higher royalties and production taxes on increased revenues.

Depreciation, depletion and amortization decreased primarily due to a reduction in asset retirement obligation costs.

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

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

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

Results of Operations for Mining for the Nine Months Ended September 30, 2017 Compared to the Nine Months Ended September 30, 2016: Net income available for common stock for the Mining segment was $9.0 million for the nine months ended September 30, 2017, compared to Net income available for common stock of $7.0 million for the same period in 2016 as a result of:

Revenue increased due to a 15% increase in tons sold, partially offset by a 3% decrease in price per ton sold. The increased tons sold were driven primarily by an 11-week outage at the Wyodak plant in the prior year. The decrease in price per ton sold was driven by higher volumes sold under fixed price contracts. During the current period, approximately 46% of the mine’s production was sold under contracts that include price adjustments based on actual mining costs, including income taxes.

Operations and maintenance increased primarily due to increased overburden removal and higher royalties and production taxes on increased revenues.

Depreciation, depletion and amortization decreased primarily due to lower asset retirement obligation costs and lower plant in service.

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

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

Income tax benefit (expense): The effective tax rate increased reflecting a prior year tax benefit of percentage depletion.


62



Oil and Gas
 
Three Months Ended September 30,
Nine Months Ended September 30,
 
2017
2016
Variance
2017
2016
Variance
 
(in thousands)
Revenue
$
6,527

$
9,639

$
(3,112
)
$
19,151

$
25,660

$
(6,509
)
 
 
 
 
 
 
 
Operations and maintenance
6,076

7,592

(1,516
)
20,385

24,539

(4,154
)
Depreciation, depletion and amortization
2,391

3,483

(1,092
)
6,300

11,415

(5,115
)
Impairment of long-lived assets

12,293

(12,293
)

52,286

(52,286
)
Total operating expenses
8,467

23,368

(14,901
)
26,685

88,240

(61,555
)
 
 
 
 
 
 
 
Operating (loss)
(1,940
)
(13,729
)
11,789

(7,534
)
(62,580
)
55,046

 
 
 
 
 
 
 
Interest income (expense), net
(1,269
)
(1,295
)
26

(3,459
)
(3,529
)
70

Other income (expense), net
(3
)
16

(19
)
14

85

(71
)
Income tax benefit (expense)
500

6,180

(5,680
)
3,370

30,747

(27,377
)
 
 
 
 
 
 
 
Net (loss)
$
(2,712
)
$
(8,828
)
$
6,116

$
(7,609
)
$
(35,277
)
$
27,668


Results of Operations for Oil and Gas for the Three Months Ended September 30, 2017 Compared to the Three Months Ended September 30, 2016: Net loss available for common stock for the Oil and Gas segment was $(2.7) million for the three months ended September 30, 2017, compared to Net loss available for common stock of $(8.8) million for the same period in 2016 as a result of:

Revenue decreased primarily due to a 9% production decrease compared to the same period in the prior year. Natural gas production decreased primarily due to the 2016 sales of non-core properties, and the intentional limiting of gas production to the minimum daily quantities required to meet contractual processing commitments in the Piceance Basin. Crude oil production also decreased due to non-core property sales in the fourth quarter of 2016. The average hedged price received for crude oil sold decreased 11%. The average hedged price received for natural gas sold decreased by 15%.

Operations and maintenance decreased primarily due to lower employee costs and lower production and ad valorem taxes on lower revenue.

Depreciation, depletion and amortization decreased primarily due to the reduction in our full cost pool resulting from the ceiling test impairments incurred in the prior year.

Impairment of long-lived assets represents a prior year non-cash write-down in the value of our natural gas and crude oil properties driven by low natural gas and crude oil prices. The prior year ceiling test write-down of $12 million used a trailing 12 month average NYMEX natural gas price of $2.28 per Mcf, adjusted to $1.03 per Mcf at the wellhead, and $41.68 per barrel for crude oil, adjusted to $35.88 per barrel at the wellhead.

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

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

Income tax (expense) benefit: Each period represents a tax benefit. The current period effective tax rate is lower due primarily to a reduction to the marginal well credit compared to the same period last year.


63



Results of Operations for Oil and Gas for the Nine Months Ended September 30, 2017 Compared to the Nine Months Ended September 30, 2016: Net loss available for common stock for the Oil and Gas segment was $(7.6) million for the nine months ended September 30, 2017, compared to Net loss available for common stock of $(35) million for the same period in 2016 as a result of:

Revenue decreased primarily due to a 17% production decrease compared to the same period in the prior year. Natural gas production decreased primarily due to the 2016 sales of non-core properties and the intentional limiting of gas production to the minimum daily quantities required to meet contractual processing commitments in the Piceance Basin. Crude oil production also decreased due to non-core property sales in the fourth quarter of 2016. The average hedged price received for crude oil sold decreased 14%. The lower production volumes and crude oil pricing were partially offset by a 21% increase in the average hedged price received for natural gas sold.

Operations and maintenance decreased primarily due to lower employee costs and lower production and ad valorem taxes on lower revenue.

Depreciation, depletion and amortization decreased primarily due to the reduction in our full cost pool resulting from the ceiling test impairments incurred in the prior year.

Impairment of long-lived assets represents a prior year non-cash write-down in the value of our natural gas and crude oil properties driven by low natural gas and crude oil prices. The prior year write down of $52 million included a $14 million write-down of depreciable properties excluded from our full-cost pool and a ceiling test write-down of $38 million. The ceiling test write-down for the nine months ended September 30, 2016 used an average NYMEX natural gas price of $2.28 per Mcf, adjusted to $1.03 per Mcf at the well head, and $41.68 per barrel for crude oil, adjusted to $35.88 per barrel at the wellhead.

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

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

Income tax (expense) benefit: Each period represents a tax benefit. The effective tax rate for the nine months ended September 30, 2016 reflects a benefit of approximately $5.8 million from additional percentage depletion deductions being claimed with respect to a change in estimate for tax purposes. Such deductions were primarily the result of a change in the application of the maximum daily limitation of 1,000 Bbls of oil equivalent allowed under the Internal Revenue Code.

The following tables provide certain operating statistics for our Oil and Gas segment:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2017
2016
 
2017
2016
Production:
 
 
 
 
 
Bbls of oil sold
45,240

89,569

 
139,642

263,788

Mcf of natural gas sold
2,379,189

2,426,892

 
6,392,999

7,148,952

Bbls of NGL sold
30,810

27,640

 
82,539

105,535

Mcf equivalent sales
2,835,487

3,130,147

 
7,726,083

9,364,891

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2017
2016
 
2017
2016
Average price received: (a)
 
 
 
 
 
Oil/Bbl
$
50.22

$
56.64

 
$
46.95

$
54.38

Gas/Mcf  
$
1.39

$
1.63

 
$
1.55

$
1.28

NGL/Bbl
$
21.79

$
11.31

 
$
19.99

$
10.95

 
 
 
 
 
 
Depletion expense/Mcfe
$
0.52

$
0.81

 
$
0.46

$
0.86

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



64



The following is a summary of certain average operating expenses per Mcfe:
 
Three Months Ended September 30, 2017
 
Three Months Ended September 30, 2016
Producing Basin
LOE
Gathering,
 Compression,
  Processing and Transportation (a)
Production Taxes
Total
 
LOE
Gathering,
 Compression,
  Processing and Transportation (a)
Production Taxes
Total
San Juan
$
1.60

$
1.04

$
0.36

$
3.00

 
$
1.69

$
1.19

$
0.38

$
3.26

Piceance
0.20

1.65

0.06

1.91

 
0.24

1.84

0.16

2.24

Powder River
1.78


0.68

2.46

 
1.89


0.20

2.09

Williston




 
0.84


1.64

2.48

All other properties
1.00


0.28

1.28

 
0.30


0.22

0.52

Total weighted average
$
0.75

$
1.25

$
0.22

$
2.22

 
$
0.84

$
1.19

$
0.33

$
2.36


 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2017
 
Nine Months Ended September 30, 2016
Producing Basin
LOE
Gathering,
 Compression,
  Processing and Transportation (a)
Production Taxes
Total
 
LOE
Gathering,
 Compression,
  Processing and Transportation (a)
Production Taxes
Total
San Juan
$
1.67

$
1.11

$
0.38

$
3.16

 
$
1.65

$
1.11

$
0.31

$
3.07

Piceance
0.42

1.83

0.05

2.30

 
0.31

1.86

0.13

2.30

Powder River
2.30


0.72

3.02

 
2.52


0.45

2.97

Williston




 
1.22


1.02

2.24

All other properties
1.39


0.30

1.69

 
0.37


0.12

0.49

Total weighted average
$
1.03

$
1.34

$
0.23

$
2.60

 
$
1.00

$
1.18

$
0.27

$
2.45

__________
(a)
These costs include both third-party costs and operations costs.

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

We have a ten-year gas gathering and processing contract for our natural gas production in the Piceance Basin which became effective in March of 2014. This take-or-pay contract requires us to pay a fee on a minimum of 20,000 Mcf per day, regardless of the volume delivered. Our gathering, compression and processing costs on a per Mcfe basis, as shown in the table above, will be higher in periods when we are not meeting the minimum contract requirements.


65



Corporate Activity

Results of Operations for Corporate activities for the Three Months Ended September 30, 2017 Compared to the Three Months Ended September 30, 2016: Net loss available for common stock for Corporate was $(2.3) million for the three months ended September 30, 2017, compared to Net loss available for common stock of $(7.2) million for the three months ended September 30, 2016. The variance from the prior year was primarily due to higher corporate expenses incurred in the prior year related to the SourceGas Acquisition. The third quarter of 2017 included approximately $0.2 million of non-recurring after-tax acquisition and transition costs compared to approximately $4.0 million of after-tax non-recurring acquisition and transition costs in the third quarter of 2016. The third quarter of 2016 included $1.7 million of after-tax internal labor related to the SourceGas Acquisition that otherwise would have been charged to other business segments and also included lower income tax expense compared to the third quarter of 2017.

Results of Operations for Corporate activities for the Nine Months Ended September 30, 2017 Compared to the Nine Months Ended September 30, 2016: Net loss available for common stock for Corporate was $(2.9) million for the nine months ended September 30, 2017, compared to Net loss available for common stock of $(29) million for the nine months ended September 30, 2016. The variance from the prior year was primarily due to higher corporate expenses incurred in the prior year related to the SourceGas Acquisition. Current year corporate expenses included approximately $1.5 million of after-tax non-recurring acquisition and transition costs, compared to a total of approximately $24 million of after-tax non-recurring acquisition and transition costs and approximately $7.4 million of after-tax internal labor related to the SourceGas Acquisition that otherwise would have been charged to other business segments. During the nine months ended September 30, 2017, we recognized a tax benefit of approximately $1.4 million tax benefit from a carryback claim for specified liability losses involving prior years. The same period in the prior year included a tax benefit of approximately $4.4 million recognized as a result of an agreement reached with IRS Appeals relating to the release of the reserve for after-tax interest expense previously accrued with respect to the liability for uncertain tax positions involving a like-kind exchange transaction from 2008.

Critical Accounting Estimates

There have been no material changes in our critical accounting estimates from those reported in our 2016 Annual Report on Form 10-K filed with the SEC. For more information on our critical accounting estimates, see Part II, Item 7 of our 2016 Annual Report on Form 10-K.

Liquidity and Capital Resources

OVERVIEW

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

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

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

66



Significant Factors Affecting Liquidity

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

Our Utilities maintain wholesale commodity contracts for the purchases and sales of electricity and natural gas which have performance assurance provisions that allow the counterparty to require collateral postings under certain conditions, including when requested on a reasonable basis due to a deterioration in our financial condition or nonperformance. A significant downgrade in our credit ratings, such as a downgrade to a level below investment grade, could result in counterparties requiring collateral postings under such adequate assurance provisions. The amount of credit support that we may be required to provide at any point in the future is dependent on the amount of the initial transaction, changes in the market price, open positions and the amounts owed by or to the counterparty. At September 30, 2017, we had sufficient liquidity to cover collateral that could be required to be posted under these contracts.

Cash Flow Activities

The following table summarizes our cash flows for the nine months ended September 30 (in thousands):

Cash provided by (used in):
2017
2016
Increase (Decrease)
Operating activities
$
319,430

$
209,201

$
110,229

Investing activities
$
(256,388
)
$
(1,459,196
)
$
1,202,808

Financing activities
$
(63,112
)
$
840,948

$
(904,060
)

Year-to-Date 2017 Compared to Year-to-Date 2016

Operating Activities

Net cash provided by operating activities was $319 million for the nine months ended September 30, 2017, compared to net cash provided by operating activities of $209 million for the same period in 2016 for a variance of $110 million. The variance was primarily attributable to:

Cash earnings (net income plus non-cash adjustments) were $65 million higher for the nine months ended September 30, 2017 compared to the same period in the prior year;

Net cash outflows from changes in operating assets and liabilities were $17 million for the nine months ended September 30, 2017, compared to net cash outflows of $44 million in the same period in the prior year. This $27 million variance was primarily due to:

Cash outflows decreased due to an increase in cash inflows of approximately $14 million for the nine months ended September 30, 2017 primarily as a result of changes in our accounts receivable, partially offset by higher natural gas in storage for the nine months ended September 30, 2017 compared to the same period in the prior year;

Cash outflows decreased by approximately $16 million as a result of changes in accounts payable and accrued liabilities driven by changes in working capital requirements, primarily related to acquisition and transaction costs that took place in the prior year;

Cash outflows increased by approximately $3.3 million as a result of changes in our current regulatory assets and liabilities driven by differences in fuel cost adjustments and commodity price impacts on working capital compared to the same period in the prior year;

Net cash outflows decreased by approximately $29 million as a result of a prior year interest rate settlement; and


67



Net cash outflows increased by $14 million due to additional pension contributions made in the current year.

Investing Activities

Net cash used in investing activities was $256 million for the nine months ended September 30, 2017, compared to net cash used in investing activities of $1.5 billion for the same period in 2016 for a variance of $1.2 billion. This variance was primarily due to:

The prior year’s cash outflows included $1.124 billion for the acquisition of SourceGas, net of $760 million of long term debt assumed (see Note 2 of our Notes to the Consolidated Financial Statements in our 2016 Annual Report on Form 10-K for more details); and

Capital expenditures of approximately $256 million for the nine months ended September 30, 2017 compared to $334 million for the nine months ended September 30, 2016. The variance to the prior year was due primarily to higher prior year capital expenditures at our Electric Utilities primarily from generation investments at Colorado Electric, partially offset by higher current year capital expenditures at our Gas Utilities.

Financing Activities

Net cash used in financing activities for the nine months ended September 30, 2017 was $63 million, compared to $841 million of net cash provided by financing activities for the same period in 2016 for a variance of $904 million. This variance was primarily driven by:

Long-term borrowings decreased by $1.8 billion due to the 2016 financings which consisted of $693 million of net proceeds from the August 19, 2016 public debt offering used to refinance the debt assumed in the SourceGas Acquisition, $500 million of proceeds from the August 9, 2016 term loan, $546 million of net proceeds from our January 13, 2016 public debt offering used to partially finance the SourceGas Acquisition and proceeds from a $29 million term loan used to fund the early settlement of a gas gathering contract;

Payments on long-term debt decreased by $1.1 billion due to the 2016 refinancing of the $760 million of long-term debt assumed in the SourceGas Acquisition and lower current year payments on term loans, $104 million paid on term loans in 2017 compared to $400 million paid on term loans in 2016.

Proceeds of $216 million from the sale of a 49.9% noncontrolling interest of Colorado IPP that took place in the prior year;

Net short-term borrowings increased by $130 million primarily due to CP borrowings used to pay down long-term debt;

Proceeds from common stock decreased by approximately $104 million due to prior year stock issuances under our ATM equity offering program;

Distributions to noncontrolling interests increased by $8.4 million compared to the prior year;

Increased dividend payments of approximately $6.1 million; and

Lower other financing activities of approximately $10 million driven primarily by higher financing costs incurred in the prior year from the 2016 debt offerings and refinancings compared to a payment of $5.6 million for a redeemable noncontrolling interest in March 2017.

Dividends

Dividends paid on our common stock totaled $71 million for the nine months ended September 30, 2017, or $0.445 per share per quarter. On November 1, 2017, our board of directors declared a quarterly dividend of $0.475 per share payable December 1, 2017, which brings our total dividend for 2017 to $1.81 per share. The amount of any future cash dividends to be declared and paid, if any, will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under our Revolving Credit Facility and our future business prospects.


68



Debt

Financing Transactions and Short-Term Liquidity

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

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 extended 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 to 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 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 September 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 Revolving Credit Facility had the following borrowings, outstanding letters of credit, and available capacity (in millions):
 
 
Current
Revolver Borrowings at
CP Program Borrowings at
Letters of Credit at
Available Capacity at
Credit Facility
Expiration
Capacity
September 30, 2017
September 30, 2017
September 30, 2017
September 30, 2017
Revolving Credit Facility
August 9, 2021
$
750

$

$
225

$
25

$
500


The weighted average interest rate on CP Program borrowings at September 30, 2017 was 1.46%. Revolving Credit Facility and CP Program financing activity for the nine months ended September 30, 2017 was (dollars in millions):
 
For the Nine Months Ended September 30, 2017
Maximum amount outstanding - commercial paper (based on daily outstanding balances)
$
238

Maximum amount outstanding - revolving credit facility (based on daily outstanding balances)
$
97

Average amount outstanding - commercial paper (based on daily outstanding balances) (a)
$
107

Average amount outstanding - revolving credit facility (based on daily outstanding balances) (a)
$
55

Weighted average interest rates - commercial paper (a)
1.28
%
Weighted average interest rates - revolving credit facility (a)
2.07
%
__________
(a)
Averages for the Revolving Credit Facility are for the first 29 days of the year after which all borrowings were through the CP Program.

The Revolving Credit Facility contains customary affirmative and negative covenants, such as limitations on certain liens, restrictions on certain transactions, and maintenance of a certain Consolidated Indebtedness to Capitalization Ratio. Under the Revolving Credit Facility, our Consolidated Indebtedness to Capitalization Ratio is calculated by dividing (i) Consolidated Indebtedness, which includes letters of credit, 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. Subject to applicable cure periods, a violation of any of these covenants would constitute an event of default that entitles the lenders to terminate their remaining commitments and accelerate all principal and interest outstanding. We were in compliance with these covenants as of September 30, 2017.


69



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

Financing Activities

Financing activities for the nine months ended September 30, 2017 consisted of short-term borrowings from our Revolving Credit Facility and CP Program. We also made principal payments of $50 million each on May 16, 2017 and July 17, 2017 on our Corporate term loan due August 9, 2019. Short-term borrowings from our CP program were used to fund the payments on the Corporate term loan. On August 4, 2017, we renewed the ATM equity offering program initiated in 2016 which reset the size of the ATM equity offering program to an aggregate value of up to $300 million. We did not issue any shares of common stock under our ATM equity offering program.

Financing activities from the prior year consisted of completing the permanent financing for the SourceGas Acquisition. In addition to the net proceeds of $536 million from our November 2015 equity issuances, we completed the Acquisition financing with $546 million of net proceeds from our January 2016 debt offering. We also refinanced the long-term debt assumed with the SourceGas Acquisition primarily through $693 million of net proceeds from our August 19, 2016 debt offerings. In addition to our debt refinancings, we issued a total of 1.97 million shares of common stock throughout 2016 for net proceeds of approximately $119 million through our ATM equity offering program, and sold a 49.9% noncontrolling interest in Black Hills Colorado IPP for $216 million in April 2016.

Future Financing Plans

We anticipate the following financing activities:

Remarketing the junior subordinated notes maturing in 2018;

Evaluating a one-to-two year extension of our Revolving Credit Facility and CP program to be completed in 2018; and

Evaluating refinancing options for term loan and short-term borrowings under our Revolving Credit Facility and CP program.

Dividend Restrictions

As a utility holding company which owns several regulated utilities, we are subject to various regulations that could influence our liquidity. Our utilities in Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming have regulatory agreements in which they cannot pay dividends if they have issued debt to third parties and the payment of a dividend would reduce their equity ratio to below 40% of their total capitalization; and neither Black Hills Utility Holdings nor its subsidiaries can extend credit to the Company except in the ordinary course of business and upon reasonable terms consistent with market terms. The use of our utility assets as collateral generally requires the prior approval of the state regulators in the state in which the utility assets are located. Additionally, our utility subsidiaries may generally be limited to the amount of dividends allowed by state regulatory authorities to be paid to us as a utility holding company and also may have further restrictions under the Federal Power Act. As a result of our holding company structure, our right as a common shareholder to receive assets of any of our direct or indirect subsidiaries upon a subsidiary’s liquidation or reorganization is junior to the claims against the assets of such subsidiaries by their creditors. Therefore, our holding company debt obligations are effectively subordinated to all existing and future claims of the creditors of our subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities, and guarantee holders. As of September 30, 2017, the restricted net assets at our Electric Utilities and Gas Utilities were approximately $257 million.

70



Our credit facilities and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. An event of default would be deemed to have occurred if we did not meet certain financial covenants. The only financial covenant under our Revolving Credit Facility and existing term loans is a Consolidated Indebtedness to Capitalization Ratio, which requires us to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00 at the end of any fiscal quarter. Our Consolidated Indebtedness to Capitalization Ratio is calculated by dividing (i) Consolidated Indebtedness, which includes letters of credit, 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. Additionally, covenants within Cheyenne Light’s financing agreements require Cheyenne Light to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of September 30, 2017, we were in compliance with these covenants.

There have been no other material changes in our financing transactions and short-term liquidity from those reported in Item 7 of our 2016 Annual Report on Form 10-K filed with the SEC.

Credit Ratings

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

The following table represents the credit ratings and outlook and risk profile of BHC at September 30, 2017:
Rating Agency
Senior Unsecured Rating
Outlook
S&P (a)
BBB
Stable
Moody’s (b)
Baa2
Stable
Fitch (c)
  BBB+
Stable
__________
(a)
On July 21, 2017, S&P affirmed BBB rating and maintained a Stable outlook.
(b)
On December 9, 2016, Moody’s issued a Baa2 rating with a Stable outlook, which reflects the higher debt leverage resulting from the incremental debt used to fund the SourceGas Acquisition.
(c)
On October 4, 2017, Fitch affirmed BBB+ rating and maintained a Stable outlook.

The following table represents the credit ratings of Black Hills Power at September 30, 2017:

Rating Agency
Senior Secured Rating
S&P
A-
Moody’s
A1
Fitch
A

There were no rating changes for Black Hills Power from previously disclosed ratings.


71



Capital Requirements

Capital Expenditures

Actual and forecasted capital requirements are as follows (in thousands):
 
Expenditures for the
 
Total
 
Total
 
Total
 
Nine Months Ended September 30, 2017 (a)
 
2017 Planned
Expenditures (b)
 
2018 Planned
Expenditures
 
2019 Planned
Expenditures
Electric Utilities
$
113,199

 
$
134,000

 
$
149,000

 
$
193,000

Gas Utilities
122,482

 
187,000

 
263,000

 
279,000

Power Generation
1,899

 
1,000

 
2,000

 
14,000

Mining
4,315

 
7,000

 
7,000

 
7,000

Oil and Gas (c)
16,951

 
21,000

 

 

Corporate
5,075

 
7,000

 
9,000

 
13,000

 
$
263,921

 
$
357,000

 
$
430,000

 
$
506,000

__________
(a)    Expenditures for the nine months ended September 30, 2017 include the impact of accruals for property, plant and equipment.
(b)    Includes actual capital expenditures for the nine months ended September 30, 2017.
(c)
Expenditures reflect the completion of two wells previously drilled in 2015 to meet minimum daily quantity requirements for the Piceance Basin gathering and processing contract.

We have updated our planned 2018 and 2019 capital expenditures to primarily reflect the following:

additional planned transmission and distribution investments at our Electric Utilities in 2018 and 2019; and
additional planned growth and integrity investments in our Gas utilities, primarily as a result of gaining further knowledge of the SourceGas utilities.

We continue to evaluate potential future acquisitions and other growth opportunities when they arise. As a result, capital expenditures may vary significantly from the estimates identified above.

Contractual Obligations

There have been no significant changes in contractual obligations from those previously disclosed in Note 19 of our Notes to the Consolidated Financial Statements in our 2016 Annual Report on Form 10-K except for those described in Note 16 of the Notes to Condensed Consolidated Financial Statements in Item 1 of Part I of this Quarterly Report on Form 10-Q.

Guarantees

There have been no significant changes to guarantees from those previously disclosed in Note 20 of the Notes to the Consolidated Financial Statements in our 2016 Annual Report on Form 10-K.

New Accounting Pronouncements

Other than the pronouncements reported in our 2016 Annual Report on Form 10-K filed with the SEC and those discussed in Note 1 of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q, there have been no new accounting pronouncements that are expected to have a material effect on our financial position, results of operations, or cash flows.


72



FORWARD-LOOKING INFORMATION

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

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

Any forward-looking statement contained in this document speaks only as of the date on which the statement was made, and the Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which the statement was made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of the factors, nor can it assess the effect of each factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. All forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are expressly qualified by the risk factors and cautionary statements described in our 2016 Annual Report on Form 10-K including statements contained within Item 1A - Risk Factors of our 2016 Annual Report on Form 10-K, Part II, Item 1A of this Quarterly Report on Form 10-Q and other reports that we file with the SEC from time to time.


73



ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Utilities

Our utility customers are exposed to natural gas price volatility. Therefore, as allowed or required by state utility commissions, we have entered into commission-approved hedging programs utilizing natural gas futures, options and basis swaps to reduce our customers’ underlying exposure to these fluctuations. The fair value of our Utilities Group’s derivative contracts is summarized below (in thousands) as of:
 
September 30, 2017
 
December 31, 2016
 
September 30, 2016
Net derivative (liabilities) assets
$
(6,541
)
 
$
(4,733
)
 
$
(10,800
)
Cash collateral offset in Derivatives
5,452

 
7,882

 
11,584

Cash collateral included in Other current assets
2,841

 
4,840

 
4,602

Net asset (liability) position
$
1,752

 
$
7,989

 
$
5,386


Oil and Gas Activities

We have entered into agreements to hedge a portion of our estimated 2017 and 2018 natural gas and crude oil production from the Oil and Gas segment. The hedge agreements in place at September 30, 2017, were as follows:

Natural Gas
 
March 31
June 30
September 30
December 31
Total Year
2017
 
 
 
 
 
Swaps - MMBtu



540,000

540,000

Weighted Average Price per MMBtu
$

$

$

$
3.04

$
3.04


Crude Oil
 
March 31
June 30
September 30
December 31
Total Year
2017
 
 
 
 
 
Swaps - Bbls



18,000

18,000

Weighted Average Price per Bbl
$

$

$

$
52.33

$
52.33

 
 
 
 
 
 
Calls - Bbls



9,000

9,000

Weighted Average Price per Bbl
$

$

$

$
50.00

$
50.00

 
 
 
 
 
 
2018
 
 
 
 
 
Swaps - Bbls
9,000

9,000

9,000

9,000

36,000

Weighted Average Price per Bbl
$
49.58

$
49.85

$
50.12

$
50.45

$
50.00


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

 
September 30, 2017
 
December 31, 2016
 
September 30, 2016
Net derivative (liabilities) assets
$
110

 
$
(1,433
)
 
$
2,177

Cash collateral offset in Derivatives
544

 
2,733

 

Net asset (liability) position
$
654

 
$
1,300

 
$
2,177



74



Financing Activities

We engage in activities to manage risks associated with changes in interest rates. Historically, we have entered into floating-to-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations associated with our floating rate debt obligations and anticipated long-term refinancings. Further details of the swap agreements are set forth in Note 9 of the Notes to Consolidated Financial Statements in our 2016 Annual Report on Form 10-K and in Note 10 of the Notes to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

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:
 
September 30, 2017
 
December 31, 2016
 
September 30, 2016
 
Designated 
Interest Rate
Swaps
 
Designated
Interest Rate
Swap
 (a)
 
Designated
Interest Rate
Swaps
(a)
Notional
$

 
$
50,000

 
$
75,000

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

 
1

 
4

Derivative assets, non-current
$

 
$

 
$

Derivative liabilities, current
$

 
$
90

 
$
654

Derivative liabilities, non-current
$

 
$

 
$

Pre-tax accumulated other comprehensive income (loss)
$

 
$
(90
)
 
$
(654
)
__________
(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.


ITEM 4.    CONTROLS AND PROCEDURES

Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) as of September 30, 2017. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at September 30, 2017.

Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Security Exchange Act of 1934, as amended, is recorded, processed, summarized and reported, within the time periods specified in the Commission’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

During the quarter ended September 30, 2017, there have been no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.



75



BLACK HILLS CORPORATION

Part II — Other Information


ITEM 1.
Legal Proceedings

For information regarding legal proceedings, see Note 19 in Item 8 of our 2016 Annual Report on Form 10-K and Note 16 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 16 is incorporated by reference into this item.

ITEM 1A.
Risk Factors

There are no material changes to the risk factors previously disclosed in Item 1A of Part I in our 2016 Annual Report on Form 10-K filed with the SEC, except those stated below:

While we plan to sell Black Hills Exploration and Production, Inc. (”BHEP”), our oil and gas exploration business, and we have initiated a sales process and retained advisors to facilitate the process, there is no assurance that we can complete the transaction or recognize any particular level of proceeds.

We plan to divest all of our oil and gas assets and fully exit our oil and gas business. Such a divestiture and exit is subject to various risks, including: suitable purchasers may not be available or willing to purchase the assets on terms and conditions reasonable to us or may only be interested in acquiring a portion of the assets; we may incur substantial costs in connection with the marketing and sale of the assets; uncertainties associated with the sale may cause a loss of key management personnel at BHEP which could make it more difficult to sell the assets or operate the business in the event that we are unable to sell it; and we may be required to record an additional impairment charge that could have an adverse effect on our financial condition and results of operations.

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

There were no unregistered securities sold during the nine months ended September 30, 2017.
 
 
 
 
 
 
 
 
 

ITEM 4.
Mine Safety Disclosures

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

ITEM 5.
Other Information

None.


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ITEM 6.
Exhibits

Exhibit Number
Description
 
 
Exhibit 2.1*
 
 
Exhibit 2.2*
 
 
Exhibit 2.3*
 
 
Exhibit 3.1*
 
 
Exhibit 3.2*
 
 
Exhibit 4.1*
Indenture dated as of May 21, 2003 between the Registrant and Wells Fargo Bank, National Association (as successor to LaSalle Bank National Association), as Trustee (filed as Exhibit 4.1 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2003). First Supplemental Indenture dated as of May 21, 2003 (filed as Exhibit 4.2 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2003). Second Supplemental Indenture dated as of May 14, 2009 (filed as Exhibit 4 to the Registrant’s Form 8-K filed on May 14, 2009). Third Supplemental Indenture dated as of July 16, 2010 (filed as Exhibit 4 to Registrant’s Form 8-K filed on July 15, 2010). Fourth Supplemental Indenture dated as of November 19, 2013 (filed as Exhibit 4 to the Registrant’s Form 8-K filed on November 18, 2013). Fifth Supplemental Indenture dated as of January 13, 2016 (filed as Exhibit 4.1 to the Registrant’s Form 8-K filed on January 13, 2016). Sixth Supplemental Indenture dated as of August 19, 2016 (filed as Exhibit 4.1 to the Registrant’s Form 8-K filed on August 19, 2016).
 
 
Exhibit 4.2*
Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as Exhibit 4.19 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669)). First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to JPMorgan Chase Bank), as Trustee (filed as Exhibit 4.20 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S‑3 (No. 333‑150669)). Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 4.21 to the Registrant’s Post-Effective Amendment No. 2 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669)). Third Supplemental Indenture, dated as of October 1, 2014, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on October 2, 2014).
 
 
Exhibit 4.3*
 
 
Exhibit 4.4*

77


 
 
Exhibit 4.5*
 
 
Exhibit 4.6*
 
 
Exhibit 4.7*
 
 
Exhibit 31.1
 
 
Exhibit 31.2
 
 
Exhibit 32.1
 
 
Exhibit 32.2
 
 
Exhibit 95
 
 
Exhibit 101
Financial Statements for XBRL Format.
__________
*
Previously filed as part of the filing indicated and incorporated by reference herein.
Indicates a board of director or management compensatory plan.

78



SIGNATURES


Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

BLACK HILLS CORPORATION
 
 
/s/ David R. Emery
 
 
David R. Emery, Chairman and
 
 
  Chief Executive Officer
 
 
 
 
 
/s/ Richard W. Kinzley
 
 
Richard W. Kinzley, Senior Vice President and
 
 
  Chief Financial Officer
 
 
 
Dated:
November 3, 2017
 


79