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BLACK HILLS CORP /SD/ - Quarter Report: 2019 September (Form 10-Q)

Table of Contents

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

Form 10-Q
☒
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES

EXCHANGE ACT OF 1934
 
 
For the quarterly period ended
September 30, 2019
OR
 

☐
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
 
 
 
 
 
 
 
7001 Mount Rushmore Road

Rapid City
 
South Dakota
 
57702

 
 
 
 
 
 
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 every Interactive Data File required to be submitted 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 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
☐
 
 
 
 
 
 
 
 
 
Non-accelerated Filer
☐
 
Smaller Reporting Company
☐
 
 
 
 
 
 
 
 
 
 
 
 
Emerging Growth Company
☐
 

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
☐
 
No x
 
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Trading Symbol(s)
Name of each exchange on which registered
Common stock of $1.00 par value
BKH
New York Stock Exchange

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, 2019
Common stock, $1.00 par value
61,454,071

shares

Table of Contents


TABLE OF CONTENTS
 
 
 
Page
 
 
 
 
 
 
 
 
 
Item 1.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 2.
 
Item 3.
 
Item 4.
 
 
 
 
 
 
 
 
 
Item 1.
 
Item 4.
 
Item 6.
 
 
 
 
 
 
 


2

Table of Contents

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)
Arkansas Gas
Black Hills Energy Arkansas, Inc., a direct, wholly-owned subsidiary of Black Hills Gas Inc.
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.
BHC
Black Hills Corporation; the Company
Black Hills Electric Generation
Black Hills Electric Generation, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
Black Hills Energy
The name used to conduct the business of our utility companies
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
Busch Ranch I
Busch Ranch Wind Farm is a 29 MW wind farm near Pueblo, Colorado, jointly owned
by Colorado Electric and Black Hills Electric Generation. Colorado Electric and Black
Hills Electric Generation each have a 50% ownership interest in the wind farm.

Busch Ranch II
Busch Ranch II wind project will be a 60 MW wind farm near Pueblo, Colorado, built by Black Hills Electric Generation to provide wind energy to Colorado Electric through a 25-year power purchase agreement.
CAPP
Customer Appliance Protection Plan
Cheyenne Light
Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy and providing electric service)
Choice Gas Program
The unbundling of the natural gas service from the distribution component, which opens up the gas supply for competition allowing customers to choose from different natural gas suppliers. Black Hills Gas Distribution and Wyoming Gas distribute the gas and Black Hills Energy Services, Wyoming Gas and Black Hills Gas Distribution are Choice Gas suppliers.
CIAC
Contribution In Aid of Construction
City of Gillette
Gillette, Wyoming
City of Cheyenne
Cheyenne, Wyoming
Chief Operating Decision Maker (CODM)
Chief Executive Officer
Colorado Electric
Black Hills Colorado Electric, LLC, an indirect, wholly-owned subsidiary of Black Hills
Utility Holdings (doing business as Black Hills Energy)
Colorado Gas
Black Hills Colorado Gas, Inc., 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) plus consolidated indebtedness (including letters of credit and certain guarantees issued) as defined within the current Revolving Credit Facility.
Cooling Degree Day (CDD)
A cooling degree day is equivalent to each degree that the average of the high and low temperatures 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.
CPCN
Certificate of Public Convenience and Necessity
CP Program
Commercial Paper Program
CPUC
Colorado Public Utilities Commission
CT
Combustion turbine
CVA
Credit Valuation Adjustment
Dodd-Frank
Dodd-Frank Wall Street Reform and Consumer Protection Act

3

Table of Contents

Dth
Dekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu)
Equity Unit
Each Equity Unit had 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 that were formerly due 2028. On November 1, 2018, we completed settlement of the stock purchase contracts that are components of the Equity Units issued in November 2015.
FASB
Financial Accounting Standards Board
FERC
United States Federal Energy Regulatory Commission
Fitch
Fitch Ratings
GAAP
Accounting principles generally accepted in the United States of America
Heating Degree Day (HDD)
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.
IPP
Independent power producer
IRS
United States Internal Revenue Service
Kansas Gas
Black Hills Kansas Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy)
MMBtu
Million British thermal units
Moody’s
Moody’s Investors Service, Inc.
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)
NPSC
Nebraska Public Service Commission
PPA
Power Purchase Agreement
Pueblo Airport Generation Station
Two 100 MW combined cycle gas-fired power generation plants owned by Colorado IPP and located at a site shared with Colorado Electric. The plants commenced operation on January 1, 2012.

Revolving Credit Facility
Our $750 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, which was amended and restated on July 30, 2018 and now terminates on July 30, 2023.
RSNs
Remarketable junior subordinated notes, issued on November 23, 2015 and retired on August 17, 2018.
SDPUC
South Dakota Public Utilities Commission
SEC
U. S. Securities and Exchange Commission
S&P
Standard and Poor’s, a division of The McGraw-Hill Companies, Inc.
South Dakota Electric
Black Hills Power, which includes operations in South Dakota, Wyoming and Montana
SSIR
System Safety and Integrity Rider
TCJA
Tax Cuts and Jobs Act enacted on December 22, 2017
Tech Services
Non-regulated product lines within Black Hills Corporation that 1) provide electrical system construction services to large industrial customers of our electric utilities, and 2) serve gas transportation customers throughout its service territory by constructing and maintaining customer-owner gas infrastructure facilities, typically through one-time contracts.
Wind Capacity Factor
Measures the amount of electricity a wind turbine produces in a given time period relative to its maximum potential
WPSC
Wyoming Public Service Commission
WRDC
Wyodak Resources Development Corporation, 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, 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
Black Hills Wyoming Gas, LLC, an indirect and wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy)

4

Table of Contents

 

BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
Three Months Ended September 30,
Nine Months Ended September 30,
 
2019
2018
2019
2018
 
(in thousands, except per share amounts)
 
 
 
 
 
Revenue
$
325,548

$
321,979

$
1,257,246

$
1,253,072

 
 
 
 
 
Operating expenses:
 
 
 
 
Fuel, purchased power and cost of natural gas sold
73,090

80,244

411,695

432,544

Operations and maintenance
117,037

115,699

366,907

352,092

Depreciation, depletion and amortization
51,884

49,046

154,507

146,345

Taxes - property and production
12,986

11,905

39,454

39,181

Total operating expenses
254,997

256,894

972,563

970,162

 
 
 
 
 
Operating income
70,551

65,085

284,683

282,910

 
 
 
 
 
Other income (expense):
 
 
 
 
Interest charges -
 
 
 
 
Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)
(36,200
)
(36,380
)
(108,232
)
(107,183
)
Allowance for funds used during construction - borrowed
2,200

701

4,555

1,345

Interest income
513

382

1,208

1,012

Allowance for funds used during construction - equity
311

193

486

503

Impairment of investment
(19,741
)
—

(19,741
)
—

Other income (expense), net
269

(703
)
(431
)
(2,426
)
Total other income (expense)
(52,648
)
(35,807
)
(122,155
)
(106,749
)
 




Income before income taxes
17,903

29,278

162,528

176,161

Income tax benefit (expense)
(2,508
)
(7,477
)
(22,078
)
11,784

Income from continuing operations
15,395

21,801

140,450

187,945

Net (loss) from discontinued operations
—

(857
)
—

(5,627
)
Net income
15,395

20,944

140,450

182,318

Net income attributable to noncontrolling interest
(3,655
)
(3,994
)
(10,319
)
(10,447
)
Net income available for common stock
$
11,740

$
16,950

$
130,131

$
171,871

 
 
 
 
 
Amounts attributable to common shareholders:
 
 
 
 
Net income from continuing operations
$
11,740

$
17,807

$
130,131

$
177,498

Net (loss) from discontinued operations
—

(857
)
—

(5,627
)
Net income available for common stock
$
11,740

$
16,950

$
130,131

$
171,871

 
 
 
 
 
Earnings (loss) per share of common stock, Basic -
 
 
 
 
Earnings from continuing operations
$
0.19

$
0.33

$
2.15

$
3.33

(Loss) from discontinued operations
—

(0.02
)
—

(0.10
)
Total earnings per share of common stock, Basic
$
0.19

$
0.32

$
2.15

$
3.22

 
 
 
 
 
Earnings (loss) per share of common stock, Diluted -
 
 
 
 
Earnings from continuing operations
$
0.19

$
0.32

$
2.15

$
3.26

(Loss) from discontinued operations
—

(0.02
)
—

(0.10
)
Total earnings per share of common stock, Diluted
$
0.19

$
0.31

$
2.15

$
3.15

 
 
 
 
 
Weighted average common shares outstanding:
 
 
 
 
Basic
60,976

53,364

60,458

53,346

Diluted
61,104

54,819

60,578

54,508



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

5

Table of Contents


BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)
Three Months Ended
September 30,
Nine Months Ended
September 30,
 
2019
2018
2019
2018
 
(in thousands)
 
 
 
 
 
Net income
$
15,395

$
20,944

$
140,450

$
182,318

 
 
 
 
 
Other comprehensive income (loss), net of tax:
 
 
 
 
Reclassification adjustments of benefit plan liability - prior service cost (net of tax of $3, $10, $13 and $29, respectively)
(16
)
(34
)
(45
)
(104
)
Reclassification adjustments of benefit plan liability - net gain (loss) (net of tax of $(92), $(138), $(197), and $(409), respectively)
(9
)
483

327

1,456

Derivative instruments designated as cash flow hedges:
 
 
 
 
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(165), $(152), $(500), and $(456), respectively)
548

560

1,639

1,682

Net unrealized gains (losses) on commodity derivatives (net of tax of $35, $0, $100 and $51, respectively)
(115
)
30

(334
)
(168
)
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $(5), $3, $142 and $(187), respectively)
124

21

(366
)
615

Other comprehensive income, net of tax
532

1,060

1,221

3,481

 
 
 
 
 
Comprehensive income
15,927

22,004

141,671

185,799

Less: comprehensive income attributable to noncontrolling interest
(3,655
)
(3,994
)
(10,319
)
(10,447
)
Comprehensive income available for common stock
$
12,272

$
18,010

$
131,352

$
175,352


See Note 13 for additional disclosures.

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

6

Table of Contents

BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)
As of
 
September 30, 2019
 
December 31, 2018
 
(in thousands)
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
13,087

 
$
20,776

Restricted cash
3,688

 
3,369

Accounts receivable, net
148,989

 
269,153

Materials, supplies and fuel
123,002

 
117,299

Derivative assets, current
412

 
1,500

Income tax receivable, net
12,931

 
12,978

Regulatory assets, current
46,206

 
48,776

Other current assets
29,106

 
29,982

Total current assets
377,421

 
503,833

 
 
 
 
Investments
21,583

 
41,013

 
 
 
 
Property, plant and equipment
6,567,229

 
6,000,015

Less: accumulated depreciation and depletion
(1,243,794
)
 
(1,145,136
)
Total property, plant and equipment, net
5,323,435

 
4,854,879

 
 
 
 
Other assets:
 
 
 
Goodwill
1,299,454

 
1,299,454

Intangible assets, net
13,566

 
14,337

Regulatory assets, non-current
214,152

 
235,459

Other assets, non-current
25,339

 
14,352

Total other assets, non-current
1,552,511

 
1,563,602

 
 
 
 
TOTAL ASSETS
$
7,274,950

 
$
6,963,327


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

7

Table of Contents

BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Continued)
(unaudited)
As of
 
September 30, 2019
 
December 31, 2018
 
(in thousands, except share amounts)
LIABILITIES AND TOTAL EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
145,085

 
$
210,609

Accrued liabilities
217,832

 
215,501

Derivative liabilities, current
2,396

 
947

Regulatory liabilities, current
25,168

 
29,810

Notes payable
294,900

 
185,620

Current maturities of long-term debt
5,743

 
5,743

Total current liabilities
691,124

 
648,230

 
 
 
 
Long-term debt
3,049,235

 
2,950,835

 
 
 
 
Deferred credits and other liabilities:
 
 
 
Deferred income tax liabilities, net
347,952

 
311,331

Regulatory liabilities, non-current
498,773

 
510,984

Benefit plan liabilities
134,150

 
145,147

Other deferred credits and other liabilities
120,820

 
109,377

Total deferred credits and other liabilities
1,101,695

 
1,076,839

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


 

 
 
 
 
Equity:
 
 
 
Stockholders’ equity —
 
 
 
Common stock $1 par value; 100,000,000 shares authorized; issued 61,480,640 and 60,048,567 shares, respectively
61,481

 
60,049

Additional paid-in capital
1,553,190

 
1,450,569

Retained earnings
742,138

 
700,396

Treasury stock, at cost – 26,572 and 44,253 shares, respectively
(1,636
)
 
(2,510
)
Accumulated other comprehensive income (loss)
(25,695
)
 
(26,916
)
Total stockholders’ equity
2,329,478

 
2,181,588

Noncontrolling interest
103,418

 
105,835

Total equity
2,432,896

 
2,287,423

 
 
 
 
TOTAL LIABILITIES AND TOTAL EQUITY
$
7,274,950

 
$
6,963,327


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

8

Table of Contents

BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
Nine Months Ended September 30,
 
2019
2018
Operating activities:
(in thousands)
Net income
$
140,450

$
182,318

Loss from discontinued operations, net of tax
—

5,627

Income from continuing operations
140,450

187,945

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation, depletion and amortization
154,507

146,345

Deferred financing cost amortization
6,326

5,682

Impairment of investment
19,741

—

Stock compensation
8,332

7,544

Deferred income taxes
24,381

(14,396
)
Employee benefit plans
7,965

10,641

Other adjustments, net
9,192

7,668

Changes in certain operating assets and liabilities:
 
 
Materials, supplies and fuel
(4,126
)
(8,380
)
Accounts receivable, unbilled revenues and other operating assets
115,325

72,061

Accounts payable and other operating liabilities
(83,436
)
(86,604
)
Regulatory assets - current
12,455

41,655

Regulatory liabilities - current
(15,644
)
21,416

Contributions to defined benefit pension plans
(12,700
)
(12,700
)
Other operating activities, net
3,307

2,007

Net cash provided by operating activities of continuing operations
386,075

380,884

Net cash provided by (used in) operating activities of discontinued operations
—

(2,162
)
Net cash provided by operating activities
386,075

378,722

 
 
 
Investing activities:
 
 
Property, plant and equipment additions
(592,537
)
(278,132
)
Purchase of investment
—

(24,429
)
Other investing activities
(735
)
2,766

Net cash provided by (used in) investing activities of continuing operations
(593,272
)
(299,795
)
Net cash provided by investing activities of discontinued operations
—

18,024

Net cash provided by (used in) investing activities
(593,272
)
(281,771
)
 
 
 
Financing activities:
 
 
Dividends paid on common stock
(91,779
)
(76,309
)
Common stock issued
101,361

1,079

Net (payments) borrowings of short-term debt
109,280

(99,200
)
Long-term debt - issuances
400,000

700,000

Long-term debt - repayments
(304,307
)
(603,307
)
Distributions to noncontrolling interest
(12,736
)
(13,755
)
Other financing activities
(1,992
)
(10,457
)
Net cash provided by (used in) financing activities
199,827

(101,949
)
Net change in cash, cash equivalents and restricted cash
(7,370
)
(4,998
)
Cash, cash equivalents and restricted cash at beginning of period
24,145

18,240

Cash, cash equivalents and restricted cash at end of period
$
16,775

$
13,242



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.

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Table of Contents

BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(unaudited)
Common Stock
Treasury Stock
 
 
 
 
 
(in thousands except share amounts)
Shares
Value
Shares
Value
Additional Paid in Capital
Retained Earnings
AOCI
Non controlling Interest
Total
December 31, 2018
60,048,567

$
60,049

44,253

$
(2,510
)
$
1,450,569

$
700,396

$
(26,916
)
$
105,835

$
2,287,423

Net income available for common stock
—

—

—

—

—

103,808

—

3,554

107,362

Other comprehensive income (loss), net of tax
—

—

—

—

—

—

457

—

457

Dividends on common stock ($0.505 per share)
—

—

—

—

—

(30,332
)
—

—

(30,332
)
Share-based compensation
48,956

49

(20,497
)
1,078

(589
)
—

—

—

538

Issuance of common stock
280,497

280

—

—

19,719

—

—

—

19,999

Issuance costs
—

—

—

—

(289
)
—

—

—

(289
)
Implementation of ASU 2016-02 Leases
—

—

—

—

—

3,390

—

—

3,390

Distributions to noncontrolling interest
—

—

—

—

—

—

—

(4,846
)
(4,846
)
March 31, 2019
60,378,020

$
60,378

23,756

$
(1,432
)
$
1,469,410

$
777,262

$
(26,459
)
$
104,543

$
2,383,702

Net income available for common stock
—

—

—

—

—

14,583

—

3,110

17,693

Other comprehensive income (loss), net of tax
—

—

—

—

—

—

232

—

232

Dividends on common stock ($0.505 per share)
—

—

—

—

—

(30,620
)
—

—

(30,620
)
Share-based compensation
54,767

54

1,603

(112
)
3,948

—

—

—

3,890

Issuance of common stock
658,598

659

—

—

49,342

—

—

—

50,001

Issuance costs
—

—

—

—

(492
)
—

—

—

(492
)
Implementation of ASU 2016-02 Leases
—

—

—

—

—

(3
)
—

—

(3
)
Distributions to noncontrolling interest
—

—

—

—

—

—

—

(4,405
)
(4,405
)
June 30, 2019
61,091,385

$
61,091

25,359

$
(1,544
)
$
1,522,208

$
761,222

$
(26,227
)
$
103,248

$
2,419,998

Net income (loss) available for common stock
—

—

—

—

—

11,740

—

3,655

15,395

Other comprehensive income (loss), net of tax
—

—

—

—

—

—

532

—

532

Dividends on common stock ($0.505 per share)
—

—

—

—

—

(30,827
)
—

—

(30,827
)
Share-based compensation
18

—

1,213

(92
)
1,769

—

—

—

1,677

Issuance of common stock
389,237

390

—

—

29,611

—

—

—

30,001

Issuance costs
—

—

—

—

(398
)
—

—

—

(398
)
Implementation of ASU 2016-02 Leases
—

—

—

—

—

3

—

—

3

Distributions to noncontrolling interest
—

—

—

—

—

—

—

(3,485
)
(3,485
)
September 30, 2019
61,480,640

$
61,481

26,572

$
(1,636
)
$
1,553,190

$
742,138

$
(25,695
)
$
103,418

$
2,432,896

 
 
 
 
 
 
 
 
 
 


10

Table of Contents

 
Common Stock
Treasury Stock
 
 
 
 
 
(in thousands except share amounts)
Shares
Value
Shares
Value
Additional Paid in Capital
Retained Earnings
AOCI
Non controlling Interest
Total
December 31, 2017
53,579,986

$
53,580

39,064

$
(2,306
)
$
1,150,285

$
548,617

$
(41,202
)
$
111,232

$
1,820,206

Net income available for common stock
—

—

—

—

—

133,004

—

3,630

136,634

Other comprehensive income (loss), net of tax
—

—

—

—

—

—

1,260

—

1,260

Dividends on common stock ($0.475 per share)
—

—

—

—

—

(25,444
)
—

—

(25,444
)
Share-based compensation
64,770

65

14,895

(743
)
1,433

—

—

—

755

Dividend reinvestment and stock purchase plan
4,061

4

—

—

215

—

—

—

219

Other stock transactions
—

—

—

—

—

(16
)
18

—

2

Distributions to noncontrolling interest
—

—

—

—

—

—

—

(5,648
)
(5,648
)
March 31, 2018
53,648,817

$
53,649

53,959

$
(3,049
)
$
1,151,933

$
656,161

$
(39,924
)
$
109,214

$
1,927,984

Net income available for common stock
—

—

—

—

—

21,917

—

2,823

24,740

Other comprehensive income (loss), net of tax
—

—

—

—

—

—

1,161

—

1,161

Dividends on common stock ($0.475 per share)
—

—

—

—

—

(25,435
)
—

—

(25,435
)
Share-based compensation
13,033

13

11,022

(593
)
3,019

—

—

—

2,439

Other stock transactions
—

—

—

—

(5
)
(1
)
—

—

(6
)
Distributions to noncontrolling interest
—

—

—

—

—

—

—

(4,350
)
(4,350
)
June 30, 2018
53,661,850

$
53,662

64,981

$
(3,642
)
$
1,154,947

$
652,642

$
(38,763
)
$
107,687

$
1,926,533

Net income (loss) available for common stock
—

—

—

—

—

16,950

—

3,994

20,944

Other comprehensive income (loss), net of tax
—

—

—

—

—

—

1,060

—

1,060

Dividends on common stock ($0.475 per share)
—

—

—

—

—

(25,430
)
—

—

(25,430
)
Share-based compensation
13

—

7,934

(430
)
2,107

—

—

—

1,677

Dividend reinvestment and stock purchase plan
—

—

—

—

1

—

—

—

1

Other stock transactions
—

—

—

—

159

(8
)
—

—

151

Distributions to noncontrolling interest
—

—

—

—

—

—

—

(3,757
)
(3,757
)
September 30, 2018
53,661,863

$
53,662

72,915

$
(4,072
)
$
1,157,214

$
644,154

$
(37,703
)
$
107,924

$
1,921,179

 
 
 
 
 
 
 
 
 
 


11

Table of Contents


BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Reference is made to Notes to Consolidated Financial Statements
included in the Company’s 2018 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 2018 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 and Mining. 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.

Effective January 1, 2019, we changed our measure of segment performance to adjusted operating income, which impacted our segment disclosures for all periods presented. See Note 3 for more information.

On November 1, 2017, the BHC board of directors approved a complete divestiture of our Oil and Gas segment. We completed the divestiture in 2018. The Oil and Gas segment assets and liabilities were classified as held for sale and the results of operations were shown in income (loss) from discontinued operations, except for certain general and administrative costs and interest expense which do not meet the criteria for income (loss) from discontinued operations. At the time the assets were classified as held for sale, depreciation, depletion and amortization expenses were no longer recorded. Unless otherwise noted, the amounts presented in the accompanying notes to the Condensed Consolidated Financial Statements relate to the Company’s continuing operations. See Note 17 and Note 21 for more information on discontinued operations.

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, 2019 and December 31, 2018 financial 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. 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, 2019 and September 30, 2018, and our financial condition as of September 30, 2019 and December 31, 2018 are not necessarily indicative of the results of operations and financial condition to be expected for any other period. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted.

Recently Issued Accounting Standards

Simplifying the Test for Goodwill Impairment, 2017-04

In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment by eliminating step 2 from the goodwill impairment test. Under the new guidance, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss will be recognized in an amount equal to that excess, limited to the amount of goodwill allocated to that reporting unit. The new standard is effective for interim and annual reporting periods beginning after December 1, 2019, applied on a prospective basis with early adoption permitted. We do not anticipate the adoption of this guidance to have any impact on our financial position, results of operations or cash flows.

12

Table of Contents


Financial Instruments -- Credit Losses: Measurement of Credit Losses on Financial Instruments, ASU 2018-19

In June 2016, the FASB issued ASU 2016-13, Financial Instruments -- Credit Losses: Measurement of Credit Losses on Financial Instruments, which was subsequently amended by ASU 2018-19 in November 2018. The standard introduces new accounting guidance for credit losses on financial instruments within its scope, including trade receivables. This new guidance adds an impairment model that is based on expected losses rather than incurred losses. It is effective for interim and annual reporting periods beginning after December 15, 2019, and will be applied on a modified-retrospective basis through a cumulative-effect adjustment to retained earnings as of January 1, 2020. We do not anticipate the adoption of this guidance to have a material impact on our financial position, results of operations or cash flows.

Recently Adopted Accounting Standards

Leases, ASU 2016-02

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) to increase transparency and comparability among organizations by requiring the recognition of right-of-use assets and lease liabilities on the balance sheet for most leases, whereas previously only financing-type lease liabilities (capital leases) were recognized on the balance sheet. Under the new standard, disclosures are required to meet the objective of enabling users of financial statements to assess the amount, timing and uncertainty of cash flows arising from leases.

We adopted the standard effective January 1, 2019. We elected not to recast comparative periods coinciding with the new lease standard transition and will report these comparative periods as presented under previous lease guidance. In addition, we elected the package of practical expedients permitted under the transition guidance with the new standard, which among other things, allowed us to carry forward the historical lease classification. We also elected the practical expedient related to land easements, allowing us to carry forward our accounting treatment for existing land easement agreements.

Adoption of the new standard resulted in the recording of an operating lease right-of-use asset of $3.1 million, an operating lease obligation liability of $3.2 million, and an accrued rent receivable of $4.5 million, as of January 1, 2019. The cumulative effect of the adoption, net of tax impact, was $3.4 million, which was recorded as an adjustment to retained earnings at January 1, 2019.

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

Effective January 1, 2019, we adopted ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements 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. The adoption of this guidance did not have a material impact on our financial position, results of operations or cash flows.




13

Table of Contents


(2)    REVENUE

Revenue Recognition

As of January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and its related amendments (collectively known as ASC 606). Revenue is recognized in an amount that reflects the consideration we expect to receive in exchange for goods or services, when control of the promised goods or services is transferred to our customers. The following tables depict the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reporting segments, for the three and nine months ended September 30, 2019 and 2018. Sales tax and other similar taxes are excluded from revenues.

Three Months Ended September 30, 2019
 Electric Utilities
 Gas Utilities
 Power Generation
 Mining
Inter-company Revenues
Total
Customer types:
(in thousands)
Retail
$
162,214

$
89,810

$
—

$
14,992

$
(8,146
)
$
258,870

Transportation
—

29,019

—

—

(195
)
28,824

Wholesale
8,210

—

16,119

—

(14,414
)
9,915

Market - off-system sales
6,452

139

—

—

(1,488
)
5,103

Transmission/Other
14,274

10,965

—

—

(4,206
)
21,033

Revenue from contracts with customers
$
191,150

$
129,933

$
16,119

$
14,992

$
(28,449
)
$
323,745

Other revenues
234

811

9,692

560

(9,494
)
1,803

Total revenues
$
191,384

$
130,744

$
25,811

$
15,552

$
(37,943
)
$
325,548

 
 
 
 
 
 
 
Timing of revenue recognition:
 
 
 
 
 
 
Services transferred at a point in time
$
—

$
—

$
—

$
14,992

$
(8,146
)
$
6,846

Services transferred over time
191,150

129,933

16,119

—

(20,303
)
316,899

Revenue from contracts with customers
$
191,150

$
129,933

$
16,119

$
14,992

$
(28,449
)
$
323,745

 
 
 
 
 
 
 

Three Months Ended September 30, 2018
 Electric Utilities
 Gas Utilities
 Power Generation (a)
 Mining
Inter-company Revenues (a)
Total
Customer Types:
 
 
 
 
 
 
Retail
$
157,049

$
88,559

$
—

$
16,751

$
(7,941
)
$
254,418

Transportation
—

30,079

—

—

(267
)
29,812

Wholesale
8,255

—

15,373

—

(13,935
)
9,693

Market - off-system sales
9,059

140

—

—

(1,349
)
7,850

Transmission/Other
10,196

11,887

—

—

(3,693
)
18,390

Revenue from contracts with customers
$
184,559

$
130,665

$
15,373

$
16,751

$
(27,185
)
$
320,163

Other revenues
231

1,011

9,118

550

(9,094
)
1,816

Total Revenues
$
184,790

$
131,676

$
24,491

$
17,301

$
(36,279
)
$
321,979

 
 
 
 
 
 
 
Timing of Revenue Recognition:
 
 
 
 
 
 
Services transferred at a point in time
$
—

$
—

$
—

$
16,751

$
(7,942
)
$
8,809

Services transferred over time
184,559

130,665

15,373

—

(19,243
)
311,354

Revenue from contracts with customers
$
184,559

$
130,665

$
15,373

$
16,751

$
(27,185
)
$
320,163

 
 
 
 
 
 
 

14

Table of Contents

Nine Months Ended September 30, 2019
 Electric Utilities
 Gas Utilities
 Power Generation
 Mining
Inter-company Revenues
Total
Customer types:
(in thousands)
Retail
$
455,409

$
567,715

$
—

$
43,249

$
(23,315
)
$
1,043,058

Transportation
—

102,159

—

—

(903
)
101,256

Wholesale
23,334

—

46,650

—

(40,923
)
29,061

Market - off-system sales
16,592

517

—

—

(5,047
)
12,062

Transmission/Other
42,865

35,767

—

—

(12,608
)
66,024

Revenue from contracts with customers
$
538,200

$
706,158

$
46,650

$
43,249

$
(82,796
)
$
1,251,461

Other revenues
2,465

1,135

29,114

1,777

(28,706
)
5,785

Total revenues
$
540,665

$
707,293

$
75,764

$
45,026

$
(111,502
)
$
1,257,246

 
 
 
 
 
 
 
Timing of revenue recognition:
 
 
 
 
 
 
Services transferred at a point in time
$
—

$
—

$
—

$
43,249

$
(23,315
)
$
19,934

Services transferred over time
538,200

706,158

46,650

—

(59,481
)
1,231,527

Revenue from contracts with customers
$
538,200

$
706,158

$
46,650

$
43,249

$
(82,796
)
$
1,251,461

 
 
 
 
 
 
 


Nine Months Ended September 30, 2018
 Electric Utilities
 Gas Utilities
 Power Generation (a)
 Mining
Inter-company Revenues (a)
Total
Customer Types:
 
 
 
 
 
 
Retail
$
449,482

$
565,816

$
—

$
49,653

$
(23,761
)
$
1,041,190

Transportation
—

100,760

—

—

(977
)
99,783

Wholesale
25,497

—

43,744

—

(39,457
)
29,784

Market - off-system sales
18,142

728

—

—

(5,531
)
13,339

Transmission/Other
36,622

36,230

—

—

(10,967
)
61,885

Revenue from contracts with customers
$
529,743

$
703,534

$
43,744

$
49,653

$
(80,693
)
$
1,245,981

Other revenues
2,218

3,106

27,429

1,675

(27,337
)
7,091

Total Revenues
$
531,961

$
706,640

$
71,173

$
51,328

$
(108,030
)
$
1,253,072

 
 
 
 
 
 
 
Timing of Revenue Recognition:
 
 
 
 
 
 
Services transferred at a point in time
$
—

$
—

$
—

$
49,653

$
(23,761
)
$
25,892

Services transferred over time
529,743

703,534

43,744

—

(56,932
)
1,220,089

Revenue from contracts with customers
$
529,743

$
703,534

$
43,744

$
49,653

$
(80,693
)
$
1,245,981

 
 
 
 
 
 
 

(a)
Due to the changes in our segment disclosures discussed in Note 3, Power Generation Wholesale revenue was revised for the three and nine months ended September 30, 2018, which resulted in an increase of $0.9 million and $2.6 million, respectively. The changes to Power Generation Wholesale revenue were offset by changes to eliminations in Inter-company Revenues within Corporate and Other and there was no impact to our consolidated Total Revenues.

Contract Balances

The nature of our primary revenue contracts provides an unconditional right to consideration upon service delivery; therefore, no customer contract assets or liabilities exist. The unconditional right to consideration is represented by the balance in our Accounts Receivable further discussed in Note 4. We do not typically incur costs that would be capitalized to obtain or fulfill a revenue contract.


15

Table of Contents

(3)    BUSINESS SEGMENT INFORMATION

Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation.

Accounting standards for presentation of segments require an approach based on the way we organize the segments for making operating decisions and how the chief operating decision maker (CODM) assesses performance.  Effective January 1, 2019, we concluded that adjusted operating income, instead of net income available for common stock which was used previously, is the most relevant metric for measuring segment performance. The change to our segment performance measure resulted in a revision of the Company’s segment disclosures for all periods to report adjusted operating income as the measure of segment performance.

Prior to January 1, 2019, operating income for the Electric Utilities and Power Generation segments and Corporate and Other included the impacts of finance lease accounting relating to Colorado Electric’s PPA with Colorado IPP. This PPA provides 200 MW of energy and capacity to Colorado Electric from Colorado IPP’s combined-cycle turbines and expires on December 31, 2031. Finance lease accounting required us to de-recognize the asset from Colorado IPP (Power Generation segment), which legally owns the asset, and recognize it at Colorado Electric (Electric Utilities segment).

The CODM assesses the performance of our segments using adjusted operating income, which recognizes intersegment revenues, costs, and assets for Colorado Electric’s PPA with Colorado IPP on an accrual basis rather than as a finance lease. Effective January 1, 2019, we changed how we account for this PPA at the segment level, which impacts disclosures for all periods for revenues, fuel and purchased power cost, operating income and total assets for the Electric Utilities and Power Generation segments as well as Corporate and Other. There were no revisions to Gas Utilities and Mining segments and this change had no effect on our consolidated revenues, fuel and purchased power cost, operating income or total assets.

Segment information and Corporate and Other is as follows (in thousands):
 
 
 
 
 
 
 
 
Three Months Ended September 30, 2019
External Operating Revenue
 
Inter-company Operating Revenue
 
 Total Revenues
 Contract Customers
 Other Revenues
 Contract Customers
 Other Revenues
Segment:
 
 
 
 
 
 
 
Electric Utilities
$
185,811

$
234


$
5,339

$
—


$
191,384

Gas Utilities
129,385

810


549

—


130,744

Power Generation
1,703

531


14,415

9,162


25,811

Mining
6,846

228


8,146

332


15,552

Inter-company eliminations
—

—

 
(28,449
)
(9,494
)
 
(37,943
)
Total
$
323,745

$
1,803

 
$
—

$
—

 
$
325,548

 
 
 
 
 
 
 
 
Three Months Ended September 30, 2018
External Operating Revenue
 
Inter-company Operating Revenue
 
 Total Revenues
 Contract Customers
 Other Revenues
 Contract Customers
 Other Revenues
Segment:
 
 
 
 
 
 
 
Electric Utilities
$
179,527

$
231

 
$
5,032

$
—

 
$
184,790

Gas Utilities
130,390

1,011

 
275

—

 
131,676

Power Generation (a)
1,437

348

 
13,936

8,770

 
24,491

Mining
8,809

226

 
7,942

324

 
17,301

Inter-company eliminations (a)
—

—

 
(27,185
)
(9,094
)
 
(36,279
)
Total
$
320,163

$
1,816

 
$
—

$
—

 
$
321,979


16

Table of Contents

Nine Months Ended September 30, 2019
External Operating
Revenue
 
Inter-company Operating Revenue
 
Total Revenues
 Contract Customers
 Other Revenues
 Contract Customers
 Other Revenues
Segment:
 
 
 
 
 
 
 
Electric Utilities
$
521,614

$
2,465

 
$
16,586

$
—

 
$
540,665

Gas Utilities
704,188

1,134

 
1,971

—

 
707,293

Power Generation
5,725

1,401

 
40,924

27,714

 
75,764

Mining
19,934

785

 
23,315

992

 
45,026

Inter-company eliminations
—

—

 
(82,796
)
(28,706
)
 
(111,502
)
Total
$
1,251,461

$
5,785

 
$
—

$
—

 
$
1,257,246

 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2018
External Operating Revenue
 
Inter-company Operating Revenue
 
 Total Revenues
 Contract Customers
 Other Revenues
 Contract Customers
 Other Revenues
Segment:
 
 
 
 
 
 
 
Electric Utilities
$
513,270

$
2,218

 
$
16,473

$
—

 
$
531,961

Gas Utilities
702,532

3,106

 
1,002

—

 
706,640

Power Generation (a)
4,287

1,066

 
39,457

26,363

 
71,173

Mining
25,892

701

 
23,761

974

 
51,328

Inter-company eliminations (a)
—

—

 
(80,693
)
(27,337
)
 
(108,030
)
Total
$
1,245,981

$
7,091

 
$
—

$
—

 
$
1,253,072



(a)
Due to the changes in our segment disclosures, Power Generation Inter-company Operating Revenue for Contract Customers was revised for the three and nine months ended September 30, 2018 which resulted in an increase of $0.9 million and $2.6 million, respectively. The changes to Power Generation were offset by changes to Inter-company eliminations within Corporate and Other and there was no impact on our consolidated Total revenues.

17

Table of Contents

 
 
 
 
 
 
Three Months Ended September 30,
Nine Months Ended September 30,
 
2019
2018
2019
2018
Adjusted operating income:
 
 
 
 
Electric Utilities (a)
$
50,653

$
43,393

$
125,219

$
123,073

Gas Utilities
4,736

4,240

116,607

116,168

Power Generation (a)
11,822

13,079

33,945

33,731

Mining
3,374

4,551

9,351

12,647

Corporate and Other (a)
(34
)
(178
)
(439
)
(2,709
)
Operating income
70,551

65,085

284,683

282,910

 
 
 
 
 
Interest expense, net
(33,487
)
(35,297
)
(102,469
)
(104,826
)
Impairment of investment
(19,741
)
—

(19,741
)
—

Other income (expense), net
580

(510
)
55

(1,923
)
Income tax benefit (expense) (b)
(2,508
)
(7,477
)
(22,078
)
11,784

Income from continuing operations
15,395

21,801

140,450

187,945

Net (loss) from discontinued operations
—

(857
)
—

(5,627
)
Net income
15,395

20,944

140,450

182,318

Net income attributable to noncontrolling interest
(3,655
)
(3,994
)
(10,319
)
(10,447
)
Net income available for common stock
$
11,740

$
16,950

$
130,131

$
171,871

___________
(a)
Due to the changes in our segment disclosures, Adjusted operating income was revised for the three and nine months ended September 30, 2018, which resulted in an increase (decrease) as follows (in millions):
Segment
Three Months Ended September 30, 2018
Nine Months Ended September 30, 2018
Electric Utilities
$
1.6

$
4.8

Power Generation
(1.4
)
(4.4
)
Corporate and Other
(0.2
)
(0.4
)
 
$
—

$
—



(b)
Income tax benefit (expense) for the nine months ended September 30, 2018 included a $49 million tax benefit resulting from legal entity restructuring. See Note 18 for more information.


Segment information and Corporate and Other 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, 2019
 
December 31, 2018
Segment:
 
 
 
Electric Utilities (a)
$
2,810,108

 
$
2,707,695

Gas Utilities
3,797,941

 
3,623,475

Power Generation (a)
414,526

 
342,085

Mining
78,073

 
80,594

Corporate and Other
174,302

 
209,478

Total assets
$
7,274,950

 
$
6,963,327


___________
(a)
Due to the changes in our segment disclosures, Electric Utilities and Power Generation Total assets were revised as of December 31, 2018 which resulted in an increase (decrease) of ($188) million and $188 million, respectively. There was no impact on our consolidated Total assets.


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Table of Contents

(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, 2019
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
39,151

$
31,843

$
(500
)
$
70,494

Gas Utilities
46,265

24,091

(2,490
)
67,866

Power Generation
2,733

—

—

2,733

Mining
1,804

—

—

1,804

Corporate
6,261

—

(169
)
6,092

Total
$
96,214

$
55,934

$
(3,159
)
$
148,989


 
Accounts
Unbilled
Less Allowance for
Accounts
December 31, 2018
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
39,721

$
35,125

$
(448
)
$
74,398

Gas Utilities
96,123

90,521

(2,592
)
184,052

Power Generation
1,876

—

—

1,876

Mining
3,988

—

—

3,988

Corporate
5,008

—

(169
)
4,839

Total
$
146,716

$
125,646

$
(3,209
)
$
269,153


 
 
 
 
 



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(5)    REGULATORY ACCOUNTING

We had the following regulatory assets and liabilities (in thousands) as of:
 
September 30, 2019
December 31, 2018
Regulatory assets
 
 
Deferred energy and fuel cost adjustments (a)
$
31,832

$
29,661

Deferred gas cost adjustments (a)
3,899

3,362

Gas price derivatives (a)
4,296

6,201

Deferred taxes on AFUDC (b)
7,691

7,841

Employee benefit plans (c)
107,921

110,524

Environmental (a)
917

959

Loss on reacquired debt (a)
19,710

21,001

Renewable energy standard adjustment (a)
2,871

1,722

Deferred taxes on flow through accounting (c)
37,609

31,044

Decommissioning costs (b)
11,206

11,700

Gas supply contract termination (a)
9,953

14,310

Other regulatory assets (a)
22,453

45,910

Total regulatory assets
260,358

284,235

Less current regulatory assets
(46,206
)
(48,776
)
Regulatory assets, non-current
$
214,152

$
235,459

 
 
 
Regulatory liabilities
 
 
Deferred energy and gas costs (a)
$
9,919

$
6,991

Employee benefit plan costs and related deferred taxes (c)
42,737

42,533

Cost of removal (a)
162,169

150,123

Excess deferred income taxes (c)
286,587

310,562

TCJA revenue reserve
2,770

18,032

Other regulatory liabilities (c)
19,759

12,553

Total regulatory liabilities
523,941

540,794

Less current regulatory liabilities
(25,168
)
(29,810
)
Regulatory liabilities, non-current
$
498,773

$
510,984

__________
(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.

Regulatory Matters

Except as discussed below, there have been no other significant changes to our Regulatory Matters from those previously disclosed in Note 13 of the Notes to the Consolidated Financial Statements in our 2018 Annual Report on Form 10-K.


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Table of Contents

Regulatory Activity

Wyoming Gas

On June 13, 2019, we received approval from the WPSC to consolidate our Wyoming gas utility operations into a new utility entity.  The Wyoming portion of Black Hills Gas Distribution, LLC, Cheyenne Light’s natural gas utility operations (Cheyenne Gas and Northeast Wyoming), and Wyoming Gas (Northwest Wyoming) were combined into a new company called Black Hills Wyoming Gas, LLC.  On June 3, 2019, Wyoming Gas filed a rate review application with the WPSC to consolidate the rates, tariffs and services of its four existing gas distribution territories in Wyoming. The rate review requests $16 million in new revenue to recover investments in safety, reliability and system integrity. Wyoming Gas is also requesting a new rider mechanism to recover future safety and integrity investments in its system. A settlement was recently reached with the intervening parties in the rate review filing and filed with the WPSC on November 1, 2019. The stipulation and agreement are subject to review and approval by the WPSC, with a decision expected by the end of 2019.

South Dakota Electric and Wyoming Electric

South Dakota Electric and Wyoming Electric received approvals for the Renewable Ready Service Tariffs and related jointly-filed CPCN to construct the $57 million, 40 MW Corriedale Wind Energy Project. The wind project will be jointly owned by the two electric utilities to deliver renewable energy for large commercial, industrial and governmental agency customers. The project is expected to be in service by the end of 2020. In September 2019, the customer subscription period was completed with customer interest fulfilling the 40 MW of available energy. On November 1, 2019, South Dakota Electric filed with the SDPUC an amendment seeking approval to increase the generating capacity under the tariff for the South Dakota portion by 12.5 MW to a total of 32.5 MW.

Nebraska

On October 29, 2019, Nebraska Gas received approval from the NPSC to merge its two gas distribution companies in Nebraska. A rate review is expected to be filed by mid-year 2020 to consolidate the rates, tariffs and services of its two existing gas distribution companies.

Kansas

On June 25, 2019, Kansas Gas received approval from the Kansas Corporation Commission for an annual increase in revenue of $1.4 million, effective July 1, 2019, based on updates to the Gas System Reliability Surcharge Rider.

Wyoming Electric

On April 30, 2019, the WPSC approved Wyoming Electric’s application for a new Blockchain Interruptible Service Tariff. The utility has partnered with the economic development organization for City of Cheyenne and Laramie County to actively recruit blockchain customers to the state. This tariff is complementary to recently enacted Wyoming legislation supporting the development of blockchain within the state.

Colorado

On February 1, 2019, Colorado Gas filed a rate review with the CPUC requesting approval to consolidate rates, tariffs, and services of its two existing gas distribution territories in Colorado. The rate review requests $2.5 million in new revenue to recover investments in safety, reliability and system integrity. Colorado Gas is also requesting a new rider mechanism to recover future safety and integrity investments in its system. A decision from the CPUC is expected by March 2020.



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Table of Contents

(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, 2019
 
December 31, 2018
Materials and supplies
$
81,382

 
$
75,081

Fuel - Electric Utilities
2,535

 
2,850

Natural gas in storage held for distribution
39,085

 
39,368

Total materials, supplies and fuel
$
123,002

 
$
117,299





(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,
 
2019
2018
 
2019
2018
 
 
 
 
 
 
Net income available for common stock
$
11,740

$
16,950

 
$
130,131

$
171,871

 
 
 
 
 
 
Weighted average shares - basic
60,976

53,364

 
60,458

53,346

Dilutive effect of:
 
 
 
 
 
Equity Units (a)
—

1,344

 
—

1,060

Equity compensation
128

111

 
120

102

Weighted average shares - diluted
61,104

54,819

 
60,578

54,508


__________
(a)
Calculated using the treasury stock method. On November 1, 2018, we completed settlement of the stock purchase contracts that were components of the Equity Units issued in November 2015.

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,
 
2019
2018
 
2019
2018
 
 
 
 
 
 
Equity compensation
2

12

 
4

15

Restricted Stock
—

—

 
1

—

Anti-dilutive shares
2

12

 
5

15




(8)    NOTES PAYABLE, CURRENT MATURITIES AND DEBT

We had the following notes payable outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
 
September 30, 2019
December 31, 2018
 
Balance Outstanding
Letters of Credit
Balance Outstanding
Letters of Credit
Revolving Credit Facility
$
50,000

$
18,313

$
—

$
22,311

CP Program
244,900

—

185,620

—

Total
$
294,900

$
18,313

$
185,620

$
22,311



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Our $750 million corporate Revolving Credit Facility extends through July 30, 2023 with two, one year extension options (subject to consent from lenders). This facility includes an accordion feature that allows us, with the consent of the administrative agent, the issuing agents and each bank increasing or providing a new commitment, to increase total commitments 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 Corporate credit rating from S&P, Fitch, and Moody's for our senior unsecured long-term debt. Based on our credit ratings, the margins for base rate borrowings, Eurodollar borrowings, and letters of credit were 0.125%, 1.125%, and 1.125%, respectively, at September 30, 2019. Based on our credit ratings, a 0.175% commitment fee was charged on the unused amount at September 30, 2019.

We have 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 short-term borrowings (payments) during the nine months ended September 30, 2019 were $109 million. At September 30, 2019, the weighted average interest rate on short-term borrowings was 2.43%.

Debt Covenants

Under our 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 was calculated by dividing (i) Consolidated Indebtedness, which includes letters of credit and certain guarantees issued, by (ii) Capital, which includes Consolidated Indebtedness plus Net Worth, which excludes noncontrolling interest in subsidiaries. As of September 30, 2019, we were in compliance with these covenants.

Debt Transaction

On June 17, 2019, we amended our Corporate term loan due July 30, 2020. This amendment increased total commitments to $400 million from $300 million, extended the term through June 17, 2021, and had substantially similar terms and covenants as the amended and restated Revolving Credit Facility. The net proceeds from the increase in total commitments were used to pay down short-term debt. Proceeds from the October 3, 2019 public debt offering were used to repay this term loan.

Subsequent Event - Debt Offering

On October 3, 2019, we completed a public debt offering of $700 million principal amount in senior unsecured notes. The debt offering consisted of $400 million of 3.05% 10-year senior notes due October 15, 2029 and $300 million of 3.875% 30-year senior notes due October 15, 2049 (together the “Notes”). The proceeds of the Notes were used for the following:

•
Repay the $400 million Corporate term loan under the Amended and Restated Credit Agreement due June 17, 2021;

•
Retire the $200 million 5.875% senior notes due July 15, 2020; and

•
Repay a portion of short-term debt.



23

Table of Contents

(9)    EQUITY

At-the-Market Equity Offering Program

Our ATM equity offering program allows us to sell shares of our common stock with an aggregate value of up 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. During the three months ended September 30, 2019, we issued a total of 389,237 shares of common stock under the ATM equity offering program for proceeds of $30 million, net of $0.3 million in commissions. During the nine months ended September 30, 2019, we issued a total of 1,328,332 shares of common stock under the ATM equity offering program for proceeds of $99 million, net of $1.0 million in commissions. As of September 30, 2019, there were no shares that were sold, but not settled.


(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 and Credit Policies and Procedures as discussed in our 2018 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, but not limited to, commodity price risk associated with our retail natural gas marketing activities and our fuel procurement for certain 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 other than retail utility 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 guaranties, 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.

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, over-the-counter swaps and basis swaps to reduce our customers’ underlying exposure to these fluctuations. These transactions are considered derivatives, and in accordance with accounting standards for derivatives and hedging, mark-to-market adjustments are recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets, net of balance sheet offsetting as permitted by GAAP.

For our regulated utilities’ hedging plans, unrealized and realized gains and losses, as well as option premiums and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in the accompanying Condensed Consolidated Balance Sheets in accordance with state commission guidelines. When the related costs are recovered through our rates, the hedging activity is recognized in the Condensed Consolidated Statements of Income.


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 2019 through October 2021; a portion of these 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 gain or loss on these designated derivatives is reported in AOCI in the accompanying Condensed Consolidated Balance Sheets. Effectiveness of our hedged position is evaluated at inception of the hedge, upon occurrence of a triggering event and as of the end of each quarter.


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Table of Contents

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, 2019
 
December 31, 2018
 
Notional
(MMBtus)
 
Maximum
Term
(months) (a)
 
Notional
(MMBtus)
 
Maximum
Term
(months) (a)
Natural gas futures purchased
2,350,000

 
15
 
4,000,000

 
24
Natural gas options purchased, net
8,580,000

 
6
 
4,320,000

 
13
Natural gas basis swaps purchased
2,090,000

 
15
 
3,960,000

 
24
Natural gas over-the-counter swaps, net (b)
5,460,000

 
25
 
3,660,000

 
24
Natural gas physical contracts, net (c)
23,459,639

 
6
 
18,325,852

 
30

__________
(a)
Term reflects the maximum forward period hedged.
(b)
As of September 30, 2019, 1,812,500 MMBtus were designated as cash flow hedges.
(c)
Volumes exclude contracts that qualify for the normal purchase, normal sales exception.

Based on September 30, 2019 prices, a $0.4 million gain would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods.

We have certain derivative contracts which contain credit provisions. These credit provisions may require the Company to post collateral when credit exposure to the Company is in excess of a negotiated line of unsecured credit. At September 30, 2019, the Company posted $0.5 million related to such provisions, which is included in Other current assets on the Condensed Consolidated Balance Sheets.

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, 2019 and 2018. Note that this presentation does not reflect gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled.
Three Months Ended September 30, 2019
(in thousands)
Derivatives in Cash Flow Hedging Relationships
 
Location of
Reclassifications from AOCI into Income
 
Amount of
Gain/(Loss) Reclassified
from AOCI
into Income
Interest rate swaps
 
Interest expense
 
$
(713
)
Commodity derivatives
 
Fuel, purchased power and cost of natural gas sold
 
(129
)
Total
 
 
 
$
(842
)

Three Months Ended September 30, 2018
(in thousands)
Derivatives in Cash Flow Hedging Relationships
 
Location of
Reclassifications from AOCI into Income
 
Amount of
Gain/(Loss) Reclassified
from AOCI
into Income
Interest rate swaps
 
Interest expense
 
$
(712
)
Commodity derivatives
 
Fuel, purchased power and cost of natural gas sold
 
(18
)
Total
 
 
 
$
(730
)


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Table of Contents

Nine Months Ended September 30, 2019
(in thousands)
Derivatives in Cash Flow Hedging Relationships
 
Location of
Reclassifications from AOCI into Income
 
Amount of
Gain/(Loss) Reclassified
from AOCI
into Income
Interest rate swaps
 
Interest expense
 
$
(2,139
)
Commodity derivatives
 
Fuel, purchased power and cost of natural gas sold
 
508

Total
 
 
 
$
(1,631
)

Nine Months Ended September 30, 2018
(in thousands)
Derivatives in Cash Flow Hedging Relationships
 
Location of
Reclassifications from AOCI into Income
 
Amount of
Gain/(Loss) Reclassified
from AOCI
into Income
Interest rate swaps
 
Interest expense
 
$
(2,138
)
Commodity derivatives
 
Fuel, purchased power and cost of natural gas sold
 
(802
)
Total
 
 
 
$
(2,940
)

The following tables summarize 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, 2019 and 2018.
 
 
 
 
 
Three Months Ended September 30,
 
2019
 
2018
 
(in thousands)
Increase (decrease) in fair value:
 
 
 
Forward commodity contracts
$
(150
)
 
$
30

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

 
712

Forward commodity contracts
129

 
18

Total other comprehensive income (loss) from hedging
$
692

 
$
760

 
Nine Months Ended September 30,
 
2019
 
2018
 
(in thousands)
Increase (decrease) in fair value:
 
 
 
Forward commodity contracts
$
(434
)
 
$
(219
)
Recognition of (gains) losses in earnings due to settlements:
 
 
 
Interest rate swaps
2,139

 
2,138

Forward commodity contracts
(508
)
 
802

Total other comprehensive income (loss) from hedging
$
1,197

 
$
2,721



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Table of Contents

Derivatives Not Designated as Hedge Instruments

The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2019 and 2018 (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 profit or loss we realized when the underlying physical and financial transactions were settled.
 
 
 
 
 
 
 
Three Months Ended September 30,
 
 
2019
 
2018
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
Fuel, purchased power and cost of natural gas sold
$
(20
)
 
$
(96
)
Commodity derivatives
Other income (expense), net
142

 
—

 
 
$
122

 
$
(96
)

 
 
Nine Months Ended September 30,
 
 
2019
 
2018
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
Fuel, purchased power and cost of natural gas sold
$
(1,180
)
 
$
929

Commodity derivatives
Other income (expense), net
$
142

 
$
—

 
 
$
(1,038
)
 
$
929



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 or Regulatory liabilities. The net unrealized losses included in our Regulatory asset or Regulatory liability accounts related to the hedges in our utilities were $4.3 million and $6.2 million as of September 30, 2019 and December 31, 2018, respectively.


(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 2018 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

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 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.

Nonrecurring Fair Value Measurement

A discussion of the fair value of our investment in equity securities of a privately held oil and gas company, a Level 3 asset, is included in Note 21.

Recurring Fair Value Measurements

 
As of September 30, 2019
 
Level 1
Level 2
Level 3
 
Cash Collateral and Counterparty
Netting
Total
 
(in thousands)
Assets:
 
 
 
 
 
 
Commodity derivatives — Utilities
$
—

$
2,750

$
—

 
$
(2,335
)
$
415

Total
$
—

$
2,750

$
—

 
$
(2,335
)
$
415

 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
Commodity derivatives — Utilities
$
—

$
6,080

$
—

 
$
(3,471
)
$
2,609

Total
$
—

$
6,080

$
—

 
$
(3,471
)
$
2,609




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Table of Contents

 
As of December 31, 2018
 
Level 1
Level 2
Level 3
 
Cash Collateral and Counterparty
Netting
Total
 
(in thousands)
Assets:
 
 
 
 
 
 
Commodity derivatives — Utilities
$
—

$
2,927

$
—

 
$
(1,408
)
$
1,519

Total
$
—

$
2,927

$
—

 
$
(1,408
)
$
1,519

 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
Commodity derivatives — Utilities
$
—

$
6,801

$
—

 
$
(5,794
)
$
1,007

Total
$
—

$
6,801

$
—

 
$
(5,794
)
$
1,007



 
 
 
 
 
 
 


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 table presents the fair value and balance sheet classification of our derivative instruments (in thousands) as of:
 
Balance Sheet Location
 
September 30, 2019
December 31, 2018
Derivatives designated as hedges:
 
 
 
 
Asset derivative instruments:
 
 
 
 
Current commodity derivatives
Derivative assets — current
 
$
—

$
415

Noncurrent commodity derivatives
Other assets, non-current
 
2

18

Liability derivative instruments:
 
 
 
 
Current commodity derivatives
Derivative liabilities — current
 
(427
)
(114
)
Noncurrent commodity derivatives
Other deferred credits and other liabilities
 
(70
)
(4
)
Total derivatives designated as hedges
 
 
$
(495
)
$
315

 
 
 
 
 
Derivatives not designated as hedges:
 
 
 
 
Asset derivative instruments:
 
 
 
 
Current commodity derivatives
Derivative assets — current
 
$
412

$
1,085

Noncurrent commodity derivatives
Other assets, non-current
 
1

1

Liability derivative instruments:
 
 
 
 
Current commodity derivatives
Derivative liabilities — current
 
(1,969
)
(833
)
Noncurrent commodity derivatives
Other deferred credits and other liabilities
 
(143
)
(56
)
Total derivatives not designated as hedges
 
 
$
(1,699
)
$
197


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 2018 Annual Report on Form 10-K.


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(12)    FAIR VALUE OF FINANCIAL INSTRUMENTS

Other financial instruments for which the carrying value did not equal fair value were as follows (in thousands) as of:
 
September 30, 2019
 
December 31, 2018
 
Carrying
Amount
Fair Value
 
Carrying
Amount
Fair Value
Long-term debt, including current maturities (a) (b)
$
3,054,978

$
3,424,747

 
$
2,956,578

$
3,039,108

__________
(a)
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.
(b)
Carrying amount of long-term debt is net of deferred financing costs.


(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 Condensed Consolidated Statements of Income for the period (in thousands):
 
Location on the Condensed Consolidated Statements of Income
Amount Reclassified from AOCI
Three Months Ended
 
Nine Months Ended
September 30, 2019
September 30, 2018
 
September 30, 2019
September 30, 2018
Gains and (losses) on cash flow hedges:
 
 
 
 
 
 
Interest rate swaps
Interest expense
$
(713
)
$
(712
)
 
$
(2,139
)
$
(2,138
)
Commodity contracts
Fuel, purchased power and cost of natural gas sold

(129
)
(18
)
 
508

(802
)
 
 
(842
)
(730
)
 
(1,631
)
(2,940
)
Income tax
Income tax benefit (expense)
170

149

 
358

643

Total reclassification adjustments related to cash flow hedges, net of tax
 
$
(672
)
$
(581
)
 
$
(1,273
)
$
(2,297
)
 
 
 
 
 
 
 
Amortization of components of defined benefit plans:
 
 
 
 
 
 
Prior service cost
Operations and maintenance
$
20

$
44

 
$
59

$
133

 
 
 
 
 
 
 
Actuarial gain (loss)
Operations and maintenance
(84
)
(621
)
 
(525
)
(1,865
)
 
 
(64
)
(577
)
 
(466
)
(1,732
)
Income tax
Income tax benefit (expense)
89

128

 
184

380

Total reclassification adjustments related to defined benefit plans, net of tax
 
$
25

$
(449
)
 
$
(282
)
$
(1,352
)
Total reclassifications
 
$
(647
)
$
(1,030
)
 
$
(1,555
)
$
(3,649
)


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Balances by classification included within AOCI, net of tax on the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands):
 
Interest Rate Swaps
Commodity Derivatives
Employee Benefit Plans
Total
As of December 31, 2018
$
(17,307
)
$
328

$
(9,937
)
$
(26,916
)
Other comprehensive income (loss)
 
 
 
 
before reclassifications
—

(334
)
—

(334
)
Amounts reclassified from AOCI
1,639

(366
)
282

1,555

As of September 30, 2019
$
(15,668
)
$
(372
)
$
(9,655
)
$
(25,695
)
 
 
 
 
 
 
 
 
 
 
 
Interest Rate Swaps
Commodity Derivatives
Employee Benefit Plans
Total
As of December 31, 2017
$
(19,581
)
$
(518
)
$
(21,103
)
$
(41,202
)
Other comprehensive income (loss)
 
 
 
 
before reclassifications
—

(168
)
—

(168
)
Amounts reclassified from AOCI
1,682

615

1,352

3,649

Reclassifications of certain tax effects from AOCI
15

—

3

18

As of September 30, 2018
$
(17,884
)
$
(71
)
$
(19,748
)
$
(37,703
)



(14)    SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

Nine Months Ended
September 30, 2019
 
September 30, 2018
 
(in thousands)
Non-cash investing and financing activities —
 
 
 
Property, plant and equipment acquired with accrued liabilities
$
86,661

 
$
49,631

 
 
 
 
Cash (paid) refunded during the period —
 
 
 
Interest (net of amounts capitalized)
$
(99,375
)
 
$
(104,035
)
Income taxes
$
2,255

 
$
(14,842
)




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(15)    EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plan

The components of net periodic benefit cost for the Defined Benefit Pension Plan were as follows (in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2019
2018
 
2019
2018
Service cost
$
1,346

$
1,708

 
$
4,037

$
5,125

Interest cost
4,344

3,867

 
13,031

11,602

Expected return on plan assets
(6,100
)
(6,185
)
 
(18,300
)
(18,555
)
Prior service cost
6

15

 
19

44

Net loss (gain)
941

2,158

 
2,822

6,473

Net periodic benefit cost
$
537

$
1,563

 
$
1,609

$
4,689



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,
 
2019
2018
 
2019
2018
Service cost
$
454

$
573

 
$
1,362

$
1,718

Interest cost
560

521

 
1,683

1,563

Expected return on plan assets
(57
)
(57
)
 
(172
)
(170
)
Prior service cost (benefit)
(99
)
(99
)
 
(298
)
(297
)
Net loss (gain)
—

54

 
—

162

Net periodic benefit cost
$
858

$
992

 
$
2,575

$
2,976



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,
 
2019
2018
 
2019
2018
Service cost
$
429

$
632

 
$
2,406

$
1,347

Interest cost
324

293

 
972

878

Prior service cost
—

—

 
1

1

Net loss (gain)
134

250

 
402

750

Net periodic benefit cost
$
887

$
1,175

 
$
3,781

$
2,976




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Contributions

Contributions to the Defined Benefit Pension Plan are cash contributions made directly to the Pension Plan Trust account. Contributions to the Postretirement Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions made in 2019 and anticipated contributions for 2019 and 2020 are as follows (in thousands):
 
Contributions Made
Contributions Made
Additional Contributions
Contributions
 
Three Months Ended September 30, 2019
Nine Months Ended September 30, 2019
Anticipated for 2019
Anticipated for 2020
Defined Benefit Pension Plan
$
12,700

$
12,700

$
—

$
12,700

Non-pension Defined Benefit Postretirement Healthcare Plans
$
1,109

$
3,326

$
1,109

$
4,815

Supplemental Non-qualified Defined Benefit and Defined Contribution Plans
$
366

$
1,098

$
366

$
1,406




(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 2018 Annual Report on Form 10-K except for those described below.

Future Purchase Agreement - Related Party

On August 2, 2019, Black Hills Wyoming and Wyoming Electric filed a request with FERC for approval of a new 60 MW PPA. If approved, Black Hills Wyoming will continue to deliver 60 MW of energy to Wyoming Electric from its Wygen I power plant starting January 1, 2023, and continuing for 20 additional years. A decision from FERC is pending.

Platte River Power Authority PPAs

•
On June 26, 2019, Colorado Electric entered into a PPA with Platte River Power Authority to purchase up to 60 MW of wind energy upon construction completion of a new wind project, which is expected in mid-2020. This agreement will expire May 31, 2030.

•
On June 26, 2019, Colorado Electric entered into a PPA with Platte River Power Authority to purchase 25 MW of unit contingent energy. This agreement was effective September 1, 2019 and will expire June 30, 2024.

The following is a schedule of unconditional purchase obligations required under the 25 MW Platte River Power Authority PPA as of September 30, 2019 (in thousands):
2019
$
1,369

2020
$
5,475

2021
$
5,475

2022
$
5,475

2023
$
5,475

Thereafter
$
2,738






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(17)    DISCONTINUED OPERATIONS

Results of operations for discontinued operations were classified as Loss from discontinued operations, net of income taxes in the accompanying Condensed Consolidated Statements of Income. Prior periods relating to our discontinued operations were also reclassified to reflect consistency within our condensed consolidated financial statements.

Oil and Gas Segment

On November 1, 2017, the BHC Board of Directors approved a complete divestiture of our Oil and Gas segment. We completed the divestiture in 2018. See Note 21 for more information.


(18)    INCOME TAXES

Income tax benefit (expense) for the Three Months Ended September 30, 2019 Compared to the Three Months Ended September 30, 2018.

Income tax benefit (expense) for the three months ended September 30, 2019 was $(2.5) million compared to $(7.5) million reported for the same period in 2018. The decrease in tax expense was primarily due to a prior year $(5.3) million income tax expense associated with changes in the previously estimated impact of tax reform on deferred income taxes.

For the three months ended September 30, 2019 the effective tax rate was 14.0% compared to 7.6% excluding the tax reform adjustments, for the same period in 2018. The higher effective tax rate is primarily due to a prior year state tax benefit.

Income tax benefit (expense) for the Nine Months Ended September 30, 2019 Compared to the Nine Months Ended September 30, 2018.

Income tax benefit (expense) for the nine months ended September 30, 2019 was $(22) million compared to $12 million reported for the same period in 2018. The increase in tax expense was primarily due to a prior year $49 million tax benefit resulting from legal entity restructuring partially offset by a prior year $(7.5) million income tax expense associated with changes in the previously estimated impact of tax reform on deferred income taxes.

For the nine months ended September 30, 2019 the effective tax rate was 13.6% compared to 17.1% excluding the legal entity restructuring and tax reform adjustments, for the same period in 2018. The lower effective tax rate is primarily due to $5.0 million of federal production tax credits and related state investment tax credits associated with new wind assets and a $1.0 million tax benefit for deferred tax amortization related to tax reform.


(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, 2019
December 31, 2018
Accrued employee compensation, benefits and withholdings
$
57,313

$
63,742

Accrued property taxes
38,937

42,510

Customer deposits and prepayments
56,220

43,574

Accrued interest and contract adjustment payments
35,100

31,759

Other (none of which is individually significant)
30,262

33,916

Total accrued liabilities
$
217,832

$
215,501





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(20)     LEASES

Lessee
We lease from third parties certain office and operation center facilities, communication tower sites, equipment, and materials storage. Our leases have remaining terms ranging from less than one year to 37 years, including options to extend that are reasonably certain to be exercised.
The components of lease expense were as follows (in thousands):
 
Income Statement Location
Three Months Ended September 30, 2019
Nine Months Ended September 30, 2019
Operating lease cost
Operations and maintenance
$
380

$
1,076

Finance lease cost:
 
 
 
Amortization of right-of-use asset
Depreciation, depletion and amortization
28

72

Interest on lease liabilities
Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)
5

14

Total lease cost
 
$
413

$
1,162





Supplemental balance sheet information related to leases was as follows (in thousands):
 
Balance Sheet Location
As of September 30, 2019
Assets:
 
 
Operating lease assets
Other assets, non-current
$
4,864

Finance lease assets
Other assets, non-current
493

Total lease assets
 
$
5,357

 
 
 
Liabilities:
 
 
Current:
 
 
Operating leases
Accrued liabilities
$
970

Finance lease
Accrued liabilities
80

 
 
 
Noncurrent:
 
 
Operating leases
Other deferred credits and other liabilities
4,252

Finance lease
Other deferred credits and other liabilities
419

Total lease liabilities
 
$
5,721




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Supplemental cash flow information related to leases was as follows (in thousands):
 
Nine Months Ended September 30, 2019
Cash paid included in the measurement of lease liabilities:
 
Operating cash flows from operating leases
$
895

Operating cash flows from finance lease
$
14

Financing cash flows from finance lease
$
66

Right-of-use assets obtained in exchange for lease obligations:
 
Operating leases
$
2,775

Finance lease
$
67



 
As of September 30, 2019
Weighted average remaining lease term (years):
 
Operating leases
8 years

Finance lease
4 years

 
 
Weighted average discount rate:
 
Operating leases
4.27
%
Finance lease
4.19
%


As of September 30, 2019, scheduled maturities of lease liabilities for future years were as follows (in thousands):
 
Operating Leases
Finance Lease
Total
2019 (a)
$
368

$
32

$
400

2020
992

126

1,118

2021
855

126

981

2022
736

126

862

2023
714

126

840

Thereafter
2,682

10

2,692

Total lease payments (b)
$
6,347

$
546

$
6,893

Less imputed interest
1,125

47

1,172

Present value of lease liabilities
$
5,222

$
499

$
5,721


(a)
Includes lease liabilities for the remaining three months of 2019.
(b)
Lease payments exclude payments to landlords for common area maintenance, real estate taxes, and insurance.

As previously disclosed in Note 14 of the Notes to the Consolidated Financial Statements in our 2018 Annual Report on Form 10-K, prior to the adoption of ASU 2016-02, Leases (Topic 842), the future minimum payments required under operating lease agreements as of December 31, 2018 were as follows (in thousands):
 
Operating Leases
2019
$
1,052

2020
464

2021
344

2022
224

2023
216

Thereafter
1,776

Total lease payments 
$
4,076



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Lessor

We lease to third parties certain generating station ground leases, communication tower sites, and a natural gas pipeline. These leases have remaining terms ranging from less than one year to 35 years.

The components of lease revenue were as follows (in thousands):
 
Income Statement Location
Three Months Ended September 30, 2019
Nine Months Ended September 30, 2019
Operating lease income
Revenue
$
544

$
1,749




As of September 30, 2019, scheduled maturities of lease receivables for future years were as follows (in thousands):
 
Operating Leases
2019 (a)
$
551

2020
2,035

2021
1,857

2022
1,793

2023
1,799

Thereafter
55,481

Total lease receivables
$
63,516


(a)
Includes lease receivables for the remaining three months of 2019.


(21)     INVESTMENTS

In February 2018, we made a contribution of $28 million of assets in exchange for equity securities in a privately held oil and gas company as we divested from our Oil and Gas segment. The carrying value of our investment in the equity securities was recorded at cost. We review this investment on a periodic basis to determine whether a significant event or change in circumstances has occurred that may have an adverse effect on the value of the investment.

During the third quarter of 2019, we assessed our investment for impairment as a result of a deterioration in earnings performance of the privately held oil and gas company and an adverse change in future natural gas prices. We engaged a third-party valuation consultant to estimate the fair value of our investment. The valuation was primarily based on an income approach but also considered a market valuation approach. The significant inputs used to estimate the fair value were the oil and gas reserve quantities and values utilizing forward market price curves, industry standard reserve adjustment factors and a discount rate of 10%. Based on the results of the valuation, we concluded that the carrying value of the investment exceeded fair value. As a result, we recorded a pre-tax impairment loss of $20 million for the three and nine months ended September 30, 2019, which was the difference between the carrying amount and the fair value of the investment.

The following table presents the carrying value of our investments (in thousands) as of:
 
September 30, 2019
 
December 31, 2018
Investment in privately held oil and gas company
$
8,359

 
$
28,100

Cash surrender value of life insurance contracts
12,907

 
12,812

Other investments
317

 
101

Total investments
$
21,583

 
$
41,013





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Table of Contents

(22)    SUBSEQUENT EVENTS

There are no subsequent events, other than those disclosed in Note 8.


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 212,000 customers in Colorado, Montana, South Dakota and Wyoming. 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 1,054,000 natural gas customers. Additionally, we sell contractual pipeline capacity and gas commodities to other utilities and marketing companies, including our affiliates, on an as-available basis.

Our Gas Utilities also provide non-regulated services through Black Hills Energy Services. Black Hills Energy Services provides approximately 47,000 retail distribution customers in Nebraska and Wyoming with unbundled natural gas commodity offerings under the regulator-approved Choice Gas Program. We also sell, install and service air conditioning, heating and water-heating equipment, and provide associated repair service and protection plans under various trade names. Service Guard and CAPP provide appliance repair services to approximately 62,000 and 28,000 residential customers, respectively, through Company technicians and third-party service providers, typically through on-going monthly service agreements. Tech Services 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 extracts coal at our coal mine near Gillette, Wyoming and sells the coal primarily to on-site, mine-mouth power generation facilities.

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. All of our non-utility business segments support our utilities. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other.

Effective January 1, 2019, we changed our measure of segment performance to adjusted operating income, which impacted our segment disclosures for all periods presented. See Note 3 of the Notes to Condensed Consolidated Financial Statements 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. 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, 2019 and 2018, and our financial condition as of September 30, 2019 and December 31, 2018, 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 58.

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.

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Table of Contents


Results of Operations

Executive Summary, Significant Events and Overview

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2019
 
2018
 
2019
 
2018
(in millions, except per share amounts)
Income
EPS
 
Income
EPS
 
Income
EPS
 
Income
EPS
 
 
 
 
 
 
 
 
 
 
 
 
Net income from continuing operations available for common stock
$
11.7

$
0.19

 
$
17.8

$
0.32

 
$
130.1

$
2.15

 
$
177.5

$
3.26

Net (loss) from discontinued operations
—

—

 
(0.9
)
(0.02
)
 
—

—

 
(5.6
)
(0.10
)
Net income available for common stock
$
11.7

$
0.19

 
$
17.0

$
0.31

 
$
130.1

$
2.15

 
$
171.9

$
3.15



Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2018.

The variance to the prior year included the following:

•
Electric Utilities’ adjusted operating income increased $7.3 million primarily due to the prior year Wyoming Electric PCA settlement, warmer summer weather in Colorado and Wyoming, increased industrial demand, and increased rider revenues partially offset by higher operating expenses driven by outside services and employee costs;
•
Gas Utilities’ adjusted operating income increased $0.5 million primarily due to new rates, increased transport and transmission, and customer growth partially offset by lower heating demand from warmer weather, reduced irrigation demand due to heavy precipitation and higher operating expenses driven by outside services and employee costs;
•
Power Generation’s adjusted operating income decreased $1.3 million primarily due to higher depreciation and property taxes from new wind assets partially offset by higher revenue from increased wind MWh sold and higher PPA prices;
•
Mining’s adjusted operating income decreased $1.2 million primarily due to lower tons sold driven by unplanned generating facility outages partially offset by lower operating expenses;
•
A $20 million non-cash impairment of our investment in equity securities of a privately held oil and gas company; and
•
A prior year $5.3 million income tax expense associated with changes in the previously estimated impact of tax reform on deferred income taxes.

Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018.

The variance to the prior year included the following:

•
Electric Utilities’ adjusted operating income increased $2.1 million primarily due to reduced power capacity charges, the prior year Wyoming Electric PCA settlement and increased rider revenues partially offset by higher operating expenses driven by outside services and employee costs;
•
Gas Utilities’ adjusted operating income increased $0.4 million primarily due to new rates offset by higher operating expenses driven by outside services and employee costs;
•
Power Generation’s adjusted operating income increased $0.2 million primarily due to higher revenue from increased wind MWh sold partially offset by higher depreciation and property taxes from new wind assets;
•
Mining’s adjusted operating income decreased $3.3 million primarily due to lower tons sold driven by planned and unplanned generating facility outages partially offset by lower operating expenses;
•
Corporate and Other expenses decreased $2.3 million primarily due to prior year expenses related to the oil and gas segment that were not reclassified to discontinued operations;
•
A $20 million non-cash impairment of our investment in equity securities of a privately held oil and gas company;
•
A prior year $49 million tax benefit resulting from legal entity restructuring partially offset by a prior year $7.5 million income tax expense associated with changes in the previously estimated impact of tax reform on deferred income taxes; and
•
A lower current year effective tax rate primarily due to $5.0 million of federal production tax credits and related state investment tax credits associated with new wind assets and a $1.0 million tax benefit for deferred tax amortization related to tax reform.



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Table of Contents

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,
 
2019
2018
Variance
2019
2018
Variance
Revenue
 
 
 
 
 
 
Revenue
$
363,491

$
358,258

$
5,233

$
1,368,748

$
1,361,102

$
7,646

Inter-company eliminations
(37,943
)
(36,279
)
(1,664
)
(111,502
)
(108,030
)
(3,472
)
 
$
325,548

$
321,979

$
3,569

$
1,257,246

$
1,253,072

$
4,174

Adjusted operating income (a)
 
 
 
 
 
 
Electric Utilities
$
50,653

$
43,393

$
7,260

$
125,219

$
123,073

$
2,146

Gas Utilities
4,736

4,240

496

116,607

116,168

439

Power Generation
11,822

13,079

(1,257
)
33,945

33,731

214

Mining
3,374

4,551

(1,177
)
9,351

12,647

(3,296
)
Corporate and Other
(34
)
(178
)
144

(439
)
(2,709
)
2,270

Operating income
70,551

65,085

5,466

284,683

282,910

1,773

 
 
 

 
 
 
Interest expense, net
(33,487
)
(35,297
)
1,810

(102,469
)
(104,826
)
2,357

Impairment of investment
(19,741
)
—

(19,741
)
(19,741
)
—

(19,741
)
Other income (expense), net
580

(510
)
1,090

55

(1,923
)
1,978

Income tax benefit (expense)
(2,508
)
(7,477
)
4,969

(22,078
)
11,784

(33,862
)
Income from continuing operations
15,395

21,801

(6,406
)
140,450

187,945

(47,495
)
Net (loss) from discontinued operations
—

(857
)
857

—

(5,627
)
5,627

Net income
15,395

20,944

(5,549
)
140,450

182,318

(41,868
)
Net income attributable to noncontrolling interest
(3,655
)
(3,994
)
339

(10,319
)
(10,447
)
128

Net income available for common stock
$
11,740

$
16,950

$
(5,210
)
$
130,131

$
171,871

$
(41,740
)
__________
(a)
In 2019, we changed our measure of segment performance to adjusted operating income, which impacted our segment disclosures for all periods presented. See Note 3 of the Notes to Condensed Consolidated Financial Statements for additional information.

Overview of Business Segments and Corporate Activity

Electric Utilities Segment

•
Cooling degree days for the three and nine months ended September 30, 2019 were 27% and 14% higher than normal compared to 9% and 29% higher than normal for the same periods in 2018.

Heating degree days for the three and nine months ended September 30, 2019 were 36% lower and 6% higher than normal, compared to 20% and 3% lower than normal for the same periods in 2018.

•
On September 17, 2019, South Dakota Electric completed construction on the final 94-mile segment of a 175-mile electric transmission line from Rapid City, South Dakota, to Stegall, Nebraska. The first 48-mile segment was placed in service on July 25, 2018, and the second 33-mile segment was placed in service on November 20, 2018.

•
Colorado Electric and Wyoming Electric set new all-time and summer peak loads:

•
On July 19, 2019, Colorado Electric set a new peak load of 422 MW, exceeding the previous peak of 413 MW set in June 2018.

•
On July 19, 2019, Wyoming Electric set a new peak load of 265 MW, exceeding the previous peak of 254 MW set in July 2018.

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Table of Contents


•
South Dakota Electric and Wyoming Electric received approvals for the Renewable Ready Service Tariffs and related jointly-filed CPCN to construct the $57 million, 40 MW Corriedale Wind Energy Project. The wind project will be jointly owned by the two electric utilities to deliver renewable energy for large commercial, industrial and governmental agency customers. The project is expected to be in service by the end of 2020. In September 2019, the customer subscription period was completed with customer interest fulfilling the 40 MW of available energy. On November 1, 2019, South Dakota Electric filed with the SDPUC an amendment seeking approval to increase the generating capacity under the tariff for the South Dakota portion by 12.5 MW to a total of 32.5 MW.

Gas Utilities Segment

•
Heating degree days for the three and nine months ended September 30, 2019 were 62% lower and 7% higher than normal, compared to 27% lower and 0% higher than normal for the same periods in 2018.

•
Regulatory activity:

◦
On October 29, 2019, Nebraska Gas received approval from the NPSC to merge its two gas distribution companies in Nebraska. A rate review is expected to be filed by mid-year 2020 to consolidate the rates, tariffs and services of its two existing gas distribution companies.

◦
On June 3, 2019, Wyoming Gas filed a rate review application with the WSPC to consolidate the rates, tariffs and services of its four existing gas distribution territories in Wyoming. The rate review requests $16 million in new revenue to recover investments in safety, reliability and system integrity. Wyoming Gas is also requesting a new rider mechanism to recover future safety and integrity investments in its system. A settlement was recently reached with the intervening parties in the rate review filing and filed with the WPSC on November 1, 2019. The stipulation and agreement are subject to review and approval by the WPSC, with a decision expected by the end of 2019. See Note 5 of the Notes to Condensed Consolidated Financial Statements for additional details.

◦
On February 1, 2019, Colorado Gas filed a rate review with the CPUC requesting approval to consolidate rates, tariffs and services of its two existing gas distribution territories in Colorado. The rate review requests $2.5 million in new revenue to recover investments in safety, reliability and system integrity. Colorado Gas is also requesting a new rider mechanism to recover future safety and integrity investments in its system. A decision from the CPUC is expected by March 2020.

•
On May 10, 2019, Wyoming Gas commenced construction on the $54 million, 35-mile Natural Bridge pipeline project to enhance supply reliability and delivery capacity for customers in central Wyoming. The new 12-inch steel pipeline will interconnect from a supply point near Douglas, Wyoming, to existing facilities near Casper, Wyoming. Construction of the pipeline is nearly complete and the project is expected to be in service by the end of 2019, with the associated investment included in the Wyoming Gas rate review filed on June 3, 2019.

Power Generation Segment

•
On August 2, 2019 Black Hills Wyoming and Wyoming Electric jointly filed a request with FERC for approval of a new 60 MW PPA. If approved, Black Hills Wyoming will continue to deliver 60 MW of energy to Wyoming Electric from its Wygen I power plant starting January 1, 2023, and for 20 additional years. A decision from FERC is pending.

•
On March 11, 2019, Black Hills Electric Generation commenced construction on the $71 million, 60 MW Busch Ranch II Wind Farm. The project is expected to be fully in service by mid-November 2019.


Mining

•
In October, negotiations were completed for the price reopener in the contract with Wyodak Plant. The new price was reset at $17.94 per ton effective July 1, 2019, compared to the prior contract price of $18.25 per ton.

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Table of Contents



Corporate and Other

•
On October 15, 2019, Moody’s affirmed South Dakota Electric’s credit rating at A1.

•
On October 3, 2019, we completed a public debt offering of $700 million in senior unsecured notes. Proceeds were used to repay the $400 million Corporate term loan due June 17, 2021, retire the $200 million 5.875% senior notes due July 15, 2020 and repay a portion of short-term debt.

•
During the nine months ended September 30, 2019, we issued a total of 1,328,332 shares of common stock under the ATM equity offering program for net proceeds of $99 million.

•
On August 29, 2019, Fitch affirmed our BBB+ rating and maintained a Stable outlook.

•
On June 17, 2019, we amended our Corporate term loan due July 30, 2020. This amendment increased total commitments to $400 million from $300 million and extended the term through June 17, 2021 on substantially similar terms and covenants. The net proceeds were used to pay down short-term debt. Proceeds from the October 3, 2019 debt transaction were used to repay this term loan.

•
On April 30, 2019, S&P affirmed South Dakota Electric’s credit rating at A.

•
On February 28, 2019, S&P affirmed our BBB+ rating and maintained a Stable outlook.


Operating Results

A discussion of operating results from our segments and Corporate activities follows in the sections below. Revenues for operating segments in the following sections are presented in total and by retail class. For disaggregation of revenue by contract type and operating segment, see Note 2 of the Notes to Condensed Consolidated Financial Statements for more information.

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 and amortization 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 and natural gas purchases 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.


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Table of Contents

Electric Utilities

 
Three Months Ended September 30,
Nine Months Ended September 30,
 
2019
2018
Variance
2019
2018
Variance
 
(in thousands)
Revenue
$
191,384

$
184,790

$
6,594

$
540,665

$
531,961

$
8,704

 
 
 
 
 
 
 
Total fuel and purchased power
71,593

74,638

(3,045
)
207,004

209,317

(2,313
)
 
 
 
 
 
 
 
Gross margin (non-GAAP)
119,791

110,152

9,639

333,661

322,644

11,017

 
 
 
 
 
 
 
Operations and maintenance
47,172

45,307

1,865

143,049

135,501

7,548

Depreciation and amortization
21,966

21,453

513

65,393

64,070

1,323

Total operating expenses
69,138

66,760

2,378

208,442

199,571

8,871

 
 
 
 
 
 
 
Adjusted operating income (a)
$
50,653

$
43,392

$
7,261

$
125,219

$
123,073

$
2,146

________________
(a)
Due to the changes in our segment disclosures discussed in Note 3 of the Notes to Condensed Consolidated Financial Statements, Electric Utilities’ Adjusted operating income was revised for the three and nine months ended September 30, 2018, which resulted in an increase of $1.6 million and $4.8 million, respectively.


Results of Operations for the Electric Utilities for the Three Months Ended September 30, 2019 Compared to the Three Months Ended September 30, 2018:

Gross margin for the three months ended September 30, 2019 increased as a result of the following:
 
(in millions)
Prior year Wyoming Electric PCA Stipulation settlement
$
3.4

Weather
1.8

Increased industrial demand
1.7

Reduction in power capacity charges
1.7

Rider recovery
1.3

Other
(0.3
)
Total increase in Gross margin (non-GAAP)
$
9.6


Operations and maintenance expense increased primarily due to $1.0 million of higher employee costs and $0.6 million of higher outside services expenses.




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Table of Contents

Results of Operations for the Electric Utilities for the Nine Months Ended September 30, 2019 Compared to the Nine Months Ended September 30, 2018:

Gross margin for the nine months ended September 30, 2019 increased as a result of the following:
 
(in millions)
Reduction in power capacity charges
$
4.9

Prior year Wyoming Electric PCA Stipulation settlement
3.7

Rider recovery
2.0

Decreased residential customer usage
(0.9
)
Decreased commercial and industrial demand
(0.2
)
Weather
(0.1
)
Other
1.6

Total increase in Gross margin (non-GAAP)
$
11.0


Operations and maintenance expense increased primarily due to $3.6 million of higher employee costs and $3.4 million of higher outside services expenses.

Depreciation and amortization increased primarily due to a higher asset base driven by prior and current year capital expenditures.


Operating Statistics
 
 
Electric Revenue (in thousands)
 
Quantities sold (MWh)
 
 
Three Months Ended
September 30,
Nine Months Ended
September 30,
 
Three Months Ended
September 30,
Nine Months Ended
September 30,
 
 
2019
2018
2019
2018
 
2019
2018
2019
2018
Residential
 
$
58,919

$
58,122

$
162,257

$
163,979

 
384,735

372,623

1,075,394

1,084,531

Commercial
 
65,732

65,794

186,434

192,680

 
560,547

550,791

1,556,449

1,560,911

Industrial
 
33,937

31,939

98,074

93,959

 
462,809

429,133

1,335,260

1,248,438

Municipal
 
4,792

4,582

13,184

13,389

 
46,106

43,972

121,025

122,953

Subtotal Retail Revenue - Electric
 
163,380

160,437

459,949

464,007

 
1,454,197

1,396,519

4,088,128

4,016,833

Contract Wholesale
 
8,211

8,256

23,335

25,497

 
229,369

221,327

646,611

677,163

Off-system/Power Marketing Wholesale
 
6,452

9,059

16,592

18,142

 
160,357

206,791

436,298

514,686

Other
 
13,341

7,038

40,789

24,315

 
—

—

—

—

Total Revenue and Energy Sold
 
191,384

184,790

540,665

531,961

 
1,843,923

1,824,637

5,171,037

5,208,682

Other Uses, Losses or Generation, net
 
—

—

—

—

 
112,172

121,478

299,038

337,939

Total Revenue and Energy
 
191,384

184,790

540,665

531,961

 
1,956,095

1,946,115

5,470,075

5,546,621

Less cost of fuel and purchased power (a)
 
71,593

74,638

207,004

209,317

 
 
 
 
 
Gross Margin (non-GAAP) (a)
 
$
119,791

$
110,152

$
333,661

$
322,644

 
 
 
 
 
________________
(a)
Due to the changes in our segment disclosures discussed in Note 3 of the Notes to Condensed Consolidated Financial Statements, cost of fuel and purchased power was revised for the three and nine months ended September 30, 2018, which resulted in an increase of $1.6 million and $4.8 million, respectively. There were corresponding decreases to Gross margin for each period.


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Table of Contents

 
 
 
 
 
 
 
 
 
 
Three Months Ended September 30,
 
Electric Revenue
(in thousands)
 
Gross Margin (non-GAAP) (in thousands)
 
Quantities Sold (MWh) (a)
 
 
2019
2018
 
2019
2018
 
2019
2018
Colorado Electric (b)
 
$
70,771

$
68,052

 
$
41,916

$
38,449

 
634,098

610,079

South Dakota Electric
 
77,022

78,067

 
55,217

52,860

 
835,725

874,962

Wyoming Electric
 
43,591

38,671

 
22,658

18,843

 
486,272

461,074

Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold
 
$
191,384

$
184,790

 
$
119,791

$
110,152

 
1,956,095

1,946,115

 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30,
 
Electric Revenue
(in thousands)
 
Gross Margin (non-GAAP) (in thousands)
 
Quantities Sold (MWh) (a)
 
 
2019
2018
 
2019
2018
 
2019
2018
Colorado Electric (b)
 
$
186,030

$
188,937

 
$
104,411

$
105,997

 
1,611,126

1,639,607

South Dakota Electric
 
225,309

222,558

 
162,390

154,158

 
2,438,366

2,541,082

Wyoming Electric
 
129,326

120,466

 
66,860

62,489

 
1,420,583

1,365,932

Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold
 
$
540,665

$
531,961

 
$
333,661

$
322,644

 
5,470,075

5,546,621

________________
(a)
Total MWh for 2019 includes Other Uses, Losses or Generation, net, which are approximately 6%, 5%, and 6% for Colorado Electric, South Dakota Electric, and Wyoming Electric, respectively.
(b)
Due to the changes in our segment disclosures discussed in Note 3 of the Notes to Condensed Consolidated Financial Statements, Gross margin was revised for the three and nine months ended September 30, 2018, which resulted in a decrease of $(1.6) million and $(4.8) million, respectively.

 
Three Months Ended
September 30,
Nine Months Ended
September 30,
Quantities Generated and Purchased (MWh)
2019
2018
2019
2018
 
 
 
 
 
Coal-fired
564,220

608,417

1,621,355

1,772,750

Natural Gas and Oil
234,366

199,351

445,498

345,978

Wind
55,407

54,450

167,331

196,932

Total Generated
853,993

862,218

2,234,184

2,315,660

Purchased
1,102,102

1,083,897

3,235,891

3,230,961

Total Generated and Purchased
1,956,095

1,946,115

5,470,075

5,546,621


 
Three Months Ended
September 30,
Nine Months Ended
September 30,
Quantities Generated and Purchased (MWh)
2019
2018
2019
2018
Generated:
 
 
 
 
Colorado Electric
149,509

163,276

341,925

388,251

South Dakota Electric
489,042

469,680

1,262,336

1,293,713

Wyoming Electric
215,442

229,262

629,923

633,696

Total Generated
853,993

862,218

2,234,184

2,315,660

Purchased:
 
 
 
 
Colorado Electric
484,589

446,803

1,269,201

1,251,356

South Dakota Electric
346,683

405,282

1,176,030

1,247,369

Wyoming Electric
270,830

231,812

790,660

732,236

Total Purchased
1,102,102

1,083,897

3,235,891

3,230,961

 
 
 
 
 
Total Generated and Purchased
1,956,095

1,946,115

5,470,075

5,546,621



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Table of Contents

 
 
 
 
 
 
 
 
 
 
 
Three Months Ended September 30,
Degree Days
 
 
2019
 
 
 
2018
 
Actual
 
Variance from
Normal
 
Actual Variance to Prior Year
 
Actual
 
Variance from
Normal
Heating Degree Days:
 
 
 
 
 
 
 
 
 
Colorado Electric
4

 
(96
)%
 
(89)%
 
35

 
(64
)%
South Dakota Electric
175

 
(22
)%
 
(26)%
 
236

 
5
 %
Wyoming Electric
120

 
(77
)%
 
(52)%
 
248

 
(19
)%
Combined (a)
86

 
(36
)%
 
(41)%
 
147

 
(20
)%
 
 
 
 
 
 
 
 
 
 
Cooling Degree Days:
 
 
 
 
 
 
 
 
 
Colorado Electric
1,079

 
58
 %
 
19%
 
910

 
33
 %
South Dakota Electric
366

 
(31
)%
 
3%
 
356

 
(33
)%
Wyoming Electric
433

 
45
 %
 
32%
 
328

 
10
 %
Combined (a)
705

 
27
 %
 
17%
 
603

 
9
 %

 
Nine Months Ended September 30,
 
2019
 
 
 
2018
Heating Degree Days
Actual
 
Variance from
Normal
 
Actual Variance to Prior Year
 
Actual
 
Variance from
Normal
 
 
 
 
 
 
 
 
 
 
Colorado Electric
3,156

 
(6
)%
 
9%
 
2,901

 
(14
)%
South Dakota Electric
5,370

 
20
 %
 
8%
 
4,972

 
11
 %
Wyoming Electric
4,677

 
5
 %
 
9%
 
4,285

 
(9
)%
Combined (a)
4,198

 
6
 %
 
8%
 
3,888

 
(3
)%
 
 
 
 
 
 
 
 
 
 
Cooling Degree Days:
 
 
 
 
 
 
 
 
 
Colorado Electric
1,226

 
37
 %
 
(13)%
 
1,404

 
57
 %
South Dakota Electric
404

 
(36
)%
 
(17)%
 
488

 
(23
)%
Wyoming Electric
462

 
33
 %
 
7%
 
430

 
24
 %
Combined (a)
791

 
14
 %
 
(12)%
 
895

 
29
 %
__________
(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,
 
2019
2018
2019
2018
Coal-fired plants (a)
94.6
%
95.7
%
90.0
%
94.0
%
Natural gas-fired plants and Other plants (b)
89.6
%
97.0
%
89.8
%
97.2
%
Wind
93.7
%
96.9
%
95.0
%
96.9
%
Total availability
91.5
%
96.6
%
90.3
%
96.1
%
 
 
 
 
 
Wind capacity factor
33.8
%
33.1
%
37.1
%
41.8
%
__________
(a)
2019 included planned outages at Neil Simpson II and Wygen III and unplanned outages at Wyodak Plant and Wygen III.
(b)
2019 included planned outages at Neil Simpson CT and Lange CT.



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Table of Contents


Gas Utilities
 
Three Months Ended September 30,
Nine Months Ended September 30,
 
2019
2018
Variance
2019
2018
Variance
 
(in thousands)
Revenue:
 
 
 
 
 
 
Natural gas - regulated
$
117,549

$
117,070

$
479

$
651,366

$
648,550

$
2,816

Other - non-regulated services
13,195

14,606

(1,411
)
55,927

58,090

(2,163
)
Total revenue
130,744

131,676

(932
)
707,293

706,640

653

 
 
 
 
 
 
 
Cost of sales:
 
 
 
 
 
 
Natural gas - regulated
28,154

30,612

(2,458
)
280,312

298,149

(17,837
)
Other - non-regulated services
4,870

5,514

(644
)
16,975

15,716

1,259

Total cost of sales
33,024

36,126

(3,102
)
297,287

313,865

(16,578
)
 
 
 
 
 
 
 
Gross margin (non-GAAP)
97,720

95,550

2,170

410,006

392,775

17,231

 
 
 
 
 
 
 
Operations and maintenance
70,170

69,746

424

225,239

212,319

12,920

Depreciation and amortization
22,814

21,564

1,250

68,160

64,288

3,872

Total operating expenses
92,984

91,310

1,674

293,399

276,607

16,792

 
 
 
 
 
 
 
Adjusted operating income
$
4,736

$
4,240

$
496

$
116,607

$
116,168

$
439



Results of Operations for the Gas Utilities for the Three Months Ended September 30, 2019 Compared to the Three Months Ended September 30, 2018:

Gross margin for the three months ended September 30, 2019 increased as a result of:
 
(in millions)
New rates
$
3.0

Customer growth - distribution
0.8

Increased transport and transmission
0.7

Weather (a)
(3.4
)
Other
1.1

Total increase in Gross margin (non-GAAP)
$
2.2


(a) Weather impacts for the three months ended September 30, 2019 compared to the same period in the prior year include reduced heating demand due to warmer temperatures and reduced irrigation loads to agriculture customers in our Nebraska Gas service territory due to higher precipitation.

Operations and maintenance expense increased primarily due to higher employee costs and higher outside services expenses.

Depreciation and amortization increased primarily due to a higher asset base driven by prior and current year capital expenditures.


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Table of Contents

Results of Operations for the Gas Utilities for the Nine Months Ended September 30, 2019 Compared to the Nine Months Ended September 30, 2018:

Gross margin for the nine months ended September 30, 2019 increased as a result of:
 
(in millions)
New rates
$
15.5

Customer growth - distribution
3.7

Increased transport and transmission
1.8

Decreased mark-to-market on non-utility natural gas commodity contracts
(2.7
)
Excess deferred taxes returned to customers
(2.5
)
Weather
(0.6
)
Other
2.0

Total increase in Gross margin (non-GAAP)
$
17.2


Operations and maintenance expense increased primarily due to $7.2 million of higher outside services expenses, $4.1 million of higher employee costs and $1.3 million of higher property taxes due to a higher asset base driven by prior and current year capital expenditures.

Depreciation and amortization increased primarily due to a higher asset base driven by prior and current year capital expenditures.


Operating Statistics
 
 
Gas Revenue (in thousands)
 
Gross Margin (non-GAAP)                                                                      (in thousands)
 
Gas Utilities Quantities Sold & Transported (Dth)
 
 
Three Months Ended
September 30,
 
Three Months Ended
September 30,
 
Three Months Ended
September 30,
 
 
2019
2018
 
2019
2018
 
2019
2018
 
 
 
 
 
 
 
 
 
 
Residential
 
$
57,244

$
58,221

 
$
43,441

$
42,598

 
3,599,549

3,708,196

Commercial
 
19,629

19,639

 
11,589

10,880

 
2,298,919

2,278,304

Industrial
 
8,770

8,258

 
2,493

2,028

 
2,960,930

2,304,098

Other (a)
 
2,499

487

 
2,499

487

 
—

—

Total Distribution
 
88,142

86,605

 
60,022

55,993

 
8,859,398

8,290,598

 
 
 
 
 
 
 
 
 
 
Transportation and Transmission
 
29,407

30,465

 
29,373

30,465

 
31,538,815

29,808,567

 
 
 
 
 
 
 
 
 
 
Total Regulated
 
117,549

117,070

 
89,395

86,458

 
40,398,213

38,099,165

 
 
 
 
 
 
 
 
 
 
Non-regulated Services
 
13,195

14,606

 
8,325

9,092

 
 
 
 
 
 
 
 
 
 
 
 
 
Total Gas Revenue & Gross Margin (non-GAAP)
 
$
130,744

$
131,676

 
$
97,720

$
95,550

 
 
 


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Table of Contents

 
 
 
 
 
 
 
 
 
 
 
 
Gas Revenue (in thousands)
 
Gross Margin (non-GAAP)                                                                      (in thousands)
 
Gas Utilities Quantities Sold & Transported (Dth)
 
 
Nine Months Ended
September 30,
 
Nine Months Ended
September 30,
 
Nine Months Ended
September 30,
 
 
2019
2018
 
2019
2018
 
2019
2018
 
 
 
 
 
 
 
 
 
 
Residential
 
$
383,466

$
383,972

 
$
201,168

$
192,072

 
44,356,725

42,642,021

Commercial
 
146,752

148,675

 
61,673

57,890

 
21,484,646

20,842,996

Industrial
 
18,764

20,805

 
5,830

5,341

 
5,141,399

5,235,417

Other (a)
 
(968
)
(6,789
)
 
(968
)
(6,789
)
 
—

—

Total Distribution
 
548,014

546,663

 
267,703

248,514

 
70,982,770

68,720,434

 
 
 
 
 
 
 
 
 
 
Transportation and Transmission
 
103,352

101,887

 
103,351

101,887

 
110,622,285

107,388,321

 
 
 
 
 
 
 
 
 
 
Total Regulated
 
651,366

648,550

 
371,054

350,401

 
181,605,055

176,108,755

 
 
 
 
 
 
 
 
 
 
Non-regulated Services
 
55,927

58,090

 
38,952

42,374

 
 
 
 
 
 
 
 
 
 
 
 
 
Total Gas Revenue & Gross Margin
 
$
707,293

$
706,640

 
$
410,006

$
392,775

 
 
 

(a)
Other revenue reflects the impact of revenue reserved in accordance with the TCJA.


 
 
Revenue (in thousands)
 
Gross Margin (non-GAAP)                                                                        (in thousands)
 
Gas Utilities Quantities Sold & Transported (Dth)

 
 
Three Months Ended
September 30,
 
Three Months Ended
September 30,
 
Three Months Ended
September 30,
 
 
2019
2018
 
2019
2018
 
2019
2018
 
 
 
 
 
 
 
 
 
 
Arkansas
 
$
21,387

$
18,743

 
$
16,249

$
13,415

 
4,094,454

4,022,089

Colorado
 
22,632

22,362

 
15,667

15,210

 
3,806,360

2,893,029

Iowa
 
16,381

16,982

 
13,135

12,556

 
5,686,772

5,595,205

Kansas
 
19,013

18,497

 
12,309

11,129

 
7,602,758

6,164,821

Nebraska
 
35,715

40,553

 
28,046

31,264

 
13,999,302

13,831,306

Wyoming
 
15,616

14,539

 
12,314

11,976

 
5,208,567

5,592,715

Total Gas Revenue & Gross Margin (non-GAAP)
 
$
130,744

$
131,676

 
$
97,720

$
95,550

 
40,398,213

38,099,165


 
 
 
 
 
 
 
 
 
 
 
 
Revenue (in thousands)
 
Gross Margin (non-GAAP)                                                                        (in thousands)
 
Gas Utilities Quantities Sold & Transported (Dth)

 
 
Nine Months Ended
September 30,
 
Nine Months Ended
September 30,
 
Nine Months Ended
September 30,
 
 
2019
2018
 
2019
2018
 
2019
2018
 
 
 
 
 
 
 
 
 
 
Arkansas
 
$
127,014

$
116,226

 
$
79,148

$
65,803

 
21,061,567

21,183,322

Colorado
 
135,816

125,898

 
73,022

66,917

 
23,050,638

19,301,834

Iowa
 
105,736

111,968

 
50,773

49,630

 
28,834,731

28,527,522

Kansas
 
77,609

81,880

 
42,385

40,896

 
24,336,744

23,391,905

Nebraska
 
183,827

196,307

 
111,828

117,925

 
57,815,316

58,223,856

Wyoming
 
77,291

74,361

 
52,850

51,604

 
26,506,059

25,480,316

Total Gas Revenue & Gross Margin (non-GAAP)
 
$
707,293

$
706,640

 
$
410,006

$
392,775

 
181,605,055

176,108,755


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.


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Table of Contents

 
Three Months Ended September 30,
 
2019
 
 
 
2018
Heating Degree Days
Actual
 
Variance
from Normal
 
Actual Variance to Prior Year
 
Actual
 
Variance
from Normal
Arkansas (a)
—
 
(100)%
 
(100)%
 
12
 
(72)%
Colorado
68
 
(68)%
 
(38)%
 
109
 
(49)%
Iowa
43
 
(69)%
 
(66)%
 
128
 
(7)%
Kansas (a)
—
 
(101)%
 
(100)%
 
54
 
(2)%
Nebraska
22
 
(80)%
 
(78)%
 
101
 
(7)%
Wyoming
183
 
(37)%
 
(22)%
 
236
 
(23)%
Combined (b)
53
 
(62)%
 
(51)%
 
109
 
(27)%


 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30,
 
2019
 
 
 
2018
Heating Degree Days:
Actual
 
Variance
from Normal
 
Actual Variance to Prior Year
 
Actual
 
Variance
from Normal
Arkansas (a)
2,347
 
(5)%
 
(5)%
 
2,460
 
(1)%
Colorado
4,115
 
—%
 
16%
 
3,548
 
(14)%
Iowa
4,611
 
10%
 
3%
 
4,460
 
6%
Kansas (a)
3,204
 
8%
 
6%
 
3,032
 
2%
Nebraska
4,169
 
10%
 
4%
 
4,016
 
6%
Wyoming
5,093
 
9%
 
12%
 
4,552
 
(4)%
Combined (b)
4,297
 
7%
 
7%
 
4,008
 
—%
__________
(a)
Arkansas and Kansas have weather normalization mechanisms that mitigate the weather impact on gross margins.
(b)
The combined heating degree days are calculated based on a weighted average of total customers by state excluding Kansas due to its weather normalization mechanism. Arkansas is excluded based on the weather normalization mechanism in effect from November through April.


Regulatory Matters

For more information on recent regulatory activity and enacted regulatory provisions with respect to the states in which our Utilities operate, see Note 5 of the Notes to Condensed Consolidated Financial Statements and Part I, Items 1 and 2 and Part II, Item 8 of our 2018 Annual Report on Form 10-K filed with the SEC.


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Table of Contents

Power Generation
 
Three Months Ended September 30,
Nine Months Ended September 30,
 
2019
2018
Variance
2019
2018
Variance
 
(in thousands)
Revenue
$
25,811

$
24,491

$
1,320

$
75,764

$
71,173

$
4,591

 
 
 
 
 
 
 
Operations and maintenance
9,229

7,434

1,795

27,750

25,520

2,230

Depreciation and amortization
4,760

3,978

782

14,069

11,922

2,147

Total operating expense
13,989

11,412

2,577

41,819

37,442

4,377

 
 
 
 
 
 
 
Adjusted operating income (a)
$
11,822

$
13,079

$
(1,257
)
$
33,945

$
33,731

$
214

________________
(a)
Due to the changes in our segment disclosures discussed in Note 3 of the Notes to Condensed Consolidated Financial Statements, Power Generation Adjusted operating income was revised for the three and nine months ended September 30, 2018, which resulted in a decrease of $(1.4) million and $(4.4) million, respectively.


Results of Operations for Power Generation for the Three and Nine Months Ended September 30, 2019 Compared to the Three and Nine Months Ended September 30, 2018:

Revenue increased in the current year due to increased wind MWh sold and higher PPA prices. Operating expenses increased in the current year primarily due to higher depreciation and property taxes from new wind assets.

The following table summarizes MWh for our Power Generation segment:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2019
2018
 
2019
2018
Quantities Sold, Generated and Purchased
(MWh) (a)
 
 
 
 
 
Sold
 
 
 
 
 
Black Hills Colorado IPP (b)
275,867

304,102

 
692,156

745,365

Black Hills Wyoming (c)
162,668

160,011

 
476,430

470,072

Black Hills Electric Generation (d)
30,912

—

 
112,461

—

Total Sold
469,447

464,113

 
1,281,047

1,215,437

 
 
 
 
 
 
Generated
 
 
 
 
 
Black Hills Colorado IPP (b)
275,867

304,102

 
692,156

745,365

Black Hills Wyoming (c)
142,219

144,476

 
407,001

407,324

Black Hills Electric Generation (d)
30,912

—

 
112,461

—

Total Generated
448,998

448,578

 
1,211,618

1,152,689

 
 
 
 
 
 
Purchased
 
 
 
 
 
Black Hills Wyoming (c)
16,865

16,685

 
56,205

65,724

Total Purchased
16,865

16,685

 
56,205

65,724

____________
(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 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.
(d)
Increase from prior year is driven by Black Hills Electric Generation’s acquisition of new wind assets.


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Table of Contents

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,
 
2019
2018
 
2019
2018
Contracted power plant fleet availability:
 
 
 
 
 
Coal-fired plant
98.0
%
97.9
%
 
95.2
%
93.9
%
Natural gas-fired plants (a)
97.6
%
99.3
%
 
98.4
%
99.4
%
Wind (b)
81.9
%
N/A

 
93.4
%
N/A

Total availability
93.6
%
98.9
%
 
96.5
%
98.0
%
 
 
 
 
 
 
Wind capacity factor (b)
15.0
%
N/A

 
22.1
%
N/A

____________
(a)
2019 included a planned outage at Pueblo Airport Generating Station.
(b)
Change from the prior year is driven by Black Hills Electric Generation’s acquisition of new wind assets.

Mining

Three Months Ended September 30,
Nine Months Ended September 30,

2019
2018
Variance
2019
2018
Variance

(in thousands)
Revenue
$
15,552

$
17,301

$
(1,749
)
$
45,026

$
51,328

$
(6,302
)
 
 
 
 
 
 
 
Operations and maintenance
9,900

10,761

(861
)
28,988

32,807

(3,819
)
Depreciation, depletion and amortization
2,278

1,989

289

6,687

5,874

813

Total operating expenses
12,178

12,750

(572
)
35,675

38,681

(3,006
)
 
 
 
 
 
 
 
Adjusted operating income
$
3,374

$
4,551

$
(1,177
)
$
9,351

$
12,647

$
(3,296
)

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,
 
2019
2018
 
2019
2018
Tons of coal sold
969

1,078

 
2,720

3,119

Cubic yards of overburden moved
2,341

2,361

 
6,380

6,763

 
 
 
 
 
 
Revenue per ton
$
15.47

$
15.54

 
$
15.90

$
15.92


Results of Operations for Mining for the Three Months Ended September 30, 2019 Compared to the Three Months Ended September 30, 2018:

Current year revenue decreased due to 10% fewer tons sold driven primarily by unplanned generation facility outages. Operating expenses decreased primarily due to lower royalties and production taxes on decreased revenues.


Results of Operations for Mining for the Nine Months Ended September 30, 2019 Compared to the Nine Months Ended September 30, 2018:

Current year revenue decreased due to 13% fewer tons sold driven primarily by planned and unplanned generation facility outages. Operating expenses decreased primarily due to lower royalties and production taxes on decreased revenues and lower fuel, labor and major maintenance expenses.

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Table of Contents

Corporate and Other
 
Three Months Ended September 30,
Nine Months Ended September 30,
 
2019
2018
Variance
2019
2018
Variance
 
(in thousands)
Adjusted operating income (loss) (a)
$
(34
)
$
(178
)
$
144

$
(439
)
$
(2,709
)
$
2,270

________________
(a)
Due to the changes in our segment disclosures as discussed in Note 3 of the Notes to Condensed Consolidated Financial Statements, Corporate and Other Adjusted operating income (loss) was revised for the three and nine months ended September 30, 2018, which resulted in a decrease of $(0.2) million and $(0.4) million, respectively.

Results of Operations for Corporate and Other for the Nine Months Ended September 30, 2019 Compared to the Three and Nine Months Ended September 30, 2018:

The variance in Adjusted operating income (loss) was primarily due to prior year expenses related to the oil and gas segment that were not reclassified to discontinued operations.


Consolidated Interest expense, Impairment of investment, Other income (expense) and Income tax benefit (expense) for the Three Months Ended September 30, 2019 Compared to the Three Months Ended September 30, 2018.

Impairment of Investment

For the three months ended September 30, 2019, we recorded a non-cash write-down of $20 million in our investment in equity securities of a privately held oil and gas company. The impairment was triggered by a deterioration in earnings performance of the privately held oil and gas company and an adverse change in future natural gas prices. See Note 21 of the Notes to Condensed Consolidated Financial Statements for additional details.

Income Tax Benefit (Expense)

Income tax benefit (expense) for the three months ended September 30, 2019 was $(2.5) million compared to $(7.5) million for the same period in 2018. The decrease in tax expense was primarily due to a prior year $(5.3) million income tax expense associated with changes in the previously estimated impact of tax reform on deferred income taxes.

For the three months ended September 30, 2019 the effective tax rate was 14.0% compared to 7.6% excluding the tax reform adjustments, for the same period in 2018. The higher effective tax rate is primarily due to a prior year state tax benefit.
  
Consolidated Interest expense, Impairment of investment, Other income (expense) and Income tax benefit (expense) for the Nine Months Ended September 30, 2019 Compared to the Nine Months Ended September 30, 2018.

Impairment of Investment

For the nine months ended September 30, 2019, we recorded a non-cash write-down of $20 million in our investment in equity securities of a privately held oil and gas company. The impairment was triggered by a deterioration in earnings performance of the privately held oil and gas company and an adverse change in future natural gas prices. See Note 21 of the Notes to Condensed Consolidated Financial Statements for additional details.


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Table of Contents

Income Tax Benefit (Expense)

Income tax benefit (expense) for the nine months ended September 30, 2019 was $(22) million compared to $12 million reported for the same period in 2018. The increase in tax expense was primarily due to a prior year $49 million tax benefit resulting from legal entity restructuring partially offset by a prior year $(7.5) million income tax expense associated with changes in the previously estimated impact of tax reform on deferred income taxes.

For the nine months ended September 30, 2019 the effective tax rate was 13.6% compared to 17.1% excluding the legal entity restructuring and tax reform adjustments, for the same period in 2018. The lower effective tax rate is primarily due to $5.0 million of federal production tax credits and related state investment tax credits associated with new wind assets, a $1.0 million tax benefit for deferred tax amortization related to tax reform.

Critical Accounting Estimates

There have been no material changes in our critical accounting estimates from those reported in our 2018 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 2018 Annual Report on Form 10-K.

Liquidity and Capital Resources

There have been no material changes in Liquidity and Capital Resources from those reported in Item 7 of our 2018 Annual Report on Form 10-K filed with the SEC except as described below.

Collateral Requirements

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, 2019, we had sufficient liquidity to cover collateral that could be required to be posted under these contracts.

Income Tax

The TCJA required revaluation of federal deferred tax assets and liabilities using the new lower corporate tax rate of 21%. We have reached agreements with regulators in seven states and are working with FERC regarding returning benefits to customers. Our working capital requirements increased as a result of complying with the TCJA and providing the benefits of the TCJA to customers. These agreements will negatively impact our cash flows by approximately $40 million to $45 million per year for each of the next several years.

Cash Flow Activities

The following table summarizes our cash flows for the nine months ended September 30, 2019 (in thousands):
Cash provided by (used in):
2019
2018
Variance
Operating activities
$
386,075

$
378,722

$
7,353

Investing activities
$
(593,272
)
$
(281,771
)
$
(311,501
)
Financing activities
$
199,827

$
(101,949
)
$
301,776



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Table of Contents

Year-to-Date 2019 Compared to Year-to-Date 2018

Operating Activities

Net cash provided by operating activities was $386 million for the nine months ended September 30, 2019, compared to net cash provided by operating activities of $379 million for the same period in 2018 for an increase of $7 million. The variance was primarily attributable to:

•
Cash earnings (income from continuing operations plus non-cash adjustments) were $19 million higher for the nine months ended September 30, 2019 compared to the same period in the prior year;

•
Net cash inflows from changes in operating assets and liabilities were $28 million for the nine months ended September 30, 2019, compared to net cash inflows of $42 million in the same period in the prior year. This $14 million decrease was primarily due to:

◦
Cash inflows increased by approximately $48 million primarily as a result of higher collections of accounts receivable for the nine months ended September 30, 2019 compared to the same period in the prior year;

◦
Cash outflows increased by approximately $3 million as a result of decreases in accounts payable and accrued liabilities driven by higher employee costs and other working capital requirements; and

◦
Cash inflows decreased by approximately $66 million as a result of changes in the timing of recovery from fuel cost adjustments as well as revenue reserved in the prior year due to the TCJA tax rate change that has subsequently been returned to customers.

Investing Activities

Net cash used in investing activities was $593 million for the nine months ended September 30, 2019, compared to net cash used in investing activities of $282 million for the same period in 2018 for a variance of $311 million. The variance was primarily attributable to:

•
Capital expenditures of approximately $593 million for the nine months ended September 30, 2019 compared to $278 million for the same period in the prior year. Higher current year expenditures are driven by higher programmatic safety, reliability and integrity spending at our Gas Utilities and Electric Utilities segments, the 35-mile Natural Bridge pipeline project at our Gas Utilities segment, the Busch Ranch II wind project at our Power Generation segment and construction of the final segment of the 175-mile transmission line from Rapid City, South Dakota, to Stegall, Nebraska at our Electric Utilities segment.

•
A $24 million investment made in the prior year partially offset by an $18 million change in net cash provided by investing activities from discontinued operations primarily due to the prior year sale of assets held for sale.


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Table of Contents

Financing Activities

Net cash provided by financing activities for the nine months ended September 30, 2019 was $200 million, compared to $102 million of net cash used in financing activities for the same period in 2018 for a variance of $302 million. This variance is primarily due to:

•
We amended our Corporate term loan due July 30, 2020, which increased our debt to $400 million from $300 million;

•
Current year issuance of common stock for net proceeds of $99 million through our ATM equity offering program;

•
Current year net short-term borrowings of $109 million driven by increased capital expenditures;

•
In the prior year, $99 million of net proceeds from the August 17, 2018 debt transaction was used to repay short-term debt;

•
$15 million of higher current year dividend payments; and

•
Payments for other financing activities decreased by $8.4 million, which was primarily driven by prior year financing costs associated with the July 30, 2018 and August 17, 2018 debt transactions.

Dividends

Dividends paid on our common stock totaled $92 million for the nine months ended September 30, 2019, or $0.505 per share per quarter. On October 31, 2019, our board of directors declared a quarterly dividend of $0.535 per share payable December 1, 2019, equivalent to an annual dividend of $2.14 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.


Financing Transactions and Short-Term Liquidity

Revolving Credit Facility and CP Program

Our Revolving Credit Facility had the following borrowings, outstanding letters of credit, and available capacity (in millions):
 
 
Current
Short-term borrowings at
Letters of Credit at
Available Capacity at
Credit Facility
Expiration
Capacity
September 30, 2019
September 30, 2019
September 30, 2019
Revolving Credit Facility and CP Program
July 30, 2023
$
750

$
295

$
18

$
437


The weighted average interest rate on short-term borrowings at September 30, 2019 was 2.43%. Short-term borrowing activity for the nine months ended September 30, 2019 was (dollars in millions):
 
For the Nine Months Ended September 30, 2019
Maximum amount outstanding - short-term borrowing (based on daily outstanding balances)
$
295

Average amount outstanding - short-term borrowing (based on daily outstanding balances)
$
171

Weighted average interest rates - short-term borrowing
2.59
%


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Table of Contents

Covenant Requirements

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. 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, 2019. See Note 8 of the Notes to Condensed Consolidated Financial Statements for more information.

Covenants within Wyoming Electric’s financing agreements require Wyoming Electric to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of September 30, 2019, we were in compliance with these covenants.
Financing Activities

Financing activities for the nine months ended September 30, 2019 consisted of the following:

•
We issued a total of 1,328,332 shares of common stock under the ATM equity offering program for proceeds of $99 million, net of $1.0 million in commissions. As of September 30, 2019, there were no shares that were sold, but not settled.

•
On June 17, 2019, we amended our Corporate term loan due July 30, 2020. This amendment increased total commitments to $400 million from $300 million, extended the term through June 17, 2021 and continues to have substantially similar terms and covenants as the amended and restated Revolving Credit Facility. The net proceeds were used to pay down short-term debt. Proceeds from the October 3, 2019 debt transaction were used to repay this term loan.

•
Short-term borrowings from our CP Program and Revolver.

On October 3, 2019, we completed a public debt offering of $700 million principal amount in senior unsecured notes. The debt offering consisted of $400 million of 3.05% 10-year senior notes due October 15, 2029 and $300 million of 3.875% 30-year senior notes due October 15, 2049. Proceeds were used to repay the $400 million Corporate term loan due June 17, 2021, retire the $200 million 5.875% senior notes due July 15, 2020, repay a portion of short-term debt.

Future Financing Plans

We will continue to assess debt and equity needs to support our capital expenditure plan.

Credit Ratings

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.

The following table represents the credit ratings and outlook and risk profile of BHC at September 30, 2019:
Rating Agency
Senior Unsecured Rating
Outlook
S&P (a)
BBB+
Stable
Moody’s (b)
Baa2
Stable
Fitch (c)
  BBB+
Stable
__________
(a)
On February 28, 2019, S&P affirmed our BBB+ rating and maintained a Stable outlook.
(b)
On December 12, 2018, Moody’s affirmed our Baa2 rating and maintained a Stable outlook.
(c)
On August 29, 2019, Fitch affirmed our BBB+ rating and maintained a Stable outlook.


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Table of Contents

The following table represents the credit ratings of South Dakota Electric at September 30, 2019:
Rating Agency
Senior Secured Rating
S&P (a)
A
Moody’s (b)
A1
Fitch (c)
A
__________
(a)
On April 30, 2019, S&P affirmed A rating.
(b)
On October 15, 2019, Moody’s affirmed A1 rating.
(c)
On August 29, 2019, Fitch affirmed A rating.

Capital Requirements

Capital Expenditures
 
Actual
Planned
Planned
Planned
Planned
Planned
Capital Expenditures by Segment
Nine Months Ended September 30, 2019 (a)
2019 (b)
2020
2021
2022
2023
(in millions)
 
 
 
 
 
 
Electric Utilities (c)
$
147

$
215

$
229

$
203

$
170

$
137

Gas Utilities (c)
367

490

361

297

274

303

Power Generation
79

84

7

9

11

6

Mining
6

8

8

12

9

9

Corporate and Other
15

23

18

22

11

12

 
$
614

$
820

$
623

$
543

$
475

$
467

__________
(a)    Expenditures for the nine months ended September 30, 2019 include the impact of accruals for property, plant and equipment.
(b)    Includes actual capital expenditures for the nine months ended September 30, 2019.
(c)    Planned capital expenditures increased for 2019 through 2023 primarily due to increased programmatic safety, reliability and integrity spending.

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 2018 Annual Report on Form 10-K except for the items described in Notes 8, 16, and 20 of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.


Off-Balance Sheet Commitments

There have been no significant changes to off-balance sheet commitments from those previously disclosed in Item 7 of our 2018 Annual Report on Form 10-K filed with the SEC except for the items described in Note 8 of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

New Accounting Pronouncements

Other than the pronouncements reported in our 2018 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.


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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 the statement was made. 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 2018 Annual Report on Form 10-K including statements contained within Item 1A - Risk Factors of our 2018 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.

ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information regarding our quantitative and qualitative disclosures about market risk is disclosed in Item 7A of our Annual Report on Form 10-K. During the nine months ended September 30, 2019, there were no material changes to our quantitative and qualitative disclosures about market risk.

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, 2019. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at September 30, 2019.

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, 2019, 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.



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BLACK HILLS CORPORATION

Part II — Other Information


ITEM 1.
Legal Proceedings

For information regarding legal proceedings, see Note 19 in Item 8 of our 2018 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 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 6.
Exhibits

Exhibit Number
Description
 
 
Exhibit 3.1*
 
 
Exhibit 3.2*
 
 
Exhibit 4.1*
 
 
 
 
 
 
 
 
 
 
Exhibit 4.2*
 
 
 

59


 
 
Exhibit 4.3*
 
 
 
 
Exhibit 4.4*
 
 
Exhibit 10.1
 
 
Exhibit 31.1
 
 
Exhibit 31.2
 
 
Exhibit 32.1
 
 
Exhibit 32.2
 
 
Exhibit 95
 
 
101.INS
XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH
XBRL Taxonomy Extension Schema Document
101.CAL
XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF
XBRL Taxonomy Extension Definition Linkbase Document
101.LAB
XBRL Taxonomy Extension Label Linkbase Document
101.PRE
XBRL Taxonomy Extension Presentation Linkbase Document
 
 
104
Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101)
__________
*
Previously filed as part of the filing indicated and incorporated by reference herein.


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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/ Linden R. Evans
 
 
Linden R. Evans, President and
 
 
  Chief Executive Officer
 
 
 
 
 
/s/ Richard W. Kinzley
 
 
Richard W. Kinzley, Senior Vice President and
 
 
  Chief Financial Officer
 
 
 
Dated:
November 5, 2019
 


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