Company Quick10K Filing
Quick10K
Black Hills Power
Closing Price ($) Shares Out (MM) Market Cap ($MM)
$67.89 60 $4,070
10-Q 2018-09-30 Quarter: 2018-09-30
10-Q 2018-06-30 Quarter: 2018-06-30
10-Q 2018-03-31 Quarter: 2018-03-31
10-K 2017-12-31 Annual: 2017-12-31
10-Q 2017-09-30 Quarter: 2017-09-30
10-Q 2017-06-30 Quarter: 2017-06-30
10-Q 2017-03-31 Quarter: 2017-03-31
10-K 2016-12-31 Annual: 2016-12-31
10-Q 2016-09-30 Quarter: 2016-09-30
10-Q 2016-06-30 Quarter: 2016-06-30
10-Q 2016-03-31 Quarter: 2016-03-31
10-K 2015-12-31 Annual: 2015-12-31
8-K 2018-01-30 Amend Bylaw, Exhibits
AEP American Electric Power
PPL PPL
AGR Avangrid
PNW Pinnacle West Capital
BEP Brookfield Renewable Partners
PAM Pampa Energy
TERP Terraform Power
EDN Edenor
AZRE Azure Power Global
AT Atlantic Power
BKH 2018-09-30
Item 2. Management's Discussion and Analysis of Financial Condition And
Item 4. Controls and Procedures
Part II - Other Information
Item 1. Legal Proceedings
Item 1A. Risk Factors
Item 6. Exhibits
EX-31.1 bhpex-311q32018.htm
EX-31.2 bhpex-312q32018.htm
EX-32.1 bhpex-321q32018.htm
EX-32.2 bhpex-322q32018.htm

Black Hills Power Earnings 2018-09-30

BKH 10Q Quarterly Report

Balance SheetIncome StatementCash Flow

10-Q 1 bhp10qq32018.htm 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 1-7978
Black Hills Power, Inc.
Incorporated in South Dakota
IRS Identification Number 46-0111677
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 and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files).
Yes x
No o

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

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

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

As of October 31, 2018, there were issued and outstanding 23,416,396 shares of the Registrant’s common stock, $1.00 par value, all of which were held beneficially and of record by Black Hills Corporation.

Reduced Disclosure

The Registrant meets the conditions set forth in General Instruction H (1) (a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format.




TABLE OF CONTENTS

 
 
Page
 
GLOSSARY OF TERMS AND ABBREVIATIONS
 
 
 
PART 1.
FINANCIAL INFORMATION
 
 
 
 
Item 1.
Financial Statements
 
 
 
 
 
Condensed Statements of Comprehensive Income - unaudited
 
Three and Nine Months Ended September 30, 2018 and 2017
 
 
 
 
 
Condensed Balance Sheets - unaudited
 
September 30, 2018 and December 31, 2017
 
 
 
 
 
Condensed Statements of Cash Flows - unaudited
 
Nine Months Ended September 30, 2018 and 2017
 
 
 
 
 
Notes to Condensed Financial Statements - unaudited
 
 
 
Item 2.
Managements’ Discussion and Analysis of Financial Condition and Results of Operations
 
 
 
Item 4.
Controls and Procedures
 
 
 
PART II.
OTHER INFORMATION
 
 
 
Item 1.
Legal Proceedings
 
 
 
Item 1A.
Risk Factors
 
 
 
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
ASC
Accounting Standards Codification
ASU
Accounting Standards Update issued by the FASB
BHC
Black Hills Corporation; the Parent Company
Black Hills Energy
The name used to conduct the business of BHC utility companies
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 Service Company
Black Hills Service Company, LLC, a direct, wholly-owned subsidiary of BHC
Cheyenne Light
Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
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.
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
Happy Jack
Happy Jack Wind Farms, LLC, a subsidiary of Duke Energy Generation Services
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
BHC Corporate headquarters building in Rapid City, South Dakota, which was completed in 2017.
kV
Kilovolt
LIBOR
London Interbank Offered Rate
Moody’s
Moody’s Investors Service, Inc.
MW
Megawatts
SDPUC
South Dakota Public Utilities Commission
SEC
U. S. Securities and Exchange Commission
Silver Sage
Silver Sage Windpower, LLC, a subsidiary of Duke Energy Generation Services
South Dakota Electric
Includes Black Hills Power operations in South Dakota, Wyoming and Montana
S&P
Standard & Poor’s, a division of The McGraw-Hill Companies, Inc.
TCJA
Tax Cuts and Jobs Act enacted December 22, 2017
WRDC
Wyodak Resources Development Corp., an indirect, wholly-owned subsidiary of BHC


3






BLACK HILLS POWER, INC.
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(unaudited)
2018
 
2017
 
2018
 
2017
 
(in thousands)
Revenue
$
78,067

 
$
73,938

 
$
222,558

 
$
213,785

 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
Fuel and purchased power
25,207

 
22,843

 
68,400

 
64,604

Operations and maintenance
19,851

 
16,747

 
57,430

 
52,589

Depreciation and amortization
9,950

 
9,053

 
29,700

 
26,578

Taxes - property
1,631

 
1,597

 
5,741

 
5,228

Total operating expenses
56,639

 
50,240

 
161,271

 
148,999

 
 
 
 
 
 
 
 
Operating income
21,428

 
23,698

 
61,287

 
64,786

 
 
 
 
 
 
 
 
Other income (expense):
 
 
 
 
 
 
 
Interest charges -
 
 
 
 
 
 
 
Interest expense incurred (including amortization of debt issuance costs, premiums, and discounts)
(5,632
)
 
(5,483
)
 
(16,873
)
 
(16,873
)
Allowance for funds used during construction - borrowed
199

 
369

 
399

 
953

Interest income
250

 
335

 
488

 
704

Allowance for funds used during construction - equity
68

 
676

 
239

 
1,864

Other income (expense), net
(315
)
 
3

 
(845
)
 
(119
)
Total other income (expense), net
(5,430
)
 
(4,100
)
 
(16,592
)
 
(13,471
)
 
 
 
 
 
 
 
 
Income before income taxes
15,998

 
19,598

 
44,695

 
51,315

Income tax expense
(2,681
)
 
(5,772
)
 
(8,493
)
 
(15,632
)
Net income
13,317

 
13,826

 
36,202

 
35,683

 
 
 
 
 
 
 
 
Other comprehensive income (loss), net of tax:
 
 
 
 
 
 
 
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax (expense) benefit of $(6) and $(6) for the three months ended September 30, 2018 and 2017, and $(17) and $(17) for the nine months ended September 30, 2018 and 2017, respectively)
10

 
10

 
31

 
31

Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(9) and $(8) for the three months ended September 30, 2018 and 2017, and $(27) and $(23) for the nine months ended September 30, 2018 and 2017, respectively)
17

 
14

 
51

 
42

Other comprehensive income (loss), net of tax
27

 
24

 
82

 
73

 
 
 
 
 
 
 
 
Comprehensive income
$
13,344

 
$
13,850

 
$
36,284

 
$
35,756


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

4




BLACK HILLS POWER, INC.
CONDENSED BALANCE SHEETS

 
As of
(unaudited)
September 30, 2018
December 31, 2017
 
(in thousands)
ASSETS
 
 
Current assets:
 
 
Cash and cash equivalents
$
13

$
16

Accounts receivable, net
28,192

29,050

Accounts receivable from affiliates
6,373

5,664

Materials, supplies and fuel
24,503

23,443

Regulatory assets, current
16,939

18,993

Other current assets
3,211

4,724

Total current assets
79,231

81,890

 
 
 
Investments
5,006

4,926

 
 
 
Property, plant and equipment
1,351,996

1,311,819

Less: accumulated depreciation and amortization
(370,978
)
(358,946
)
Total property, plant and equipment, net
981,018

952,873

 
 
 
Other assets:
 
 
Regulatory assets, non-current
56,728

59,710

Other assets, non-current
9,665

3,747

Total other assets, non-current
66,393

63,457

 
 
 
TOTAL ASSETS
$
1,131,648

$
1,103,146


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

5




BLACK HILLS POWER, INC.
CONDENSED BALANCE SHEETS
(Continued)
 
As of
(unaudited)
September 30, 2018
December 31, 2017
 
(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDER’S EQUITY
 
 
Current liabilities:
 
 
Accounts payable
$
20,388

$
14,766

Accounts payable to affiliates
22,939

25,653

Accrued liabilities
43,931

38,205

Money pool notes payable
13,888

13,397

Regulatory liabilities, current
8,216

842

Total current liabilities
109,362

92,863

 
 
 
Long-term debt
340,000

339,895

 
 
 
Deferred credits and other liabilities:
 
 
Deferred income tax liabilities, net
113,247

110,618

Regulatory liabilities, non-current
158,063

148,013

Benefit plan liabilities
15,207

16,285

Other deferred credits and other liabilities
1,251

1,240

Total deferred credits and other liabilities
287,768

276,156

 
 
 
Commitments and contingencies (Notes 5, 6 and 9)


 
 
 
Stockholder’s equity:
 
 
Common stock $1 par value; 50,000,000 shares authorized; 23,416,396 shares issued
23,416

23,416

Additional paid-in capital
39,575

39,575

Retained earnings
332,703

332,499

Accumulated other comprehensive loss
(1,176
)
(1,258
)
Total stockholder’s equity
394,518

394,232

 
 
 
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY
$
1,131,648

$
1,103,146


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


6



BLACK HILLS POWER, INC.
CONDENSED STATEMENTS OF CASH FLOWS

(unaudited)
Nine Months Ended September 30,
 
2018
2017
 
(in thousands)
Operating activities:
 
 
Net income
$
36,202

$
35,683

Adjustments to reconcile net income to net cash provided by operating activities-
 
 
Depreciation and amortization
29,700

26,578

Deferred income tax
4,619

6,188

Employee benefits
1,139

613

AFUDC
(239
)
(2,817
)
Other adjustments, net
2,362

2,298

Change in operating assets and liabilities -
 
 
Accounts receivable and other current assets
224

6,567

Accounts payable and other current liabilities
2,337

3,077

Regulatory assets - current
2,004

1,543

Regulatory liabilities - current
8,224


Contributions to defined benefit pension plan
(1,795
)
(4,000
)
Other operating activities, net
(1,400
)
(1,097
)
Net cash provided by (used in) operating activities
83,377

74,633

 
 
 
Investing activities:
 
 
Property, plant and equipment additions
(47,527
)
(61,537
)
Proceeds from sale of assets
4,994


Change in money pool notes receivable, net

(12,472
)
Other investing activities
(5,338
)
313

Net cash provided by (used in) investing activities
(47,871
)
(73,696
)
 
 
 
Financing activities:
 
 
Change in money pool notes payable, net
(35,509
)

Net cash provided by (used in) financing activities
(35,509
)

 
 
 
Net change in cash and cash equivalents
(3
)
937

 
 
 
Cash and cash equivalents, beginning of period
16

234

Cash and cash equivalents, end of period
$
13

$
1,171


See Note 8 for supplemental cash flow information.

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

7



BLACK HILLS POWER, INC.

Notes to Condensed Financial Statements
(unaudited)
(Reference is made to Notes to Financial Statements
included in our 2017 Annual Report on Form 10-K)

(1)    MANAGEMENT’S STATEMENT

The unaudited condensed financial statements included herein have been prepared by Black Hills Power, Inc. (the “Company,” “we,” “us,” 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 financial statements should be read in conjunction with the financial statements and the notes thereto, included in our 2017 Annual Report on Form 10-K filed with the SEC.

The information furnished in the accompanying condensed 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. The results of operations for the three months ended September 30, 2018 and September 30, 2017, and our financial condition as of September 30, 2018 and December 31, 2017 are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period.

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 finalize 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.


8



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 not adjusted. 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.







9



(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 electric utility services tariffs - Our regulated operations, as defined by ASC 980, 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 commodity electricity and 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 regulated utility sales are subject to regulatory-approved tariffs.

Power sales agreements - We 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, we also sell 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.

The following table depicts the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition. Sales tax and other similar taxes are excluded from revenues.
 
Three Months Ended September 30, 2018
Nine Months Ended September 30, 2018
 
(in thousands)
Customer types:
 
 
Retail
$
49,874

$
147,040

Wholesale
8,255

25,496

Market - off-system sales
7,625

13,349

Transmission/Other
12,183

36,273

Revenue from contracts with customers
77,937

222,158

Other revenues
130

400

Total revenues
$
78,067

$
222,558

 
 
 
Timing of revenue recognition:
 
 
Services transferred over time
$
77,937

$
222,158

Revenue from contracts with customers
$
77,937

$
222,158


The majority of the 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 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.

Revenue Not in Scope of ASC 606

Other revenues included in the table above include revenue accounted for under separate accounting guidance, including lease revenue under ASC 840 and alternative revenue programs revenue under ASC 980.

10




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. We have been collaborating with our regulators in the states in which we provide 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 estimated and recorded a revenue reserve of approximately $2.5 million and $8.2 million during the three and nine months ended September 30, 2018.

On September 4, 2018, the SDPUC approved a settlement agreement for South Dakota Electric allowing the company to pass on the benefits of a lower corporate federal income tax rate to our South Dakota retail customers. The aggregate 2018 benefit of approximately $7.7 million will be delivered to customers in October 2018. For 2019, the settlement agreement provides an estimated $8.9 million aggregate reduction in base rates for customers.

Unbilled Revenue

Revenues attributable to energy 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 may 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 and is further discussed in Business Description in Note 1 of our Notes to the Financial Statements of our 2017 Annual Report on Form 10-K. 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.

(3)
ACCOUNTS RECEIVABLE

Following is a summary of Accounts receivable, net included in the accompanying Condensed Balance Sheets (in thousands) as of:
 
September 30, 2018
December 31, 2017
Accounts receivable trade
$
17,019

$
15,994

Unbilled revenues
11,275

13,280

Allowance for doubtful accounts
(102
)
(224
)
Accounts receivable, net
$
28,192

$
29,050



11



(4)
REGULATORY ACCOUNTING

Our regulated electric operations are subject to regulation by various state and federal agencies. The accounting policies followed are generally subject to the Uniform System of Accounts of the FERC.

Our regulatory assets and liabilities were as follows (in thousands) as of:
 
September 30, 2018
 
December 31, 2017
Regulatory assets:
 
 
 
Unamortized loss on reacquired debt (a)
$
1,326

 
$
1,534

Deferred taxes on AFUDC (b)
5,010

 
5,095

Employee benefit plans(c)

19,619

 
19,465

Deferred energy and fuel cost adjustments (a)
17,697

 
19,602

Deferred taxes on flow through accounting
8,302

 
7,579

Decommissioning costs, net of amortization
8,710

 
10,252

Vegetation management, net of amortization
10,942

 
12,669

Other regulatory assets (a)
2,061

 
2,507

Total regulatory assets
$
73,667

 
$
78,703

Less current regulatory assets
(16,939
)
 
(18,993
)
Regulatory assets, non-current
$
56,728

 
$
59,710


Regulatory liabilities:
 
 
 
Cost of removal for utility plant (a)
$
51,106

 
$
44,056

Employee benefit plan costs and related deferred taxes (c)
6,808

 
6,808

Excess deferred income taxes
99,774

 
97,101

TCJA revenue reserve
8,188

 

Other regulatory liabilities
403

 
890

Total regulatory liabilities
$
166,279

 
$
148,855

Less current regulatory liabilities
(8,216
)
 
(842
)
Regulatory liabilities, non-current
$
158,063

 
$
148,013

____________________
(a)
We are allowed 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.


12



Regulatory Matters
Except as discussed below, there have been no other significant changes to our Regulatory Matters from those previously disclosed in Note 1 of the Notes to the Financial Statements in our 2017 Annual Report on Form 10-K.

On April 30, 2018, Black Hills Power and the SDPUC staff signed an amendment to the stipulation executed in June 2017. The amendment provides clarifying language to certain provisions from the stipulation specific to the TCJA and performance based rates. The amendment was approved by the SDPUC on May 15, 2018.

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.

On September 4, 2018, the SDPUC approved a settlement agreement for South Dakota Electric allowing the company to pass on the benefits of a lower corporate federal income tax rate to our South Dakota retail customers. The aggregate 2018 benefit of approximately $7.7 million will be delivered to customers in October 2018. For 2019, the settlement agreement provides an estimated $8.9 million aggregate reduction in base rates for customers.

We estimated and recorded a reserve to revenue of approximately $2.5 million and $8.2 million during the three and nine months ended September 30, 2018.


(5)
RELATED-PARTY TRANSACTIONS

Non-Cash Dividend to Parent

We recorded non-cash dividends to our Parent of $36 million and $32 million for nine months ended September 30, 2018 and September 30, 2017, respectively, and changed the utility Money pool note by $36 million and $32 million for the nine months ended September 30, 2018 and September 30, 2017, respectively.

Receivables and Payables

We have accounts receivable and accounts payable balances related to transactions with other BHC subsidiaries. The balances were as follows (in thousands) as of:
 
September 30, 2018
 
December 31, 2017
Accounts receivables from affiliates
$
6,373

 
$
5,664

Accounts payable to affiliates
$
22,939

 
$
25,653


Money Pool Notes Receivable and Notes Payable

We participate in the Utility Money Pool Agreement (the Agreement). Under the Agreement, we may borrow from the pool; however the Agreement restricts the pool from loaning funds to BHC or to any of BHC’s non-utility subsidiaries. The Agreement does not restrict us from paying dividends to BHC. Borrowings under the Agreement bear interest at the weighted average daily cost of our parent company’s external borrowings as defined under the Agreement, or if there are no external funds outstanding on that date, then the rate will be the daily one-month LIBOR plus 1.0%. At September 30, 2018, the average cost of borrowing under the Utility Money Pool was 2.60%.

We had the following balances with the Utility Money Pool (in thousands) as of:
 
September 30, 2018
 
December 31, 2017
Money pool notes payable
$
13,888

 
$
13,397


Our net interest income (expense) relating to balances with the Utility Money Pool was as follows (in thousands):
 
Three Months Ended September 30,
Nine Months Ended September 30,
 
2018
2017
2018
2017
Net interest income (expense)
$
(75
)
$
53

$
(207
)
$
269



13



Other related party activity was as follows (in thousands):
 
Three Months Ended September 30,
Nine Months Ended September 30,
 
2018
2017
2018
2017
Revenue:
 
 
 
 
Energy sold to Cheyenne Light
$
311

$
361

$
1,515

$
1,866

Rent from electric properties
$
908

$
935

$
3,025

$
2,805

Horizon Point shared facility revenues
$
2,826

$

$
8,078

$

 
 
 
 
 
Fuel and purchased power:
 
 
 
 
Purchases of coal from WRDC
$
4,161

$
4,054

$
12,477

$
11,386

Purchase of excess energy from Cheyenne Light
$
193

$
208

$
361

$
324

Purchase of renewable wind energy from Cheyenne Light - Happy Jack
$
262

$
199

$
1,284

$
1,174

Purchase of renewable wind energy from Cheyenne Light - Silver Sage
$
582

$
351

$
2,371

$
2,007

 
 
 
 
 
Gas transportation service agreement:
 
 
 
 
Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation
$
96

$
99

$
288

$
297

 
 
 
 
 
Corporate support:
 
 
 
 
Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings (a)
$
9,836

$
6,626

$
25,046

$
20,346

____________________
(a)
The increase for the three and nine months ended September 30, 2018 is driven by Horizon Point shared facility expenses, higher allocation of employee costs and interest expense.

Horizon Point Agreement

We have a shared facility agreement among South Dakota Electric, Black Hills Service Company, and Black Hills Utility Holdings where there is a cost allocation for the use of the Horizon Point facility that is owned by South Dakota Electric.  This cost allocation includes the recovery of and return on allocable property and recovery of incurred administrative service expenses for the operation and maintenance of the Horizon Point facility.

(6)
EMPLOYEE BENEFIT PLANS

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

2017
 
2018

2017
Service cost
$
129

 
$
137

 
$
387

 
$
409

Interest cost
548

 
585

 
1,645

 
1,755

Expected return on plan assets
(887
)
 
(898
)
 
(2,660
)
 
(2,692
)
Prior service cost
11

 
10

 
33

 
32

Net loss (gain)
516

 
308

 
1,548

 
922

Net periodic benefit cost
$
317

 
$
142

 
$
953

 
$
426



14



Defined Benefit Postretirement Healthcare Plan

The components of net periodic benefit cost for the Defined Benefit Postretirement Healthcare Plan were as follows (in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
Service cost
$
48

 
$
52

 
$
145

 
$
155

Interest cost
45

 
44

 
134

 
132

Prior service cost (benefit)
(84
)
 
(84
)
 
(252
)
 
(252
)
Net periodic benefit cost
$
9

 
$
12

 
$
27

 
$
35


Supplemental Non-qualified Defined Benefit Plans

The components of net periodic benefit cost for the Supplemental Non-qualified Defined Benefit Plans were as follows (in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
Interest cost
$
27

 
$
29

 
$
81

 
$
87

Net loss (gain)
26

 
22

 
78

 
65

Net periodic benefit cost
$
53

 
$
51

 
$
159

 
$
152


For the three and nine months ended September 30, 2018, service costs were recorded in Operations and maintenance expense while non-service costs were recorded in Other income (expense), net on the Condensed Statements of Comprehensive Income. For the three and nine months ended September 30, 2017, service costs and non-service costs were recorded in Operations and maintenance expense. Because prior years’ costs were not considered material, they were not reclassified on the Condensed Statements of Comprehensive Income. See Note 1 for additional information.

Contributions

Contributions to the Defined Benefit Pension Plan are cash contributions made directly to the Pension Plan Trust account. On July 25, 2018, we made a contribution of approximately $1.8 million (included in the table below) to the Defined Benefit Pension Plan. Contributions to the Postretirement Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions made for 2018 and anticipated contributions for 2018 and 2019 are as follows (in thousands):
 
Contributions
Nine Months Ended
September 30, 2018
Remaining Anticipated Contributions for 2018
Anticipated Contributions for 2019
Defined Benefit Pension Plan
$
1,795

$

$
1,850

Defined Benefit Postretirement Healthcare Plan
$
401

$
134

$
412

Supplemental Non-qualified Defined Benefit Plans
$
184

$
61

$
242


15



(7)
FAIR VALUE OF FINANCIAL INSTRUMENTS

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Accounting guidance on fair value measurements establishes a hierarchy for grouping assets and liabilities, based on significance of inputs. For additional information see Note 1 included in our 2017 Annual Report on Form 10-K filed with the SEC.

The estimated fair values of our financial instruments were as follows (in thousands) as of:
 
September 30, 2018
 
December 31, 2017
 
Carrying Amount
Fair Value
 
Carrying Amount
Fair Value
Cash and cash equivalents (a)
$
13

$
13

 
$
16

$
16

Long-term debt, including current maturities (b) (c)
$
340,000

$
411,948

 
$
339,895

$
446,978

_________________
(a)
Carrying value approximates fair value due to either 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)
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.
(c)
Carrying amount of long-term debt is net of deferred financing costs.

(8)
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

 
Nine Months Ended September 30,
 
2018
 
2017
 
(in thousands)
Non-cash investing and financing activities -
 
 
 
Property, plant and equipment acquired with accrued liabilities
$
10,540

 
$
10,242

Non-cash (decrease) to money pool notes receivable, net
$
(36,000
)
 
$
(32,000
)
Non-cash dividend to Parent
$
36,000

 
$
32,000

 
 
 
 
Cash (paid) refunded during the period for -
 
 
 
Interest (net of amounts capitalized)
$
(14,104
)
 
$
(12,838
)

(9)
COMMITMENTS AND CONTINGENCIES


There have been no significant changes to commitments and contingencies from those previously disclosed in Note 11 of our Notes to the Financial Statements in our 2017 Annual Report on Form 10-K except for those described below.

Platte River Power Authority PPA

On August 16, 2018, we entered into a PPA with Platte River Power Authority (PRPA) to purchase up to 12 MW of wind energy through PRPA’s agreement with Silver Sage. This agreement will expire September 30, 2029.


16



(10)
INCOME TAXES

On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA reduced the U.S. federal corporate tax rate from 35% to 21%. The Company remeasured deferred income taxes at the 21% federal tax rate as of December 31, 2017, which reflected our provisional estimate of the impact of the TCJA, under SEC Staff Accounting Bulletin No. 118. We have made our best estimate regarding the probability of settlements of net regulatory liabilities established pursuant to the TCJA. The amount of the settlements may change based on decisions and actions by the state regulatory commissions. In addition to current year revenue reserves disclosed in Note 4, we recorded additional changes in estimates of the provisional amounts recorded at December 31, 2017, primarily related to bonus depreciation and other plan and property items, after filing our 2017 tax returns which decreased tax expense by $0.2 million for the three and nine months ended September 30, 2018. We will continue to evaluate subsequent regulations, clarifications and interpretations of the assumptions made, which could change our estimates to the TCJA, which we expect to finalize in the fourth quarter.


17



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

Amounts are presented on a pre-tax basis unless otherwise indicated.
Minor differences in amounts may result due to rounding.

Significant Events

On September 4, 2018, the SDPUC approved a settlement agreement for South Dakota Electric allowing the company to pass on the benefits of a lower corporate federal income tax rate to our South Dakota retail customers. The aggregate 2018 benefit of approximately $7.7 million will be delivered to customers in October 2018. For 2019, the settlement agreement provides an estimated $8.9 million aggregate reduction in base rates for customers.

On August 16, 2018, we entered into a PPA with Platte River Power Authority (PRPA) to purchase up to 12 MW of wind energy through PRPA’s agreement with Silver Sage. This agreement will expire September 30, 2029.

On August 9, 2018, S&P upgraded South Dakota Electric’s credit rating to A.

On July 25, 2018, we placed in service the first 48-mile segment of a $70 million, 175-mile, 230-kilovolt transmission line from Rapid City, South Dakota, to Stegall, Nebraska. The remaining segment is expected to be in service by the end of 2019.

On July 19. 2018, Fitch affirmed South Dakota Electric’s credit rating at A.

Results of Operations

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

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


18



The following tables provide certain financial information and operating statistics:

 
Three Months Ended September 30,
Nine Months Ended September 30,
 
2018
2017
Variance
2018
2017
Variance
 
(in thousands)
Revenue
$
78,067

$
73,938

$
4,129

$
222,558

$
213,785

$
8,773

Fuel and purchased power
25,207

22,843

2,364

68,400

64,604

3,796

Gross margin (a)
52,860

51,095

1,765

154,158

149,181

4,977

 
 
 
 
 
 
 
Operating expenses
31,432

27,397

4,035

92,871

84,395

8,476

Operating income
21,428

23,698

(2,270
)
61,287

64,786

(3,499
)
 
 
 
 
 
 
 
Interest income (expense), net
(5,183
)
(4,779
)
(404
)
(15,986
)
(15,216
)
(770
)
Other income (expense), net
(247
)
679

(926
)
(606
)
1,745

(2,351
)
Income tax expense
(2,681
)
(5,772
)
3,091

(8,493
)
(15,632
)
7,139

Net income
$
13,317

$
13,826

$
(509
)
$
36,202

$
35,683

$
519

________________
(a)
Non-GAAP measure



Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017. Net income was $36 million compared to $36 million for the same period in the prior year primarily due to the following:

Gross margin increased primarily due to $8.1 million Horizon Point shared facility revenue, higher power marketing and wholesale revenue of $1.9 million, a $1.4 million increase in residential margins primarily from higher volume usage per customer, and higher rider revenues of $2.0 million primarily related to transmission investment recovery. These increases were partially offset by an $8.2 million reserve to revenue to reflect the reduction of the lower federal income tax rate from the TCJA on our existing rate tariffs and lower commercial and industrial volume of $0.6 million.

Operating expenses increased due to depreciation and property taxes increases of $3.6 million from higher asset base driven by the prior year additions of Horizon Point and the Teckla-Lange transmission line. Higher vegetation management expenses, higher employee costs, and higher facility costs comprise the remainder of the increase compared to the same period in the prior year.

Interest expense, net increased due to higher prior year AFUDC associated with higher prior year capital spend.

Other income (expense), net decreased due to the presentation change of non-service pension costs to Other income (expense), net in the current year, previously reported in Operations and maintenance, and higher prior year AFUDC associated with higher prior year capital spend.

Income tax expense: The effective tax rate decreased from the prior year due to the reduction in the federal corporate income tax rate from 35 percent to 21 percent from the TCJA, effective January 1, 2018.


19



 
Electric Revenue by Customer Type
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
(in thousands)
 
2018
 
Percentage Change
 
2017
 
2018
 
Percentage Change
 
2017
Residential
$
17,971

 
—%
 
$
18,020

 
$
55,458

 
3%
 
$
53,724

Commercial
25,601

 
1%
 
25,459

 
72,683

 
—%
 
72,608

Industrial
7,685

 
(6)%
 
8,149

 
24,131

 
(3)%
 
24,774

Municipal
1,005

 
(6)%
 
1,071

 
2,692

 
(6)%
 
2,849

Total retail revenue
52,262

 
(1)%
 
52,699

 
154,964

 
1%
 
153,955

Wholesale (a)
8,255

 
3%
 
8,048

 
25,496

 
13%
 
22,593

Market - off-system sales (b)
7,625

 
59%
 
4,787

 
13,349

 
21%
 
11,044

Other revenue (c)
9,925

 
18%
 
8,404

 
28,749

 
10%
 
26,193

Total revenue
$
78,067

 
6%
 
$
73,938

 
$
222,558

 
4%
 
$
213,785

____________________
(a)
Increase for the nine months ended September 30, 2018 was primarily driven by increased volumes on long-term wholesale contracts.
(b)
Increase for the three and nine months ended September 30, 2018 was due to higher trading volume opportunities.
(c)
Increase for the three and nine months ended September 30, 2018 was primarily driven by Horizon Point shared facility revenues.

 
Megawatt Hours Sold by Customer Type
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
Percentage Change
 
2017
 
2018
 
Percentage Change
 
2017
Residential
125,159

 
(3)%
 
129,616

 
404,177

 
5%
 
386,709

Commercial
204,621

 
(4)%
 
212,773

 
586,336

 
1%
 
582,899

Industrial (a)
95,473

 
(13)%
 
109,745

 
305,875

 
(5)%
 
323,038

Municipal (b)
9,070

 
(11)%
 
10,156

 
24,052

 
(7)%
 
25,865

Total retail quantity sold
434,323

 
(6)%
 
462,290

 
1,320,440

 
—%
 
1,318,511

Wholesale (c)
221,327

 
19%
 
185,723

 
677,163

 
26%
 
537,720

Market - off-system sales (d)
172,141

 
32%
 
130,825

 
406,109

 
5%
 
388,287

Total quantity sold
827,791

 
6%
 
778,838

 
2,403,712

 
7%
 
2,244,518

Losses and company use (e)
47,171

 
(16)%
 
56,447

 
137,370

 
(12)%
 
155,477

Total energy
874,962

 
5%
 
835,285

 
2,541,082

 
6%
 
2,399,995

____________________
(a)
Increase for the three months ended September 30, 2018 was primarily driven by lower demand and milder summer weather.
(b)
Increase for three months ended September 30, 2018 was due to milder summer weather.
(c)
Increase for the three and nine months ended September 30, 2018 was primarily driven by increased volumes on long-term wholesale contracts.
(d)
Increase for three months ended September 30, 2018 was due to improved pricing in markets compared to same period in prior year.
(e)
Includes company uses, line losses, and excess exchange production.


20



 
Megawatt Hours Generated and Purchased
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
Generated -
2018
 
Percentage Change
 
2017
 
2018
 
Percentage Change
 
2017
Coal-fired
407,936

 
(4)%
 
423,766

 
1,195,104

 
9%
 
1,101,291

Natural Gas and Oil (a) 
61,744

 
13%
 
54,466

 
98,609

 
30%
 
75,840

Total generated
469,680

 
(2)%
 
478,232

 
1,293,713

 
10%
 
1,177,131

 

 
 
 

 
 
 
 
 
 
Total purchased
405,282

 
14%
 
357,053

 
1,247,369

 
2%
 
1,222,864

Total generated and purchased
874,962

 
5%
 
835,285

 
2,541,082

 
6%
 
2,399,995

____________________
(a) Increase is primarily due to low natural gas prices and the ability to generate at a lower cost than to purchase excess generation on the open market for the three and nine months ended September 30, 2018.

 
Power Plant Availability
 
Three Months Ended September 30,
Nine Months Ended September 30,
 
2018
2017
2018
 
2017
Coal-fired plants (a)
93.8
%
 
97.5
%
 
92.7
%
 
84.8
%
Other plants
96.0
%
 
93.7
%
 
97.6
%
 
97.0
%
Total availability
95.0
%
 
95.5
%
 
95.3
%
 
91.3
%
____________________
(a)
2017 included planned outages at Neil Simpson II, Wyodak and Wygen II.

 
Degree Days
 
Degree Days
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
 
Actual
Variance from 30-year Average
 
Actual
Variance from 30-year Average
 
Actual
Variance from 30-year Average
 
Actual
Variance from 30-year Average
 
 
 
 
 
 
 
 
 
 
 
 
Heating degree days
236

5
 %
 
202

(10
)%
 
4,972

11
 %
 
4,242

(5
)%
Cooling degree days
356

(33
)%
 
595

11
 %
 
488

(23
)%
 
709

12
 %

Credit Ratings

Credit ratings impact our ability to obtain short and long-term financing, the cost of such financing, and vendor payment terms, including collateral requirements. The following table represents our secured credit rating from each agency’s review which was in effect at September 30, 2018:

Rating Agency
Secured Rating
S&P (a)
A
Moody’s
A1
Fitch (b)
A
__________
(a)
On August 9, 2018, S&P upgraded to A rating.
(b)
On July 19, 2018, Fitch affirmed A rating.


21



FORWARD-LOOKING INFORMATION

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

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

Any forward-looking statement contained in this document speaks only as of the date on which the statement is made, and the Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which the statement is 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 Item 1A of our 2017 Annual Report on Form 10-K, including statements contained within Item 1A - Risk Factors and Part II, Item 1A of this Quarterly Report on Form 10-Q.

ITEM 4.
CONTROLS AND PROCEDURES

This section should be read in conjunction with Item 9A, “Controls and Procedures” included in our Annual Report on Form 10-K for the year ended December 31, 2017.

Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) as of September 30, 2018. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective as of September 30, 2018.

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

Changes in Internal Control over Financial Reporting

During the quarter ended September 30, 2018, 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.


22



BLACK HILLS POWER, INC.

Part II - Other Information

Item 1.
Legal Proceedings

For information regarding legal proceedings, see Note 11 of Notes to Financial Statements in Item 8 of our 2017 Annual Report on Form 10-K and Note 9 of our Notes to Condensed Financial Statements in this Quarterly Report on Form 10-Q, which information from Note 9 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 Annual Report on Form 10-K for the year ended December 31, 2017.


Item 6.
Exhibits

Exhibit 3.1*

Exhibit 3.2*

Exhibit 4.1*

Exhibit 31.1

Exhibit 31.2

Exhibit 32.1

Exhibit 32.2

Exhibit 101
Financial Statements for XBRL Format
_________________________
*
Previously filed as part of the filing indicated and incorporated by reference herein.



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BLACK HILLS POWER, INC.

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 POWER, INC.


/S/ DAVID R. EMERY
David R. Emery, Chairman
and Chief Executive Officer


/S/ RICHARD W. KINZLEY
Richard W. Kinzley, Senior Vice President
and Chief Financial Officer

Dated: November 6, 2018


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