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



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

Form 10-Q
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
 
EXCHANGE ACT OF 1934
 
For the quarterly period ended March 31, 2019
OR
 
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
 
EXCHANGE ACT OF 1934
 
For the transition period from __________ to __________.
 
 
 
Commission File Number 001-31303
Black Hills Corporation
Incorporated in South Dakota
 
IRS Identification Number 46-0458824
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 o
 
 
 
 
 
 
 
Non-accelerated filer o
 
Smaller reporting company o
 
 
 
 
 
 
 
 
 
Emerging growth company o
 

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

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
 
Yes o
 
No x
 
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 April 30, 2019
Common stock, $1.00 par value
60,367,972

shares





TABLE OF CONTENTS
 
 
 
Page
 
Glossary of Terms and Abbreviations
 
 
 
 
 
PART I.
FINANCIAL INFORMATION
 
 
 
 
 
Item 1.
Financial Statements
 
 
 
 
 
 
Condensed Consolidated Statements of Income - unaudited
 
 
 
   Three Months Ended March 31, 2019 and 2018
 
 
 
 
 
 
Condensed Consolidated Statements of Comprehensive Income - unaudited
 
 
 
   Three Months Ended March 31, 2019 and 2018
 
 
 
 
 
 
Condensed Consolidated Balance Sheets - unaudited
 
 
 
   March 31, 2019, December 31, 2018 and March 31, 2018
 
 
 
 
 
 
Condensed Consolidated Statements of Cash Flows - unaudited
 
 
 
   Three Months Ended March 31, 2019 and 2018
 
 
 
 
 
 
Notes to Condensed Consolidated Financial Statements - unaudited
 
 
 
 
 
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
 
 
 
 
Item 3.
Quantitative and Qualitative Disclosures about Market Risk
 
 
 
 
 
Item 4.
Controls and Procedures
 
 
 
 
 
PART II.
OTHER INFORMATION
 
 
 
 
 
Item 1.
Legal Proceedings
 
 
 
 
 
Item 1A.
Risk Factors
 
 
 
 
 
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
 
 
 
 
 
Item 4.
Mine Safety Disclosures
 
 
 
 
 
Item 5.
Other Information
 
 
 
 
 
Item 6.
Exhibits
 
 
 
 
 
 
Signatures
 


2



GLOSSARY OF TERMS AND ABBREVIATIONS

The following terms and abbreviations appear in the text of this report and have the definitions described below:
AFUDC
Allowance for Funds Used During Construction
AOCI
Accumulated Other Comprehensive Income (Loss)
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)
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 distributes the gas and Black Hills Energy Services is one of the Choice Gas suppliers.
CIAC
Contribution In Aid of Construction
City of Gillette
Gillette, Wyoming
Colorado Electric
Black Hills Colorado Electric, LLC, 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 Credit Agreement.
Cooling Degree Day (CDD)
A cooling degree day is equivalent to each degree that the average of the high and low temperature for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations.
CPCN
Certificate of Public Convenience and Necessity
CP Program
Commercial Paper Program
CPUC
Colorado Public Utilities Commission
CVA
Credit Valuation Adjustment
Dodd-Frank
Dodd-Frank Wall Street Reform and Consumer Protection Act
Dth
Dekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu)

3



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.
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
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
SEC
U. S. Securities and Exchange Commission
SourceGas
SourceGas Holdings LLC and its subsidiaries, a gas utility owned by funds managed by Alinda Capital Partners and GE Energy Financial Services, a unit of General Electric Co. (NYSE:GE) that was acquired on February 12, 2016, and is now named Black Hills Gas Holdings, LLC (doing business as Black Hills Energy)
SourceGas Acquisition
The acquisition of SourceGas Holdings, LLC by Black Hills Utility Holdings
S&P
Standard and Poor’s, a division of The McGraw-Hill Companies, Inc.
South Dakota Electric
Includes Black Hills Power operations in South Dakota, Wyoming and Montana
SSIR
System Safety and Integrity Rider
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.
WPSC
Wyoming Public Service Commission
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


4



 

BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
Three Months Ended March 31,
 
2019
2018
 
(in thousands, except per share amounts)
 
 
 
Revenue
$
597,810

$
575,389

 
 
 
Operating expenses:
 
 
Fuel, purchased power and cost of natural gas sold
248,779

247,639

Operations and maintenance
123,913

116,096

Depreciation, depletion and amortization
51,028

48,590

Taxes - property and production
13,519

13,300

Other operating expenses
440

1,490

Total operating expenses
437,679

427,115

 
 
 
Operating income
160,131

148,274

 
 
 
Other income (expense):
 
 
Interest charges -
 
 
Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)
(35,974
)
(35,438
)
Allowance for funds used during construction - borrowed
958

133

Interest income
299

310

Allowance for funds used during construction - equity
48

68

Other income (expense), net
(837
)
(172
)
Total other income (expense)
(35,506
)
(35,099
)
 
 
 
Income before income taxes
124,625

113,175

Income tax benefit (expense)
(17,263
)
25,802

Income from continuing operations
107,362

138,977

Net (loss) from discontinued operations

(2,343
)
Net income
107,362

136,634

Net income attributable to noncontrolling interest
(3,554
)
(3,630
)
Net income available for common stock
$
103,808

$
133,004

 
 
 
Amounts attributable to common shareholders:
 
 
Net income from continuing operations
$
103,808

$
135,347

Net (loss) from discontinued operations

(2,343
)
Net income available for common stock
$
103,808

$
133,004

 
 
 
Earnings (loss) per share of common stock, Basic -
 
 
Earnings from continuing operations
$
1.73

$
2.54

(Loss) from discontinued operations

(0.05
)
Total earnings per share of common stock, Basic
$
1.73

$
2.49

 
 
 
Earnings (loss) per share of common stock, Diluted -
 
 
Earnings from continuing operations
$
1.73

$
2.50

(Loss) from discontinued operations

(0.04
)
Total earnings per share of common stock, Diluted
$
1.73

$
2.46

 
 
 
Weighted average common shares outstanding:
 
 
Basic
59,920

53,319

Diluted
60,060

54,122



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

5




BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)
Three Months Ended
March 31,
 
2019
2018
 
(in thousands)
 
 
 
Net income
$
107,362

$
136,634

 
 
 
Other comprehensive income (loss), net of tax:
 
 
Reclassification adjustments of benefit plan liability - prior service cost (net of tax of $5 and $10, respectively)
(14
)
(35
)
Reclassification adjustments of benefit plan liability - net gain (loss) (net of tax of $(53) and $(136), respectively)
167

486

Derivative instruments designated as cash flow hedges:
 
 
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(163) and $(152), respectively)
550

561

Net unrealized gains (losses) on commodity derivatives (net of tax of $(54) and $69, respectively)
180

(228
)
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $128 and $(145), respectively)
(426
)
476

Other comprehensive income, net of tax
457

1,260

 
 
 
Comprehensive income
107,819

137,894

Less: comprehensive income attributable to noncontrolling interest
(3,554
)
(3,630
)
Comprehensive income available for common stock
$
104,265

$
134,264


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



BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)
As of
 
March 31,
2019
 
December 31, 2018
 
March 31,
2018
 
(in thousands)
ASSETS
 
 
 
 
 
Current assets:
 
 
 
 
 
Cash and cash equivalents
$
12,225

 
$
20,776

 
$
30,947

Restricted cash
3,494

 
3,369

 
2,958

Accounts receivable, net
282,602

 
269,153

 
257,772

Materials, supplies and fuel
87,676

 
117,299

 
82,045

Derivative assets, current
932

 
1,500

 
295

Income tax receivable, net
15,309

 
12,978

 
13,900

Regulatory assets, current
54,303

 
48,776

 
54,492

Other current assets
28,029

 
29,982

 
24,972

Current assets held for sale

 

 
24,724

Total current assets
484,570

 
503,833

 
492,105

 
 
 
 
 
 
Investments
41,247

 
41,013

 
40,927

 
 
 
 
 
 
Property, plant and equipment
6,127,050

 
6,000,015

 
5,608,539

Less: accumulated depreciation and depletion
(1,187,112
)
 
(1,145,136
)
 
(1,048,933
)
Total property, plant and equipment, net
4,939,938

 
4,854,879

 
4,559,606

 
 
 
 
 
 
Other assets:
 
 
 
 
 
Goodwill
1,299,454

 
1,299,454

 
1,299,454

Intangible assets, net
14,136

 
14,337

 
7,357

Regulatory assets, non-current
232,404

 
235,459

 
212,740

Other assets, non-current
25,823

 
14,352

 
14,800

Total other assets, non-current
1,571,817

 
1,563,602

 
1,534,351

 
 
 
 
 
 
TOTAL ASSETS
$
7,037,572

 
$
6,963,327

 
$
6,626,989


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

7



BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Continued)
(unaudited)
As of
 
March 31,
2019
 
December 31, 2018
 
March 31,
2018
 
(in thousands, except share amounts)
LIABILITIES AND TOTAL EQUITY
 
 
 
 
 
Current liabilities:
 
 
 
 
 
Accounts payable
$
178,678

 
$
210,609

 
$
106,281

Accrued liabilities
196,072

 
215,501

 
194,040

Derivative liabilities, current
95

 
947

 
891

Regulatory liabilities, current
45,777

 
29,810

 
42,499

Notes payable
164,650

 
185,620

 
164,200

Current maturities of long-term debt
5,743

 
5,743

 
255,743

Current liabilities held for sale

 

 
24,910

Total current liabilities
591,015

 
648,230

 
788,564

 
 
 
 
 
 
Long-term debt
2,950,299

 
2,950,835

 
2,858,787

 
 
 
 
 
 
Deferred credits and other liabilities:
 
 
 
 
 
Deferred income tax liabilities, net
337,184

 
311,331

 
290,491

Regulatory liabilities, non-current
511,482

 
510,984

 
495,362

Benefit plan liabilities
145,883

 
145,147

 
160,580

Other deferred credits and other liabilities
118,007

 
109,377

 
105,221

Total deferred credits and other liabilities
1,112,556

 
1,076,839

 
1,051,654

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


 

 

 
 
 
 
 
 
Equity:
 
 
 
 
 
Stockholders’ equity —
 
 
 
 
 
Common stock $1 par value; 100,000,000 shares authorized; issued 60,378,020; 60,048,567; and 53,648,817 shares, respectively
60,378

 
60,049

 
53,649

Additional paid-in capital
1,469,410

 
1,450,569

 
1,151,933

Retained earnings
777,262

 
700,396

 
656,161

Treasury stock, at cost – 23,756; 44,253; and 53,959 shares, respectively
(1,432
)
 
(2,510
)
 
(3,049
)
Accumulated other comprehensive income (loss)
(26,459
)
 
(26,916
)
 
(39,924
)
Total stockholders’ equity
2,279,159

 
2,181,588

 
1,818,770

Noncontrolling interest
104,543

 
105,835

 
109,214

Total equity
2,383,702

 
2,287,423

 
1,927,984

 
 
 
 
 
 
TOTAL LIABILITIES AND TOTAL EQUITY
$
7,037,572

 
$
6,963,327

 
$
6,626,989


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

8



BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
Three Months Ended March 31,
 
2019
2018
Operating activities:
(in thousands)
Net income
$
107,362

$
136,634

Loss from discontinued operations, net of tax

2,343

Income from continuing operations
107,362

138,977

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation, depletion and amortization
51,028

48,590

Deferred financing cost amortization
2,007

1,900

Stock compensation
3,296

2,209

Deferred income taxes
19,602

(25,430
)
Employee benefit plans
3,137

3,378

Other adjustments, net
4,428

3,053

Changes in certain operating assets and liabilities:
 
 
Materials, supplies and fuel
29,387

31,196

Accounts receivable, unbilled revenues and other operating assets
(15,857
)
(25,113
)
Accounts payable and other operating liabilities
(41,689
)
(71,149
)
Regulatory assets - current
13,031

47,903

Regulatory liabilities - current
(1,635
)
16,098

Other operating activities, net
1,796

(278
)
Net cash provided by operating activities of continuing operations
175,893

171,334

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

(1,459
)
Net cash provided by operating activities
175,893

169,875

 
 
 
Investing activities:
 
 
Property, plant and equipment additions
(144,126
)
(69,972
)
Purchase of investment

(23,500
)
Other investing activities
(901
)
(261
)
Net cash provided by (used in) investing activities of continuing operations
(145,027
)
(93,733
)
Net cash provided by (used in) investing activities of discontinued operations

20,179

Net cash provided by (used in) investing activities
(145,027
)
(73,554
)
 
 
 
Financing activities:
 
 
Dividends paid on common stock
(30,332
)
(25,444
)
Common stock issued
19,949

372

Net (payments) borrowings of short-term debt
(20,970
)
(47,100
)
Long-term debt - repayments
(1,436
)
(1,436
)
Distributions to noncontrolling interest
(4,846
)
(5,648
)
Other financing activities
(1,657
)
(1,400
)
Net cash provided by (used in) financing activities
(39,292
)
(80,656
)
Net change in cash, cash equivalents and restricted cash
(8,426
)
15,665

Cash, cash equivalents and restricted cash at beginning of period
24,145

18,240

Cash, cash equivalents and restricted cash at end of period
$
15,719

$
33,905



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.

9



BLACK HILLS CORPORATION

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

Accounting standards for presentation of segments requires an approach based on the way we organize the segments for making operating decisions and how the chief operating decision maker (CODM) assesses performance.  We have changed our segment performance metrics and 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 CODM assesses the performance of our segments by using adjusted operating income, which considers the power sales arrangement between Colorado IPP and Colorado Electric be treated as an executory contract. Adjusted operating income adjusts this power sales arrangement from being accounted for as a capital lease to being accounted for as an executory contract on an accrual basis. This adjustment impacts Electric Utilities and Power Generation segments and Corporate and Other. There were no adjustments to Gas Utilities and Mining segments and this adjustment had no effect on our consolidated operating income.
 
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 profit and adjust revenues, operating income, and total assets for the power sales agreement to an executory contract and not a capital lease. See Notes 2 and 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 of our Oil and Gas segment in 2018. The Oil and Gas segment assets and liabilities have been classified as held for sale and the results of operations are 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 for more information on discontinued operations.


10




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 March 31, 2019, December 31, 2018, and March 31, 2018 financial information and are of a normal recurring nature. Certain industries in which we operate are highly seasonal, and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements. In particular, the normal peak usage season for electric utilities is June through August while the normal peak usage season for gas utilities is November through March. Significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three months ended March 31, 2019 and March 31, 2018, and our financial condition as of March 31, 2019, December 31, 2018, and March 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.

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.

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.




11




(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 months ended March 31, 2019 and 2018. Sales tax and other similar taxes are excluded from revenues.

 
 
 
 
 
 
 

 
 
 
 
 
 
 
Three Months Ended March 31, 2019
 Electric Utilities
 Gas Utilities
 
 Power Generation (a)
 Mining
Inter-company Revenues (a)
Total
Customer types:
(in thousands)
Retail
$
153,463

$
354,275

 
$

$
15,829

$
(8,128
)
$
515,439

Transportation

44,517

 


(432
)
44,085

Wholesale
8,343


 
15,469


(13,213
)
10,599

Market - off-system sales
6,692

217

 


(2,224
)
4,685

Transmission/Other
14,175

13,190

 


(4,203
)
23,162

Revenue from contracts with customers
182,673

412,199

 
15,469

15,829

(28,200
)
597,970

Other revenues
254

(1,119
)
(b) 
9,776

600

(9,671
)
(160
)
Total revenues
$
182,927

$
411,080

 
$
25,245

$
16,429

$
(37,871
)
$
597,810

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

$

 
$

$
15,829

$
(8,128
)
$
7,701

Services transferred over time
182,673

412,199

 
15,469


(20,072
)
590,269

Revenue from contracts with customers
$
182,673

$
412,199

 
$
15,469

$
15,829

$
(28,200
)
$
597,970

 
 
 
 
 
 
 
 





12



Three Months Ended March 31, 2018
 Electric Utilities
 Gas Utilities
 
 Power Generation (a)
 Mining
Inter-company Revenues (a)
Total
Customer Types:
 
 
 
 
 
 
 
Retail
$
147,057

$
341,394

 
$

$
16,557

$
(7,842
)
$
497,166

Transportation

41,669

 


(409
)
41,260

Wholesale
9,050


 
14,769


(13,049
)
10,770

Market - Off-System Sales
4,144

427

 


(2,522
)
2,049

Transmission/Other
13,071

12,670

 


(3,631
)
22,110

Revenue from contracts with customers
$
173,322

$
396,160

 
$
14,769

$
16,557

$
(27,453
)
$
573,355

Other Revenues
233

1,184

(b) 
9,170

571

(9,124
)
2,034

Total Revenues
$
173,555

$
397,344

 
$
23,939

$
17,128

$
(36,577
)
$
575,389

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

$

 
$

$
16,557

$
(7,842
)
$
8,715

Services transferred over time
173,322

396,160

 
14,769


(19,611
)
564,640

Revenue from contracts with customers
$
173,322

$
396,160

 
$
14,769

$
16,557

$
(27,453
)
$
573,355

 
 
 
 
 
 
 
 


(a)
Due to changes to our segment performance measure as disclosed in Note 1, Power Generation Wholesale revenue was recast for the three months ended March 31, 2018 which resulted in a change of $0.8 million. For the three months ended March 31, 2019, the impact to Power Generation Wholesale revenue was $3.4 million. The changes to Power Generation were offset by changes to eliminations in Inter-company Revenues and there was no impact to our consolidated Total Revenues.
(b)
Other revenues in the Gas Utilities segment include alternative revenue programs related to weather normalization mechanisms for Arkansas Gas and Kansas Gas that are considered out of scope for ASC 606.

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 exists. 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.


13



(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.

As disclosed in Note 1, changes to our segment performance measure resulted in a revision of the Company’s segment disclosures for all periods to adjust revenues, operating income, and assets related to the power sales arrangement between Colorado IPP and Colorado Electric from being accounted for as a capital lease to being accounted for as an executory contract on an accrual basis. This change had no effect on our consolidated revenues, operating income, or total assets. See below for more information.

Segment information and Corporate and Other is as follows (in thousands):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended March 31, 2019
External Operating
Revenue
 
Inter-company Operating Revenue
 
Total Revenues
 Contract Customers
 Other Revenues
 Contract Customers
 Other Revenues
Segment:
 
 
 
 
 
 
 
Electric Utilities
$
176,663

$
254

 
$
6,010

$

 
$
182,927

Gas Utilities (a)
411,500

(1,119
)
 
699


 
411,080

Power Generation (b)
2,257

436

 
13,212

9,340

 
25,245

Mining
7,550

269

 
8,279

331

 
16,429

Corporate and Other


 


 

Inter-company eliminations (b)


 
(28,200
)
(9,671
)
 
(37,871
)
Total
$
597,970

$
(160
)
 
$

$

 
$
597,810

 
 
 
 
 
 
 
 
Three Months Ended March 31, 2018
External Operating Revenue
 
Inter-company Operating Revenue
 
 Total Revenues
 Contract Customers
 Other Revenues
 Contract Customers
 Other Revenues
Segment:
 
 
 
 
 
 
 
Electric Utilities
$
167,178

$
233

 
$
6,144

$

 
$
173,555

Gas Utilities (a)
395,742

1,184

 
418


 
397,344

Power Generation (b)
1,720

371

 
13,049

8,799

 
23,939

Mining
8,715

246

 
7,842

325

 
17,128

Corporate and Other


 


 

Inter-company eliminations (b)


 
(27,453
)
(9,124
)
 
(36,577
)
Total
$
573,355

$
2,034

 
$

$

 
$
575,389



(a)
Other revenues in the Gas Utilities segment include alternative revenue programs related to weather normalization mechanisms for Arkansas Gas and Kansas Gas that are considered out of scope for ASC 606.
(b)
Due to changes to our segment performance measure, Power Generation Inter-company Operating Revenue for Contract Customers was recast for the three months ended March 31, 2018 which resulted in a change of $0.8 million. For the three months ended March 31, 2019, the impact to Power Generation Inter-company Operating Revenue for Contract Customers was $3.4 million. The changes to Power Generation were offset by changes to Inter-company eliminations and there was no impact on our consolidated Total revenues.

14



 
 
 
 
Three Months Ended March 31,
 
2019
2018
Adjusted operating income:
 
 
Electric Utilities (a)
$
41,020

$
38,480

Gas Utilities
103,314

95,443

Power Generation (a)
11,967

11,776

Mining
4,337

4,271

Corporate and Other (a)
(507
)
(1,696
)
Operating income
160,131

148,274

 
 
 
Interest expense, net
(34,717
)
(34,995
)
Other income (expense), net
(789
)
(104
)
Income tax benefit (expense) (b)
(17,263
)
25,802

Income from continuing operations
107,362

138,977

Net (loss) from discontinued operations

(2,343
)
Net income
107,362

136,634

Net income attributable to noncontrolling interest
(3,554
)
(3,630
)
Net income available for common stock
$
103,808

$
133,004

___________
(a)
Due to changes to our segment performance measure, Adjusted operating income was recast for the three months ended March 31, 2018, for Electric Utilities, Power Generation, and Corporate and Other which resulted in changes of $1.7 million, ($1.6) million, and ($0.1) million, respectively. The impact to Adjusted operating income for the three months ended March 31, 2019, for Electric Utilities, Power Generation, and Corporate and Other was ($5.4) million, $0.7 million, and $4.7 million, respectively. There was no impact on our consolidated Operating income.
(b)
Income tax benefit (expense) for the three months ended March 31, 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:
March 31, 2019
 
December 31, 2018
 
March 31, 2018
Segment:
 
 
 
 
 
Electric Utilities (a)
$
2,755,056

 
$
2,707,695

 
$
2,629,267

Gas Utilities
3,639,430

 
3,623,475

 
3,398,473

Power Generation (a)
372,503

 
342,085

 
314,764

Mining
63,088

 
80,594

 
65,568

Corporate and Other
207,495

 
209,478

 
194,193

Discontinued operations

 

 
24,724

Total assets
$
7,037,572

 
$
6,963,327

 
$
6,626,989


___________
(a)
Due to changes to our segment performance measure, Electric Utilities Total assets were recast as of December 31, 2018 and March 31, 2018 which resulted in changes of ($188) million and ($261) million, respectively. Power Generation Total Assets were recast as of December 31, 2018, and March 31, 2018 which resulted in changes of $188 million and $261 million, respectively. The impact to Electric Utilities and Power Generation Total Assets as of March 31, 2019, was ($186) million and $186 million, respectively. There was no impact on our consolidated Total assets.


15



(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
March 31, 2019
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
45,764

$
31,075

$
(535
)
$
76,304

Gas Utilities
138,005

62,566

(4,008
)
196,563

Power Generation
3,167



3,167

Mining
2,791



2,791

Corporate
3,946


(169
)
3,777

Total
$
193,673

$
93,641

$
(4,712
)
$
282,602


 
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


 
Accounts
Unbilled
Less Allowance for
Accounts
March 31, 2018
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
40,492

$
33,907

$
(624
)
$
73,775

Gas Utilities
120,910

60,142

(3,684
)
177,368

Power Generation
1,580



1,580

Mining
3,133



3,133

Corporate
1,916



1,916

Total
$
168,031

$
94,049

$
(4,308
)
$
257,772




16



(5)    REGULATORY ACCOUNTING

We had the following regulatory assets and liabilities (in thousands) as of:
 
March 31, 2019
December 31, 2018
March 31, 2018
Regulatory assets
 
 
 
Deferred energy and fuel cost adjustments (a)
$
35,512

$
29,661

$
25,056

Deferred gas cost adjustments (a)
5,124

3,362

2,118

Gas price derivatives (a)
3,939

6,201

11,045

Deferred taxes on AFUDC (b)
7,771

7,841

7,808

Employee benefit plans (c)
111,724

110,524

109,999

Environmental (a)
945

959

1,012

Loss on reacquired debt (a)
20,570

21,001

20,267

Renewable energy standard adjustment (a)
1,533

1,722

1,600

Deferred taxes on flow through accounting (c)
33,226

31,044

28,014

Decommissioning costs (b)
11,694

11,700

12,552

Gas supply contract termination (a)
12,866

14,310

18,590

Other regulatory assets (a)
41,803

45,910

29,171

Total regulatory assets
286,707

284,235

267,232

Less current regulatory assets
(54,303
)
(48,776
)
(54,492
)
Regulatory assets, non-current
$
232,404

$
235,459

$
212,740

 
 
 
 
Regulatory liabilities
 
 
 
Deferred energy and gas costs (a)
$
19,018

$
6,991

$
20,194

Employee benefit plan costs and related deferred taxes (c)
42,207

42,533

40,332

Cost of removal (a)
154,170

150,123

139,002

Excess deferred income taxes (c)
307,894

310,562

310,622

TCJA revenue reserve
16,549

18,032

15,239

Other regulatory liabilities (c)
17,421

12,553

12,472

Total regulatory liabilities
557,259

540,794

537,861

Less current regulatory liabilities
(45,777
)
(29,810
)
(42,499
)
Regulatory liabilities, non-current
$
511,482

$
510,984

$
495,362

__________
(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.

Regulatory Activity

Nebraska

On March 29, 2019, Nebraska Gas filed an application with the NPSC requesting to merge its two gas distribution utilities into a new public utility entity. The filing also requests to merge the terms and conditions of the existing tariffs of the two utilities into a single tariff.

Wyoming

On March 6, 2019, Wyoming Gas filed an application with the WPSC requesting to merge its four gas distribution utilities into a new public utility entity. The filing also requests the new entity adopt the terms and conditions of the existing tariffs.

17




Colorado

On February 1, 2019, Colorado Gas filed a rate review with the CPUC requesting approval to consolidate the base rate areas, tariffs, terms and conditions and adjustment clauses of its two legacy utilities. The rate review also requests $2.5 million in new revenue to recover costs and investments in safety, reliability and system integrity.


(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:
 
March 31, 2019
 
December 31, 2018
 
March 31, 2018
Materials and supplies
$
76,728

 
$
75,081

 
$
72,045

Fuel - Electric Utilities
2,485

 
2,850

 
2,903

Natural gas in storage held for distribution
8,463

 
39,368

 
7,097

Total materials, supplies and fuel
$
87,676

 
$
117,299

 
$
82,045





(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 March 31,
 
2019
2018
 
 
 
Net income available for common stock
$
103,808

$
133,004

 
 
 
Weighted average shares - basic
59,920

53,319

Dilutive effect of:
 
 
Equity Units (a)

733

Equity compensation
140

70

Weighted average shares - diluted
60,060

54,122


__________
(a)
Calculated using the treasury stock method. On November 1, 2018, we completed settlement of the stock purchase contracts that are 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 March 31,
 
2019
2018
 
 
 
Equity compensation
6

71

Anti-dilutive shares
6

71




18




(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:
 
March 31, 2019
December 31, 2018
March 31, 2018
 
Balance Outstanding
Letters of Credit
Balance Outstanding
Letters of Credit
Balance Outstanding
Letters of Credit
Revolving Credit Facility
$

$
14,006

$

$
22,310

$

$
15,830

CP Program
164,650


185,620


164,200


Total
$
164,650

$
14,006

$
185,620

$
22,310

$
164,200

$
15,830



Revolving Credit Facility and CP Program

On July 30, 2018, we amended and restated our corporate Revolving Credit Facility, maintaining total commitments of $750 million and extending the term through July 30, 2023 with two one year extension options (subject to consent from lenders). This facility is similar to the former revolving credit facility, which 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 March 31, 2019. Based on our credit ratings, a 0.175% commitment fee was charged on the unused amount at March 31, 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 payments under the CP Program during the three months ended March 31, 2019 were $21 million and our notes outstanding as of March 31, 2019 were $165 million. As of March 31, 2019, the weighted average interest rate on CP Program borrowings was 2.70%. As of March 31, 2019, we had outstanding letters of credit of totaling approximately $14 million.

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.

Our Revolving Credit Facility and term loans require compliance with the following financial covenant at the end of each quarter:
 
As of March 31, 2019
 
Covenant Requirement
Consolidated Indebtedness to Capitalization Ratio
58.1%
 
Less than
65%


As of March 31, 2019, we were in compliance with this covenant.






19



(9)    EQUITY

A summary of the changes in equity is as follows:

 
 
 
 
 
 
 
 
 
 

Three Months Ended March 31, 2019
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 (loss) 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
)
Cumulative effect of ASU 2016-02, Leases implementation





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

 
 
 
 
 
 
 
 
 
 
Three Months Ended March 31, 2018
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 (loss) 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



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 March 31, 2019, we issued a total of 280,497 shares of common stock under the ATM equity offering program for $20 million, net of $0.2 million in commissions. As of March 31, 2019, there were no shares that were sold, but not settled.





20



(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 guarantees, prepayments, letters of credit, and other security agreements.

We perform ongoing credit evaluations of our customers and adjust credit limits based on payment history and the customer’s current creditworthiness, as determined by review of their current credit information. We maintain a provision for estimated credit losses based upon historical experience and any specific customer collection issue that is identified.

Our derivative and hedging activities recorded in the accompanying Condensed Consolidated Balance Sheets, Condensed Consolidated Statements of Income and Condensed Consolidated Statements of Comprehensive Income are detailed below and in Note 11.

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 April 2019 through May 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.


21



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:
 
March 31, 2019
 
December 31, 2018
 
March 31, 2018
 
Notional
(MMBtus)
 
Maximum
Term
(months) (a)
 
Notional
(MMBtus)
 
Maximum
Term
(months) (a)
 
Notional
(MMBtus)
 
Maximum
Term
(months) (a)
Natural gas futures purchased
3,120,000

 
21
 
4,000,000

 
24
 
6,760,000

 
33
Natural gas options purchased, net
1,150,000

 
10
 
4,320,000

 
13
 
170,000

 
11
Natural gas basis swaps purchased
3,020,000

 
21
 
3,960,000

 
24
 
6,770,000

 
33
Natural gas over-the-counter swaps, net (b)
3,316,000

 
26
 
3,660,000

 
24
 
2,760,000

 
26
Natural gas physical contracts, net (c)
2,786,980

 
12
 
18,325,852

 
30
 
386,250

 
32

__________
(a)
Term reflects the maximum forward period hedged.
(b)
As of March 31, 2019, 534,000 MMBtus were designated as cash flow hedges.
(c)
Volumes exclude contracts that qualify for the normal purchase, normal sales exception.

Based on March 31, 2019 prices, a $0.1 million loss would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods.

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 March 31, 2019, the Company posted $0.2 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 months ended March 31, 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 March 31, 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
 
554

Total
 
 
 
$
(159
)

Three Months Ended March 31, 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
 
$
(713
)
Commodity derivatives
 
Fuel, purchased power and cost of natural gas sold
 
(621
)
Total
 
 
 
$
(1,334
)


22



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 months ended March 31, 2019 and 2018.
 
 
 
 
 
Three Months Ended March 31,
 
2019
 
2018
 
(in thousands)
Increase (decrease) in fair value:
 
 
 
Forward commodity contracts
$
234

 
$
(297
)
Recognition of (gains) losses in earnings due to settlements:
 
 
 
Interest rate swaps
713

 
713

Forward commodity contracts
(554
)
 
621

Total other comprehensive income (loss) from hedging
$
393

 
$
1,037


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 months ended March 31, 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 March 31,
 
 
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
$
25

 
$
254

 
 
$
25

 
$
254


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 assets or Regulatory liability accounts related to the hedges in our utilities were $3.9 million, $6.2 million and $11 million at March 31, 2019, December 31, 2018 and March 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.


23



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 component based on the credit spreads of the counterparties when we are in an unrealized gain position or on our own credit spread when we are in an unrealized loss position.

Recurring Fair Value Measurements

 
As of March 31, 2019
 
Level 1
Level 2
Level 3
 
Cash Collateral and Counterparty
Netting
Total
 
(in thousands)
Assets:
 
 
 
 
 
 
Commodity derivatives — Utilities
$

$
1,375

$

 
$
(388
)
$
987

Total
$

$
1,375

$

 
$
(388
)
$
987

 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
Commodity derivatives — Utilities
$

$
4,122

$

 
$
(4,009
)
$
113

Total
$

$
4,122

$

 
$
(4,009
)
$
113



 
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




24



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

$
414

$

 
$
(119
)
$
295

Total
$

$
414

$

 
$
(119
)
$
295

 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
Commodity derivatives — Utilities
$

$
12,259

$

 
$
(11,175
)
$
1,084

Total
$

$
12,259

$

 
$
(11,175
)
$
1,084



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
 
March 31, 2019
December 31, 2018
March 31, 2018
Derivatives designated as hedges:
 
 
 
 
 
Asset derivative instruments:
 
 
 
 
 
Current commodity derivatives
Derivative assets — current
 
$
131

$
415

$

Noncurrent commodity derivatives
Other assets, non-current
 
9

18


Liability derivative instruments:
 
 
 
 
 
Current commodity derivatives
Derivative liabilities — current
 
(11
)
(114
)
(394
)
Noncurrent commodity derivatives
Other deferred credits and other liabilities
 

(4
)
(29
)
Total derivatives designated as hedges
 
 
$
129

$
315

$
(423
)
 
 
 
 
 
 
Derivatives not designated as hedges:
 
 
 
 
 
Asset derivative instruments:
 
 
 
 
 
Current commodity derivatives
Derivative assets — current
 
$
801

$
1,085

$
295

Noncurrent commodity derivatives
Other assets, non-current
 
46

1


Liability derivative instruments:
 
 
 
 
 
Current commodity derivatives
Derivative liabilities — current
 
(84
)
(833
)
(497
)
Noncurrent commodity derivatives
Other deferred credits and other liabilities
 
(18
)
(56
)
(164
)
Total derivatives not designated as hedges
 
 
$
745

$
197

$
(366
)

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.


25



(12)    FAIR VALUE OF FINANCIAL INSTRUMENTS

The estimated fair values of our financial instruments, excluding derivatives which are presented in Note 11, were as follows (in thousands) as of:
 
March 31, 2019
 
December 31, 2018
 
March 31, 2018
 
Carrying
Amount
Fair Value
 
Carrying
Amount
Fair Value
 
Carrying
Amount
Fair Value
Cash and cash equivalents (a)
$
12,225

$
12,225

 
$
20,776

$
20,776

 
$
30,947

$
30,947

Restricted cash (a)
$
3,494

$
3,494

 
$
3,369

$
3,369

 
$
2,958

$
2,958

Notes payable (b)
$
164,650

$
164,650

 
$
185,620

$
185,620

 
$
164,200

$
164,200

Long-term debt, including current maturities (c) (d)
$
2,956,042

$
3,137,538

 
$
2,956,578

$
3,039,108

 
$
3,114,530

$
3,265,965

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

(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, net of tax (in thousands):
 
Location on the Condensed Consolidated Statements of Income
Amount Reclassified from AOCI
Three Months Ended
March 31, 2019
March 31, 2018
Gains and (losses) on cash flow hedges:
 
 
 
Interest rate swaps
Interest expense
$
(713
)
$
(713
)
Commodity contracts
Fuel, purchased power and cost of natural gas sold

554

(621
)
 
 
(159
)
(1,334
)
Income tax
Income tax benefit (expense)
35

297

Total reclassification adjustments related to cash flow hedges, net of tax
 
$
(124
)
$
(1,037
)
 
 
 
 
Amortization of components of defined benefit plans:
 
 
 
Prior service cost
Operations and maintenance
$
19

$
45

 
 
 
 
Actuarial gain (loss)
Operations and maintenance
(220
)
(622
)
 
 
(201
)
(577
)
Income tax
Income tax benefit (expense)
48

126

Total reclassification adjustments related to defined benefit plans, net of tax
 
$
(153
)
$
(451
)
Total reclassifications
 
$
(277
)
$
(1,488
)


26



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

180


180

Amounts reclassified from AOCI
550

(426
)
153

277

As of March 31, 2019
$
(16,757
)
$
82

$
(9,784
)
$
(26,459
)
 
 
 
 
 
 
 
 
 
 
 
Interest Rate Swaps
Commodity Derivatives
Employee Benefit Plans
Total
Balance as of December 31, 2017
$
(19,581
)
$
(518
)
$
(21,103
)
$
(41,202
)
Other comprehensive income (loss)
 
 
 
 
before reclassifications

(228
)

(228
)
Amounts reclassified from AOCI
561

476

451

1,488

Reclassifications of certain tax effects from AOCI
15


3

18

As of March 31, 2018
$
(19,005
)
$
(270
)
$
(20,649
)
$
(39,924
)



(14)    SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

Three Months Ended
March 31, 2019
 
March 31, 2018
 
(in thousands)
Non-cash investing and financing activities —
 
 
 
Property, plant and equipment acquired with accrued liabilities
$
56,571

 
$
21,708

 
 
 
 
Cash (paid) refunded during the period —
 
 
 
Interest (net of amounts capitalized)
$
(30,672
)
 
$
(36,928
)
Income taxes
$
8

 
$
(14,336
)




27



(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 March 31,
 
2019
2018
Service cost
$
1,346

$
1,708

Interest cost
4,343

3,867

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

15

Net loss (gain)
941

2,158

Net periodic benefit cost
$
536

$
1,563



Defined Benefit Postretirement Healthcare Plans

The components of net periodic benefit cost for the Defined Benefit Postretirement Healthcare Plans were as follows (in thousands):
 
Three Months Ended March 31,
 
2019
2018
Service cost
$
454

$
573

Interest cost
560

521

Expected return on plan assets
(57
)
(57
)
Prior service cost (benefit)
(99
)
(99
)
Net loss (gain)

54

Net periodic benefit cost
$
858

$
992



Supplemental Non-qualified Defined Benefit and Defined Contribution Plans

The components of net periodic benefit cost for the Supplemental Non-qualified Defined Benefit and Defined Contribution Plans were as follows (in thousands):
 
Three Months Ended March 31,
 
2019
2018
Service cost (a)
$
1,285

$
280

Interest cost
324

293

Net loss (gain)
134

250

Net periodic benefit cost
$
1,743

$
823


__________
(a)
The increase in service cost for the three months ended March 31, 2019 compared to the same period in 2018 is primarily driven by market returns.

28



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
Additional Contributions
Contributions
 
Three Months Ended March 31, 2019
Anticipated for 2019
Anticipated for 2020
Defined Benefit Pension Plan
$

$
12,700

$
12,700

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

$
3,326

$
4,271

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

$
1,097

$
1,562



(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.

Dividend Restrictions

Our Revolving Credit Facility and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. As of March 31, 2019, we were in compliance with the debt covenants.

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

Our utilities are generally limited in the amount of dividends allowed to be paid to us as a utility holding company under the Federal Power Act and settlement agreements with state regulatory jurisdictions and financing agreements. As of March 31, 2019, the restricted net assets at our Electric Utilities and Gas Utilities were approximately $257 million.


(17)    DISCONTINUED OPERATIONS

Results of operations for discontinued operations have been classified as Loss from discontinued operations, net of income taxes in the accompanying Condensed Consolidated Statements of Income. Assets and liabilities of the discontinued operations have been reclassified and reflected on the accompanying Condensed Consolidated Balance Sheets as “Current assets held for sale” and “Current liabilities held for sale”, respectively. Prior periods relating to our discontinued operations have also been reclassified to reflect consistency within our condensed consolidated financial statements.


29



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 of our Oil and Gas segment in 2018.

Total assets and liabilities of our Oil and Gas segment at March 31, 2018 were classified as Current assets held for sale and Current liabilities held for sale on the accompanying Condensed Consolidated Balance Sheets due to the final disposals occurring in 2018.
 
As of
(in thousands)
March 31, 2018
Other current assets
$
4,332

Deferred income tax assets, noncurrent, net

3,739

Property, plant and equipment, net
16,653

Other current liabilities
(17,233
)
Other noncurrent liabilities
(7,677
)
Net (liabilities)
$
(186
)




(18)    INCOME TAXES

Income tax benefit (expense), net for the three months ended March 31, 2019 was $(17) million compared to $26 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 $2.3 million income tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes; and

A current year $3.4 million increase in income tax benefit from forecasted federal production tax credits and state investment tax credits as well as $1.8 million of income tax benefit for deferred tax amortization related to tax reform (which is offset by reduced revenue at our utilities).


Prior year tax benefit related to legal restructuring

As part of the Company’s ongoing efforts to continue to integrate the legal entities that the Company acquired in recent years, certain legal entity restructuring transactions occurred on March 31, 2018.  As a result of these transactions, $49 million of deferred income tax assets, related to goodwill that is amortizable for tax purposes, were recorded and deferred tax benefits of $49 million were recorded to Income tax benefit (expense) on the Condensed Consolidated Statements of Income. Due to this being a common control transaction, it had no effect on the other assets and liabilities of these entities.

Prior year TCJA expense

On December 22, 2017, the TCJA was signed into law reducing the federal corporate rate from 35% to 21% effective January 1, 2018. During the three months ended March 31, 2018, we recorded approximately $2.3 million of additional tax expense associated with changes in the prior estimated impacts of TCJA related items.



30



(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:
 
March 31, 2019
December 31, 2018
March 31, 2018
Accrued employee compensation, benefits and withholdings
$
48,078

$
63,742

$
46,262

Accrued property taxes
43,662

42,510

42,912

Customer deposits and prepayments
39,125

43,574

35,748

Accrued interest and contract adjustment payments
35,149

31,759

30,426

CIAC current portion
1,485

1,485

1,552

Other (none of which is individually significant)
28,573

32,431

37,140

Total accrued liabilities
$
196,072

$
215,501

$
194,040




(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 lease 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 March 31, 2019
Operating lease cost
Operations and maintenance
$
311

Finance lease cost:
 
 
Amortization of right-of-use asset
Depreciation, depletion and amortization
17

Interest on lease liabilities
Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)
3

Total lease cost
 
$
331






31



Supplemental balance sheet information related to leases was as follows (in thousands):
 
Balance Sheet Location
As of March 31, 2019
Assets:
 
 
Operating lease assets
Other assets, non-current
$
5,331

Finance lease assets
Other assets, non-current
481

Total lease assets
 
$
5,812

 
 
 
Liabilities:
 
 
Current:
 
 
Operating leases
Accrued liabilities
$
974

Finance leases
Accrued liabilities
92

 
 
 
Noncurrent:
 
 
Operating leases
Other deferred credits and other liabilities
4,563

Finance leases
Other deferred credits and other liabilities
391

Total lease liabilities
 
$
6,020



Supplemental cash flow information related to leases was as follows (in thousands):
 
Three Months Ended March 31, 2019
Cash paid included in the measurement of lease liabilities:
 
Operating cash flows from operating leases
$
246

Operating cash flows from finance lease
$
3

Financing cash flows from finance lease
$
15

Right-of-use assets obtained in exchange for lease obligations:
 
Operating leases
$
2,328

Finance leases
$



 
As of March 31, 2019
Weighted average remaining lease term (years):
 
Operating leases
8 years

Finance leases
5 years

 
 
Weighted average discount rate:
 
Operating leases
4.23
%
Finance leases
4.21
%



32



As of March 31, 2019, scheduled maturities of lease liabilities for future years were as follows (in thousands):
 
Operating Leases
Finance Leases
Total
2019 (a)
$
952

$
83

$
1,035

2020
936

111

1,047

2021
820

111

931

2022
698

111

809

2023
699

110

809

Thereafter
2,653

9

2,662

Total lease payments (b)
$
6,758

$
535

$
7,293

Less imputed interest
1,221

52

1,273

Present value of lease liabilities
$
5,537

$
483

$
6,020


(a)
Includes lease liabilities for the remaining nine 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



Lessor

We lease to third parties certain generating station ground leases, communication tower sites, and 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 March 31, 2019
Operating lease income
Revenue
$
638




33




As of March 31, 2019, scheduled maturities of lease receivables for future years were as follows (in thousands):
 
Operating Leases
2019 (a)
$
1,652

2020
2,010

2021
1,843

2022
1,793

2023
1,799

Thereafter
55,481

Total lease receivables
$
64,578


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


34



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 regulatory-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 produces 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.

Accounting standards for presentation of segments requires an approach based on the way we organize the segments for making operating decisions and how the chief operating decision maker (CODM) assesses performance.  We have changed our segment performance metrics and concluded that adjusted operating income, instead of net income available for common stock that was used previously, is the most relevant metric for measuring segment performance.

The CODM assesses the performance of our segments by using adjusted operating income, which considers the power sales arrangement between Colorado IPP and Colorado Electric be treated as an executory contract. Adjusted operating income adjusts this power sales arrangement from being accounted for as a capital lease to being accounted for as an executory contract on an accrual basis. This adjustment impacts Electric Utilities and Power Generation segments and Corporate and Other. There were no adjustments to Gas Utilities and Mining segments and this adjustment had no effect on our consolidated operating income.
 
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 profit and adjust operating income for the power sales agreement as an executory contract and not a capital lease.


35



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 months ended March 31, 2019 and 2018, and our financial condition as of March 31, 2019, December 31, 2018 and March 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 53.

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.

Results of Operations

Executive Summary, Significant Events and Overview

Three Months Ended March 31, 2019 Compared to Three Months Ended March 31, 2018. Net income from continuing operations available for common stock for the three months ended March 31, 2019 was $104 million, or $1.73 per diluted share, compared to $135 million, or $2.50 per diluted share, reported for the same period in 2018. The variance to the prior year included the following:

Electric Utilities’ adjusted operating income increased $2.5 million primarily due to favorable winter weather compared to prior year partially offset by higher operating expenses driven by outside services and employee costs;
Gas Utilities’ operating income increased $7.9 million primarily due to new rates and favorable winter weather compared to prior year partially offset by higher operating expenses driven by outside services and employee costs; and
A prior year $49 million tax benefit resulting from legal entity restructuring partially offset by:
A prior year $2.3 million income tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes; and
A current year $3.4 million increase in income tax benefit from forecasted federal production tax credits and state investment tax credits as well as $1.8 million of income tax benefit for deferred tax amortization related to tax reform (which is offset by reduced revenue at our utilities).

Net income available for common stock for the three months ended March 31, 2019 was $104 million, or $1.73 per diluted share, compared to $133 million, or $2.46 per diluted share reported for the same period in 2018. (Loss) from discontinued operations for the three months ended March 31, 2018 was $(2.3) million or $(0.04). There was no (Loss) from discontinued operations for the three months ended March 31, 2019.


36



The following table summarizes select financial results by operating segment and details significant items (in thousands):
 
Three Months Ended March 31,
 
2019
2018
Variance
Revenue
 
 
 
Revenue
$
635,681

$
611,966

$
23,715

Inter-company eliminations
(37,871
)
(36,577
)
(1,294
)
 
$
597,810

$
575,389

$
22,421

Adjusted operating income (a)
 
 
 
Electric Utilities
$
41,020

$
38,480

$
2,540

Gas Utilities
103,314

95,443

7,871

Power Generation
11,967

11,776

191

Mining
4,337

4,271

66

Corporate and Other
(507
)
(1,696
)
1,189

Operating income
160,131

148,274

11,857

 
 
 

Interest expense, net
(34,717
)
(34,995
)
278

Other income (expense), net
(789
)
(104
)
(685
)
Income tax benefit (expense) (b) (c)
(17,263
)
25,802

(43,065
)
Income from continuing operations
107,362

138,977

(31,615
)
Net (loss) from discontinued operations

(2,343
)
2,343

Net income
107,362

136,634

(29,272
)
Net income attributable to noncontrolling interest
(3,554
)
(3,630
)
76

Net income available for common stock
$
103,808

$
133,004

$
(29,196
)
 
 
 
 
Amounts attributable to common shareholders:
 
 
 
Net income from continuing operations available for common stock
$
103,808

$
135,347

$
(31,539
)
Net (loss) from discontinued operations

(2,343
)
2,343

Net income available for common stock
$
103,808

$
133,004

$
(29,196
)
__________
(a)
Due to changes to our segment performance measure, Adjusted operating income was recast for the three months ended March 31, 2018 for Electric Utilities and Power Generation segments and Corporate and Other. These changes had no impact on our consolidated financial results. See segment discussions in the sections below for more information.
(b)
Income tax benefit (expense) for the three months ended March 31, 2019 included a $3.4 million increase in income tax benefit from forecasted federal production tax credits and state investment tax credits as well as $1.8 million of income tax benefit for deferred tax amortization related to tax reform (which is offset by reduced revenue at our utilities).
(c)
Income tax benefit (expense) for the three months ended March 31, 2018 included a $49 million tax benefit resulting from legal entity restructuring and $2.3 million of income tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes.


 
Overview of Business Segments and Corporate Activity

Electric Utilities Segment

Electric Utilities experienced colder winter weather during the three months ended March 31, 2019 compared to the same period in 2018. Heating degree days for the three months ended March 31, 2019 were 7% higher than normal, compared to 1% higher than normal for the same period in 2018.


37



Gas Utilities Segment

Gas Utilities experienced colder winter weather during the three months ended March 31, 2019 compared to the same period in 2018. Heating degree days for the three months ended March 31, 2019 were 11% higher than normal, compared to 2% higher than normal for the same period in 2018.

Regulatory activity:

On March 29, 2019, Nebraska Gas filed an application with the NPSC to consolidate its two gas distribution utilities into a new public utility entity. The filing also requests to consolidate the terms and conditions of the existing tariffs of the two utilities into a single tariff.

On March 6, 2019, Wyoming Gas filed an application with the WPSC to consolidate its four gas distribution utilities into a new public utility entity. The filing also requests the new entity adopt the terms and conditions of the existing tariffs.

On February 1, 2019, Colorado Gas filed a rate review with the CPUC requesting approval to consolidate the base rate areas, tariffs, terms and conditions and adjustment clauses of its two legacy utilities. The rate review also requests $2.5 million in new revenue to recover costs and investments in safety, reliability and system integrity.

Power Generation Segment

On March 11, 2019, Black Hills Electric Generation commenced construction on the $71 million, 60-megawatt Busch Ranch II Wind Farm. The wind farm is expected to be completed and in service in 2019.

Corporate and Other

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

During the three months ended March 31, 2019, we issued a total of 280,497 shares of common stock for net proceeds of approximately $20 million through our ATM equity offering program.

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.


38



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.

Electric Utilities

 
Three Months Ended March 31,
 
2019
2018
Variance
 
(in thousands)
Revenue
$
182,927

$
173,555

$
9,372

 
 
 
 
Total fuel and purchased power
73,283

68,738

4,545

 
 
 
 
Gross margin (non-GAAP)
109,644

104,817

4,827

 
 
 
 
Operations and maintenance
47,144

45,093

2,051

Depreciation and amortization
21,480

21,244

236

Total operating expenses
68,624

66,337

2,287

 
 
 
 
Adjusted operating income (a)
$
41,020

$
38,480

$
2,540

________________
(a)
Due to changes to our segment performance measure, Adjusted operating income was recast for the three months ended 2018, which resulted in a change of $1.7 million. The impact to Adjusted operating income for the three months ended March 31, 2019 was ($5.4) million. There was no impact on our consolidated Operating income.

Results of Operations for the Electric Utilities for the Three Months Ended March 31, 2019 Compared to the Three Months Ended March 31, 2018:

Gross margin for the three months ended March 31, 2019 increased as a result of the following:
 
(in millions)
Reduction in purchased power capacity charges
$
1.6

Off-system power marketing
1.3

Weather
0.6

Rider recovery
0.4

Residential customer growth
0.3

Other
0.6

Total increase in Gross margin (non-GAAP)
$
4.8



Operations and maintenance increased primarily due to higher outside services expenses and higher employee costs driven by labor and benefits.

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






39



Operating Statistics
 
 
Electric Revenue (in thousands)
 
Quantities sold (MWh)
 
 
Three Months Ended
March 31,
 
Three Months Ended
March 31,
 
 
2019
2018
 
2019
2018
Residential
 
$
57,638

$
55,741

 
389,178

383,270

Commercial
 
60,963

61,984

 
505,573

500,136

Industrial
 
32,440

30,800

 
426,614

400,709

Municipal
 
4,139

4,141

 
36,636

36,324

Subtotal Retail Revenue - Electric
 
155,180

152,666

 
1,358,001

1,320,439

Contract Wholesale
 
8,343

9,050

 
223,020

237,704

Off-system/Power Marketing Wholesale
 
6,692

4,144

 
140,850

129,041

Other
 
12,712

7,695

 


Total Revenue and Energy Sold
 
182,927

173,555

 
1,721,871

1,687,184

Other Uses, Losses or Generation, net
 


 
97,000

90,855

Total Revenue and Energy
 
182,927

173,555

 
1,818,871

1,778,039

Less cost of fuel and purchased power (a)
 
73,283

68,738

 
 
 
Gross Margin (non-GAAP) (a)
 
$
109,644

$
104,817

 
 
 
________________
(a)
Due to changes to our segment performance measure, Fuel and purchased power was recast for the three months ended March 31, 2018, which resulted in a change of $1.6 million. The impact to Fuel and purchased power for the three months ended March 31, 2019 was $8.7 million. There were corresponding changes to Gross margin for each period.

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric Revenue (in thousands)
 
Gross Margin (non-GAAP) (in thousands)
 
Quantities Sold (MWh) (a)
Three Months Ended March 31,
 
2019
2018
 
2019
2018
 
2019
2018
Colorado Electric (b)
 
$
59,847

$
58,353

 
$
31,444

$
31,746

 
491,682

487,000

South Dakota Electric
 
79,041

73,815

 
56,308

51,376

 
845,001

828,177

Wyoming Electric
 
44,039

41,387

 
21,892

21,695

 
482,188

462,862

Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold
 
$
182,927

$
173,555

 
$
109,644

$
104,817

 
1,818,871

1,778,039


(a)
Total MWh for 2019 includes Other Uses, Losses or Generation, net, which are approximately 5%, 5%, and 6% for Colorado Electric, South Dakota Electric, and Wyoming Electric, respectively.
(b)
Due to changes to our segment performance measure, Gross margin was recast for the three months ended March 31, 2018, which resulted in a change of ($1.6) million. The impact to Gross margin for the three months ended March 31, 2019 was ($8.7) million.

 
Three Months Ended
March 31,
Quantities Generated and Purchased (MWh)
2019
2018
 
 
 
Coal-fired
585,295

595,600

Natural Gas and Oil
124,657

41,323

Wind
55,419

73,981

Total Generated
765,371

710,904

Purchased
1,053,500

1,067,135

Total Generated and Purchased
1,818,871

1,778,039



40



 
Three Months Ended
March 31,
Quantities Generated and Purchased (MWh)
2019
2018
Generated:
 
 
Colorado Electric
100,530

92,048

South Dakota Electric
457,369

412,194

Wyoming Electric
207,472

206,662

Total Generated
765,371

710,904

Purchased:
 
 
Colorado Electric
391,152

394,952

South Dakota Electric
387,632

415,983

Wyoming Electric
274,716

256,200

Total Purchased
1,053,500

1,067,135

 
 
 
Total Generated and Purchased
1,818,871

1,778,039


 
 
 
 
 
 
 
 
 
 

 
Three Months Ended March 31,
 
2019
 
 
 
2018
Heating Degree Days
Actual
 
Variance from
Normal
 
Actual Variance to Prior Year
 
Actual
 
Variance from
Normal
 
 
 
 
 
 
 
 
 
 
Colorado Electric
2,549

 
(4
)%
 
6%
 
2,406

 
(9
)%
South Dakota Electric
3,916

 
22
 %
 
6%
 
3,699

 
15
 %
Wyoming Electric
3,198

 
 %
 
7%
 
2,984

 
(7
)%
Combined (a)
3,147

 
7
 %
 
6%
 
2,964

 
1
 %
__________
(a)
Combined actuals are calculated based on the weighted average number of total customers by state.

Electric Utilities Power Plant Availability
Three Months Ended March 31,
 
2019
2018
Coal-fired plants
96.2
%
95.0
%
Natural gas-fired plants and Other plants
90.7
%
96.5
%
Wind
96.8
%
97.1
%
Total availability
92.9
%
96.1
%
 
 
 
Wind capacity factor
42.6
%
50.4
%


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 of this Quarterly Report on Form 10-Q 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.



41




Gas Utilities
 
Three Months Ended March 31,
 
2019
2018
Variance
 
(in thousands)
Revenue:
 
 
 
Natural gas - regulated
$
383,875

$
370,268

$
13,607

Other - non-regulated services
27,205

27,076

129

Total revenue
411,080

397,344

13,736

 
 
 
 
Cost of sales:
 
 
 
Natural gas - regulated
201,050

205,084

(4,034
)
Other - non-regulated services
6,229

4,601

1,628

Total cost of sales
207,279

209,685

(2,406
)
 
 
 
 
Gross margin (non-GAAP)
203,801

187,659

16,142

 
 
 
 
Operations and maintenance
77,938

70,906

7,032

Depreciation and amortization
22,549

21,310

1,239

Total operating expenses
100,487

92,216

8,271

 
 
 
 
Adjusted operating income
$
103,314

$
95,443

$
7,871



Results of Operations for the Gas Utilities for the Three Months Ended March 31, 2019 Compared to the Three Months Ended March 31, 2018:

Gross margin for the three months ended March 31, 2019 increased as a result of:
 
(in millions)
New rates
$
8.9

Weather (a)
5.2

Customer growth - distribution
1.8

Transport and transmission
1.7

Other
0.9

Excess deferred taxes returned to customers
(2.4
)
Total increase in Gross margin (non-GAAP)
$
16.1


(a) Heating degree days at the Gas Utilities for the three months ended March 31, 2019 were 11% higher than normal compared to 2% higher than normal in the same period in the prior year.

Operations and maintenance increased primarily due to $3.3 million of higher outside services expenses and $2.3 million of higher employee costs driven by labor, benefits and additional headcount. Various other expenses comprise the remainder of the increase compared to the same period in the prior year.

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



42






Operating Statistics
 
 
Gas Revenue (in thousands)
 
Gross Margin (non-GAAP)                                                                      (in thousands)
 
Gas Utilities Quantities Sold & Transported (Dth)
 
 
Three Months Ended
March 31,
 
Three Months Ended
March 31,
 
Three Months Ended
March 31,
 
 
2019
2018
 
2019
2018
 
2019
2018
 
 
 
 
 
 
 
 
 
 
Residential
 
$
241,129

$
234,751

 
$
105,057

$
96,777

 
32,838,018

30,096,237

Commercial
 
96,139

95,005

 
35,158

32,203

 
14,990,848

13,949,121

Industrial
 
6,014

5,982

 
2,017

1,674

 
1,182,527

1,183,617

Other (a)
 
(4,354
)
(7,531
)
 
(4,354
)
(7,531
)
 


Total Distribution
 
338,928

328,207

 
137,878

123,123

 
49,011,393

45,228,975

 
 
 
 
 
 
 
 
 
 
Transportation and Transmission
 
44,947

42,061

 
44,947

42,061

 
46,316,160

44,733,475

 
 
 
 
 
 
 
 
 
 
Total Regulated
 
383,875

370,268

 
182,825

165,184

 
95,327,553

89,962,450

 
 
 
 
 
 
 
 
 
 
Non-regulated Services
 
27,205

27,076

 
20,976

22,475

 
 
 
 
 
 
 
 
 
 
 
 
 
Total Gas Revenue & Gross Margin (non-GAAP)
 
$
411,080

$
397,344

 
$
203,801

$
187,659

 
 
 

(a)
Includes reserve to revenue to reflect the reduction of the lower federal income tax rate from the TCJA on our existing rate tariffs.
 
 
 
 
 
 
 
 
 
 
 
 
Revenue (in thousands)
 
Gross Margin (non-GAAP)                                                                        (in thousands)
 
Gas Utilities Quantities Sold & Transported (Dth)

 
 
Three Months Ended
March 31,
 
Three Months Ended
March 31,
 
Three Months Ended
March 31,
 
 
2019
2018
 
2019
2018
 
2019
2018
 
 
 
 
 
 
 
 
 
 
Arkansas
 
$
79,391

$
70,388

 
$
44,282

$
35,917

 
12,424,196

11,878,626

Colorado
 
76,471

71,398

 
37,600

33,145

 
13,176,925

11,703,351

Iowa
 
65,641

67,884

 
23,050

22,426

 
15,663,687

15,502,989

Kansas
 
41,217

42,381

 
18,119

17,897

 
10,443,270

10,297,328

Nebraska
 
108,797

106,761

 
56,073

53,860

 
28,999,018

27,987,224

Wyoming
 
39,563

38,532

 
24,677

24,414

 
14,620,457

12,592,932

Total Gas Revenue & Gross Margin (non-GAAP)
 
$
411,080

$
397,344

 
$
203,801

$
187,659

 
95,327,553

89,962,450


 
 
 
 
 
 
 
 
 
 

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.


43



 
Three Months Ended March 31,
 
2019
 
 
 
2018
Heating Degree Days
Actual
 
Variance
from Normal
 
Actual Variance to Prior Year
 
Actual
 
Variance
from Normal
Arkansas (a)
2,101
 
—%
 
3%
 
2,048
 
(3)%
Colorado
3,030
 
3%
 
12%
 
2,704
 
(8)%
Iowa
3,830
 
14%
 
8%
 
3,531
 
5%
Kansas (a)
2,779
 
13%
 
13%
 
2,470
 
—%
Nebraska
3,483
 
15%
 
9%
 
3,207
 
6%
Wyoming
3,513
 
10%
 
8%
 
3,244
 
1%
Combined (b)
3,449
 
11%
 
9%
 
3,159
 
2%
__________
(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 of this Quarterly Report on Form 10-Q 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.

Power Generation
 
Three Months Ended March 31,
 
2019
2018
Variance
 
(in thousands)
Revenue
$
25,245

$
23,939

$
1,306

 
 
 
 
Operations and maintenance
8,688

8,127

561

Depreciation and amortization
4,590

4,036

554

Total operating expense
13,278

12,163

1,115

 
 
 
 
Adjusted operating income (a)
$
11,967

$
11,776

$
191

________________
(a)
Due to changes to our segment performance measure, Adjusted operating income was recast for the three months ended March 31, 2018, which resulted in a change of ($1.6) million. The impact to Adjusted operating income for the three months ended March 31, 2019 was $0.7 million. There was no impact on our consolidated Operating income.


Results of Operations for Power Generation for the Three Months Ended March 31, 2019 Compared to the Three Months Ended March 31, 2018: Revenue increased in the current year due to increased wind megawatt hours sold and higher power purchase agreement prices. Operating expenses increased in the current year due to higher employee costs and higher depreciation from new wind assets.

44




The following table summarizes MWh for our Power Generation segment:
 
Three Months Ended March 31,
 
2019
2018
Quantities Sold, Generated and Purchased
(MWh) (a)
 
 
Sold
 
 
Black Hills Colorado IPP (b)
205,973

232,375

Black Hills Wyoming (c)
164,049

165,601

Black Hills Electric Generation (d)
12,864


Total Sold
382,886

397,976

 
 
 
Generated
 
 
Black Hills Colorado IPP (b)
205,973

232,375

Black Hills Wyoming (c)
132,593

134,029

Black Hills Electric Generation (d)
12,864


Total Generated
351,430

366,404

 
 
 
Purchased
 
 
Black Hills Wyoming (c)
25,579

31,917

Total Purchased
25,579

31,917

____________
(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 primarily by Black Hills Electric Generation’s acquisition of a 50% ownership interest in Busch Ranch I on December 11, 2018.

The following table provides certain operating statistics for our plants within the Power Generation segment:
 
Three Months Ended March 31,
 
2019
2018
Contracted power plant fleet availability:
 
 
Coal-fired plant
94.8
%
94.7
%
Natural gas-fired plants
95.6
%
99.5
%
Wind (a)
90.4
%
N/A

Total availability
94.1
%
98.3
%
____________
(a)
Black Hills Electric Generation acquired a 50% ownership interest in Busch Ranch I on December 11, 2018.


45



Mining

Three Months Ended March 31,

2019
2018
Variance

(in thousands)
Revenue
$
16,429

$
17,128

$
(699
)
 
 
 
 
Operations and maintenance
9,913

10,922

(1,009
)
Depreciation, depletion and amortization
2,179

1,935

244

Total operating expenses
12,092

12,857

(765
)
 
 
 
 
Adjusted operating income
$
4,337

$
4,271

$
66


The following table provides certain operating statistics for our Mining segment (in thousands, except for Revenue per ton):
 
Three Months Ended March 31,
 
2019
2018
Tons of coal sold
997

1,078

Cubic yards of overburden moved
1,994

2,022

 
 
 
Revenue per ton
$
15.87

$
15.89


Results of Operations for Mining for the Three Months Ended March 31, 2019 Compared to the Three Months Ended March 31, 2018:

Current year revenue decreased due to 8% fewer tons sold driven by a planned outage at the Wyodak power plant. Operating expenses decreased primarily due to lower royalties and production taxes on decreased revenues, and lower major maintenance expenses.


Corporate and Other
 
Three Months Ended March 31,
 
2,019
2.018
Variance
 
(in thousands)
Adjusted operating (loss) (a)
$
(507
)
$
(1,696
)
$
1,189

________________
(a)
Due to changes to our segment performance measure, Adjusted operating loss was recast for the three months ended March 31, 2018, which results in a change of ($0.1) million. The impact to Adjusted operating loss for the three months ended March 31, 2019 was $4.7 million. There was no impact on our consolidated Operating income.


Results of Operations for Corporate and Other for the Three Months Ended March 31, 2019 Compared to the Three Months Ended March 31, 2018:

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


46



Consolidated interest expense, Other income (expense) and Income tax (expense) benefit

Interest Expense

Interest expense, net for the three months ended March 31, 2019 was $35 million compared to $35 million for the same period in 2018.

Other (Expense) Income

Other (expense) income, net for the three months ended March 31, 2019 was $(0.8) million compared to $(0.1) million for the same period in 2018.

Income Tax Benefit (Expense)

Income tax benefit (expense), net for the three months ended March 31, 2019 was $(17) million compared to $26 million 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 $2.3 million income tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes; and

A current year $3.4 million increase in income tax benefit from forecasted federal production tax credits and state investment tax credits as well as $1.8 million of income tax benefit for deferred tax amortization related to tax reform (which is offset by reduced revenue at our utilities).


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.


47



Liquidity and Capital Resources

OVERVIEW

Our Company requires significant cash to support and grow our business. Our predominant source of cash is supplied by our operations and supplemented with corporate financings. This cash is used for, among other things, working capital, capital expenditures, dividends, pension funding, investments in or acquisitions of assets and businesses, payment of debt obligations, and redemption of outstanding debt and equity securities when required or financially appropriate. As discussed in more detail below under income taxes, we expect an increase in working capital requirements as a result of complying with the TCJA and the impact of providing TCJA benefits to customers.

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

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

Significant Factors Affecting Liquidity

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

Our utilities maintain wholesale commodity contracts for the purchases and sales of electricity and natural gas which have performance assurance provisions that allow the counterparty to require collateral postings under certain conditions, including when requested on a reasonable basis due to a deterioration in our financial condition or nonperformance. A significant downgrade in our credit ratings, such as a downgrade to a level below investment grade, could result in counterparties requiring collateral postings under such adequate assurance provisions. The amount of credit support that we may be required to provide at any point in the future is dependent on the amount of the initial transaction, changes in the market price, open positions and the amounts owed by or to the counterparty. At March 31, 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 six states and are working with regulators in our seventh state, as well as
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. This 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 three months ended March 31 (in thousands):
Cash provided by (used in):
2019
2018
Variance
Operating activities
$
175,893

$
169,875

$
6,018

Investing activities
$
(145,027
)
$
(73,554
)
$
(71,473
)
Financing activities
$
(39,292
)
$
(80,656
)
$
41,364



48



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

Operating Activities

Net cash provided by operating activities was $176 million for the three months ended March 31, 2019, compared to net cash provided by operating activities of $170 million for the same period in 2018 for an increase of $6 million. The variance was primarily attributable to:

Cash earnings (income from continuing operations plus non-cash adjustments) were $18 million higher for the three months ended March 31, 2019 compared to the same period in the prior year;

Net cash outflows from changes in operating assets and liabilities were $15 million for the three months ended March 31, 2019, compared to net cash outflows of $1 million in the same period in the prior year. This $14 million increase was primarily due to:

Cash inflows increased by approximately $7 million primarily as a result of higher collections of accounts receivable, partially offset by higher materials inventory and natural gas in storage for the three months ended March 31, 2019 compared to the same period in the prior year;

Cash outflows decreased by approximately $29 million as a result of increases in accounts payable and accrued liabilities driven by working capital requirements; and

Cash inflows decreased by approximately $53 million as a result of changes in our current regulatory assets and liabilities driven by differences in fuel cost adjustments and 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 $145 million for the three months ended March 31, 2019, compared to net cash used in investing activities of $74 million for the same period in 2018 for a variance of $71 million. The variance was primarily attributable to:

Capital expenditures of approximately $144 million for the three months ended March 31, 2019 compared to $70 million for the same period in the prior year. Higher current year expenditures are driven by the Busch Ranch II wind project at our Power Generation segment and increased programmatic spending at our Gas and Electric Utilities; and

A $24 million investment made in the prior year partially offset by a $20 million change in net cash provided by investing activities from discontinued operations primarily due to the prior year sale of assets held for sale.

Financing Activities

Net cash used in financing activities for the three months ended March 31, 2019 was $39 million, compared to $81 million of net cash used in financing activities for the same period in 2018 for a variance of $41 million. This variance is primarily due to:

Lower current year net repayments of short-term borrowings of $26 million;

Current year issuance of common stock for net proceeds of approximately $20 million through our ATM equity offering program; and

$4.9 million of higher current year dividend payments.


49



Dividends

Dividends paid on our common stock totaled $30 million for the three months ended March 31, 2019, or $0.505 per share per quarter. On April 29, 2019, our board of directors declared a quarterly dividend of $0.505 per share payable June 1, 2019, equivalent to an annual dividend of $2.02 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.

Debt

Financing Transactions and Short-Term Liquidity

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

Revolving Credit Facility and CP Program

On July 30, 2018, we amended and restated our corporate Revolving Credit Facility, maintaining total commitments of $750 million and extending the term through July 30, 2023 with two one-year extension options (subject to consent from lenders). This facility is similar to the former revolving credit facility, which 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. See Note 8 for more information.

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. See Note 8 for more information.

Our Revolving Credit Facility had the following borrowings, outstanding letters of credit, and available capacity (in millions):
 
 
Current
Revolver Borrowings at
CP Program Borrowings at
Letters of Credit at
Available Capacity at
Credit Facility
Expiration
Capacity
March 31, 2019
March 31, 2019
March 31, 2019
March 31, 2019
Revolving Credit Facility
July 30, 2023
$
750

$

$
165

$
14

$
571


The weighted average interest rate on CP Program borrowings at March 31, 2019 was 2.71%. Revolving Credit Facility and CP Program financing activity for the three months ended March 31, 2019 was (dollars in millions):
 
For the Three Months Ended March 31, 2019
Maximum amount outstanding - commercial paper (based on daily outstanding balances)
$
237

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

Average amount outstanding - commercial paper (based on daily outstanding balances)
$
172

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

Weighted average interest rates - commercial paper
2.70
%
Weighted average interest rates - revolving credit facility
%

The Revolving Credit Facility contains customary affirmative and negative covenants, such as limitations on certain liens, restrictions on certain transactions, and maintenance of a certain Consolidated Indebtedness to Capitalization Ratio. Under the Revolving Credit Facility, our Consolidated Indebtedness to Capitalization Ratio is calculated by dividing (i) Consolidated Indebtedness (which includes letters of credit and certain guarantees issued), by (ii) Capital, which is Consolidated Indebtedness plus Consolidated Net Worth (which excludes noncontrolling interests in subsidiaries. Subject to applicable cure periods, a violation of any of these covenants would constitute an event of default that entitles the lenders to terminate their remaining commitments and accelerate all principal and interest outstanding. We were in compliance with these covenants as of March 31, 2019.


50



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

Financing Activities

Financing activities for the three months ended March 31, 2019 consisted of the following:

We issued a total of 280,497 shares of common stock under the ATM equity offering program for $20 million, net of $0.2 million in commissions. As of March 31, 2019, there were no shares that were sold, but not settled.

Short-term borrowings from our CP Program.

Future Financing Plans

Evaluating refinancing options for our $200 million senior notes due July 15, 2020 and the $300 million Corporate term loan due July 30, 2020.

Continue our ATM equity offering program to issue an additional $60 to $80 million of common stock for the remainder of 2019.

Dividend Restrictions

As a utility holding company which owns several regulated utilities, we are subject to various regulations that could influence our liquidity. Our utilities in Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming have regulatory agreements in which they cannot pay dividends if they have issued debt to third parties and the payment of a dividend would reduce their equity ratio to below 40% of their total capitalization; and neither Black Hills Utility Holdings nor its subsidiaries can extend credit to the Company except in the ordinary course of business and upon reasonable terms consistent with market terms. The use of our utility assets as collateral generally requires the prior approval of the state regulators in the state in which the utility assets are located. Additionally, our utility subsidiaries may generally be limited to the amount of dividends allowed by state regulatory authorities to be paid to us as a utility holding company and also may have further restrictions under the Federal Power Act.
As a result of our holding company structure, our right as a common shareholder to receive assets of any of our direct or indirect subsidiaries upon a subsidiary’s liquidation or reorganization is junior to the claims against the assets of such subsidiaries by their creditors. Therefore, our holding company debt obligations are effectively subordinated to all existing and future claims of the creditors of our subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities, and guarantee holders. See Note 16 for more information.
Our credit facilities and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. An event of default would be deemed to have occurred if we did not comply with certain financial or other covenants.
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 March 31, 2019, we were in compliance with these covenants.
There have been no other material changes in our financing transactions and short-term liquidity from those reported in Item 7 of our 2018 Annual Report on Form 10-K filed with the SEC.

Credit Ratings

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


51



The following table represents the credit ratings and outlook and risk profile of BHC at March 31, 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 October 11, 2018, Fitch affirmed our BBB+ rating and maintained a Stable outlook.

The following table represents the credit ratings of South Dakota Electric at March 31, 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 December 12, 2018, Moody’s affirmed A1 rating.
(c)
On October 11, 2018, Fitch affirmed A rating.

Capital Requirements

Capital Expenditures
 
Actual
Planned
Planned
Planned
Planned
Planned
Capital Expenditures by Segment
Three Months Ended March 31, 2019 (a)
2019 (b)
2020
2021
2022
2023
(in millions)
 
 
 
 
 
 
Electric Utilities (c)
$
35

$
205

$
221

$
203

$
170

$
137

Gas Utilities (c)
58

464

323

289

277

274

Power Generation
28

84

9

8

10

4

Mining
4

8

7

11

10

7

Corporate and Other
7

16

22

8

5

7

 
$
132

$
777

$
582

$
519

$
472

$
429

__________
(a)    Expenditures for the three months ended March 31, 2019 include the impact of accruals for property, plant and equipment.
(b)    Includes actual capital expenditures for the three months ended March 31, 2019.
(c)    Planned capital expenditures increased for 2019 through 2023 primarily due to increased programmatic 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.

Guarantees

There have been no significant changes to guarantees from those previously disclosed in Note 20 of the Notes to the Consolidated Financial Statements in our 2018 Annual Report on Form 10-K.


52



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.

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

Utilities

Our utility customers are exposed to natural gas price volatility. Therefore, as allowed or required by state utility commissions, we have entered into commission-approved hedging programs utilizing natural gas futures, options and basis swaps to reduce our customers’ underlying exposure to these fluctuations. We also reduce the commodity price risk in the unregulated area of our business by using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and/or sales. The fair value of our utilities’ derivative contracts is summarized below (in thousands) as of:
 
March 31, 2019
 
December 31, 2018
 
March 31, 2018
Net derivative (liabilities) assets
$
(2,203
)
 
$
(2,214
)
 
$
(6,002
)
Cash collateral offset in Derivatives
3,621

 
4,386

 
5,078

Cash collateral included in Other current assets
1,717

 
2,880

 
2,020

Net asset (liability) position
$
3,135

 
$
5,052

 
$
1,096


Financing Activities

From time-to-time, we have entered into floating-to-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations associated with our floating rate debt obligations and anticipated debt refinancings. At March 31, 2019, December 31, 2018 and March 31, 2018, we had no outstanding interest rate swap agreements.


53



ITEM 4.    CONTROLS AND PROCEDURES

Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) as of March 31, 2019. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at March 31, 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 March 31, 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.


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 1A.
Risk Factors

There are no material changes to the risk factors previously disclosed in Item 1A of Part I in our 2018 Annual Report on Form 10-K filed with the SEC.

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

There were no unregistered securities sold during the three months ended March 31, 2019.
 
 
 
 
 
 
 
 
 

ITEM 4.
Mine Safety Disclosures

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

ITEM 5.
Other Information

None.


54


ITEM 6.
Exhibits

Exhibit Number
Description
 
 
Exhibit 3.1*
 
 
Exhibit 3.2*
 
 
Exhibit 4.1*
 
 
 
 
 
 
 
 
 
Exhibit 4.2*
 
 
 
 
 
Exhibit 4.3*
 
 
 
 
Exhibit 4.4*
 
 
Exhibit 31.1
 
 

55


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
 
 
__________
*
Previously filed as part of the filing indicated and incorporated by reference herein.


56



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:
May 3, 2019
 


57