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Section 1: 10-Q (10-Q)

Document


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

Form 10-Q
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
 
EXCHANGE ACT OF 1934
 
For the quarterly period ended September 30, 2018
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
 

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 November 1, 2018
Common stock, $1.00 par value
59,974,620

shares






TABLE OF CONTENTS
 
 
 
Page
 
Glossary of Terms and Abbreviations
 
 
 
 
 
PART I.
FINANCIAL INFORMATION
 
 
 
 
 
Item 1.
Financial Statements
 
 
 
 
 
 
Condensed Consolidated Statements of Income - unaudited
 
 
 
   Three and Nine Months Ended September 30, 2018 and 2017
 
 
 
 
 
 
Condensed Consolidated Statements of Comprehensive Income - unaudited
 
 
 
   Three and Nine Months Ended September 30, 2018 and 2017
 
 
 
 
 
 
Condensed Consolidated Balance Sheets - unaudited
 
 
 
   September 30, 2018, December 31, 2017 and September 30, 2017
 
 
 
 
 
 
Condensed Consolidated Statements of Cash Flows - unaudited
 
 
 
   Nine Months Ended September 30, 2018 and 2017
 
 
 
 
 
 
Notes to Condensed Consolidated Financial Statements - unaudited
 
 
 
 
 
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
 
 
 
 
Item 3.
Quantitative and Qualitative Disclosures about Market Risk
 
 
 
 
 
Item 4.
Controls and Procedures
 
 
 
 
 
PART II.
OTHER INFORMATION
 
 
 
 
 
Item 1.
Legal Proceedings
 
 
 
 
 
Item 1A.
Risk Factors
 
 
 
 
 
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
 
 
 
 
 
Item 4.
Mine Safety Disclosures
 
 
 
 
 
Item 5.
Other Information
 
 
 
 
 
Item 6.
Exhibits
 
 
 
 
 
 
Signatures
 


2



GLOSSARY OF TERMS AND ABBREVIATIONS

The following terms and abbreviations appear in the text of this report and have the definitions described below:
AFUDC
Allowance for Funds Used During Construction
AOCI
Accumulated Other Comprehensive Income (Loss)
APSC
Arkansas Public Service Commission
Arkansas Gas
Black Hills Energy Arkansas, Inc., a direct, wholly-owned subsidiary of Black Hills Gas Inc.
ASC
Accounting Standards Codification
ASU
Accounting Standards Update issued by the FASB
ATM
At-the-market equity offering program
Availability
The availability factor of a power plant is the percentage of the time that it is available to provide energy.
Bbl
Barrel
BHC
Black Hills Corporation; the Company
Black Hills 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
Busch Ranch Wind Farm is a 29 MW wind farm near Pueblo, Colorado, jointly owned by Colorado Electric and AltaGas. Colorado Electric has 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, Inc., an indirect, wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy)
Colorado IPP
Black Hills Colorado IPP, LLC a 50.1% owned subsidiary of Black Hills Electric Generation
Consolidated Indebtedness to Capitalization Ratio
Any Indebtedness outstanding at such time, divided by Capital at such time. Capital being Consolidated Net-Worth (excluding noncontrolling interest and including the aggregate outstanding amount of RSNs) plus Consolidated Indebtedness (including letters of credit, certain guarantees issued and excluding RSNs) as defined within the current Credit Agreement.
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 over a 30-year average.
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 has a stated amount of $50, consisting of a purchase contract issued by BHC to purchase shares of BHC common stock and a 1/20, or 5% undivided beneficial ownership interest in $1,000 principal amount of BHC RSNs that were formerly due 2028 prior to the successful remarketing on August 17, 2018.
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
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 over a 30-year average.
Horizon Point
Corporate headquarters building in Rapid City, South Dakota, which was completed in 2017.
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)
LIBOR
London Interbank Offered Rate
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)
OCA
Office of Consumer Advocate
Peak View Wind Project
$109 million 60 MW wind generating project for Colorado Electric, adjacent to Busch Ranch wind farm
PCA
Power Cost Adjustment
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.
RMNG
Rocky Mountain Natural Gas, a regulated gas utility acquired in the SourceGas Acquisition that provides regulated transmission and wholesale natural gas service to Black Hills Gas in western Colorado (doing business as Black Hills Energy)
RSNs
Remarketable junior subordinated notes, issued on November 23, 2015
SEC
U. S. Securities and Exchange Commission
SourceGas
SourceGas Holdings LLC and its subsidiaries, a gas utility owned by funds managed by Alinda Capital Partners and GE Energy Financial Services, a unit of General Electric Co. (NYSE:GE) that was acquired on February 12, 2016, and is now named Black Hills Gas Holdings, LLC (doing business as Black Hills Energy)
SourceGas Acquisition
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 September 30,
Nine Months Ended September 30,
 
2018
2017
2018
2017
 
(in thousands, except per share amounts)
 
 
 
 
 
Revenue
$
321,979

$
335,611

$
1,253,072

$
1,224,968

 
 
 
 
 
Operating expenses:
 
 
 
 
Fuel, purchased power and cost of natural gas sold
80,244

86,281

432,544

404,222

Operations and maintenance
115,477

109,258

350,099

335,707

Depreciation, depletion and amortization
49,046

47,109

146,345

140,636

Taxes - property, production and severance
11,905

12,408

39,181

38,866

Other operating expenses
222

996

1,993

5,996

Total operating expenses
256,894

256,052

970,162

925,427

 
 
 
 
 
Operating income
65,085

79,559

282,910

299,541

 
 
 
 
 
Other income (expense):
 
 
 
 
Interest charges -
 
 
 
 
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts)
(36,480
)
(35,287
)
(107,360
)
(105,417
)
Allowance for funds used during construction - borrowed
701

753

1,345

2,061

Capitalized interest
100

64

177

197

Interest income
382

402

1,012

700

Allowance for funds used during construction - equity
193

696

503

1,982

Other income (expense), net
(703
)
189

(2,426
)
(6
)
Total other income (expense), net
(35,807
)
(33,183
)
(106,749
)
(100,483
)
 
 
 
 
 
Income before income taxes
29,278

46,376

176,161

199,058

Income tax benefit (expense)
(7,477
)
(13,478
)
11,784

(58,518
)
Income from continuing operations
21,801

32,898

187,945

140,540

(Loss) from discontinued operations, net of tax
(857
)
(1,300
)
(5,627
)
(3,485
)
Net income
20,944

31,598

182,318

137,055

Net income attributable to noncontrolling interest
(3,994
)
(3,935
)
(10,447
)
(10,674
)
Net income available for common stock
$
16,950

$
27,663

$
171,871

$
126,381

 
 
 
 
 
Amounts attributable to common shareholders:
 
 
 
 
Net income from continuing operations
$
17,807

$
28,963

$
177,498

$
129,866

Net (loss) from discontinued operations
(857
)
(1,300
)
(5,627
)
(3,485
)
Net income available for common stock
$
16,950

$
27,663

$
171,871

$
126,381

 
 
 
 
 
Earnings per share of common stock:
 
 
 
 
Earnings (loss) per share, Basic -
 
 
 
 
Income from continuing operations, per share
$
0.33

$
0.54

$
3.33

$
2.44

(Loss) from discontinued operations, per share
(0.02
)
(0.02
)
(0.10
)
(0.06
)
Earnings per share, Basic (a)
$
0.32

$
0.52

$
3.22

$
2.38

 
 
 
 
 
Earnings (loss) per share, Diluted -
 
 
 
 
Income from continuing operations, per share
$
0.32

$
0.52

$
3.26

$
2.35

(Loss) from discontinued operations, per share
(0.02
)
(0.02
)
(0.10
)
(0.06
)
Earnings per share, Diluted (a)
$
0.31

$
0.50

$
3.15

$
2.29

Weighted average common shares outstanding:
 
 
 
 
Basic
53,364

53,243

53,346

53,208

Diluted
54,819

55,432

54,508

55,254

 
 
 
 
 
Dividends declared per share of common stock
$
0.475

$
0.445

$
1.425

$
1.335


(a) EPS may not sum due to rounding.

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
September 30,
Nine Months Ended
September 30,
 
2018
2017
2018
2017
 
(in thousands)
 
 
 
 
 
Net income
$
20,944

$
31,598

$
182,318

$
137,055

 
 
 
 
 
Other comprehensive income (loss), net of tax:
 
 
 
 
Reclassification adjustments of benefit plan liability - prior service cost (net of tax (expense) benefit of $10 and $17 for the three months ended September 30, 2018 and 2017 and $29 and $52 for the nine months ended September 30, 2018 and 2017, respectively)
(34
)
(32
)
(104
)
(94
)
Reclassification adjustments of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(138) and $(145) for the three months ended September 30, 2018 and 2017 and $(409) and $(445) for the nine months ended September 30, 2018 and 2017, respectively)
483

269

1,456

797

Derivative instruments designated as cash flow hedges:
 
 
 
 
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax (expense) benefit of $(152) and $(249) for the three months ended September 30, 2018 and 2017 and $(456) and $(779) for the nine months ended September 30, 2018 and 2017, respectively)
560

464

1,682

1,449

Net unrealized gains (losses) on commodity derivatives (net of tax (expense) benefit of $0 and $94 for the three months ended September 30, 2018 and 2017 and $51 and $(442) for the nine months ended September 30, 2018 and 2017, respectively)
30

(160
)
(168
)
755

Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax (expense) benefit of $3 and $95 for the three months ended September 30, 2018 and 2017 and $(187) and $344 for the nine months ended September 30, 2018 and 2017, respectively)
21

(166
)
615

(590
)
Other comprehensive income, net of tax
1,060

375

3,481

2,317

 
 
 
 
 
Comprehensive income
22,004

31,973

185,799

139,372

Less: comprehensive income attributable to noncontrolling interest
(3,994
)
(3,935
)
(10,447
)
(10,674
)
Comprehensive income available for common stock
$
18,010

$
28,038

$
175,352

$
128,698


See Note 14 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
 
September 30,
2018
 
December 31, 2017
 
September 30,
2017
 
(in thousands)
ASSETS
 
 
 
 
 
Current assets:
 
 
 
 
 
Cash and cash equivalents
$
10,001

 
$
15,420

 
$
13,449

Restricted cash
3,241

 
2,820

 
2,683

Accounts receivable, net
152,796

 
248,330

 
150,325

Materials, supplies and fuel
122,618

 
113,283

 
122,866

Derivative assets, current
1,392

 
304

 
433

Income tax receivable, net
11,025

 

 

Regulatory assets, current
48,302

 
81,016

 
61,023

Other current assets
32,691

 
25,367

 
25,586

Current assets held for sale
2,854

 
84,242

 
8,653

Total current assets
384,920

 
570,782

 
385,018

 
 
 
 
 
 
Investments
41,202

 
13,090

 
12,947

 
 
 
 
 
 
Property, plant and equipment
5,819,000

 
5,567,518

 
5,499,557

Less: accumulated depreciation and depletion
(1,118,783
)
 
(1,026,088
)
 
(1,000,875
)
Total property, plant and equipment, net
4,700,217

 
4,541,430

 
4,498,682

 
 
 
 
 
 
Other assets:
 
 
 
 
 
Goodwill
1,299,454

 
1,299,454

 
1,299,454

Intangible assets, net
6,954

 
7,559

 
7,765

Regulatory assets, non-current
212,048

 
216,438

 
239,571

Other assets, non-current
17,143

 
10,149

 
11,626

Noncurrent assets held for sale

 

 
108,685

Total other assets, non-current
1,535,599

 
1,533,600

 
1,667,101

 
 
 
 
 
 
TOTAL ASSETS
$
6,661,938

 
$
6,658,902

 
$
6,563,748


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
 
September 30,
2018
 
December 31, 2017
 
September 30,
2017
 
(in thousands, except share amounts)
LIABILITIES AND TOTAL EQUITY
 
 
 
 
 
Current liabilities:
 
 
 
 
 
Accounts payable
$
115,900

 
$
160,887

 
$
94,790

Accrued liabilities
201,353

 
219,462

 
206,779

Derivative liabilities, current
1,154

 
2,081

 
1,458

Accrued income taxes, net

 
1,022

 
5,587

Regulatory liabilities, current
41,442

 
6,832

 
7,042

Notes payable
112,100

 
211,300

 
225,170

Current maturities of long-term debt
255,743

 
5,743

 
5,743

Current liabilities held for sale
2,538

 
41,774

 
7,701

Total current liabilities
730,230

 
649,101

 
554,270

 
 
 
 
 
 
Long-term debt
2,951,389

 
3,109,400

 
3,109,864

 
 
 
 
 
 
Deferred credits and other liabilities:
 
 
 
 
 
Deferred income tax liabilities, net
292,753

 
336,520

 
618,315

Regulatory liabilities, non-current
508,846

 
478,294

 
198,189

Benefit plan liabilities
151,613

 
159,646

 
149,803

Other deferred credits and other liabilities
105,928

 
105,735

 
113,996

Non-current liabilities held for sale

 

 
23,329

Total deferred credits and other liabilities
1,059,140

 
1,080,195

 
1,103,632

 
 
 
 
 
 
Commitments and contingencies (See Notes 9, 11, 16, 17)


 

 

 
 
 
 
 
 
Equity:
 
 
 
 
 
Stockholders’ equity —
 
 
 
 
 
Common stock $1 par value; 100,000,000 shares authorized; issued 53,661,863; 53,579,986; and 53,524,529 shares, respectively
53,662

 
53,580

 
53,525

Additional paid-in capital
1,157,214

 
1,150,285

 
1,147,922

Retained earnings
644,154

 
548,617

 
516,371

Treasury stock, at cost – 72,915; 39,064; and 41,457 shares, respectively
(4,072
)
 
(2,306
)
 
(2,448
)
Accumulated other comprehensive income (loss)
(37,703
)
 
(41,202
)
 
(32,566
)
Total stockholders’ equity
1,813,255

 
1,708,974

 
1,682,804

Noncontrolling interest
107,924

 
111,232

 
113,178

Total equity
1,921,179

 
1,820,206

 
1,795,982

 
 
 
 
 
 
TOTAL LIABILITIES AND TOTAL EQUITY
$
6,661,938

 
$
6,658,902

 
$
6,563,748


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)
Nine Months Ended September 30,
 
2018
2017
Operating activities:
(in thousands)
Net income
$
182,318

$
137,055

Loss from discontinued operations, net of tax
5,627

3,485

Income from continuing operations
187,945

140,540

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation, depletion and amortization
146,345

140,636

Deferred financing cost amortization
5,682

6,212

Stock compensation
7,544

7,594

Deferred income taxes
(14,396
)
65,536

Employee benefit plans
10,641

8,470

Other adjustments, net
7,668

(3,549
)
Changes in certain operating assets and liabilities:
 
 
Materials, supplies and fuel
(8,380
)
(19,511
)
Accounts receivable, unbilled revenues and other operating assets
72,061

103,963

Accounts payable and other operating liabilities
(86,604
)
(112,288
)
Regulatory assets - current
41,655

1,287

Regulatory liabilities - current
21,416

(4,328
)
Contributions to defined benefit pension plans
(12,700
)
(27,700
)
Other operating activities, net
2,007

(1,410
)
Net cash provided by operating activities of continuing operations
380,884

305,452

Net cash provided by (used in) operating activities of discontinued operations
(2,162
)
13,978

Net cash provided by operating activities
378,722

319,430

 
 
 
Investing activities:
 
 
Property, plant and equipment additions
(278,132
)
(238,840
)
Purchase of investment
(24,429
)

Other investing activities
2,766

160

Net cash provided by (used in) investing activities of continuing operations
(299,795
)
(238,680
)
Net cash provided by (used in) investing activities of discontinued operations
18,024

(17,298
)
Net cash provided by (used in) investing activities
(281,771
)
(255,978
)
 
 
 
Financing activities:
 
 
Dividends paid on common stock
(76,309
)
(71,334
)
Common stock issued
1,079

3,562

Net (payments) borrowings of short-term debt
(99,200
)
128,570

Long-term debt - issuances
700,000


Long-term debt - repayments
(603,307
)
(104,307
)
Distributions to noncontrolling interest
(13,755
)
(12,884
)
Other financing activities
(10,457
)
(6,719
)
Net cash provided by (used in) financing activities
(101,949
)
(63,112
)
Net change in cash, cash equivalents and restricted cash
(4,998
)
340

Cash, cash equivalents and restricted cash at beginning of period
18,240

15,792

Cash, cash equivalents and restricted cash at end of period
$
13,242

$
16,132


See Note 15 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 2017 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 2017 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.

On November 1, 2017, the BHC board of directors approved a complete divestiture of our Oil and Gas segment. The Oil and Gas segment assets and liabilities are classified as held for sale and the results of operations are shown in income (loss) from discontinued operations, excluding certain general and administrative costs and interest expense which do not meet the criteria for income (loss) from discontinued operations. As of September 30, 2018, we have sold nearly all of our oil and gas assets and we closed our oil and gas office in August. Transaction closing for the last few assets and final accounting are expected within the fourth quarter. See Note 18 for more information on discontinued operations.

Use of Estimates and Basis of Presentation

The information furnished in the accompanying Condensed Consolidated Financial Statements reflects certain estimates required and all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the September 30, 2018, December 31, 2017, and September 30, 2017 financial information and are of a normal recurring nature. Certain industries in which we operate are highly seasonal, and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements, as well as changes in market prices. In particular, the normal peak usage season for electric utilities is June through August while the normal peak usage season for gas utilities is November through March. Significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three and nine months ended September 30, 2018 and September 30, 2017, and our financial condition as of September 30, 2018, December 31, 2017, and September 30, 2017, are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted.

Cash and Cash Equivalents and Restricted Cash

For purposes of the cash flow statements, we consider all highly liquid investments with original maturities of three months or less at the time of purchase to be cash equivalents.

Investments

We account for investments that we do not control under the cost method of accounting as we do not have the ability to exercise significant influence over the operating and financial policies of the investee. The cost method investments are recorded at cost and we record dividend income when applicable dividends are declared.


10



Recently Issued Accounting Standards

Leases, ASU 2016-02

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases. This ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for most leases, whereas today only financing-type lease liabilities (capital leases) are recognized on the balance sheet. In addition, the definition of a lease has been revised in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement, which may result in changes to the classification of an arrangement as a lease. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. The ASU expands the disclosure requirements of lease arrangements. Under the current guidance, lessees and lessors will use a modified retrospective transition approach, which requires application of the new guidance at the beginning of the earliest comparative period presented in the year of adoption. The guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted. In January 2018, the FASB issued amendments to the new lease standard, ASU No. 2018-01, allowing an entity to elect not to assess whether certain land easements are, or contain, leases when transitioning to the new lease standard. The FASB also issued additional amendments to the new lease standard in July 2018, ASU No. 2018-11, allowing companies to adopt the new standard with a cumulative effect adjustment as of the beginning of the year of adoption with prior year comparative financial information and disclosures remaining as previously reported.

We expect to adopt this standard on January 1, 2019. For existing or expired land easements that were not previously accounted for as a lease, we anticipate electing the practical expedient which provides for no assessment of these easements. Further, we anticipate adopting the new standard with a cumulative effect adjustment with prior year comparative financial information remaining as previously reported when transitioning to the new standard. The standard also provides a transition practical expedient, commonly referred to as the “package of three”, that must be taken together and allows entities to (1) not reassess whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases. We expect to elect the “package of three” practical expedient. We continue to evaluate the additional transition practical expedients available under the guidance. At this time, we do not believe the implementation of this standard will have a material impact on our financial position, results of operations or cash flows. We continue to develop our process of identifying and categorizing our lease contracts and evaluating our current business processes relating to leases. We have selected, configured, and tested a new lease software solution and will be entering lease data into the new system in preparation for the January 1, 2019 standard adoption. We also continue to monitor utility industry lease implementation guidance that may change existing and future lease classification.

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

In August 2017, the FASB issued 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. This ASU is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. We do not anticipate the adoption of this guidance to have a material impact on our financial position, results of operations or cash flows.

Simplifying the Test for Goodwill Impairment, ASU 2017-04

In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment (Topic 350) 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 15, 2019, applied on a prospective basis with early adoption permitted. We do not anticipate the adoption of this standard to have any impact on our financial position, results of operations or cash flows.


11



Recently Adopted Accounting Standards

Revenue from Contracts with Customers, ASU 2014-09

Effective January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and its related amendments (collectively known as ASC 606). Under this standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In addition, the standard requires disclosure of the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. We applied the five-step method outlined in the ASU to all in-scope revenue streams and elected the modified retrospective implementation method. Implementation of the standard did not have a material impact on our financial position, results of operations or cash flows. Implementation of the standard did not have a significant impact on the measurement or recognition of revenue; therefore, no cumulative adoption adjustment to the opening balance of Retained earnings at the date of initial application was necessary. The additional disclosures required by the ASU are included in Note 2.

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

Effective January 1, 2018, we adopted ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost. The standard requires employers to report the service cost component in the same line item(s) as other compensation costs, and requires the other components of net periodic pension and post-retirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component may be eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. The capitalization of only the service cost component of net periodic pension and post-retirement benefit costs in assets was applied on a prospective basis for the nine months ended September 30, 2018. Retrospective impact was not material and therefore prior year presentation was not changed. For our rate-regulated entities, we capitalize the other components of net periodic benefit costs into regulatory assets or regulatory liabilities and maintain a FERC-to-GAAP reporting difference for these capitalized costs. The presentation changes required for net periodic pension and post-retirement costs resulted in offsetting changes to Operating income and Other income. Implementation of the standard did not have a material impact on our financial position, results of operations or cash flows.

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

Effective January 1, 2018, we adopted ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). This ASU requires changes in the presentation of certain items, including but not limited to, debt prepayment or debt extinguishment costs, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. We implemented this standard effective January 1, 2018 using the retrospective transition method. This standard had no impact on our financial position, results of operations or cash flows.

Statement of Cash Flows: Restricted Cash, ASU 2016-18

Effective January 1, 2018, we adopted ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. This ASU provides guidance on the presentation of restricted cash or restricted cash equivalents and reduces the diversity in practice. This ASU requires amounts generally described as restricted cash and restricted cash equivalents to be included with cash and cash equivalents when reconciling beginning-of-period and end-of-period total amounts on the statement of cash flows. We elected, as permitted by the standard, to early adopt ASU 2016-18 retrospectively as of January 1, 2017 and have applied it to all periods presented herein. The adoption of ASU 2016-18 did not have a material impact to our condensed consolidated financial statements. The effect of the adoption of ASU 2016-18 on our Condensed Consolidated Statements of Cash Flows was to include restricted cash balances in the beginning and end of period balances of cash, cash equivalents, and restricted cash. The change in restricted cash was previously disclosed in investing activities in the Condensed Consolidated Statements of Cash Flows.

12




(2)    REVENUE

Revenue Recognition
Revenues are 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. Our primary types of revenue contracts are:

Regulated natural gas and electric utility services tariffs - Our utilities have regulated operations, as defined by ASC 980, that provide services to regulated customers under rates, charges, terms and conditions of service, and prices determined by the jurisdictional regulators designated for our service territories. Collectively, these rates, charges, terms and conditions are included in a tariff, which governs all aspects of the provision of our regulated services. Our regulated services primarily encompass single performance obligations material to the context of the contract for delivery of either commodity natural gas, commodity electricity, natural gas transportation or electric transmission services. These service revenues are variable based on quantities delivered, influenced by seasonal business and weather patterns. Tariffs are only permitted to be changed through a rate-setting process involving the regulator-empowered statute to establish contractual rates between the utility and its customers. All of our utilities’ regulated sales are subject to regulatory-approved tariffs.

Power sales agreements - Our electric utilities and power generation segments have long-term wholesale power sales agreements with other load-serving entities, including affiliates, for the sale of excess power from owned generating units. These agreements include a combination of “take or pay” arrangements, where the customer is obligated to pay for the energy regardless of whether it actually takes delivery, as well as “requirements only” arrangements, where the customer is only obligated to pay for the energy the customer needs. In addition to these long-term contracts, Black Hills also sells excess energy to other load-serving entities on a short-term basis as a member of the Western States Power Pool. The pricing for all of these arrangements is included in the executed contracts or confirmations, reflecting the standalone selling price and is variable based on energy delivered.

Coal supply agreements - Our mining segment sells coal primarily under long-term contracts to utilities for use at their power generating plants, including affiliate electric utilities, and an affiliate non-regulated power generation entity. The contracts include a single promise to supply coal necessary to fuel the customers’ facilities during the contract term. The transaction price is established in the coal supply agreements, including cost-based agreements with the affiliated regulated utilities, and is variable based on tons of coal delivered.

Other non-regulated services - Our natural gas and electric utility segments also provide non-regulated services primarily comprised of appliance repair service and protection plans, electric and natural gas technical infrastructure construction and maintenance services, and in Nebraska and Wyoming, an unbundled natural gas commodity offering under the regulatory-approved Choice Gas Program. Revenue contracts for these services generally represent a single performance obligation with the price reflecting the standalone selling price stated in the agreement, and the revenue is variable based on the units delivered or services provided.


13



The following tables depict the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reporting segments, for the three and nine months ended September 30, 2018. Sales tax and other similar taxes are excluded from revenues.
Three Months Ended September 30, 2018
 Electric Utilities
 Gas Utilities
 Power Generation
 Mining
Inter-company Revenues
Total
Customer types:
(in thousands)
Retail
$
157,049

$
88,559

$

$
16,751

$
(7,941
)
$
254,418

Transportation

30,079



(267
)
29,812

Wholesale
8,255


14,485


(13,047
)
9,693

Market - off-system sales
9,059

140



(1,349
)
7,850

Transmission/Other
10,196

11,887



(3,693
)
18,390

Revenue from contracts with customers
184,559

130,665

14,485

16,751

(26,297
)
320,163

Other revenues
231

1,011

9,118

550

(9,094
)
1,816

Total revenues
$
184,790

$
131,676

$
23,603

$
17,301

$
(35,391
)
$
321,979

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

$

$

$
16,751

$
(7,941
)
$
8,810

Services transferred over time
184,559

130,665

14,485


(18,356
)
311,353

Revenue from contracts with customers
$
184,559

$
130,665

$
14,485

$
16,751

$
(26,297
)
$
320,163

 
 
 
 
 
 
 

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

$
565,816

$

$
49,653

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

Transportation

100,760



(977
)
99,783

Wholesale
25,497


41,161


(36,874
)
29,784

Market - off-system sales
18,142

728



(5,531
)
13,339

Transmission/Other
36,622

36,230



(10,967
)
61,885

Revenue from contracts with customers
529,743

703,534

41,161

49,653

(78,110
)
1,245,981

Other revenues
2,218

3,106

27,429

1,675

(27,337
)
7,091

Total revenues
$
531,961

$
706,640

$
68,590

$
51,328

$
(105,447
)
$
1,253,072

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

$

$

$
49,653

$
(23,761
)
$
25,892

Services transferred over time
529,743

703,534

41,161


(54,349
)
1,220,089

Revenue from contracts with customers
$
529,743

$
703,534

$
41,161

$
49,653

$
(78,110
)
$
1,245,981

 
 
 
 
 
 
 
The majority of our revenue contracts are based on variable quantities delivered; any fixed consideration contracts with an expected duration of one year or more are immaterial to our consolidated revenues. Variable consideration constraints in the form of discounts, rebates, credits, price concessions, incentives, performance bonuses, penalties or other similar items are not material for our revenue contracts. We are the principal in our revenue contracts, as we have control over the services prior to those services being transferred to the customer.


14



Revenue Not in Scope of ASC 606
Other revenues included in the tables above include our revenue accounted for under separate accounting guidance, including lease revenue under ASC 840, derivative revenue under ASC 815 and alternative revenue programs revenue under ASC 980. The majority of our lease revenue is related to a 20-year power sale agreement between Colorado IPP and affiliate Colorado Electric. This agreement is accounted for as a direct financing lease whereby Colorado IPP receives revenue for energy delivered and related capacity payments. This lease revenue is eliminated in our consolidated revenues.

Significant Judgments and Estimates
TCJA Revenue Reserve

The TCJA or “tax reform” signed into law on December 22, 2017, reduced the federal corporate income tax rate from 35% to 21% effective for tax years beginning after December 31, 2017. Black Hills has been collaborating with utility commissions in the states in which it provides utility service to deliver to customers the benefits of a lower corporate federal income tax rate beginning in 2018 with the passage of the TCJA. We have received state utility commission approvals to provide the benefits of federal tax reform to utility customers in six states. We estimated and recorded a reserve to revenue of approximately $6.0 million and $29 million during the three and nine months ended September 30, 2018, respectively. As of September 30, 2018, $7.9 million has been returned to customers and approximately $21 million remains in reserve.

Unbilled Revenue

Revenues attributable to natural gas and electricity delivered to customers but not yet billed are estimated and accrued, and the related costs are charged to expense. Factors influencing the determination of unbilled revenues include estimates of delivered sales volumes based on weather information and customer consumption trends.

Contract Balances

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

Practical Expedients
Our revenue contracts generally provide for performance obligations that are fulfilled and transfer control to customers over time, represent a series of distinct services that are substantially the same, involve the same pattern of transfer to the customer, and provide a right to consideration from our customers in an amount that corresponds directly with the value to the customer for the performance completed to date. Therefore, we recognize revenue in the amount to which we have a right to invoice.

We have revenue contract performance obligations with similar characteristics, and we reasonably expect that the financial statement impact of applying the new revenue recognition guidance to a portfolio of contracts would not differ materially from applying this guidance to the individual contracts or performance obligations within the portfolio. Therefore, we have elected the portfolio approach in applying the new revenue guidance.


15



(3)    BUSINESS SEGMENT INFORMATION

Segment information and Corporate and Other included in the accompanying Condensed Consolidated Statements of Income were as follows (in thousands):
Three Months Ended September 30, 2018
External Operating Revenue
 
Inter-company Operating Revenue
 
 Total Revenues
 
Net income (loss) from continuing operations
 Contract Customers
 Other Revenues
 Contract Customers
 Other Revenues
Segment:
 
 
 
 
 
 
 
 
 
Electric Utilities
$
179,527

$
231


$
5,032

$


$
184,790


$
21,578

Gas Utilities
130,390

1,011


275



131,676


(13,277
)
Power Generation (b)
1,437

348


13,048

8,770


23,603


6,691

Mining
8,809

226


7,942

324


17,301


3,572

Corporate and Other








(757
)
Inter-company eliminations


 
(26,297
)
(9,094
)
 
(35,391
)
 

Total
$
320,163

$
1,816

 
$

$

 
$
321,979

 
$
17,807


Under our modified retrospective adoption of ASU 2014-09, revenues for the three and nine months ended September 30, 2017 are not presented by contract type.
 
Three Months Ended September 30, 2017
External Operating Revenue
 
Inter-company Operating Revenue
 
Net income (loss) from continuing operations
 
 
Segment:
 
 
 
 
 
 
Electric Utilities
$
181,238

 
$
2,333

 
$
27,324

 
Gas Utilities
142,821

 
73

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

 
21,117

 
6,155

 
Mining
9,742

 
7,751

 
3,477

 
Corporate and Other

 

 
(3,664
)
 
Inter-company eliminations

 
(31,274
)
 

 
Total
$
335,611

 
$

 
$
28,963


 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2018
External Operating
Revenue
 
Inter-company Operating Revenue
 
Total Revenues
 
Net income (loss) from continuing operations
 Contract Customers
 Other Revenues
 Contract Customers
 Other Revenues
Segment:
 
 
 
 
 
 
 
 
 
Electric Utilities
$
513,270

$
2,218

 
$
16,473

$

 
$
531,961

 
$
63,313

Gas Utilities (a)
702,532

3,106

 
1,002


 
706,640

 
93,182

Power Generation (b)
4,287

1,066

 
36,874

26,363

 
68,590

 
17,319

Mining
25,892

701

 
23,761

974

 
51,328

 
9,561

Corporate and Other


 


 

 
(5,877
)
Inter-company eliminations


 
(78,110
)
(27,337
)
 
(105,447
)
 

Total
$
1,245,981

$
7,091

 
$

$

 
$
1,253,072

 
$
177,498


16



 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2017
External Operating Revenue
 
Inter-company
Operating
Revenue
 
Net income (loss) from continuing operations
 
 
Segment:
 
 
 
 
 
 
Electric Utilities
$
518,925

 
$
9,123

 
$
68,386

 
Gas Utilities
674,161

 
90

 
41,409

 
Power Generation (b)
5,382

 
62,907

 
18,017

 
Mining
26,500

 
22,485

 
9,048

 
Corporate and Other (c)

 

 
(6,994
)
 
Inter-company eliminations

 
(94,605
)
 

 
Total
$
1,224,968

 
$

 
$
129,866

___________
(a)
Net income from continuing operations available for common stock for the nine months ended September 30, 2018 included a $49 million tax benefit resulting from legal entity restructuring. See Note 19 Income Taxes of the Notes to Condensed Consolidated Financial Statements for more information.
(b)
Net income from continuing operations available for common stock for the three and nine months ended September 30, 2018 and September 30, 2017 reflects net income attributable to noncontrolling interests of $4.0 million and $10.4 million, and $3.9 million and $10.6 million, respectively.
(c)
Net income (loss) from continuing operations available for common stock for the nine months ended September 30, 2017 included a $1.4 million tax benefit recognized from carryback claims for specified liability losses involving prior tax years.

Segment information and Corporate and Other balances included in the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands):
Total Assets (net of inter-company eliminations) as of:
September 30, 2018
 
December 31, 2017
 
September 30, 2017
Segment:
 
 
 
 
 
Electric Utilities (a)
$
2,853,414

 
$
2,906,275

 
$
2,911,919

Gas Utilities
3,433,316

 
3,426,466

 
3,288,104

Power Generation (a)
122,428

 
60,852

 
64,357

Mining
72,602

 
65,455

 
66,700

Corporate and Other
177,324

 
115,612

 
115,330

Discontinued operations
2,854

 
84,242

 
117,338

Total assets
$
6,661,938

 
$
6,658,902

 
$
6,563,748

__________
(a)
The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation Station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric as a capital lease.


17



(4)    ACCOUNTS RECEIVABLE

Following is a summary of Accounts receivable, net included in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
 
Accounts
Unbilled
Less Allowance for
Accounts
September 30, 2018
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
43,108

$
31,381

$
(386
)
$
74,103

Gas Utilities
48,638

24,768

(2,188
)
71,218

Power Generation
1,696



1,696

Mining
3,749



3,749

Corporate
2,030



2,030

Total
$
99,221

$
56,149

$
(2,574
)
$
152,796


 
Accounts
Unbilled
Less Allowance for
Accounts
December 31, 2017
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
39,347

$
36,384

$
(586
)
$
75,145

Gas Utilities
81,256

88,967

(2,495
)
167,728

Power Generation
1,196



1,196

Mining
2,804



2,804

Corporate
1,457



1,457

Total
$
126,060

$
125,351

$
(3,081
)
$
248,330


 
Accounts
Unbilled
Less Allowance for
Accounts
September 30, 2017
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
42,716

$
29,762

$
(494
)
$
71,984

Gas Utilities
49,842

24,516

(1,190
)
73,168

Power Generation
1,010



1,010

Mining
3,534



3,534

Corporate
629



629

Total
$
97,731

$
54,278

$
(1,684
)
$
150,325



18



(5)    REGULATORY ACCOUNTING

We had the following regulatory assets and liabilities (in thousands) as of:
 
September 30, 2018
December 31, 2017
September 30, 2017
Regulatory assets
 
 
 
Deferred energy and fuel cost adjustments (a)
$
29,976

$
20,187

$
20,559

Deferred gas cost adjustments (a)
720

31,844

12,833

Gas price derivatives (a)
6,192

11,935

11,297

Deferred taxes on AFUDC (b)
7,804

7,847

15,645

Employee benefit plans (c)
106,734

109,235

105,671

Environmental (a)
972

1,031

1,051

Asset retirement obligations (a)
526

517

514

Loss on reacquired debt (a)
21,431

20,667

21,067

Renewable energy standard adjustment (a)
1,131

1,088

1,956

Deferred taxes on flow through accounting (c) (e)
29,342

26,978

41,900

Decommissioning costs (b)
11,052

13,287

13,989

Gas supply contract termination (a)
15,745

20,001

21,402

Other regulatory assets (a)
28,725

32,837

32,710

Total regulatory assets
260,350

297,454

300,594

Less current regulatory assets
(48,302
)
(81,016
)
(61,023
)
Regulatory assets, non-current
$
212,048

$
216,438

$
239,571

 
 
 
 
Regulatory liabilities
 
 
 
Deferred energy and gas costs (a)
$
15,980

$
3,427

$
3,780

Employee benefit plan costs and related deferred taxes (c) (e)
39,332

40,629

66,620

Cost of removal (a)
146,177

130,932

125,360

Excess deferred income taxes (c) (d)
316,625

301,553

52

TCJA revenue reserve
20,592



Other regulatory liabilities (c)
11,582

8,585

9,419

Total regulatory liabilities
550,288

485,126

205,231

Less current regulatory liabilities
(41,442
)
(6,832
)
(7,042
)
Regulatory liabilities, non-current
$
508,846

$
478,294

$
198,189

__________
(a)
Recovery of costs, but we are not allowed a rate of return.
(b)
In addition to recovery of costs, we are allowed a rate of return.
(c)
In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base.
(d)
The increase in the regulatory tax liability is primarily related to the revaluation of deferred income tax balances at the lower income tax rate. As of September 30, 2018 and December 31, 2017, all of the liability was classified as non-current due to uncertainties around the timing and other regulatory decisions that will affect the amount of regulatory tax liability amortized and returned to customers through rate reductions or other revenue offsets.
(e)
The variance to the prior periods is primarily due to the decrease in federal income tax from 35% to 21% as a result of the TCJA.

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 2017 Annual Report on Form 10-K.


19



TCJA revenue reserve - The TCJA signed into law on December 22, 2017, reduced the federal corporate income tax rate from 35% to 21%. Effective January 1, 2018, the key impact of tax reform on existing utility revenues/tariffs established prior to tax reform results primarily from the change in the federal tax rate from 35% to 21% (including the effects of tax gross-ups not yet approved) affecting current income tax expense embedded in those tariffs. Black Hills has been collaborating with utility commissions in the states in which it provides utility service to deliver to customers the benefits of a lower corporate federal income tax rate beginning in 2018 with the passage of the TCJA. We have received state utility commission approvals to provide the benefits of federal tax reform to utility customers in six states. We estimated and recorded a reserve to revenue of approximately $6.0 million and $29 million during the three and nine months ended September 30, 2018, respectively. As of September 30, 2018, $7.9 million has been returned to customers.

A list of states where benefits to customers of federal tax reform have been approved is summarized below.

State
Approximate 2018 Benefit for Customers
Start Date for Customer Benefits
Arkansas
$
9.7
 million
October 2018
Colorado
$
10.8
 million
July 2018
Iowa
$
2.4
 million
June 2018
Kansas
$
1.9
 million
April 2018
Nebraska
$
3.8
 million
July 2018
South Dakota
$
7.7
 million
October 2018

In support of returning benefits to customers, the three rate review requests filed in 2017 for Arkansas Gas, Wyoming Gas (Northwest Wyoming) and Rocky Mountain Natural Gas (a pipeline system in Colorado) were adjusted to include the benefits to customers of federal tax reform as discussed below.

Rate Reviews

RMNG
In Colorado, new rates for RMNG went into effect June 1, 2018 after an administrative law judge recommended approval of a settlement agreement and the CPUC took no further action. The settlement included $1.1 million in annual revenue increases and an extension of the SSIR to recover costs from 2018 through December 31, 2021. The annual increase is based on a return on equity of 9.9% and a capital structure of 46.63% equity and 53.37% debt. New rates are inclusive of customer benefits related to the TCJA.

Wyoming Gas
On July 16, 2018, the WPSC reached a bench decision approving our Wyoming Gas (Northwest Wyoming) settlement and stipulation with the OCA. We received the final order in the third quarter of 2018. The settlement provides for $1.0 million of new revenue, a return on equity of 9.6%, and a capital structure of 54.0% equity and 46.0% debt. New rates, inclusive of customer benefits related to the TCJA, were effective September 1, 2018.

Arkansas Gas
On October 5, 2018, Arkansas Gas received approval from the APSC for a general rate increase. The new rates will generate approximately $12 million of new annual revenue. The APSC’s approval also allows Arkansas Gas to include $11 million of revenue that is currently being collected through certain rider mechanisms in the new base rates. The new revenue increase is based on a return on equity of 9.61% and a capital structure of 49.1% equity and 50.9% debt. New rates, inclusive of customer benefits related to the TCJA, were effective October 15, 2018.

Wyoming Electric
On October 31, Wyoming Electric received approval from the WPSC for a comprehensive, multi-year settlement regarding its PCA Application filed earlier in 2018. Wyoming Electric’s PCA permits the recovery of costs associated with fuel, purchased electricity and other specified costs, including the portion of the company’s energy that is delivered from the Wygen I PPA with Black Hills Wyoming. Wyoming Electric will provide an aggregate $7.0 million in customer credits through the PCA mechanism in 2018, 2019 and 2020 to resolve all outstanding issues relating to its current and prior PCA filings. The settlement also stipulates the adjustment for the variable cost segment of the Wygen I PPA with Wyoming Electric will escalate by 3.0% annually through 2022, providing price certainty for Wyoming Electric and its customers. As of September 30, 2018, we have recorded a liability of $4.5 million related to the PCA.

20




Nebraska Gas
On June 1, 2018, Nebraska Gas Distribution filed an application with the NPSC requesting a continuation of the SSIR beyond the expiration date of October 31, 2019. On September 5, 2018, the NSPC approved continuation of the SSIR tariff to December 31, 2020. The SSIR provides approximately $6.0 million of revenue annually on investments made prior to January 1, 2018, with investments after that date to be recovered through other methods. If a base rate review is filed prior to expiration of the rider, that rate request will include the remaining investment to be recovered.

Kansas Gas
On June 19, 2018, Kansas Gas received approval from the Kansas Corporation Commission to double annual eligible investments up to $8.0 million for safety related integrity investments under the Gas System Reliability rider.


(6)    MATERIALS, SUPPLIES AND FUEL

The following amounts by major classification are included in Materials, supplies and fuel in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
 
September 30, 2018
 
December 31, 2017
 
September 30, 2017
Materials and supplies
$
73,777

 
$
69,732

 
$
70,284

Fuel - Electric Utilities
2,750

 
2,962

 
2,993

Natural gas in storage held for distribution
46,091

 
40,589

 
49,589

Total materials, supplies and fuel
$
122,618

 
$
113,283

 
$
122,866




(7)    INVESTMENTS

In February 2018, we contributed $28 million of assets in exchange for equity securities in a privately held company. The carrying value of our investment in the equity securities was determined using the cost method. We review this investment on a periodic basis to determine whether a significant event or change in circumstances has occurred that may have an adverse effect on the value of the investment. We estimate that the fair value of this cost method investment approximated or exceeded its carrying value as of September 30, 2018.

The following table presents the carrying value of our investments (in thousands) as of:
 
September 30, 2018
 
December 31, 2017
 
September 30, 2017
Cost method investment
$
28,134

 
$

 
$

Cash surrender value of life insurance contracts
13,068

 
13,090

 
12,947

Total investments
$
41,202

 
$
13,090

 
$
12,947



(8)    EARNINGS PER SHARE

A reconciliation of share amounts used to compute Earnings (loss) per share in the accompanying Condensed Consolidated Statements of Income was as follows (in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
2017
 
2018
2017
 
 
 
 
 
 
Net income available for common stock
$
16,950

$
27,663

 
$
171,871

$
126,381

 
 
 
 
 
 
Weighted average shares - basic
53,364

53,243

 
53,346

53,208

Dilutive effect of:
 
 
 
 
 
Equity Units (a)
1,344

2,015

 
1,060

1,872

Equity compensation
111

174

 
102

174

Weighted average shares - diluted
54,819

55,432

 
54,508

55,254

__________
(a)
Calculated using the treasury stock method.

The following outstanding securities were excluded in the computation of diluted net income (loss) per share as their inclusion would have been anti-dilutive (in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
2017
 
2018
2017
 
 
 
 
 
 
Equity compensation
12


 
15


Anti-dilutive shares
12


 
15




(9)    NOTES PAYABLE, CURRENT MATURITIES AND DEBT

We had the following notes payable outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
 
September 30, 2018
December 31, 2017
September 30, 2017
 
Balance Outstanding
Letters of Credit
Balance Outstanding
Letters of Credit
Balance Outstanding
Letters of Credit
Revolving Credit Facility
$

$
15,203

$

$
26,848

$

$
25,391

CP Program
112,100


211,300


225,170


Total
$
112,100

$
15,203

$
211,300

$
26,848

$
225,170

$
25,391


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 September 30, 2018. Based on our credit ratings, a 0.175% commitment fee was charged on the unused amount at September 30, 2018. Margins and the commitment fee rate decreased in August 2018 due to our upgraded credit rating from S&P.

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.

21



Our net payments under the CP Program during the nine months ended September 30, 2018 were $99 million and our notes outstanding as of September 30, 2018 were $112 million. As of September 30, 2018, the weighted average interest rate on CP Program borrowings was 2.42%.

Debt Covenants

Under our Revolving Credit Facility and term loan agreement (before each was amended and restated), we were required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00. At September 30, 2018, our Consolidated Indebtedness to Capitalization Ratio was calculated by dividing (i) Consolidated Indebtedness (which included letters of credit and certain guarantees issued but excluded the RSNs), by (ii) Capital, which is Consolidated Indebtedness plus Consolidated Net Worth (which excluded noncontrolling interests in subsidiaries and included the aggregate outstanding amount of the RSNs). Under our amended and restated revolving Credit Facility and amended and restated term loan agreement, we are also required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00, but as of September 30, 2018 only, Consolidated Net Worth will include the amount receivable by the Company in connection with the common stock settlement under the purchase contracts which are part of the Equity Units, rather than the outstanding amount of the RSNs.

Our Revolving Credit Facility and term loans require compliance with the following financial covenant at the end of each quarter:
 
As of September 30, 2018
 
Covenant Requirement
Consolidated Indebtedness to Capitalization Ratio
61.4%
 
Less than
65%

As of September 30, 2018, we were in compliance with this covenant.

Current Maturities

As of September 30, 2018, our $250 million senior unsecured notes due January 11, 2019 and $5.7 million of principal due in the next twelve months on our Corporate term loan due June 7, 2021 are classified as Current maturities of long-term debt on our Condensed Consolidated Balance Sheets.

Long-Term Debt

On August 17, 2018, we issued $400 million principal amount, 4.350% senior unsecured notes due 2033. A portion of these notes were issued in a private exchange that resulted in the retirement of all $299 million principal amount of our RSNs due 2028. The remainder of the notes were sold for cash in a public offering, with the net proceeds being used to pay down short-term debt.

The issuance of these new senior notes was the culmination of a series of transactions that also included the contractually required remarketing of such RSNs on behalf of the holders of our Equity Units, with the proceeds being deposited as collateral to secure the obligations of those holders under the purchase contracts included in the Equity Units (see subsequent event in Note 10). As a result of the remarketing, the annual interest rate on such RSNs was automatically reset to 4.579% (however, because the RSNs were then immediately retired, no interest accrued at this reset rate).

On July 30, 2018, we amended and restated our unsecured term loan due August 2019. This amended and restated term loan, with $300 million outstanding at September 30, 2018, will now mature on July 30, 2020 and has substantially similar terms and covenants as the amended and restated Revolving Credit Facility. The interest cost associated with this term loan is 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 and Eurodollar borrowings were 0.000% and 0.700%, respectively, at September 30, 2018.


22



(10)    EQUITY

A summary of the changes in equity is as follows:

Nine Months Ended September 30, 2018
Total Stockholders’ Equity
Noncontrolling Interest
Total Equity
 
 
(in thousands)
 
Balance at December 31, 2017
$
1,708,974

$
111,232

$
1,820,206

Net income (loss)
171,871

10,447

182,318

Other comprehensive income
3,481


3,481

Dividends on common stock
(76,309
)

(76,309
)
Share-based compensation
4,871


4,871

Dividend reinvestment and stock purchase plan
220


220

Other stock transactions
147


147

Distribution to noncontrolling interest

(13,755
)
(13,755
)
Balance at September 30, 2018
$
1,813,255

$
107,924

$
1,921,179


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

$
115,495

$
1,730,134

Net income (loss)
126,381

10,567

136,948

Other comprehensive income
2,317


2,317

Dividends on common stock
(71,334
)

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


5,853

Dividend reinvestment and stock purchase plan
2,300


2,300

Redeemable noncontrolling interest
(886
)

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


3,714

Other stock transactions
(180
)

(180
)
Distribution to noncontrolling interest

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

$
113,178

$
1,795,982


At-the-Market Equity Offering Program

On August 4, 2017, we renewed our ATM equity offering program which reset the size of the program to an aggregate value of up to $300 million. The renewed program, which allows us to sell shares of our common stock, is the same as the prior program other than the aggregate value increased from $200 million to $300 million. The shares may be offered from time to time pursuant to a sales agreement dated August 4, 2017. Shares of common stock are offered pursuant to our shelf registration statement filed with the SEC. We did not issue any common shares during the nine months ended September 30, 2018 or September 30, 2017 under the ATM equity offering program.


23



Subsequent Event - Equity Units Settlement

On October 29, 2018, we announced the settlement rate for the stock purchase contracts that are components of the Equity Units issued November 23, 2015. The settlement rate was based upon the minimum settlement rate, as adjusted to account for past dividends, because the average of the closing price per share of Black Hills Corporation common stock on the New York Stock Exchange for the 20 consecutive trading days ending on October 29, 2018 exceeded the threshold appreciation price. Each holder of the Equity Units on that date, following payment of $50.00 for each unit which it holds, received 1.0655 shares of Black Hills Corporation common stock for each such unit. The holders' obligations to make such payments were satisfied with proceeds generated by the successful remarketing on August 17, 2018, of the RSNs that formerly constituted a component of the Equity Units.

Upon settlement of all outstanding stock purchase obligations, the Company received gross proceeds of approximately $299 million in exchange for approximately 6.372 million shares of common stock. Proceeds will be used to pay down the $250 million senior unsecured notes due January 11, 2019, with the balance used to pay down short-term debt.

As of November 1, 2018, after the Equity Units settlement, we had shares outstanding of approximately 59.97 million.


(11)    RISK MANAGEMENT ACTIVITIES

Our activities in the regulated and non-regulated energy sectors expose us to a number of risks in the normal operation of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and credit risk. To manage and mitigate these identified risks, we have adopted the Black Hills Corporation Risk Policies and Procedures as discussed in our 2017 Annual Report on Form 10-K.

Market Risk

Market risk is the potential loss that might occur as a result of an adverse change in market price or rate. We are exposed to the following market risks including, but not limited to:

Commodity price risk associated with our retail natural gas marketing activities and our fuel procurement for certain gas-fired generation assets; and

Interest rate risk associated with our variable rate debt.

Credit Risk

Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty.

For production and generation activities, we attempt to mitigate our credit exposure by conducting business primarily with high credit quality entities, setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements, and mitigating credit exposure with less creditworthy counterparties through parental guarantees, prepayments, letters of credit, and other security agreements.

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

Our derivative and hedging activities recorded in the accompanying Condensed Consolidated Balance Sheets, Condensed Consolidated Statements of Income and Condensed Consolidated Statements of Comprehensive Income are detailed below and in Note 12.


24



Utilities

The operations of our utilities, including natural gas sold by our Gas Utilities and natural gas used by our Electric Utilities’ generation plants or those plants under PPAs where our Electric Utilities must provide the generation fuel (tolling agreements), expose our utility customers to volatility in natural gas prices. Therefore, as allowed or required by state utility commissions, we have entered into commission-approved hedging programs utilizing natural gas futures, options, over-the-counter swaps and basis swaps to reduce our customers’ underlying exposure to these fluctuations. These transactions are considered derivatives, and in accordance with accounting standards for derivatives and hedging, mark-to-market adjustments are recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets, net of balance sheet offsetting as permitted by GAAP.

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

We buy, sell and deliver natural gas at competitive prices by managing commodity price risk. As a result of these activities, this area of our business is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risks using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and/or sales during time frames ranging from October 2018 through May 2020; 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 effective portion of the gain or loss on these designated derivatives is reported in AOCI in the accompanying Condensed Consolidated Balance Sheets and the ineffective portion, if any, is reported in Fuel, purchased power and cost of natural gas sold in the accompanying Condensed Consolidated Statements of Income. Effectiveness of our hedging position is evaluated at inception of the hedge, upon occurrence of a triggering event and as of the end of each quarter.

The contract or notional amounts and terms of the natural gas derivative commodity instruments held at our utilities are composed of both long and short positions. We were in a net long position as of:
 
September 30, 2018
 
December 31, 2017
 
September 30, 2017
 
Notional
(MMBtus)
 
Maximum
Term
(months) (a)
 
Notional
(MMBtus)
 
Maximum
Term
(months) (a)
 
Notional
(MMBtus)
 
Maximum
Term
(months) (a)
Natural gas futures purchased
5,300,000

 
27
 
8,330,000

 
36
 
10,250,000

 
39
Natural gas options purchased, net
9,670,000

 
16
 
3,540,000

 
14
 
7,360,000

 
17
Natural gas basis swaps purchased
5,140,000

 
27
 
8,060,000

 
36
 
9,170,000

 
39
Natural gas over-the-counter swaps, net (b)
4,370,000

 
20
 
3,820,000

 
29
 
4,600,000

 
20
Natural gas physical contracts, net (c)
19,539,851

 
33
 
12,826,605

 
35
 
21,071,714

 
38
__________
(a)
Term reflects the maximum forward period hedged.
(b)
As of September 30, 2018, 2,236,000 MMBtus were designated as cash flow hedges for the natural gas over-the-counter swaps purchased.
(c)
Volumes exclude contracts that qualify for the normal purchase, normal sales exception.

Based on September 30, 2018 prices, a $0.1 million gain would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods.

We have certain derivative contracts which contain credit provisions. These credit provisions may require the Company to post collateral when credit exposure to the Company is in excess of a negotiated line of unsecured credit. At September 30, 2018, the Company posted $0.7 million related to such provisions, which is included in Other current assets on the Condensed Consolidated Balance Sheets.


25



Financing Activities

At September 30, 2018, we had no outstanding interest rate swap agreements. Our last interest rate swap agreement with a $50 million notional value, which was designated to borrowings on our Revolving Credit Facility, expired in January 2017.

Discontinued Operations

Our Oil and Gas segment was exposed to risks associated with changes in the market prices of oil and gas. Through December 2017, we used exchange traded futures, swaps and options to hedge portions of our crude oil and natural gas production to mitigate commodity price risk and preserve cash flows. Hedge accounting was elected on the swaps and futures contracts. These transactions were designated upon inception as cash flow hedges, documented under accounting standards for derivatives and hedging and initially met prospective effectiveness testing. As a result of divesting our Oil and Gas assets, these activities were discontinued and there were no outstanding derivative agreements as of September 30, 2018 or December 31, 2017. At September 30, 2017, we had outstanding crude oil futures and swap contracts with notional volumes of 54,000 Bbls, crude oil option contracts with notional volumes of 9,000 Bbls and natural gas futures and swap contracts with notional volumes of 540,000 MMBtus.

Cash Flow Hedges

The impacts of cash flow hedges on our Condensed Consolidated Statements of Income is presented below for the three and nine months ended September 30, 2018 and 2017 (in thousands). Note that this presentation does not reflect gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled.
Three Months Ended September 30, 2018
Derivatives in Cash Flow Hedging Relationships
 
Location of
Reclassifications from AOCI into Income
 
Amount of
Gain/(Loss) Reclassified
from AOCI
into Income
(Settlements)
 
Location of
Gain/(Loss)
Recognized in
Income on
Derivative
(Ineffective
Portion)
 
Amount of
Gain/(Loss)
Recognized in
Income on
Derivative
(Ineffective
Portion)
Interest rate swaps
 
Interest expense
 
$
(712
)
 
Interest expense
 
$

Commodity derivatives
 
Fuel, purchased power and cost of natural gas sold
 
(18
)
 
Fuel, purchased power and cost of natural gas sold
 

Total
 
 
 
$
(730
)
 
 
 
$


Three Months Ended September 30, 2017
Derivatives in Cash Flow Hedging Relationships
 
Location of
Reclassifications from AOCI into Income
 
Amount of
Gain/(Loss) Reclassified
from AOCI
into Income
(Settlements)
 
Location of
Gain/(Loss)
Recognized in
Income on
Derivative
(Ineffective
Portion)
 
Amount of
Gain/(Loss)
Recognized in
Income on
Derivative
(Ineffective
Portion)
Interest rate swaps
 
Interest expense
 
$
(713
)
 
Interest expense
 
$

Commodity derivatives
 
Net (loss) from discontinued operations
 
295

 
Net (loss) from discontinued operations
 

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

Total
 
 
 
$
(452
)
 
 
 
$