10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended March 31, 2016
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 April 30, 2016, 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	3
PART 1.	FINANCIAL INFORMATION
Item 1.	Financial Statements
	Condensed Statements of Income and Comprehensive Income - unaudited	4
	Three Months Ended March 31, 2016 and 2015
	Condensed Balance Sheets - unaudited	5
	March 31, 2016 and December 31, 2015
	Condensed Statements of Cash Flows - unaudited	7
	Three Months Ended March 31, 2016 and 2015
	Notes to Condensed Financial Statements - unaudited	8
Item 2.	Managements’ Discussion and Analysis of Financial Condition and Results of Operations	15
Item 4.	Controls and Procedures	18
PART II.	OTHER INFORMATION	19
Item 1.	Legal Proceedings	19
Item 1A.	Risk Factors	19
Item 6.	Exhibits	19
	Signatures	20
	Exhibit Index	21

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 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)
Cheyenne Prairie	Cheyenne Prairie Generating Station is a 132 MW natural gas-fired generating facility jointly owned by Black Hills Power and Cheyenne Light, Fuel and Power Company. Cheyenne Prairie was placed into commercial service 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
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
Fitch	Fitch Ratings
GAAP	Generally Accepted Accounting Principles in the United States of America
Global Settlement	Settlement with a utilities commission where the dollar figure is agreed upon, but the specific adjustments used by each party to arrive at the figure are not specified in public rate orders.
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
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
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 March 31,
(unaudited)	2016			2015
	(in thousands)
Revenue	$	68,642		$	70,283
Operating expenses:
Fuel, purchased power and natural gas	20,730			22,104
Operations and maintenance	17,031			17,091
Depreciation and amortization	8,612			8,125
Taxes - property	1,489			1,473
Total operating expenses	47,862			48,793
Operating income	20,780			21,490
Other income (expense):
Interest expense	(5,454		)	(5,692		)
AFUDC - borrowed	223			39
Interest income	202			104
AFUDC - equity	423			70
Other income (expense), net	74			35
Total other income (expense)	(4,532		)	(5,444		)
Income from continuing operations before income taxes	16,248			16,046
Income tax expense	(5,062		)	(5,643		)
Net income	11,186			10,403
Other comprehensive income (loss):
Reclassification adjustments of cash flow hedges settled and included in net income (net of tax (expense) benefit of $(6) and $336 for the three months ended March 31, 2016 and 2015)	10			352
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(7) and $(8) for the three months ended March 31, 2016 and 2015)	14			15
Other comprehensive income	24			367
Comprehensive income	$	11,210		$	10,770

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)	March 31, 2016			December 31, 2015
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	28,999		$	7,559
Receivables - customers, net	27,140			27,856
Receivables - affiliates	8,391			5,747
Other receivables, net	242			236
Money pool notes receivable, net	50,630			76,813
Materials, supplies and fuel	22,891			24,282
Regulatory assets, current	18,550			14,096
Other, current assets	4,995			43,118
Total current assets	161,838			199,707
Investments	4,756			4,725
Property, plant and equipment	1,175,978			1,166,126
Less accumulated depreciation and amortization	(329,494		)	(326,074		)
Total property, plant and equipment, net	846,484			840,052
Other assets:
Regulatory assets, non-current	71,125			71,717
Other, non-current assets	345			3,292
Total other assets	71,470			75,009
TOTAL ASSETS	$	1,084,548		$	1,119,493

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)	March 31, 2016			December 31, 2015
	(in thousands, except common stock par value and share amounts)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Accounts payable	$	21,508		$	21,297
Accounts payable - affiliates	27,148			30,032
Accrued liabilities	22,014			69,454
Regulatory liabilities, current	34			—
Total current liabilities	70,704			120,783
Long-term debt	339,651			342,756
Deferred credits and other liabilities:
Deferred income tax liability, net, non-current	207,508			188,961
Regulatory liabilities, non-current	52,644			51,583
Benefit plan liabilities	20,363			20,033
Other, non-current liabilities	2,989			3,398
Total deferred credits and other liabilities	283,504			263,975
Commitments and contingencies (Notes 4, 5 and 8)
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	328,981			330,295
Accumulated other comprehensive loss	(1,283		)	(1,307		)
Total stockholder’s equity	390,689			391,979
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	1,084,548		$	1,119,493

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)	Three Months Ended March 31,
	2016			2015
	(in thousands)
Operating activities:
Net income	$	11,186		$	10,403
Adjustments to reconcile net income to net cash provided by operating activities-
Depreciation and amortization	8,612			8,125
Deferred income tax	18,076			4,962
Employee benefits	443			601
AFUDC - equity	(423		)	(70		)
Other adjustments, net	296			85
Change in operating assets and liabilities -
Accounts receivable and other current assets	(2,041		)	7,951
Accounts payable and other current liabilities	(5,725		)	(10,237		)
Regulatory assets - current	(4,193		)	(2,722		)
Regulatory liabilities - current	—			3,715
Other operating activities, net	481			(719		)
Net cash provided by (used in) operating activities	26,712			22,094
Investing activities:
Property, plant and equipment additions	(18,928		)	(8,697		)
Change in money pool notes receivable, net	13,683			35,111
Other investing activities	(27		)	(44		)
Net cash provided by (used in) investing activities	(5,272		)	26,370
Financing activities:
Net cash provided by (used in) financing activities	—			—
Net change in cash and cash equivalents	21,440			48,464
Cash and cash equivalents, beginning of period	7,559			6,620
Cash and cash equivalents, end of period	$	28,999		$	55,084

See Note 7 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 2015 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 2015 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 March 31, 2016, December 31, 2015 and March 31, 2015 financial information and are of a normal recurring nature. The results of operations for the three months ended March 31, 2016 and March 31, 2015, and our financial condition as of March 31, 2016 and December 31, 2015 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

Leases, ASU 2016-02

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases. This ASU requires lessees to recognize a right-of-use asset and lease liability for all leases with terms of more than 12 months. Lessees are permitted to make an accounting policy election to not recognize the asset and liability for leases with a term of 12 months or less. 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 ASC is largely unchanged from the previous accounting standard. In addition, the ASU expands the disclosure requirements of lease arrangements. Lessees and lessors will use a modified retrospective transition approach, which includes a number of practical expedients. The guidance is effective for the Company beginning after December 15, 2019. Early adoption is permitted. We are currently assessing the impact that adoption of ASU 2016-02 will have on our financial position, results of operations or cash flows.

Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent), ASU 2015-07

On May 1, 2015, the FASB issued ASU 2015-07, Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent).The ASU removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient and also removes certain disclosure requirements. The new requirements were effective for us beginning January 1, 2016 and will be applied retrospectively to all periods presented, in our 2016 Form 10-K. This ASU will not materially affect our financial statements and disclosures, but will change certain presentation and disclosure of the fair value of certain plan assets in our pension and other postretirement benefit plan disclosures in our 2016 Form 10-K, for all periods presented.

Simplifying the Presentation of Debt Issuance Costs, ASU 2015-03

In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. Debt issuance costs related to a recognized debt liability will be presented on the balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as an asset. Amortization of these costs will continue to be reported as interest expense. ASU 2015-03 is effective for annual and interim reporting periods beginning after December 15, 2015. We adopted ASU 2015-03 in the first quarter of 2016 on a retrospective basis. As of March 31, 2016, we have presented the debt issuance costs, previously reported in other assets, as direct deductions from the carrying amount of long-term debt. The implementation of this standard resulted in reductions of other non-current assets and long-term debt of $3.1 million as of December 31, 2015. Adoption of ASU 2015-03 did not have a material impact on our financial position.

8

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. On July 9, 2015, FASB voted to defer the effective date of ASU 2014-09 by one year. The proposed guidance would be effective for annual and interim reporting periods beginning after December 15, 2017 and early adoption is permitted. We are currently evaluating the impact of adoption, 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:

	March 31, 2016			December 31, 2015
Accounts receivable trade	$	15,777		$	15,268
Unbilled revenues	11,619			12,795
Allowance for doubtful accounts	(256		)	(207		)
Receivables - customers, net	$	27,140		$	27,856

(3) 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:

	Recovery/Amortization Period (in years)	March 31, 2016		December 31, 2015
Regulatory assets:
Unamortized loss on reacquired debt (a)	9	$	2,025	$	2,096
AFUDC (b)	45	8,719		8,571
Employee benefit plans (c)	12	20,866		20,866
Deferred energy and fuel cost adjustments - current (a)	Less than 1 year	21,493		19,875
Flow through accounting (a)	35	12,412		12,104
Decommissioning costs, net of amortization(b)	10	13,317		13,686
Other regulatory assets (a)(d)	2	10,843		8,615
Total regulatory assets		$	89,675	$	85,813

Regulatory liabilities:
Cost of removal for utility plant (a)	53	$	39,157	$	38,131
Employee benefit plans (c)	12	12,616		12,616
Other regulatory liabilities	13	906		836
Total regulatory liabilities		$	52,679	$	51,583

____________________

(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, respectively.

(d) Includes approximately $7.0 million and $5.0 million of vegetation management expenses at March 31, 2016 and December 31, 2015, respectively, for which we are allowed a rate of return.

9

(4) 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:

	March 31, 2016		December 31, 2015
Receivables - affiliates	$	8,391	$	5,747
Accounts payable - affiliates	$	27,148	$	30,032

Money Pool Notes Receivable and Notes Payable

We have entered into a Utility Money Pool Agreement (the “Agreement”) with BHC, Black Hills Service Company 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 March 31, 2016, the average cost of borrowing under the Utility Money Pool was 1.62%.

We had the following balances with the Utility Money Pool (in thousands) as of:

	March 31, 2016		December 31, 2015
Money pool notes receivable, net	$	50,630	$	76,813

Our net interest income (expense) relating to balances with the Utility Money Pool was as follows (in thousands):

	Three Months Ended March 31,
	2016		2015
Net interest income (expense)	$	278	$	258

10

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

	Three Months Ended March 31,
	2016		2015
Revenue:
Energy sold to Cheyenne Light	$	661	$	326
Rent from electric properties	$	1,213	$	1,124
Fuel and purchased power:
Purchases of coal from WRDC	$	4,796	$	4,045
Purchase of excess energy from Cheyenne Light	$	55	$	476
Purchase of renewable wind energy from Cheyenne Light - Happy Jack	$	664	$	549
Purchase of renewable wind energy from Cheyenne Light - Silver Sage	$	1,127	$	936
Gas transportation service agreement:
Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation	$	136	$	103
Corporate support:
Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings	$	6,721	$	7,033

11

(5) EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plan

Beginning in 2016, we changed the method used to estimate the service and interest cost components of the net periodic pension, supplemental non-qualified defined benefit and other postretirement benefit costs. The new method uses the spot yield curve approach to estimate the service and interest costs by applying the specific spot rates along the yield curve used to determine the benefit obligations to relevant projected cash outflows. Previously, those costs were determined using a single weighted-average discount rate. The change does not affect the measurement of the total benefit obligations as the change in service and interest costs offsets the actuarial gains and losses recorded in other comprehensive income. The new method provides a more precise measure of interest and service costs by improving the correlation between the projected benefit cash flows and the discrete spot yield curve rates. We accounted for this change as a change in estimate prospectively beginning in the first quarter of 2016. The discount rates used to measure the 2016 service costs are 4.81%, 4.88% and 4.18% for pension, supplemental non-qualified defined benefit and other postretirement benefit costs, respectively. The discount rates used to measure the 2016 interest costs are 3.90%, 3.82% and 3.17% for pension, supplemental non-qualified defined benefit and other postretirement benefit costs, respectively. The previous method would have used a discount rate for both service and interest costs of 4.63% for pension, 4.50% for supplemental non-qualified defined benefit and 4.03% for other postretirement benefit costs. The decrease in the 2016 service and interest costs is approximately $0.5 million, $0.3 million and $0.1 million for the pension, supplemental non-qualified defined benefit and other postretirement benefit costs, respectively, as compared to the previous method.

The components of net periodic benefit cost for the Defined Benefit Pension Plan were as follows (in thousands):

	Three Months Ended March 31,
	2016			2015
Service cost	$	151		$	199
Interest cost	625			739
Expected return on plan assets	(908		)	(984		)
Prior service cost	11			11
Net loss (gain)	499			549
Net periodic benefit cost	$	378		$	514

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 March 31,
	2016			2015
Service cost	$	51		$	58
Interest cost	47			54
Prior service cost (benefit)	(84		)	(84		)
Net periodic benefit cost	$	14		$	28

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 March 31,
	2016		2015
Interest cost	$	30	$	36
Net loss (gain)	21		23
Net periodic benefit cost	$	51	$	59

12

Contributions

We anticipate we will make contributions to the benefit plans during 2016 and 2017. Contributions to the Defined Benefit 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 Three Months Ended March 31, 2016		Remaining Anticipated Contributions for 2016		Anticipated Contributions for 2017
Defined Benefit Pension Plan	$	—	$	1,638	$	1,615
Defined Benefit Postretirement Healthcare Plan	$	155	$	464	$	509
Supplemental Non-qualified Defined Benefit Plans	$	54	$	162	$	248

13

(6) 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 2015 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:

	March 31, 2016				December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents (a)	$	28,999	$	28,999	$	7,559	$	7,559
Long-term debt, including current maturities (b)	$	339,651	$	429,059	$	342,756	$	404,864

_________________

(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.

(7) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

Three months ended March 31,	2016			2015
	(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment acquired with accrued liabilities	$	5,087		$	2,042
Non-cash (decrease) to money pool notes receivable, net	$	(12,500	)	$	—
Non-cash dividend to Parent	$	12,500		$	—
Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(2,989	)	$	(2,718	)
Income taxes, net	$	—		$	—

(8) 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 2015 Annual Report on Form 10-K.

14

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

Name Rebranding

We now operate with the trade name Black Hills Energy. BHC rebranded all of its regulated utilities to operate under the name Black Hills Energy.

Regulatory Matters

During the first quarter of 2016, we commenced construction of the $54 million, 230-kV, 144 mile-long transmission line that will connect the Teckla Substation in northeast Wyoming, to the Lange Substation near Rapid City, South Dakota. The project is expected to be placed in service by the end of 2016.

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 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.

The following tables provide certain financial information and operating statistics:

	Three Months Ended March 31,
	2016			2015			Variance
	(in thousands)
Revenue	$	68,642		$	70,283		$	(1,641	)
Fuel and purchased power	20,730			22,104			(1,374		)
Gross margin	47,912			48,179			(267		)
Operating expenses	27,132			26,689			443
Operating income	20,780			21,490			(710		)
Interest income (expense), net	(5,029		)	(5,549		)	520
Other income (expense), net	497			105			392
Income tax expense	(5,062		)	(5,643		)	581
Net income	$	11,186		$	10,403		$	783

15

	Electric Revenue by Customer Type
	Three Months Ended March 31,
	(in thousands)
	2016		Percentage Change	2015
Residential	$	19,315	(4)%	$	20,140
Commercial	23,589		(5)%	24,741
Industrial	8,501		2%	8,299
Municipal	831		(3)%	858
Total retail revenue	52,236		(3)%	54,038
Contract wholesale	4,174		(23)%	5,420
Wholesale off-system	4,586		(31)%	6,635
Other revenue	7,646		82%	4,190
Total revenue	$	68,642	(2)%	$	70,283

	Megawatt Hours Sold by Customer Type
	Three Months Ended March 31,
	2016	Percentage Change	2015
Residential	142,753	(3)%	146,963
Commercial	188,888	(3)%	195,078
Industrial	108,021	(3)%	111,859
Municipal	7,441	(3)%	7,700
Total retail quantity sold	447,103	(3)%	461,600
Contract wholesale	63,453	(25)%	84,271
Wholesale off-system	193,373	(21)%	245,638
Total quantity sold	703,929	(11)%	791,509
Losses and company use	39,324	48%	26,646
Total energy	743,253	(9)%	818,155

	Megawatt Hours Generated and Purchased
	Three Months Ended March 31,
Generated -	2016	Percentage Change	2015
Coal-fired	388,001	3%	376,834
Gas-fired (a)	15,562	441%	2,878
Total generated	403,563	6%	379,712
Total purchased	339,690	(23)%	438,443
Total generated and purchased	743,253	(9)%	818,155

__________

(a) An increase in generation from Cheyenne Prairie was driven by outages at the Wyodak plant during the three months ended March 31, 2016.

16

	Power Plant Availability
	Three Months Ended March 31,
	2016		2015
Coal-fired plants (a)	92.4	%	87.7	%
Other plants	98.3	%	95.2	%
Total availability	95.8	%	92.0	%

__________________

(a) The three months ended March 31, 2015 reflects a planned annual outage at Neil Simpson II and an unplanned outage for a catalyst repair at Wygen III.

	Degree Days
	Three Months Ended March 31,
	2016			2015
	Actual	Variance from 30-year Average		Actual	Variance from 30-year Average
Heating degree days:
Heating degree days	2,806	(13	)%	2,873	(11	)%

Three Months Ended March 31, 2016 Compared to Three Months Ended March 31, 2015. Net income was $11 million compared to $10.4 million for the same period in the prior year primarily due to the following:

Gross margindecreased primarily due to lower residential volume due to milder weather and a decrease in commercial and industrial MWh sold, partially offset by the benefit from an additional day as a result of leap year.

Operations and maintenance increased primarily due to higher depreciation expense driven by additional plant in service compared to the same period in the prior year.

Interest expense, net decreased primarily due to higher AFUDC interest income in the current year driven by higher construction work-in-process balances compared to the same period in the prior year.

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

Income tax expense: The effective tax rate decreased due primarily to a favorable re-measurement of an uncertain tax position liability involving research and development credits and deductions, as a result of an agreement reached during the first quarter of 2016 with the IRS.

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 were in effect at March 31, 2016:

Rating Agency	Secured Rating
S&P	A-
Moody’s	A1
Fitch	A

17

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 2015 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, 2015.

Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) as of March 31, 2016. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective as of March 31, 2016.

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

Changes in Internal Control over Financial Reporting

During the quarter ended March 31, 2016, 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.

18

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 2015 Annual Report on Form 10-K and Note 8 of our Notes to Condensed Financial Statements in this Quarterly Report on Form 10-Q, which information from Note 8 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, 2015.

Item 6. Exhibits

Exhibit 3.1* Restated Articles of Incorporation of the Registrant dated March 30, 2015 (filed as Exhibit 3.1 to Registrant’s

Form 10-Q for the quarterly period ended March 31, 2015).

Exhibit 3.2* Amended and Restated Bylaws of the Registrant dated March 30, 2015 (filed as Exhibit 3.2 to Registrant’s

Form 10-Q for the quarterly period ended March 31, 2015).

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)). 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.

19

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: May 11, 2016

20

EXHIBIT INDEX

Exhibit Number Description

Exhibit 3.1* Restated Articles of Incorporation of the Registrant dated March 30, 2015 (filed as Exhibit 3.1 to Registrant’s Form 10-Q for the quarterly period ended March 31, 2015).

Exhibit 3.2* Amended and Restated Bylaws of the Registrant dated March 30, 2015 (filed as Exhibit 3.2 to Registrant’s Form 10-Q for the quarterly period ended March 31, 2015).

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)). 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

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, David R. Emery, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Black Hills Power, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; and

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; and

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting.

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	May 11, 2016
		/S/ DAVID R. EMERY
		David R. Emery
		Chairman and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Richard W. Kinzley, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Black Hills Power, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting.

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	May 11, 2016
		/S/ RICHARD W. KINZLEY
		Richard W. Kinzley
		Senior Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Black Hills Power, Inc. (the “Company”) on Form 10-Q for the period ended March 31, 2016 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, David R. Emery, Chairman and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13 (a) or

15 (d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material

respects, the financial condition and results of operations of the Company.

Date:	May 11, 2016
		/S/ DAVID R. EMERY
		David R. Emery
		Chairman and Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Black Hills Power, Inc. (the “Company”) on Form 10-Q for the period ended March 31, 2016 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Richard W. Kinzley, Senior Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13 (a) or

15 (d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material

respects, the financial condition and results of operations of the Company.

Date:	May 11, 2016
		/S/ RICHARD W. KINZLEY
		Richard W. Kinzley
		Senior Vice President and Chief Financial Officer

XML

Document and Entity Information Document - shares	3 Months Ended
	Mar. 31, 2016	Apr. 30, 2016
Document Information [Line Items]
Entity Registrant Name	BLACK HILLS POWER INC
Entity Central Index Key	0000012400
Document Type	10-Q
Document Period End Date	Mar. 31, 2016
Amendment Flag	false
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		23,416,396

XML

Condensed Statements of Income and Comprehensive Income - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Income Statement [Abstract]
Revenue	$ 68,642	$ 70,283
Operating expenses:
Fuel, purchased power and natural gas	20,730	22,104
Operations and maintenance	17,031	17,091
Depreciation and amortization	8,612	8,125
Taxes - property	1,489	1,473
Total operating expenses	47,862	48,793
Operating income	20,780	21,490
Other income (expense):
Interest expense	(5,454)	(5,692)
AFUDC - borrowed	223	39
Interest income	202	104
AFUDC - equity	423	70
Other income (expense), net	74	35
Total other income (expense)	(4,532)	(5,444)
Income from continuing operations before income taxes	16,248	16,046
Income tax expense	(5,062)	(5,643)
Net Income	11,186	10,403
Other comprehensive income (loss):
Reclassification adjustments of cash flow hedges settled and included in net income (net of tax (expense) benefit of $(6) and $336 for the three months ended March 31, 2016 and 2015)	10	352
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(7) and $(8) for the three months ended March 31, 2016 and 2015)	14	15
Other comprehensive income	24	367
Comprehensive income	$ 11,210	$ 10,770

XML

Condensed Statements of Income and Comprehensive Income OCI Parenthetical - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Income Statement [Abstract]
Reclassification adjustment of cash flow hedges settled, (tax) benefit	$ (6)	$ 336
Reclassification adjustment of benefit and other postretirement plans included in net income, (tax) benefit	$ (7)	$ (8)

XML

Condensed Balance Sheets - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 28,999	$ 7,559
Receivables - customers, net	27,140	27,856
Receivables - affiliates	8,391	5,747
Other receivables, net	242	236
Money pool notes receivable, net	50,630	76,813
Materials, supplies and fuel	22,891	24,282
Regulatory assets, current	18,550	14,096
Other, current assets	4,995	43,118
Total current assets	161,838	199,707
Investments	4,756	4,725
Property, plant and equipment	1,175,978	1,166,126
Less accumulated depreciation and amortization	(329,494)	(326,074)
Total property, plant and equipment, net	846,484	840,052
Other assets:
Regulatory assets, non-current	71,125	71,717
Other, non-current assets	345	3,292
Total other assets	71,470	75,009
TOTAL ASSETS	1,084,548	1,119,493
Current liabilities:
Accounts payable	21,508	21,297
Accounts payable - affiliates	27,148	30,032
Accrued liabilities	22,014	69,454
Regulatory liabilities, current	34	0
Total current liabilities	70,704	120,783
Long-term debt, net of current maturities	339,651	342,756
Deferred credits and other liabilities:
Deferred income tax liability, net, non-current	207,508	188,961
Regulatory liabilities, non-current	52,644	51,583
Benefit plan liabilities	20,363	20,033
Other, non-current liabilities	2,989	3,398
Total deferred credits and other liabilities	$ 283,504	$ 263,975
Commitments and contingencies (Notes 4, 5 and 8)
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	328,981	330,295
Accumulated other comprehensive loss	(1,283)	(1,307)
Total stockholder’s equity	390,689	391,979
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$ 1,084,548	$ 1,119,493

XML

Balance Sheet Parentheticals - $ / shares	Mar. 31, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Common Stock, Par Value Per Share (usd per share)	$ 1	$ 1
Common Stock, Shares Authorized	50,000,000	50,000,000
Common Stock, Shares, Issued	23,416,396	23,416,396

XML

Condensed Statements of Cash Flows - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Operating activities:
Net income	$ 11,186	$ 10,403
Adjustments to reconcile net income to net cash provided by operating activities-
Depreciation and amortization	8,612	8,125
Deferred income tax	18,076	4,962
Employee benefits	443	601
AFUDC - equity	(423)	(70)
Other adjustments, net	296	85
Change in operating assets and liabilities -
Accounts receivable and other current assets	(2,041)	7,951
Accounts payable and other current liabilities	(5,725)	(10,237)
Regulatory assets - current	(4,193)	(2,722)
Regulatory liabilities - current	0	3,715
Other operating activities, net	481	(719)
Net cash provided by (used in) operating activities	26,712	22,094
Investing activities:
Property, plant and equipment additions	(18,928)	(8,697)
Change in money pool notes receivable, net	13,683	35,111
Other investing activities	(27)	(44)
Net cash provided by (used in) investing activities	(5,272)	26,370
Financing activities:
Net cash provided by (used in) financing activities	0	0
Net change in cash and cash equivalents	21,440	48,464
Cash and Cash Equivalents:
Cash and cash equivalents, beginning of period	7,559	6,620
Cash and cash equivalents, end of period	$ 28,999	$ 55,084

XML

Management's Statement:

3 Months Ended

Mar. 31, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Management's Statement

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 2015 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 March 31, 2016, December 31, 2015 and March 31, 2015 financial information and are of a normal recurring nature. The results of operations for the three months ended March 31, 2016 and March 31, 2015, and our financial condition as of March 31, 2016 and December 31, 2015 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

Leases, ASU 2016-02

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases. This ASU requires lessees to recognize a right-of-use asset and lease liability for all leases with terms of more than 12 months. Lessees are permitted to make an accounting policy election to not recognize the asset and liability for leases with a term of 12 months or less. 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 ASC is largely unchanged from the previous accounting standard. In addition, the ASU expands the disclosure requirements of lease arrangements. Lessees and lessors will use a modified retrospective transition approach, which includes a number of practical expedients. The guidance is effective for the Company beginning after December 15, 2019. Early adoption is permitted. We are currently assessing the impact that adoption of ASU 2016-02 will have on our financial position, results of operations or cash flows.

Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent), ASU 2015-07

On May 1, 2015, the FASB issued ASU 2015-07, Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent).The ASU removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient and also removes certain disclosure requirements. The new requirements were effective for us beginning January 1, 2016 and will be applied retrospectively to all periods presented, in our 2016 Form 10-K. This ASU will not materially affect our financial statements and disclosures, but will change certain presentation and disclosure of the fair value of certain plan assets in our pension and other postretirement benefit plan disclosures in our 2016 Form 10-K, for all periods presented.

Simplifying the Presentation of Debt Issuance Costs, ASU 2015-03

In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. Debt issuance costs related to a recognized debt liability will be presented on the balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as an asset. Amortization of these costs will continue to be reported as interest expense. ASU 2015-03 is effective for annual and interim reporting periods beginning after December 15, 2015. We adopted ASU 2015-03 in the first quarter of 2016 on a retrospective basis. As of March 31, 2016, we have presented the debt issuance costs, previously reported in other assets, as direct deductions from the carrying amount of long-term debt. The implementation of this standard resulted in reductions of other non-current assets and long-term debt of $3.1 million as of December 31, 2015. Adoption of ASU 2015-03 did not have a material impact on our financial position.

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. On July 9, 2015, FASB voted to defer the effective date of ASU 2014-09 by one year. The proposed guidance would be effective for annual and interim reporting periods beginning after December 15, 2017 and early adoption is permitted. We are currently evaluating the impact of adoption, if any, that ASU 2014-09 will have on our financial position, results of operations or cash flows.

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Accounts Receivable and Allowance For Doubtful Accounts:

3 Months Ended

Mar. 31, 2016

Accounts Receivable, Net [Abstract]

Accounts Receivable and Allowance for Doubtful Accounts

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:

	March 31, 2016			December 31, 2015
Accounts receivable trade	$	15,777		$	15,268
Unbilled revenues	11,619			12,795
Allowance for doubtful accounts	(256		)	(207		)
Receivables - customers, net	$	27,140		$	27,856

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Regulatory Accounting:

3 Months Ended

Mar. 31, 2016

Regulated Operations [Abstract]

Regulatory Assets and Liabilities

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:

	Recovery/Amortization Period (in years)	March 31, 2016		December 31, 2015
Regulatory assets:
Unamortized loss on reacquired debt (a)	9	$	2,025	$	2,096
AFUDC (b)	45	8,719		8,571
Employee benefit plans (c)	12	20,866		20,866
Deferred energy and fuel cost adjustments - current (a)	Less than 1 year	21,493		19,875
Flow through accounting (a)	35	12,412		12,104
Decommissioning costs, net of amortization(b)	10	13,317		13,686
Other regulatory assets (a)(d)	2	10,843		8,615
Total regulatory assets		$	89,675	$	85,813

Regulatory liabilities:
Cost of removal for utility plant (a)	53	$	39,157	$	38,131
Employee benefit plans (c)	12	12,616		12,616
Other regulatory liabilities	13	906		836
Total regulatory liabilities		$	52,679	$	51,583

____________________

(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, respectively.

(d) Includes approximately $7.0 million and $5.0 million of vegetation management expenses at March 31, 2016 and December 31, 2015, respectively, for which we are allowed a rate of return.

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Related Party Transactions:

3 Months Ended

Mar. 31, 2016

Related Party Transactions [Abstract]

Related Party Transactions Disclosure

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:

	March 31, 2016		December 31, 2015
Receivables - affiliates	$	8,391	$	5,747
Accounts payable - affiliates	$	27,148	$	30,032

Money Pool Notes Receivable and Notes Payable

We have entered into a Utility Money Pool Agreement (the “Agreement”) with BHC, Black Hills Service Company 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 March 31, 2016, the average cost of borrowing under the Utility Money Pool was 1.62%.

We had the following balances with the Utility Money Pool (in thousands) as of:

	March 31, 2016		December 31, 2015
Money pool notes receivable, net	$	50,630	$	76,813

Our net interest income (expense) relating to balances with the Utility Money Pool was as follows (in thousands):

	Three Months Ended March 31,
	2016		2015
Net interest income (expense)	$	278	$	258

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

	Three Months Ended March 31,
	2016		2015
Revenue:
Energy sold to Cheyenne Light	$	661	$	326
Rent from electric properties	$	1,213	$	1,124
Fuel and purchased power:
Purchases of coal from WRDC	$	4,796	$	4,045
Purchase of excess energy from Cheyenne Light	$	55	$	476
Purchase of renewable wind energy from Cheyenne Light - Happy Jack	$	664	$	549
Purchase of renewable wind energy from Cheyenne Light - Silver Sage	$	1,127	$	936
Gas transportation service agreement:
Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation	$	136	$	103
Corporate support:
Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings	$	6,721	$	7,033

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Employee Benefit Plans:

3 Months Ended

Mar. 31, 2016

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Employee Benefit Plans Disclosure

EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plan

Beginning in 2016, we changed the method used to estimate the service and interest cost components of the net periodic pension, supplemental non-qualified defined benefit and other postretirement benefit costs. The new method uses the spot yield curve approach to estimate the service and interest costs by applying the specific spot rates along the yield curve used to determine the benefit obligations to relevant projected cash outflows. Previously, those costs were determined using a single weighted-average discount rate. The change does not affect the measurement of the total benefit obligations as the change in service and interest costs offsets the actuarial gains and losses recorded in other comprehensive income. The new method provides a more precise measure of interest and service costs by improving the correlation between the projected benefit cash flows and the discrete spot yield curve rates. We accounted for this change as a change in estimate prospectively beginning in the first quarter of 2016. The discount rates used to measure the 2016 service costs are 4.81%, 4.88% and 4.18% for pension, supplemental non-qualified defined benefit and other postretirement benefit costs, respectively. The discount rates used to measure the 2016 interest costs are 3.90%, 3.82% and 3.17% for pension, supplemental non-qualified defined benefit and other postretirement benefit costs, respectively. The previous method would have used a discount rate for both service and interest costs of 4.63% for pension, 4.50% for supplemental non-qualified defined benefit and 4.03% for other postretirement benefit costs. The decrease in the 2016 service and interest costs is approximately $0.5 million, $0.3 million and $0.1 million for the pension, supplemental non-qualified defined benefit and other postretirement benefit costs, respectively, as compared to the previous method.

The components of net periodic benefit cost for the Defined Benefit Pension Plan were as follows (in thousands):

	Three Months Ended March 31,
	2016			2015
Service cost	$	151		$	199
Interest cost	625			739
Expected return on plan assets	(908		)	(984		)
Prior service cost	11			11
Net loss (gain)	499			549
Net periodic benefit cost	$	378		$	514

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 March 31,
	2016			2015
Service cost	$	51		$	58
Interest cost	47			54
Prior service cost (benefit)	(84		)	(84		)
Net periodic benefit cost	$	14		$	28

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 March 31,
	2016		2015
Interest cost	$	30	$	36
Net loss (gain)	21		23
Net periodic benefit cost	$	51	$	59

Contributions

We anticipate we will make contributions to the benefit plans during 2016 and 2017. Contributions to the Defined Benefit 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 Three Months Ended March 31, 2016		Remaining Anticipated Contributions for 2016		Anticipated Contributions for 2017
Defined Benefit Pension Plan	$	—	$	1,638	$	1,615
Defined Benefit Postretirement Healthcare Plan	$	155	$	464	$	509
Supplemental Non-qualified Defined Benefit Plans	$	54	$	162	$	248

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Fair Value of Financial Instruments:

3 Months Ended

Mar. 31, 2016

Fair Value Disclosures [Abstract]

Fair Value of Financial Instruments

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 2015 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:

	March 31, 2016				December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents (a)	$	28,999	$	28,999	$	7,559	$	7,559
Long-term debt, including current maturities (b)	$	339,651	$	429,059	$	342,756	$	404,864

_________________

(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.

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Supplemental Disclosure of Cash Flow Information:

3 Months Ended

Mar. 31, 2016

Supplemental Cash Flow Information [Abstract]

Cash Flow, Supplemental Disclosures

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

Three months ended March 31,	2016			2015
	(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment acquired with accrued liabilities	$	5,087		$	2,042
Non-cash (decrease) to money pool notes receivable, net	$	(12,500	)	$	—
Non-cash dividend to Parent	$	12,500		$	—
Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(2,989	)	$	(2,718	)
Income taxes, net	$	—		$	—

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Commitment and Contingencies:

3 Months Ended

Mar. 31, 2016

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies Disclosure

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 2015 Annual Report on Form 10-K.

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Accounts Receivable and Allowance For Doubtful Accounts: Accounts Receivable and Allowance For Doubtful Accounts (Tables)

3 Months Ended

Mar. 31, 2016

Accounts Receivable, Net [Abstract]

Schedule of Accounts Receivable

Following is a summary of Receivables - customers, net included in the accompanying Condensed Balance Sheets (in thousands) as of:

	March 31, 2016			December 31, 2015
Accounts receivable trade	$	15,777		$	15,268
Unbilled revenues	11,619			12,795
Allowance for doubtful accounts	(256		)	(207		)
Receivables - customers, net	$	27,140		$	27,856

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Regulatory Accounting: Regulatory Accounting (Tables)

3 Months Ended

Mar. 31, 2016

Regulated Operations [Abstract]

Schedule of Regulatory Assets

Our regulatory assets and liabilities were as follows (in thousands) as of:

	Recovery/Amortization Period (in years)	March 31, 2016		December 31, 2015
Regulatory assets:
Unamortized loss on reacquired debt (a)	9	$	2,025	$	2,096
AFUDC (b)	45	8,719		8,571
Employee benefit plans (c)	12	20,866		20,866
Deferred energy and fuel cost adjustments - current (a)	Less than 1 year	21,493		19,875
Flow through accounting (a)	35	12,412		12,104
Decommissioning costs, net of amortization(b)	10	13,317		13,686
Other regulatory assets (a)(d)	2	10,843		8,615
Total regulatory assets		$	89,675	$	85,813

Schedule of Regulatory Liabilities

Regulatory liabilities:
Cost of removal for utility plant (a)	53	$	39,157	$	38,131
Employee benefit plans (c)	12	12,616		12,616
Other regulatory liabilities	13	906		836
Total regulatory liabilities		$	52,679	$	51,583

____________________

(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, respectively.

(d) Includes approximately $7.0 million and $5.0 million of vegetation management expenses at March 31, 2016 and December 31, 2015, respectively, for which we are allowed a rate of return.

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Related Party Transactions: Related Party Transactions (Tables)

3 Months Ended

Mar. 31, 2016

Related Party Transactions [Abstract]

Schedule of Related Party Accounts Receivable and Payable

The balances were as follows (in thousands) as of:

	March 31, 2016		December 31, 2015
Receivables - affiliates	$	8,391	$	5,747
Accounts payable - affiliates	$	27,148	$	30,032

Schedule of Related Party Notes

We had the following balances with the Utility Money Pool (in thousands) as of:

	March 31, 2016		December 31, 2015
Money pool notes receivable, net	$	50,630	$	76,813

Schedule of Related Party Interest Income Expense

Our net interest income (expense) relating to balances with the Utility Money Pool was as follows (in thousands):

	Three Months Ended March 31,
	2016		2015
Net interest income (expense)	$	278	$	258

Schedule of Revenues and Purchases from Related Parties

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

	Three Months Ended March 31,
	2016		2015
Revenue:
Energy sold to Cheyenne Light	$	661	$	326
Rent from electric properties	$	1,213	$	1,124
Fuel and purchased power:
Purchases of coal from WRDC	$	4,796	$	4,045
Purchase of excess energy from Cheyenne Light	$	55	$	476
Purchase of renewable wind energy from Cheyenne Light - Happy Jack	$	664	$	549
Purchase of renewable wind energy from Cheyenne Light - Silver Sage	$	1,127	$	936
Gas transportation service agreement:
Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation	$	136	$	103
Corporate support:
Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings	$	6,721	$	7,033

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Employee Benefit Plans: Employee Benefit Plans (Tables)

3 Months Ended

Mar. 31, 2016

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Schedule of Net Benefit Costs

The components of net periodic benefit cost for the Defined Benefit Pension Plan were as follows (in thousands):

	Three Months Ended March 31,
	2016			2015
Service cost	$	151		$	199
Interest cost	625			739
Expected return on plan assets	(908		)	(984		)
Prior service cost	11			11
Net loss (gain)	499			549
Net periodic benefit cost	$	378		$	514

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 March 31,
	2016			2015
Service cost	$	51		$	58
Interest cost	47			54
Prior service cost (benefit)	(84		)	(84		)
Net periodic benefit cost	$	14		$	28

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 March 31,
	2016		2015
Interest cost	$	30	$	36
Net loss (gain)	21		23
Net periodic benefit cost	$	51	$	59

Schedule of Defined Benefit Plans Contributions

Contributions and anticipated contributions are as follows (in thousands):

	Contributions Three Months Ended March 31, 2016		Remaining Anticipated Contributions for 2016		Anticipated Contributions for 2017
Defined Benefit Pension Plan	$	—	$	1,638	$	1,615
Defined Benefit Postretirement Healthcare Plan	$	155	$	464	$	509
Supplemental Non-qualified Defined Benefit Plans	$	54	$	162	$	248

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Fair Value of Financial Instruments: Fair Value of Financial Instruments(Tables)

3 Months Ended

Mar. 31, 2016

Fair Value Disclosures [Abstract]

Schedule of Fair Value of Financial Instruments

The estimated fair values of our financial instruments were as follows (in thousands) as of:

	March 31, 2016				December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents (a)	$	28,999	$	28,999	$	7,559	$	7,559
Long-term debt, including current maturities (b)	$	339,651	$	429,059	$	342,756	$	404,864

_________________

(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.

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Supplemental Disclosure of Cash Flow Information: Supplemental Disclosures of Cash Flow Information (Tables)

3 Months Ended

Mar. 31, 2016

Supplemental Cash Flow Information [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

Three months ended March 31,	2016			2015
	(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment acquired with accrued liabilities	$	5,087		$	2,042
Non-cash (decrease) to money pool notes receivable, net	$	(12,500	)	$	—
Non-cash dividend to Parent	$	12,500		$	—
Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(2,989	)	$	(2,718	)
Income taxes, net	$	—		$	—

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Management's Statement: Simplifying the Presentation of Debt Issuance Costs (Details) $ in Millions	Dec. 31, 2015 USD ($)
Other Noncurrent Liabilities [Member]
New Accounting Pronouncement - Deferred Financing Costs	$ 3.1

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Accounts Receivable and Allowance For Doubtful Accounts: Accounts Receivable and Allowance For Doubtful Accounts (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Accounts Receivable [Line Items]
Allowance for doubtful accounts	$ (256)	$ (207)
Receivables - customers, net	27,140	27,856
Billed Revenues [Member]
Accounts Receivable [Line Items]
Accounts receivable, trade	15,777	15,268
Unbilled Revenues [Member]
Accounts Receivable [Line Items]
Accounts receivable, trade	$ 11,619	$ 12,795

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Regulatory Accounting: Regulatory Accounting (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2016	Dec. 31, 2015
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets		$ 89,675	$ 85,813
Regulatory Liabilities		$ 52,679	51,583
Cost of removal for utility plant [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities Amortization Period, Unclassified		53 years
Regulatory Liabilities	[1]	$ 39,157	38,131
Employee benefit plans [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities Amortization Period, Unclassified		12 years
Regulatory Liabilities	[2]	$ 12,616	12,616
Other regulatory liabilities [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities Amortization Period, Unclassified		13 years
Regulatory Liabilities		$ 906	836
Unamortized Loss on reacquired debt [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets Amortization Period, Unclassified		9 years
Regulatory Assets	[1]	$ 2,025	2,096
Allowance For Funds Used During Construction [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets Amortization Period, Unclassified		45 years
Regulatory Assets	[3]	$ 8,719	8,571
Employee benefit plans [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets Amortization Period, Unclassified		12 years
Regulatory Assets	[2]	$ 20,866	20,866
Deferred energy and fuel cost adjustments - current [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	[1]	$ 21,493	19,875
Flow through accounting [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets Amortization Period, Unclassified		35 years
Regulatory Assets	[1]	$ 12,412	12,104
Decommissioning costs, net of amortization [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets Amortization Period, Unclassified		10 years
Regulatory Assets		$ 13,317	13,686
Other regulatory assets [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets Amortization Period, Unclassified		2 years
Regulatory Assets	[1],[4]	$ 10,843	8,615
Vegetation Management [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets		$ 7,000	$ 5,000

[1] Recovery of costs, but we are not allowed a rate of return.

[2] 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, respectively.

[3] In addition to recovery of costs, we are allowed a rate of return.

[4] Includes approximately $7.0 million and $5.0 million of vegetation management expenses at March 31, 2016 and December 31, 2015, respectively, for which we are allowed a rate of return.

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Related Party Transactions: Related Party Transactions (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Related Party Transaction [Line Items]
Receivables - affiliates	$ 8,391		$ 5,747
Accounts payable - affiliates	$ 27,148		30,032
Related Party Transaction, Utility Money Pool Interest Rate	1.62%
Money pool notes receivable, net	$ 50,630		$ 76,813
Parent [Member]
Related Party Transaction [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	1.00%
Utility Money Pool [Member]
Related Party Transaction [Line Items]
Net interest income (expense)	$ 278	$ 258
Subsidiary of Common Parent [Member] | Allocated Costs From Related Parties [Member]
Related Party Transaction [Line Items]
Costs and expenses, related parties	6,721	7,033
Subsidiary of Common Parent [Member] | Purchase Of Natural Gas, Cheyenne Light [Member]
Related Party Transaction [Line Items]
Costs and expenses, related parties	136	103
Subsidiary of Common Parent [Member] | Coal, Purchased [Member]
Related Party Transaction [Line Items]
Costs and expenses, related parties	4,796	4,045
Subsidiary of Common Parent [Member] | Purchase of Excess Energy, Cheyenne Light [Member]
Related Party Transaction [Line Items]
Costs and expenses, related parties	55	476
Subsidiary of Common Parent [Member] | Happy Jack Wind Purchase Power Agreeement [Member]
Related Party Transaction [Line Items]
Costs and expenses, related parties	664	549
Subsidiary of Common Parent [Member] | Silver Sage Wind Power Purchase Agreement [Member]
Related Party Transaction [Line Items]
Costs and expenses, related parties	1,127	936
Subsidiary of Common Parent [Member] | Energy sold to Cheyenne Light [Member]
Related Party Transaction [Line Items]
Revenue from related parties	661	326
Subsidiary of Common Parent [Member] | Lease Agreements [Member]
Related Party Transaction [Line Items]
Revenue from related parties	$ 1,213	$ 1,124

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Employee Benefit Plans: Employee Benefit Plans (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Defined Benefit Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Decrease In Interest and Service Costs Resulting From New Spot Method Approach	$ 500
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	151	$ 199
Interest cost	625	739
Expected return on plan assets	(908)	(984)
Prior service cost (benefit)	11	11
Net loss (gain)	499	549
Net periodic benefit cost	378	514
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions made by Employer	0
Remaining Anticipated Contributions for Current Year	1,638
Anticipated Contributions for Next Year	1,615
Defined Benefit Postretirement Healthcare Plan
Defined Benefit Plan Disclosure [Line Items]
Decrease In Interest and Service Costs Resulting From New Spot Method Approach	100
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	51	58
Interest cost	47	54
Prior service cost (benefit)	(84)	(84)
Net periodic benefit cost	14	28
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions made by Employer	155
Remaining Anticipated Contributions for Current Year	464
Anticipated Contributions for Next Year	509
Supplemental Non-qualified Defined Benefit Plans
Defined Benefit Plan Disclosure [Line Items]
Decrease In Interest and Service Costs Resulting From New Spot Method Approach	300
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Interest cost	30	36
Net loss (gain)	21	23
Net periodic benefit cost	51	$ 59
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions made by Employer	54
Remaining Anticipated Contributions for Current Year	162
Anticipated Contributions for Next Year	$ 248
Scenario, Previously Reported [Member] | Defined Benefit Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.63%
Scenario, Previously Reported [Member] | Defined Benefit Postretirement Healthcare Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.03%
Scenario, Previously Reported [Member] | Supplemental Non-qualified Defined Benefit Plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.50%
Service Cost [Member] | Defined Benefit Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.81%
Service Cost [Member] | Defined Benefit Postretirement Healthcare Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.18%
Service Cost [Member] | Supplemental Non-qualified Defined Benefit Plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.88%
Interest Cost [Member] | Defined Benefit Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	3.90%
Interest Cost [Member] | Defined Benefit Postretirement Healthcare Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	3.17%
Interest Cost [Member] | Supplemental Non-qualified Defined Benefit Plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	3.82%

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Fair Value of Financial Instruments: Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands		Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015	Dec. 31, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents, carrying amount		$ 28,999	$ 7,559	$ 55,084	$ 6,620
Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents, carrying amount	[1]	28,999	7,559
Long-term debt, including current maturities, carrying amount	[2]	339,651	342,756
Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents, fair value	[1]	28,999	7,559
Long-term debt, including current maturities, fair value	[2]	$ 429,059	$ 404,864

[1] 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.

[2] 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.

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Supplemental Disclosure of Cash Flow Information: Supplemental Disclosures of Cash Flow Information (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Noncash Investing and Financing Items [Abstract]
Property, plant and equipment acquired with accrued liabilities	$ 5,087	$ 2,042
Interest and Income Taxes Paid Net [Abstract]
Interest paid, (net of amounts capitalized)	(2,989)	(2,718)
Income taxes, net	0	0
Subsidiary of Common Parent [Member]
Noncash Investing and Financing Items [Abstract]
Non-cash (decrease) to money pool notes receivable, net	(12,500)	0
Parent [Member]
Noncash Investing and Financing Items [Abstract]
Non-cash dividend to Parent	$ 12,500	$ 0