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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, 2014
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

625 Ninth Street, Rapid City, South Dakota 57701

Registrant’s telephone number (605) 721-1700

Former name, former address, and former fiscal year if changed since last report
NONE

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes x
No o

Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files).
Yes x
No o

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company (as defined in Rule 12b-2 of the Exchange Act).
Large accelerated filer
o
 
Accelerated filer
o
 
 
 
 
 
Non-accelerated filer
x
 
Smaller reporting company
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, 2014, 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 Income and Comprehensive Income - unaudited
 
Three and Nine Months Ended September 30, 2014 and 2013
 
 
 
 
 
Condensed Balance Sheets - unaudited
 
September 30, 2014 and December 31, 2013
 
 
 
 
 
Condensed Statements of Cash Flows - unaudited
 
Nine Months Ended September 30, 2014 and 2013
 
 
 
 
 
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
 
 
 
 
Exhibit Index


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
ASU
Accounting Standards Update
BHC
Black Hills Corporation, the Parent Company
Black Hills Energy
The name used to conduct the business of Black Hills Utility Holdings, Inc., and its subsidiaries
Black Hills Utility Holdings
Black Hills Utility Holdings, Inc. a direct, wholly-owned subsidiary of BHC
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 BHC
Cheyenne Prairie
Cheyenne Prairie Generating Station is a 132 MW natural gas-fired generating facility in Cheyenne, Wyoming, jointly owned by Cheyenne Light and Black Hills Power. Cheyenne Prairie was placed into commercial operations on October 1, 2014.
Cooling degree day
A cooling degree day is equivalent to each degree that the average of the high and low temperature for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30-year average.
CPCN
Certificate of Public Convenience and Necessity
CT
Combustion Turbine
EPA
Environmental Protection Agency
FASB
Financial Accounting Standards Board
FERC
Federal Energy Regulatory Commission
Fitch
Fitch Ratings
GAAP
Generally Accepted Accounting Principles in the United States of America
Happy Jack
Happy Jack Wind Farms, LLC, a subsidiary of Duke Energy Generation Services
Heating degree day
A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30-year average.
kV
Kilovolt
LIBOR
London Interbank Offered Rate
Moody’s
Moody’s Investor Services, Inc.
MW
Megawatts
MWh
Megawatt-hours
SEC
U.S. Securities and Exchange Commission
Silver Sage
Silver Sage Windpower, LLC, a subsidiary of Duke Energy Generation Services
S&P
Standard & Poor’s Rating Services
WPSC
Wyoming Public Service Commission
WRDC
Wyodak Resources Development Corp., an indirect, wholly-owned subsidiary of BHC


3






BLACK HILLS POWER, INC.
CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(unaudited)
2014
 
2013
 
2014
 
2013
 
(in thousands)
 
 
 
 
 
 
 
 
Revenue
$
67,729

 
$
67,268

 
$
199,736

 
$
187,917

 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
Fuel, purchased power and natural gas
23,919

 
22,454

 
72,242

 
65,676

Operations and maintenance
16,261

 
17,744

 
51,709

 
51,693

Depreciation and amortization
7,090

 
7,036

 
20,949

 
21,058

Taxes - property
1,452

 
1,330

 
4,502

 
3,990

Total operating expenses
48,722

 
48,564

 
149,402

 
142,417

 
 
 
 
 
 
 
 
Operating income
19,007

 
18,704

 
50,334

 
45,500

 
 
 
 
 
 
 
 
Other income (expense):
 
 
 
 
 
 
 
Interest expense
(4,992
)
 
(4,974
)
 
(14,923
)
 
(14,745
)
AFUDC - borrowed
76

 
25

 
205

 
124

Interest income
201

 
144

 
470

 
207

AFUDC - equity
165

 
45

 
427

 
228

Other income (expense), net
5

 
(52
)
 
100

 
174

Total other income (expense)
(4,545
)
 
(4,812
)
 
(13,721
)
 
(14,012
)
 
 
 
 
 
 
 
 
Income from continuing operations before income taxes
14,462

 
13,892

 
36,613

 
31,488

Income tax expense
(4,546
)
 
(4,594
)
 
(11,824
)
 
(9,956
)
Net income
9,916

 
9,298

 
24,789

 
21,532

 
 
 
 
 
 
 
 
Other comprehensive income (loss):
 
 
 
 
 
 
 
Reclassification adjustments of cash flow hedges settled and included in net income (net of tax (expense) benefit of $(6) and $(6) for the three months ended September 30, 2014 and 2013 and $(17) and $(18) for the nine months ended September 30, 2014 and 2013, respectively)
10

 
10

 
31

 
30

Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(4) and $(5) for the three months ended September 30, 2014 and 2013 and $(12) and $(17) for the nine months ended September 30, 2014 and 2013, respectively)
8

 
12

 
22

 
34

Other comprehensive income
18

 
22

 
53

 
64

 
 
 
 
 
 
 
 
Comprehensive income
$
9,934

 
$
9,320

 
$
24,842

 
$
21,596


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

4




BLACK HILLS POWER, INC.
CONDENSED BALANCE SHEETS

(unaudited)
September 30, 2014
December 31, 2013
 
(in thousands)
ASSETS
 
 
Current assets:
 
 
Cash and cash equivalents
$
4,641

$
2,259

Receivables - customers, net
31,419

25,799

Receivables - affiliates
5,448

4,934

Other receivables, net
312

579

Money pool notes receivable, net

17,292

Materials, supplies and fuel
24,311

23,278

Deferred income tax assets, net, current

2,170

Regulatory assets, current
9,924

4,891

Other, current assets
4,549

4,933

Total current assets
80,604

86,135

 
 
 
Investments
4,554

4,431

 
 
 
Property, plant and equipment
1,163,813

1,095,884

Less accumulated depreciation and amortization
(351,298
)
(334,174
)
Total property, plant and equipment, net
812,515

761,710

 
 
 
Other assets:
 
 
Regulatory assets, non-current
45,630

40,373

Other, non-current assets
9,546

8,524

Total other assets
55,176

48,897

TOTAL ASSETS
$
952,849

$
901,173


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

5




BLACK HILLS POWER, INC.
CONDENSED BALANCE SHEETS

(unaudited)
September 30, 2014
December 31, 2013
 
(in thousands, except common stock par value and share amounts)
LIABILITIES AND STOCKHOLDER’S EQUITY
 
 
Current liabilities:
 
 
Accounts payable
$
32,538

$
26,144

Accounts payable - affiliates
22,271

21,082

Accrued liabilities
19,064

14,966

Money pool notes payable, net
19,433


Deferred income tax liabilities, net, current
621


Regulatory liabilities, current
364

161

Total current liabilities
94,291

62,353

 
 
 
Long-term debt, net of current maturities
257,751

269,948

 
 
 
Deferred credits and other liabilities:
 
 
Deferred income tax liability, net, non-current
178,368

167,309

Regulatory liabilities, non-current
42,020

43,357

Benefit plan liabilities
10,766

12,105

Other, non-current liabilities
2,957

4,247

Total deferred credits and other liabilities
234,111

227,018

 
 
 
Commitments and contingencies (Notes 5, 6 and 10)
 
 
 
 
 
Stockholders’ 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
304,849

280,060

Accumulated other comprehensive loss
(1,144
)
(1,197
)
Total stockholders’ equity
366,696

341,854

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY
$
952,849

$
901,173


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,
 
2014
2013
 
(in thousands)
Operating activities:
 
 
Net income
$
24,789

$
21,532

Adjustments to reconcile net income to net cash provided by operating activities-
 
 
Depreciation and amortization
20,949

21,058

Deferred income tax
11,803

9,630

Employee benefits
971

2,322

AFUDC - equity
(427
)
(228
)
Other adjustments, net
(55
)
1,070

Change in operating assets and liabilities -
 
 
Accounts receivable and other current assets
(11,368
)
952

Accounts payable and other current liabilities
12,787

(1,797
)
Contributions to defined benefit pension plan
(1,696
)
(2,299
)
Other operating activities, net
(6,851
)
724

Net cash provided by (used in) operating activities
50,902

52,964

 
 
 
Investing activities:
 
 
Property, plant and equipment additions
(72,460
)
(52,242
)
Change in money pool notes receivable, net
17,292

(733
)
Other investing activities
(123
)
(43
)
Net cash provided by (used in) investing activities
(55,291
)
(53,018
)
 
 
 
Financing activities:
 
 
Change in money pool notes payable, net
19,433


Long-term debt - repayments
(12,200
)

Other financing activities
(462
)

Net cash provided by (used in) financing activities
6,771


 
 
 
Net change in cash and cash equivalents
2,382

(54
)
 
 
 
Cash and cash equivalents, beginning of period
2,259

3,805

Cash and cash equivalents, end of period
$
4,641

$
3,751


See Note 9 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 2013 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 2013 Annual Report on Form 10-K filed with the SEC.

Accounting methods historically employed require certain estimates as of interim dates. The information furnished in the accompanying condensed financial statements reflects all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the September 30, 2014, December 31, 2013 and September 30, 2013 financial information and are of a normal recurring nature. The results of operations for the three months and nine months ended September 30, 2014 and September 30, 2013, and our financial condition as of September 30, 2014 and December 31, 2013 are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period.

Recently Issued and Adopted Accounting Standards

We have implemented all new accounting pronouncements that are in effect and may impact our financial statements and do not believe that there are any other new accounting pronouncements that have been issued that might have a material impact on our financial position, results of operations, or cash flows.

Revenue from Contracts with Customers, ASU 2014-09
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The standard provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer, as opposed to recognizing revenue when the risks and rewards transfer to the customer under the existing revenue guidance. ASU 2014-09 is effective for annual and interim reporting periods beginning after December 15, 2016 and early adoption is not permitted. We are currently assessing the impact, if any, that ASU 2014-09 will have on our financial position, results of operations or cash flows.


(2)
ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS

Following is a summary of Receivables - customers, net included in the accompanying Condensed Balance Sheets (in thousands) as of:
 
September 30, 2014
December 31, 2013
Accounts receivable trade
$
23,261

$
16,300

Unbilled revenues
8,382

9,719

Allowance for doubtful accounts
(224
)
(220
)
Receivables - customers, net
$
31,419

$
25,799



8



(3)
REGULATORY ASSETS AND LIABILITIES

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:
 
Recovery/Amortization Period
(in years)
September 30, 2014
 
December 31, 2013
Regulatory assets:
 
 
 
 
Unamortized loss on reacquired debt(a)
10
$
2,447

 
$
2,257

AFUDC(b)
45
8,386

 
8,327

Employee benefit plans(c)
13
15,314

 
15,233

Deferred energy and fuel cost adjustments - current (a)
1
14,418

 
7,711

Flow through accounting(a)
35
11,031

 
9,723

Other(a)
2
3,958

 
2,013

Total regulatory assets
 
$
55,554

 
$
45,264


Regulatory liabilities:
 
 
 
 
Cost of removal for utility plant(a)
53
$
30,852

 
$
30,467

Employee benefit plans
13
10,328

 
10,177

Other
13
1,204

 
2,874

Total regulatory liabilities
 
$
42,384

 
$
43,518

____________________
(a)
Recovery or return 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 of costs, we are allowed a return on a portion of this amount or a reduction in rate base, respectively.


(4)
PROPERTY, PLANT AND EQUIPMENT

On March 21, 2014, we retired our Osage, Ben French and Neil Simpson I electric generating plants primarily due to federal environmental regulations. The total plant to be decommissioned remaining in Property, plant and equipment at September 30, 2014 is as follows (in thousands):
Cost of Plant
Accumulated Depreciation
Net Book Value
$
54,230

$
(49,718
)
$
4,512


We reasonably expect the remaining book value to be recovered through future rates.


9




(5)
RELATED-PARTY TRANSACTIONS

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, 2014
 
December 31, 2013
Receivables - affiliates
$
5,448

 
$
4,934

Accounts payable - affiliates
$
22,271

 
$
21,082


Money Pool Notes Receivable and Notes Payable

We have entered into a Utility Money Pool Agreement (the “Agreement”) with BHC, Cheyenne Light and Black Hills Energy. We are the administrator of the Money Pool. Under the Agreement, we may borrow from BHC; however the Agreement restricts us 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 and advances under the Agreement bear interest at the weighted average daily cost of our parent company’s credit facility 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, 2014, the average cost of borrowing under the Utility Money Pool was 1.42%.

We had the following balances with the Utility Money Pool (in thousands) as of:
 
September 30, 2014
 
December 31, 2013
Money pool notes receivable, net
$

 
$
17,292

Money pool notes payable, net
$
19,433

 
$


Our net interest income relating to balances with the Utility Money Pool was as follows (in thousands):
 
Three Months Ended September 30,
Nine Months Ended September 30,
 
2014
2013
2014
2013
Net interest income (expense)
$
(3
)
$
132

$
81

$
420


Other related party activity was as follows (in thousands):

 
Three Months Ended September 30,
Nine Months Ended September 30,
 
2014
2013
2014
2013
Revenue:
 
 
 
 
Energy sold to Cheyenne Light
$
391

$
238

$
1,467

$
595

Rent from electric properties
$
1,126

$
987

$
3,200

$
2,961

 
 
 
 
 
Fuel and purchased power:
 
 
 
 
Purchases of coal from WRDC
$
4,854

$
4,822

$
13,886

$
14,087

Purchase of excess energy from Cheyenne Light
$
1,117

$
964

$
2,330

$
2,898

Purchase of renewable wind energy from Cheyenne Light - Happy Jack
$
264

$
228

$
1,393

$
1,293

Purchase of renewable wind energy from Cheyenne Light - Silver Sage
$
430

$
414

$
2,274

$
2,210

 
 
 
 
 
Corporate support:
 
 
 
 
Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings
$
6,274

$
7,583

$
20,433

$
22,637


10





(6)
EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plan

The components of net periodic benefit cost for the Defined Benefit Pension Plan were as follows (in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
Service cost
$
176

 
$
213

 
$
528

 
$
639

Interest cost
748

 
742

 
2,244

 
2,226

Expected return on plan assets
(925
)
 
(941
)
 
(2,776
)
 
(2,823
)
Prior service cost
11

 
11

 
32

 
33

Net loss (gain)
235

 
652

 
705

 
1,956

Net periodic benefit cost
$
245

 
$
677

 
$
733

 
$
2,031


Non-pension Defined Benefit Postretirement Healthcare Plan

The components of net periodic benefit cost for the Non-Pension Defined Benefit Postretirement Healthcare Plan were as follows (in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
Service cost
$
56

 
$
54

 
$
168

 
$
162

Interest cost
60

 
60

 
180

 
180

Prior service cost (benefit)
(84
)
 
(69
)
 
(252
)
 
(207
)
Net loss (gain)

 
2

 

 
6

Net periodic benefit cost
$
32

 
$
47

 
$
96

 
$
141



11



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,
 
2014
 
2013
 
2014
 
2013
Interest cost
$
36

 
$
33

 
$
109

 
$
99

Net loss (gain)
11

 
17

 
33

 
51

Net periodic benefit cost
$
47

 
$
50

 
$
142

 
$
150


Contributions

We anticipate we will make contributions to the benefit plans during 2014 and 2015. Contributions to the Defined Pension Plan are cash contributions made directly to the Pension Plan Trust accounts. Contributions to the Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions and anticipated contributions are as follows (in thousands):
 
Contributions Nine Months Ended September 30, 2014
Remaining Anticipated Contributions for 2014
Anticipated Contributions for 2015
Defined Benefit Pension Plan
$
1,696

$

$
2,193

Non-Pension Defined Benefit Postretirement Healthcare Plan
$
415

$
138

$
595

Supplemental Non-qualified Defined Benefit Plans
$
163

$
54

$
215


(7)    LONG-TERM DEBT

On September 30, 2014, we repaid in full $12 million in principal on the 5.35% Pollution Control Revenue Bonds originally due to mature on October 1, 2024. In addition, we paid the accrued interest on these bonds of $0.3 million.


(8)
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 2013 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, 2014
 
December 31, 2013
 
Carrying Amount
Fair Value
 
Carrying Amount
Fair Value
Cash and cash equivalents (a)
$
4,641

$
4,641

 
$
2,259

$
2,259

Long-term debt, including current maturities (b)
$
257,751

$
330,397

 
$
269,948

$
317,531

_________________
(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 using the market approach based on observable inputs of quoted market prices and yields available for debt instruments either directly or indirectly for similar maturities and debt ratings in active markets and therefore is classified in Level 2 in the fair value hierarchy. The carrying amount of our variable rate debt approximates fair value due to the variable interest rates with short reset periods.


12




(9)
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

Nine months ended September 30,
2014
 
2013
 
(in thousands)
Non-cash investing and financing activities -
 
 
 
Property, plant and equipment acquired with accrued liabilities
$
9,534

 
$
9,495

Non-cash (decrease) to money pool notes receivable, net
$

 
$
(8,000
)
Non-cash dividend to Parent
$

 
$
8,000

 
 
 
 
Cash (paid) refunded during the period for -
 
 
 
Interest (net of amounts capitalized)
$
(13,301
)
 
$
(12,784
)
Income taxes, net
$

 
$
223


(10)
COMMITMENTS AND CONTINGENCIES

Other than the items discussed below, 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 2013 Annual Report on Form 10-K.

Cheyenne Prairie

Construction was completed on Cheyenne Prairie, a natural gas-fired electric generating facility jointly owned by us and Cheyenne Light. We own 55 MW and Cheyenne Light owns 40 MW of the facility’s combined-cycle unit. Our cost is approximately $91 million for our share of the combined-cycle unit. The facility was placed into commercial operation on October 1, 2014. Included in our cost of Cheyenne Prairie are contingencies of approximately $1.1 million remaining on contracts pertaining to site finishing, contractor close-outs, and construction management demobilization and cleanup. Resolution of these contingencies is expected in the fourth quarter of 2014.

Oil Creek Fire

On June 29, 2012, a forest and grassland fire occurred in the western Black Hills of Wyoming. A state fire investigator concluded that the fire was caused by the failure of a transmission structure which we owned, operated and maintained. On April 16, 2013, a lawsuit was filed in the United States District Court for the District of Wyoming, which forty-seven plaintiffs and the State of Wyoming have now joined, asserting claims for damages against us. The claims include allegations of negligence, negligence per se, common law nuisance, and trespass. In addition to claims for these compensatory damages, the lawsuit seeks recovery of punitive damages. Our investigation of the cause and origin of the fire is ongoing. We have denied and will vigorously defend all claims arising out of the fire, pending the completion of our investigation. We cannot predict the outcome of our investigation, the viability of alleged claims or the outcome of the litigation.

Civil litigation of this kind, however, is likely to lead to settlement negotiations, including negotiations prompted by pre-trial civil court procedures. We believe such negotiations would effect a settlement of all claims. Regardless of whether the litigation is determined at trial or through settlement, we expect to incur significant investigation, legal and expert services expenses associated with the litigation. We maintain insurance coverage to limit our exposure to losses due to civil liability claims, and related litigation expense. The deductible applicable to some types of claims arising out of this fire is $1.0 million. We expect this coverage to limit our exposure, and we will pursue recoveries to the maximum extent available under the policies. Based upon information currently available, we believe that a loss associated with settlement of pending claims is probable. Accordingly, as of September 30, 2014, we recorded a loss contingency liability related to these claims, and we recorded a receivable for costs we believe are reimbursable and probable of recovery under our insurance coverage. Both of these entries reflect our reasonable estimate of probable future litigation expense and settlement costs; we did not base these contingencies on any determination that it is probable we would be found liable for these claims were they to be litigated.


13



Given the uncertainty of litigation, however, a loss related to the fire, the litigation and related claims in excess of the loss we have determined to be probable is reasonably possible. However, we cannot reasonably estimate the amount of such possible loss because our investigation and review of damage claims documentation is ongoing, and there are significant factual and legal issues to be resolved. Further claims may be presented by these and other parties. While we have received claims seeking recovery for fire suppression, reclamation and rehabilitation costs, damage to fencing and other personal property, alleged injury to timber, grass or hay, livestock and related operations, and diminished value of real estate, currently totaling $50 million, we are not yet able, for the reasons described above, to reasonably estimate the amount of any reasonable possible losses in excess of the amount we have accrued. Based upon information currently available, however, management does not expect the outcome of the claims to have a material adverse effect upon our consolidated financial condition, results of operations or cash flows.

(11)    SUBSEQUENT EVENT

Long-Term Debt

On October 1, 2014, in a private placement to provide permanent financing for Cheyenne Prairie, we issued $85 million of 4.43% coupon first mortgage bonds due October 20, 2044.

Related-Party Gas Transportation Service Agreement

On October 1, 2014, we entered into a gas transportation service agreement with Cheyenne Light in connection with gas supply for Cheyenne Prairie. The agreement is for a term of 40 years, in which we pay a monthly service and facility fee for firm and interruptible gas transportation.

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

Cheyenne Prairie

On October 1, 2014, Black Hills Power and Cheyenne Light placed into commercial service their jointly-owned Cheyenne Prairie generating station. Cheyenne Prairie is a natural gas-fired generating facility built to serve Black Hills Power and Cheyenne Light customers. We own 55 MW and Cheyenne Light owns 40 MW of the facility’s combined-cycle unit. Our cost is approximately $91 million for our share of the combined-cycle unit. Cheyenne Prairie was constructed on time and on budget. Construction financing costs were recovered through construction financing riders. New rates were implemented on October 1, 2014 for Black Hills Power customers in Wyoming, as previously approved by the WPSC, and interim rates were implemented on October 1, 2014 for customers in South Dakota.

Bond Issuance

On October 1, 2014, we issued $85 million of 4.43% coupon first mortgage bonds due October 20, 2044 to provide permanent financing for Cheyenne Prairie. Proceeds from the bond sale also funded the September 30, 2014 early redemption of our 5.35% $12 million pollution control revenue bonds, originally due October 1, 2024.

Regulatory Matters

We received approval from the WPSC on the rate case associated with Cheyenne Prairie, previously filed on January 17, 2014. On August 21, 2014, the WPSC approved rate case settlement agreements authorizing an increase for Black Hills Power of approximately $2.2 million for annual electric revenue, effective October 1, 2014. The settlement also included a return on equity of 9.9% and a capital structure of 53.3% equity and 46.7% debt.

On July 22, 2014, we filed a CPCN with the WPSC to construct a $54 million, 230-kV, 144 mile-long transmission line that would connect the Teckla Substation in northeast Wyoming, to the Lange Substation near Rapid City, South Dakota, for the Wyoming portion of this line. On June 30, 2014, we filed an application with the SDPUC, for a permit to construct the South Dakota portion of this line. Approval by the WPSC and SDPUC is anticipated in the fourth quarter of 2014.

14




On March 31, 2014, we filed a rate request with the SDPUC for an annual revenue increase of $14.6 million to recover operating expenses and infrastructure investments, primarily for Cheyenne Prairie. The filing seeks a return on equity of 10.25%, and a capital structure of approximately 53.3% equity and 46.7% debt. Interim rates were implemented on October 1, 2014 when Cheyenne Prairie commenced commercial operations. A final ruling from the SDPUC is expected in the first quarter of 2015.

On March 21, 2014, we retired the Ben French, Neil Simpson I, and Osage coal-fired power plants. These three plants totaling 81 MW were closed because of federal environmental regulations. These plants are primarily replaced by our share of Cheyenne Prairie. On October 1, 2014, we transferred the remaining net book value of these plants to a regulatory asset in accordance with an order granted by the SDPUC.

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 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, purchased power and natural gas. 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.

The following tables provide certain financial information and operating statistics:

 
Three Months Ended September 30,
Nine Months Ended September 30,
 
2014
2013
Variance
2014
2013
Variance
 
(in thousands)
Revenue
$
67,729

$
67,268

$
461

$
199,736

$
187,917

$
11,819

Fuel and purchased power
23,919

22,454

1,465

72,242

65,676

6,566

Gross margin
43,810

44,814

(1,004
)
127,494

122,241

5,253

 
 
 
 
 
 
 
Operating expenses
24,803

26,110

(1,307
)
77,160

76,741

419

Operating income
19,007

18,704

303

50,334

45,500

4,834

 
 
 
 
 
 
 
Interest income (expense), net
(4,715
)
(4,805
)
90

(14,248
)
(14,414
)
166

Other income (expense), net
170

(7
)
177

527

402

125

Income tax expense
(4,546
)
(4,594
)
48

(11,824
)
(9,956
)
(1,868
)
Net income
$
9,916

$
9,298

$
618

$
24,789

$
21,532

$
3,257



15




 
Electric Revenue by Customer Type
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
(in thousands)
 
2014
 
Percentage Change
 
2013
 
2014
 
Percentage Change
 
2013
Residential
$
15,941

 
(6)%
 
$
16,951

 
$
50,333

 
7%
 
$
46,928

Commercial
24,747

 
6%
 
23,319

 
67,475

 
13%
 
59,716

Industrial
6,816

 
—%
 
6,850

 
21,685

 
8%
 
20,070

Municipal
964

 
(11)%
 
1,078

 
2,602

 
(1)%
 
2,639

Total retail revenue
48,468

 
1%
 
48,198

 
142,095

 
10%
 
129,353

Contract wholesale
5,551

 
(5)%
 
5,847

 
15,622

 
(6)%
 
16,540

Wholesale off-system
6,278

 
(23)%
 
8,123

 
20,764

 
(7)%
 
22,222

Other revenue
7,432

 
46%
 
5,100

 
21,255

 
7%
 
19,802

Total revenue
$
67,729

 
1%
 
$
67,268

 
$
199,736

 
6%
 
$
187,917


 
Megawatt Hours Sold by Customer Type
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2014
 
Percentage Change
 
2013
 
2014
 
Percentage Change
 
2013
Residential
120,117

 
(9)%
 
131,664

 
398,821

 
(2)%
 
406,159

Commercial
214,590

 
7%
 
201,332

 
575,579

 
4%
 
551,712

Industrial
96,443

 
(2)%
 
98,174

 
302,208

 
2%
 
295,662

Municipal
9,387

 
(12)%
 
10,691

 
24,781

 
(7)%
 
26,621

Total retail quantity sold
440,537

 
—%
 
441,861

 
1,301,389

 
2%
 
1,280,154

Contract wholesale
83,714

 
(4)%
 
87,092

 
250,941

 
(7)%
 
268,529

Wholesale off-system
171,189

 
(35)%
 
261,567

 
595,483

 
(23)%
 
777,854

Total quantity sold
695,440

 
(12)%
 
790,520

 
2,147,813

 
(8)%
 
2,326,537

Losses and company use
67,325

 
45%
 
46,474

 
170,279

 
28%
 
132,629

Total energy
762,765

 
(9)%
 
836,994

 
2,318,092

 
(6)%
 
2,459,166



 
Megawatt Hours Generated and Purchased
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
Generated -
2014
 
Percentage Change
 
2013
 
2014
 
Percentage Change
 
2013
Coal-fired
414,551

(a)(b) 
(9)%
 
457,329

 
1,168,641

(a)(b) 
(12)%
 
1,334,441

Gas-fired
12,054

(c) 
(34)%
 
18,275

 
17,026

(c) 
(34)%
 
25,953

Total generated
426,605

 
(10)%
 
475,604

 
1,185,667

 
(13)%
 
1,360,394

 
 
 
 
 
 
 
 
 
 
 
 
Total purchased
336,160

 
(7)%
 
361,390

 
1,132,425

 
3%
 
1,098,772

Total generated and purchased
762,765

 
(9)%
 
836,994

 
2,318,092

 
(6)%
 
2,459,166

__________________
(a) Decrease reflects the retirement of Neil Simpson I on March 21, 2014.
(b)
The nine months ended September 30, 2014 reflects a planned annual outage at Neil Simpson II and an unplanned outage for a catalyst repair at Wygen III.
(c)
The nine months ended September 30, 2014 include a planned outage at Ben French CT's #1 and #2 for a controls upgrade.


16




 
Power Plant Availability
 
Three Months Ended September 30,
Nine Months Ended September 30,
 
2014
2013
2014
 
2013
Coal-fired plants (a)
96.5
%
 
96.6
%
 
89.8
%
 
96.8
%
Other plants (b)
91.4
%
 
92.6
%
 
91.0
%
 
96.1
%
Total availability
94.2
%
 
95.0
%
 
90.3
%
 
96.5
%
____________________
(a)
The nine months ended September 30, 2014 reflects a planned annual outage at Neil Simpson II and an unplanned outage for a catalyst repair at Wygen III.
(b)
The nine months ended September 30, 2014 include a planned outage at Ben French CT's #1 and #2 for a controls upgrade.


 
Degree Days
Degree Days
 
Three Months Ended September 30,
Nine Months Ended September 30,
 
2014
2013
2014
2013
 
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 and cooling degree days:
 
 
 
 
 
 
 
 
Heating degree days
241

15
 %
107

(49
)%
4,676

6
 %
4,544

6
%
Cooling degree days
382

(32
)%
646

15
 %
481

(28
)%
724

8
%


Three Months Ended September 30, 2014 Compared to Three Months Ended September 30, 2013. Net income was $9.9 million compared to $9.3 million for the same period in the prior year primarily due to the following:

Gross margin decreased primarily due to a 41% decrease in cooling degree days compared to the same period in the prior year resulting in a $1.3 million decrease on lower demand and residential MWh sold. Wholesale margins were also impacted from plant outages related to unit contingent contracts, resulting in $0.7 million decrease in wholesale margins. These decreases were partially offset by increased rider margins of $0.5 million due to a return on additional investment in our generating facilities and higher common use system revenues of $0.3 million.

Operations and maintenance decreased primarily due to lower generation plant maintenance and employee costs.

Interest expense, net was comparable to the same period in the prior year, reflecting lower interest expense in the current year, partially offset by lower current year interest income driven by a decrease in lending to the Utility money pool.

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

Income tax expense: The effective tax rate was lower in 2014 when compared to 2013 due primarily to an increase in an estimated flow through tax adjustment, partially offset by a prior period research and development tax credit not being extended to 2014.


17



Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013. Net income was $25 million compared to $22 million for the same period in the prior year primarily due to the following:

Gross margin increased primarily due a return on additional investments which increased base electric margins by $3.6 million, increased rider margins by $2.7 million, and a $0.8 million increase resulting from higher retail megawatt hours sold, primarily due to increased commercial and industrial loads. These increases were partially offset by a $1.7 million decrease in contract wholesale margins primarily due to plant outages related to unit contingent contracts.

Operations and maintenance increased primarily due to increased generation maintenance and property taxes, partially offset by lower vegetation management and employee costs.

Interest expense, net was comparable to the same period in the prior year, reflecting lower interest expense in the current year, partially offset by lower current year interest income driven by a decrease in lending to the Utility money pool.

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

Income tax expense: The effective tax rate was higher in 2014 when compared to 2013 due primarily to the research and development tax credit not being extended to 2014. The prior year reflected the entire year of the 2012 research and development tax credit due to retroactive reinstatement of the credit in January 2013 by the U.S. Congress.

Financing Plans and Activity

On September 30, 2014 we repaid in full $12 million in principal on the 5.35% Pollution Control Revenue Bonds originally due to mature on October 1, 2024. In addition, we paid the accrued interest on these bonds of $0.3 million.

On October 1, 2014, in a private placement to provide permanent financing for Cheyenne Prairie, we issued $85 million of 4.43% coupon first mortgage bonds due October 20, 2044.

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. As of September 30, 2014, our credit ratings for our Senior Secured Debt, as assessed by the three major credit rating agencies, were as follows:
Rating Agency
Rating
S&P
A-
Moody’s(*)
A1
Fitch (**)
A
______________________
*
On January 30, 2014, Moody’s upgraded the BHP credit rating to A1 with a stable outlook.
** On June 13, 2014, Fitch upgraded the BHP credit rating to A with a Stable outlook.


18



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.

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 2013 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 10Q.

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, 2013.

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, 2014. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective.

There were no changes in our internal control over financial reporting during the quarter ended September 30, 2014, that materially affected or are reasonably likely to materially affect our internal control over financial reporting.


19



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 2013 Annual Report on Form 10-K and Note 10 of our Notes to Condensed Financial Statements in this Quarterly Report on Form 10-Q, which information from Note 10 is incorporated by reference into this item.


Item 1A.
Risk Factors

Except as noted below, 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, 2013.

Federal and state laws concerning greenhouse gas regulations and air emissions may materially increase our generation and production costs and could render some of our generating units uneconomical to operate and maintain.

We own and operate regulated fossil-fuel generating plants in South Dakota and Wyoming. Recent developments under federal and state laws and regulations governing air emissions from fossil-fuel generating plants will likely result in more stringent emission limitations, which could have a material impact on our costs of operations. In addition to the environmental matters identified in Item 1A of our Annual Report on Form 10-K, the following recently proposed regulations could negatively impact our operations.

On June 2, 2014, the EPA proposed the Clean Power Plan to cut carbon emissions from existing electric generating units. The design of the Clean Power Plan is to decrease existing coal-fired generation, and increase the utilization of existing gas generation, increase renewable energy, and demand side management. This rule could have a significant impact on our coal, natural gas and oil generating fleet. The rule calls for states to develop plans to meet their assigned emission rate targets by 2030. The rule also allows states to formulate a regional approach whereby they would join with other states and be assigned a new single target for the group. We are currently evaluating this proposal, but cannot predict the impact on operations as this rule is expected to be final in June 2015, and state plans are expected to be due at the earliest in June 2016, with extensions possible to 2017 and 2018. We expect any impact to us to be mitigated through the recent Osage, Ben French and Neil Simpson I plant closures.

New or more stringent regulations or other energy efficiency requirements could require us to incur significant additional costs relating to, among other things, the installation of additional emission control equipment, the acceleration of capital expenditures, the purchase of additional emissions allowances or offsets, the acquisition or development of additional energy supply from renewable resources, and the closure of certain generating facilities. To the extent our regulated fossil-fuel generating plants are included in rate base we will attempt to recover costs associated with complying with emission standards or other requirements. We will also attempt to recover the emission compliance costs of our non-regulated fossil-fuel generating plants from utility and other purchasers of the power generated by those non-regulated power plants. Any unrecovered costs could have a material impact on our results of operations and financial condition. In addition, future changes in environmental regulations governing air emissions could render some of our power generating units more expensive or uneconomical to operate and maintain.


20



   

Item 6.
Exhibits

Exhibit 3.1*
Restated Articles of Incorporation of the Registrant (filed as an exhibit to the Registrant’s Form 8-K dated June 7, 1994 (No. 1-7978)).

Exhibit 3.2*
Articles of Amendment to the Articles of Incorporation of the Registrant, as filed with the Secretary of State of the State of South Dakota on December 22, 2000 (filed as an exhibit to the Registrant’s Form 10-K for 2000).

Exhibit 3.3*
Bylaws of the Registrant (filed as an exhibit to the Registrant’s Registration Statement on Form S-8 dated July 13, 1999).

Exhibit 4.1*
Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as Exhibit 4.19 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669-01)). First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to J.P. Morgan Chase Bank), as Trustee (filed as Exhibit 4.20 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669-01)). Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 4.21 to the Registration Statement on Form S-3 (No. 333-150669-01)).

Exhibit 10*
Third Supplemental Indenture, dated as of October 1, 2014, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on October 2, 2014).

Exhibit 31.1
Certification of Chief Executive Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.

Exhibit 31.2
Certification of Chief Financial Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.

Exhibit 32.1
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.

Exhibit 32.2
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.

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



21



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/ ANTHONY S. CLEBERG
Anthony S. Cleberg, Executive Vice President
and Chief Financial Officer

Dated: November 6, 2014


22



EXHIBIT INDEX

Exhibit Number
Description

Exhibit 3.1*
Restated Articles of Incorporation of the Registrant (filed as an exhibit to the Registrant’s Form 8-K dated June 7, 1994 (No. 1-7978)).

Exhibit 3.2*
Articles of Amendment to the Articles of Incorporation of the Registrant, as filed with the Secretary of State of the State of South Dakota on December 22, 2000 (filed as an exhibit to the Registrant’s Form 10-K for 2000).

Exhibit 3.3*
Bylaws of the Registrant (filed as an exhibit to the Registrant’s Registration Statement on Form S-8 dated July 13, 1999).

Exhibit 4.1*
Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as Exhibit 4.19 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669-01)). First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to J.P. Morgan Chase Bank), as Trustee (filed as Exhibit 4.20 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669-01)). Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 4.21 to the Registration Statement on Form S-3 (No. 333-150669-01)).

Exhibit 10*
Third Supplemental Indenture, dated as of October 1, 2014, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on October 2, 2014).

Exhibit 31.1
Certification of Chief Executive Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.

Exhibit 31.2
Certification of Chief Financial Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.

Exhibit 32.1
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.

Exhibit 32.2
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.

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


23