UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

Form 10-K



x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, ~~2012~~2013



¨	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 1-07978

BLACK HILLS POWER, INC.



Incorporated in South Dakota		IRS Identification Number 46-0111677
625 Ninth Street, Rapid City, South Dakota 57701

~~Registrant's~~Registrant’s telephone number, including area code: (605) 721-1700

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes x No ¨

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes x No ¨

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 ¨

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 (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files).

Yes x No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of ~~Registrant's~~Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.

This paragraph is not applicable to the Registrant. x

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 ¨ Accelerated filer ¨ Non-accelerated filer x Smaller reporting company ¨

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes ¨ No x

State the aggregate market value of the voting stock held by non-affiliates of the Registrant.

All outstanding shares are held by the ~~Registrant's~~Registrant’s parent company, Black Hills Corporation. Accordingly, the aggregate market value of the voting common stock of the Registrant held by non-affiliates is $0.

Indicate the number of shares outstanding of each of the ~~Registrant's~~Registrant’s classes of common stock, as of the latest practicable date.



Class	Outstanding at ~~February 28, 2013~~January 31, 2014
Common stock, $1.00 par value	23,416,396 shares

Reduced Disclosure

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



TABLE OF CONTENTS

		Page

	GLOSSARY OF TERMS AND ABBREVIATIONS	3

ITEMS 1. and 2.	BUSINESS AND PROPERTIES	5

ITEM 1A.	RISK FACTORS	11

ITEM 1B.	UNRESOLVED STAFF COMMENTS	17

ITEM 3.	LEGAL PROCEEDINGS	17

ITEM 5.	MARKET FOR ~~REGISTRANT'S~~REGISTRANT’S COMMON EQUITY RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	1718

ITEM 7.	~~MANAGEMENT'S~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS	1718

ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	23

ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	5155

ITEM 9A.	CONTROLS AND PROCEDURES	5255

ITEM 9B.	OTHER INFORMATION	5256

ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	5256

ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	5357

	SIGNATURES	5659

	INDEX TO EXHIBITS	5760

GLOSSARY OF TERMS AND ABBREVIATIONS

The following terms and abbreviations appear in the text of this report and have the definitions described below:



AFUDC	Allowance for Funds Used During Construction
AOCI	Accumulated Other Comprehensive Income
ASC	Accounting Standards Codification
ASU	Accounting Standards Update as issued by FASB
Basin Electric	Basin Electric Power Cooperative
BHC	Black Hills Corporation, the Parent of Black Hills Power, Inc.
Black Hills Non-regulated Holdings	Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of BHC
Black Hills Service Company	Black Hills Service Company LLC, a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Utility Holdings	Black Hills Utility Holdings, Inc. a direct, wholly-owned subsidiary of BHC
Black Hills Wyoming	Black Hills Wyoming, LLC, an indirect, wholly-owned subsidiary of Black Hills Electric Generation, Inc., a subsidiary of Black Hills Non-regulated Holdings
Cheyenne Light	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of BHC
Cheyenne Prairie	Cheyenne Prairie Generating Station currently being constructed in Cheyenne, Wyo. by Cheyenne Light and Black Hills Power. Construction is expected to be completed for this 132 MW facility in 2014.
City of Gillette	The City of Gillette, Wyoming, affiliate of the JPB.
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.
CT	Combustion turbine
CPCN	Certificate of Public Convenience and Necessity
DSM	Demand Side Management
ECA	Energy Cost Adjustment -- adjustments that allow us to pass the prudently-incurred cost of fuel and purchased power through to customers.
EPA	United States Environmental Protection Agency
FASB	Financial Accounting Standards Board
FDIC	Federal Depository Insurance Corporation
FERC	Federal Energy Regulatory Commission
Fitch	Fitch Ratings
GAAP	Accounting principles generally accepted in the United States of America
GHG	Greenhouse gas
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.
~~IFRS~~	~~International Financial Reporting Standards~~
IRS	Internal Revenue Service
JPB	Consolidated Wyoming Municipalities Electric Power System Joint Powers Board. The JPB exists for the purpose of, among other things, financing the electrical system of the City of Gillette. The JPB financed the purchase of 23% of the Wygen III power plant for the City of Gillette.
kV	Kilovolt
LIBOR	London Interbank Offered Rate




MAPP	Mid-Continent Area Power Pool
MATS	Utility Mercury and Air Toxics Rules under the United States EPA National Emissions Standards for Hazardous Air Pollutants from Coal and Oil Fired Electric Utility Steam Generating Units
MDU	Montana Dakota Utilities Company
MEAN	Municipal Energy Agency of Nebraska
~~Moody's~~Moody’s	~~Moody's~~Moody’s Investor Services, Inc.
MTPSC	Montana Public Service Commission
MW	Megawatts
MWh	Megawatt-hours
NAN/A	Not Applicable
NOL	Net operating loss
NO_x	Nitrogen oxide
~~NQDC~~PacifiCorp	~~Non-Qualified Deferred Compensation Plan~~PacifiCorp, a wholly owned subsidiary of MidAmerican Energy Holdings Company, itself an affiliate of Berkshire Hathaway
Peak System Load	Peak system load represents the highest point of customer usage for a single hour for the system in total. Our system peaks include demand loads for 100% of plants regardless of joint ownership.
PPA	Power Purchase Agreement
RMSA	Retirement Medical Savings Account
SDPUC	South Dakota Public Utilities Commission
SEC	United States Securities and Exchange Commission
Silver Sage	Silver Sage Windpower, LLC, a subsidiary of Duke Energy Generation Services
SO₂	Sulfur dioxide
S&P	Standard & ~~Poor's~~Poor’s Rating Services
~~System Peak Demand~~	~~System peak demand represents the highest point of customer usage for a single hour for the system in total. Our system peaks include demand loads for 100% of plants regardless of joint ownership.~~
TCA	Transmission Cost Adjustment --- adjustments passed through to the customer based on transmission costs that are higher or lower than the costs approved in the rate case.
Thunder Creek	Thunder Creek Gas Services, LLC
WECC	Western Electricity Coordinating Council
WPSC	Wyoming Public Service Commission
WRDC	Wyodak Resources Development Corporation, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, LLC

PART I

Forward-Looking Information

This Form 10-K 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 7 - Management’s Discussion & Analysis.

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

Any forward-looking statement contained in this document speaks only as of the date on which the statement is made, and the Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which the statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of the factors, nor can it assess the effect of each factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. All forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are expressly qualified by the risk factors and cautionary statements in this Form 10-K, including statements contained within Item 1A - Risk Factors.

~~PART I~~

ITEMS 1 and 2. BUSINESS AND PROPERTIES

General

Black Hills Power ("(“the Company,~~" "we," "us"~~” “we,” “us” and ~~"our"~~“our”) is a regulated electric utility incorporated in South Dakota and serving customers in South Dakota, Wyoming and Montana. We began providing electric utility service in 1941. We are a wholly-owned subsidiary of the publicly traded Black Hills Corporation. Engaging in the generation, transmission and distribution of electricity provides a solid foundation of revenues, earnings and cash flow that support our capital expenditures, dividends to our Parent, and our overall performance and growth.

As of December 31, ~~2012~~2013, our ownership interests in electric generation plants were as follows:


Unit(1)	Fuel Type	Location	Ownership Interest %	Owned Capacity (MW)	Year Installed	Fuel Type	Location	Ownership Interest %	Owned Capacity (MW)	Year Installed
Wygen III⁽¹⁾⁽²⁾	Coal	Gillette, WY	52%	57.2	2010	Coal	Gillette, WY	52%	57.2	2010
Neil Simpson II	Coal	Gillette, WY	100%	90.0	1995	Coal	Gillette, WY	100%	90.0	1995
Wyodak ⁽²⁾⁽³⁾	Coal	Gillette, WY	20%	72.4	1978	Coal	Gillette, WY	20%	72.4	1978
Osage ⁽³⁾⁽⁴⁾	Coal	Osage, WY	100%	34.5	1948-1952	Coal	Osage, WY	100%	34.5	1948-1952
Ben French⁽³⁾⁽⁴⁾	Coal	Rapid City, SD	100%	25.0	1960	Coal	Rapid City, SD	100%	25.0	1960
Neil Simpson I⁽³⁾⁽⁴⁾	Coal	Gillette, WY	100%	21.8	1969	Coal	Gillette, WY	100%	21.8	1969
Neil Simpson CT	Gas	Gillette, WY	100%	40.0	2000	Gas	Gillette, WY	100%	40.0	2000
Lange CT	Gas	Rapid City, SD	100%	40.0	2002	Gas	Rapid City, SD	100%	40.0	2002
Ben French Diesel #1-5	Oil	Rapid City, SD	100%	10.0	1965	Oil	Rapid City, SD	100%	10.0	1965
Ben French CTs #1-4	Gas/Oil	Rapid City, SD	100%	80.0	1977-1979	Gas/Oil	Rapid City, SD	100%	80.0	1977-1979
				470.9					470.9

_______________________


(1)	Construction of a gas-fired power generation facility is underway to support the customers of Black Hills Power. The facility will include one combined-cycle, 95 megawatt unit that will be jointly owned by Cheyenne Light (40 MW) and Black Hills Power (55 MW). This facility is expected to be completed in the fourth quarter of 2014.


(2)	We operate Wygen III, a 110 MW mine-mouth coal-fired power plant and own a 52% interest in the facility. MDU owns a 25% interest and the City of Gillette owns the remaining 23% interest. WRDC furnishes all of the coal fuel supply for the plant.


~~(2)~~(3)	Wyodak is a 362 MW mine-mouth coal-fired power plant owned 80% by PacifiCorp and 20% by us. This baseload plant is operated by PacifiCorp and WRDC furnishes all of the coal fuel supply for 100% of the plant.

~~(3)~~(4)

Operations at Osage were suspended October 1, 2010 and Ben French were suspended on August 31, 2012 due to the availability of more economical generation alternatives when evaluating costs to retrofit these plants to comply with environmental standards, including EPA regulations. Osage, Ben French and Neil Simpson I will be retired on or before March 21, 2014, the effective compliance date of the EPA Industrial and Commercial Boiler Regulations for Area Sources of Hazardous Air Pollutants regulations. While the net book value of these plants is estimated to be insignificant at the time of retirement, we would reasonably expect any remaining value to be recovered through future ~~rates.~~rates and costs will be deferred as Regulatory assets on the accompanying Balance Sheets.

Distribution and Transmission. Our distribution and transmission system serves approximately 69,000 electric customers, with an electric transmission system of ~~592~~1,179 miles of high voltage lines (greater than 69 ~~KV)~~kV) and ~~3,059~~2,462 miles of lower voltage lines. In addition, we jointly own 4744 miles of high voltage lines with Basin Electric. Our service territory covers areas with a strong and stable economic base including western South Dakota, northeastern Wyoming and southeastern Montana. Approximately 90% of our retail electric revenues in ~~2012~~2013 were generated in South Dakota. We are subject to state regulation by the SDPUC, the WPSC and the MTPSC.

The following are characteristics of our distribution and transmission business:

We have a diverse customer and revenue base. Our revenue mix for the year ended December 31, ~~2012~~2013 was comprised of ~~30%~~32% commercial, ~~24%~~25% residential, 8%9% contract wholesale, ~~13%~~12% wholesale off-system, 11% industrial and ~~14%~~12% municipal and other revenue.

We own 35% and Basin Electric owns 65% of a DC transmission tie that interconnects the Western and Eastern transmission grids, which are independently-operated transmission grids serving the ~~western~~Western United States and the Eastern United States, respectively. This transmission tie provides transmission access to both the WECC region in the West and the MAPP region in the East. Our system is located in the WECC region. The total transfer capacity of the tie is 200 MW from West to East and 200 MW from East to West. This transmission tie allows us to buy and sell energy in the Eastern interconnection without having to isolate and physically reconnect load or generation between the two electrical transmission grids. The transmission tie accommodates scheduling transactions in both directions simultaneously. This transfer capability provides additional opportunity to sell our excess generation or to make economic purchases to serve our native load and our contract obligations, and to take advantage of the power price differentials between the two electric grids. Additionally, our system is capable of directly interconnecting up to 80 MW of generation or load to the Eastern transmission grid. Transmission constraints within the MAPP transmission system may limit the amount of capacity that may be directly interconnected to the Eastern system at any given time.

We have firm point-to-point transmission access to deliver up to 50 MW of power on ~~PacifiCorp's~~PacifiCorp’s transmission system to wholesale customers in the Western region through 2023.

We have firm network transmission access to deliver power on ~~PacifiCorp's~~PacifiCorp’s system to Sheridan, Wyoming to serve our power sales contract with MDU through 2017, with the right to renew pursuant to the terms of ~~PacifiCorp's~~PacifiCorp’s transmission tariff.

Power Sales Agreements. We sell a portion of our current load under long-term contracts. Our key contracts include:

MDU owns a 25% ownership interest in Wygen ~~III's~~III’s net generating capacity for the life of the plant. During periods of reduced production at Wygen III, or during periods when Wygen III is off-line, we will provide MDU with 25 MW from our other generation facilities or from system purchases with reimbursement of costs by MDU.

The City of Gillette owns a 23% ownership interest in Wygen ~~III's~~III’s net generating capacity for the life of the plant. During periods of reduced production at Wygen III, or during periods when Wygen III is off-line, we will provide the City of Gillette with its first 23 MW from our other generation facilities or from system purchases with reimbursement of costs by the City of Gillette. Under this agreement we will also provide the City of Gillette their operating component of spinning reserves.

•An agreement under which we supply 20 MW of energy and capacity to MEAN under a contract that expires in 2023. This contract is unit-contingent based on the availability of our Neil Simpson II and Wygen III plants. The unit-contingent capacity amounts from Wygen III and Neil Simpson II are as follows:



~~2013-2017~~2014-2017	20 MW - 10 MW contingent on Wygen III and 10 MW contingent on Neil Simpson II
2018-2019	15 MW - 10 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II
2020-2021	12 MW - 6 MW contingent on Wygen III and 6 MW contingent on Neil Simpson II
2022-2023	10 MW - 5 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II.

A ~~five-year~~ PPA with MEAN whereby MEAN will purchase 5 MW of unit-contingent capacity from Neil Simpson II and 5 MW of unit-contingent capacity from Wygen III through May 2015.

Regulated Power Plants and Purchased Power. Our electric load is primarily served by our generating facilities in South Dakota and Wyoming, which provide approximately 471 MW of generating capacity, with the balance supplied under purchased power and capacity contracts. We generated approximately ~~52%~~56% of our energy requirements in ~~2012~~2013 and purchased approximately ~~48%~~44% which was supplied under the following contracts:

A PPA with PacifiCorp expiring in 2023, whereby we purchase 50 MW of coal-fired baseload power.

A ~~20-year~~ PPA with Cheyenne Light expiring in 2028, under which we will purchase up to 14.7 MW of wind energy through Cheyenne ~~Light's~~Light’s agreement with Happy Jack.

A ~~20-year~~ PPA with Cheyenne Light expiring in 2029, under which we will purchase up to 20 MW of wind energy through Cheyenne ~~Light's~~Light’s agreement with Silver Sage.

A Generation Dispatch Agreement with Cheyenne Light that requires us to purchase all of Cheyenne ~~Light's~~Light’s excess energy.

Since 1995, we have been a net producer of energy. Our ~~2012~~2013 winter peak system load was ~~362~~403 MW and our ~~2012~~2013 summer peak system load was ~~449~~422 MW. None of our generation is restricted by hours of operation, thereby providing us the ability to generate power to meet demand whenever necessary and economically feasible. We have historically optimized the utilization of our power supply resources by selling wholesale power to other utilities and to power marketers in the spot market, and through short-term sales contracts primarily in the WECC and MAPP regions. Our 301 MW of low-cost, coal-fired resources supports most of our native load requirements and positions us for wholesale off-system sales.

Operating Agreements

Shared Services Agreement- ~~During 2010, we entered into~~We have a shared services agreement with Cheyenne Light and Black Hills Wyoming whereby each entity charges for the use of assets and the performance of services being used by, or performed for, an affiliate entity. The revenues and expenses associated with these assets are included in rate base.

Jointly Owned Facilities - Black Hills Power, the City of Gillette and MDU are parties to a joint ownership agreement, whereby Black Hills Power charges the City of Gillette and MDU for administrative services, plant operations and maintenance for their share of the Wygen III generating facility for the life of the plant.

Regulations

Rate Regulation

The following table illustrates certain enacted regulatory information with respect to the states in which we operate:

State

Authorized Rate of Return on Equity

Authorized Return on Rate Base

Capital Structure Debt/Equity

Effective Date

Other Tariffs, Riders and Rate Matters

Percentage of Off-System Sale Profits Shared with Rate Payers

Authorized Rate of Return on Equity

Authorized Return on Rate Base

Capital Structure Debt/Equity

Effective Date

Other Tariffs, Riders and Rate Matters

Percentage of Off-System Sale Profits Shared with Customers

Global Settlement

8.60%

Global Settlement

4/2010

ECA,TCA, Energy Efficiency Cost Recovery/ DSM

65%

Global Settlement

7.93%

Global Settlement

6/2013

ECA,TCA, Energy Efficiency Cost Recovery/ DSM

65%

8.16%

6/2011

Environmental Improvement Cost Recovery Adjustment Tariff

8.16%

6/2011

Environmental Improvement Cost Recovery Adjustment Tariff

10.5%

8.60%

48%/52%

6/2010

TCA, ECA

10.5%

8.60%

48%/52%

6/2010

TCA, ECA

50% subject to symmetrical deadband

15.0%

11.73%

47%/53%

1983

ECA

15.0%

11.73%

47%/53%

1983

ECA

FERC

10.8%

9.12%

43%/57%

2/2009

FERC Transmission Tariff

10.8%

9.12%

43%/57%

2/2009

FERC Transmission Tariff

Rates for our retail electric service are subject to regulation by the SDPUC for customers in South Dakota, the WPSC for customers in Wyoming and the MTPSC for customers in Montana. Any changes in retail rates are subject to approval by the respective regulatory body. We have rate adjustment mechanisms in Montana and South Dakota which provide for pass-through of certain costs related to the purchase, production and/or transmission of electricity. We are also subject to the jurisdiction of FERC with respect to accounting practices and wholesale electricity sales. We have been granted market-based rate authority by FERC and are not required to file cost-based tariffs for wholesale electric rates. Rates charged by us for use of our transmission system are subject to regulation by FERC.

In ~~October 2012,~~September 2013, the ~~WPSC~~SDPUC approved Cheyenne Prairie’s construction financing rider effective April 1, 2013 which allows for recovery of construction financing costs from customers during the construction period in lieu of traditional AFUDC. The rider ~~was implemented November 1, 2012 and will allow Cheyenne Light and~~allows Black Hills Power to ~~each~~earn and collect a rate of return during the construction period on the total project cost that relates to South Dakota customers. This rider is similar to the rider approved by WPSC effective November 1, 2012 which allows Black Hills Power to earn and collect a rate of return during the construction period on approximately ~~60% share~~60 percent of the total project cost ~~relating~~that relates to ~~our~~ Wyoming ~~customers, while also saving customers money over the long-term. This will increase~~customers. These riders increased gross margin by approximately ~~$0.3 million and $0.4~~$2.7 million in ~~2013 and 2014, respectively.~~2013.

In South Dakota, Wyoming and Montana, we have cost adjustment mechanisms that allow us to pass to our customers the prudently-incurred cost of fuel and purchased power.

In South Dakota ~~beginning April 1, 2010,~~ we have an annual adjustment clause which provides for the direct recovery of increased fuel and purchased power incurred to serve South Dakota customers. Additionally, ~~as of April 1, 2010,~~ the ECA ~~clause was modified in the rate case settlement to contain~~contains an off-system sales sharing mechanism in which South Dakota customers ~~will~~ receive a credit equal to ~~65%~~65 percent of off-system power marketing operating income. The modification also adjusts the methodology to directly assign renewable resources and firm purchases to the customer load. In Wyoming ~~beginning June 1, 2010~~has a similar Fuel and Purchased Power Cost ~~Adjustment was instituted.~~Adjustment.

In South Dakota we have an approved annual Environmental Improvement Cost Recovery Adjustment tariff that went into effect June 1, 2011 and recovers costs associated with generation plant environmental improvements.

We have an approved FERC Transmission Tariff based on a formulaic approach that determines the revenue component of Black Hills Power’s open access transmission tariff. The revenue requirement is based on an equity return of 10.8%, a capital structure of 57% equity and 43% debt and a return on rate base which is adjusted annually.

Rate Matters

South Dakota

In January 2014, Black Hills Power filed a rate case with the WPSC requesting an electric revenue increase of $2.8 million to recover investment in Cheyenne Prairie, existing infrastructure and increasing operating costs. The filing seeks a return on equity of 10.25% and a capital structure of 53% equity and 47% debt.

In December 2012, we filed a rate case with the SDPUC requesting an electric revenue increase of $13.7 million, or 9.94%, to recover investment in distribution and transmission lines, generation plant upgrades, environmental compliance and increased operating costs. On September 17, 2013, the SDPUC approved a rate increase of $8.8 million, or 6.4%, effective June 16, 2013.

Power Plant Suspension/Retirements

~~On August 6, 2012, we announced that in~~In order to comply with environmental regulations, including the new EPA Industrial &and Commercial Boiler Regulations for Area Sources of Hazardous Air Pollutants regulations, operations at our 25 MW coal-fired Ben French power plant were suspended as of August 31, 2012. Operations at our 35 MW coal-fired Osage power plant were suspended as of October 1, 2010. These plants as well as our 22 MW coal-fired plant Neil Simpson I will be retired on or before March 21, 2014. We intend to operate Neil Simpson I until the planned retirement date.

Cheyenne Prairie

As a result of the planned plant retirements for some of our older coal-fired power plants discussed above, Cheyenne Light and Black Hills Power filed a joint CPCN to construct a new $222 million, 132 MW natural gas-fired electric generation facility in Cheyenne, Wyoming. The facility will include construction of one simple-cycle, 37 MW combustion turbine that will be wholly owned by Cheyenne Light and one combined cycle 95 MW unit that will be jointly owned by Cheyenne Light (40 MW) and Black Hills Power (55 MW).

~~Cheyenne Light and Black Hills Power received final approvals and permits for Cheyenne Prairie.~~ The ~~WPSC approved the CPCN on July 31, 2012 authorizing the construction, operation and maintenance of this new generating facility. The State of Wyoming issued the air permit for the~~ project on August 31, 2012 and the EPA issued the greenhouse gas air permit on September 27, 2012. Upon receipt of the final permit, the major equipment for the project was ordered. Commencement of construction for the new plant is expected to be placed into service in ~~spring 2013 with commercial operation in~~the fourth quarter of 2014.

~~South Dakota~~

In December 2012, we filed a rate case with the SDPUC requesting an electric revenue increase of $13.7 million, or 9.94%, to recover investment in distribution and transmission lines, generation plant upgrades, environmental compliance and increased operating costs. We have requested an effective date of April 1, 2013 and a decision is anticipated during the third quarter of 2013. If the SDPUC has not reached a decision within 180 days, interim rates will go into effect June 16, 2013.

We filed a request with the SDPUC to use a construction financing rider during the construction of Cheyenne Prairie in lieu of traditional AFUDC. This rider ~~would be~~is similar to the one approved by the WPSC for Cheyenne Light and Black Hills ~~Power's~~Power for Wyoming ~~customers.~~customers in 2012. On January 17, 2013, the SDPUC approved a stipulation with interim rates effective April 1, 2013 ~~subject to refund.~~and on Sept. 17, 2013, the SDPUC approved the construction financing rider. The rider ~~will allow us~~allows Black Hills Power to earn and collect a rate of return during the construction period on ~~our~~its approximately ~~40 percent~~40% share of the total project cost ~~relating~~that relates to ~~our~~ South Dakota customers, while also saving customers money over the long-term. If approved, this will increase gross margin by approximately $3.6 million and $5.6 million in 2013 and 2014, respectively. We anticipate a final ruling by the SDPUC on this rider during the third quarter of 2013.customers.

State Regulation

Certain states where we conduct electric utility operations have adopted renewable energy portfolio standards that require or encourage us to source, by a certain future date, a minimum percentage of the electricity delivered to customers from renewable energy generation facilities. At December 31, ~~2012~~2013, we were subject to the following renewable energy portfolio standards or objectives:

South Dakota. South Dakota has adopted a renewable portfolio objective that encourages, but does not mandate utilities to generate, or cause to be generated, at least 10% of their retail electricity supply from renewable energy sources by 2015.

Montana. In 2005 Montana established a renewable portfolio standard that requires public utilities to obtain a percentage of their retail electricity sales from eligible renewable resources. In March 2013, we filed a petition with the MPSC requesting a waiver of the renewable portfolio standards primarily due to exceeding the applicable “cost cap” included in the standards. However, in March 2013, the Montana Legislature adopted legislation that excluded Black Hills Power from all renewable portfolio standard requirements under Senate Bill 164, primarily due to the very low number of customers we have in Montana and the relatively high cost of meeting the renewable requirements.

Wyoming. Wyoming currently has no renewable energy portfolio standard.

Absent a specific renewable energy mandate in South Dakota, our current strategy is to prudently incorporate renewable energy into our resource supply, seeking to minimize associated rate increases for our utility customers.

~~Montana~~. Montana established a renewable portfolio standard that requires us to obtain a percentage of our retail electric sales in Montana from eligible renewable resources according to the following schedule: (i) 10% for compliance years through 2014 and (ii) 15% for compliance year 2015 and thereafter. Utilities can meet this standard by entering into long-term purchase contracts for electricity bundled with renewable-energy credits, by purchasing the renewable-energy credits separately, or by a combination of both. The law includes cost caps that limit the additional cost utilities must pay for renewable energy and allows cost recovery from ratepayers for contracts pre-approved by the MTPSC. We are currently in compliance with applicable standards and our current strategy is to incorporate renewable energy as required to comply with the standard.

~~Wyoming. Wyoming is exploring the implementation of renewable energy portfolio standards but has not currently adopted standards.~~

Mandatory portfolio standards have increased, and may continue to increase the power supply costs of our electric utility operations. Although we will seek to recover these higher costs in rates, we can provide no assurance that we will be able to secure full recovery of the costs we pay to be in compliance with standards or objectives. We cannot at this time reasonably forecast the potential costs associated with any new renewable energy standards that have been or may be proposed at the federal or state level.

Environmental Regulations

We are subject to numerous federal, state and local laws and regulations relating to the protection of the environment and the safety and health of personnel and the public. These laws and regulations affect a broad range of our utility activities, and generally regulate: (i) the protection of air and water quality; (ii) the identification, generation, storage, handling, transportation, disposal, record-keeping, labeling, reporting of, and emergency response in connection with hazardous and toxic materials and wastes, including asbestos; and (iii) the protection of plant and animal species and minimization of noise emissions. We have incurred, and expect to incur, capital, operating and maintenance costs for the operations of our plants to comply with these laws and regulations. While the requirements are evolving, it is virtually certain that environmental requirements placed on the operations will continue to be more restrictive.

In 2011, the EPA issued the Industrial and Commercial Boiler Regulations for Area Sources of Hazardous Air Pollutants, with updates on December 21, 2012, which impose emission limits, fuel requirements and monitoring requirements. The rule has a compliance deadline of March 21, 2014. In anticipation of this rule and our evaluation of costs to retrofit these plants, we suspended operations at the Osage plant inon October 1, 2010 and as a result of this rule, we suspended operations at the Ben French facility on August 31, 2012 with plans to retire Ben French, Osage and Neil Simpson I on or before March 21, 2014.

On February 16, 2012, the EPA signed the National Emission Standards for Hazardous Air Pollutants from Coal and Oil Fired Electric Utility Steam Generating Units (MATS), which became effective on April 16, 2012. This rule imposes requirements for mercury, acid gases, metals and other pollutants. Affected units ~~will~~ have ~~three years from the rule effective date to be in~~a compliance deadline of April 16, 2015, with a pathway defined to apply for a one year extension due to certain very limited circumstances. The current state air ~~permits~~permit for Wygen III ~~provide~~provides mercury emission limits and monitoring requirements with which we are in compliance. ~~In 2009, we added mercury monitors to our~~ Neil Simpson II ~~plant. The~~and Wygen III ~~plant, which commenced operations~~have been utilized for internal study and review of mercury emission control technology and have mercury monitors in ~~2010, also has mercury monitors.~~place. Neil Simpson II, Wygen III and the Wyodak plant are expected to be in compliance ~~within~~by the compliance ~~time frame,~~deadline, without incurring significant costs.

On June 3, 2010, the EPA promulgated the GHG Tailoring Rule, implementing regulations of GHG for permitting purposes. This rule will impact us in the event of a major modification at an existing facility or in the event we establish a new major source of GHG emissions, as defined by EPA regulations. Upon renewal of operating permits for existing permitted facilities monitoring and reporting requirements will be implemented. New projects or major modifications to existing projects will result in a Best Available Control Technology review that could result in more stringent emission control practices and technologies. Wyoming passed GHG legislation in 2012 and 2013, enabling the state to implement EPA’s GHG program. Rules were adopted and submitted to EPA, with approval granted in the November 22, 2013 Federal Register. As of December 23, 2013, Wyoming has full jurisdiction over the GHG permitting program which includes the transfer of the Cheyenne Prairie EPA GHG air permit, to the state of Wyoming. This eliminates the increased time, expense and considerable risk of obtaining a permit from EPA.

On January 8, 2014, the EPA re-proposed Standards of Performance for Greenhouse Gas Emissions from New Stationary Sources: Electric Utility Generating Units. We expect multiple revisions and legal actions before the final rule is issued, so we cannot be certain of impacts from this rule.

On April 13, 2012, the EPA proposed Electric Utility New Source Performance Standards for GHG. These standards will apply to Cheyenne Prairie. They are scheduled to be final in the first half of 2013 and, as proposed, would not have a significant impact on this project. However, until we can evaluate the final version of these standards, we cannot be certain of this assumption.

In August 2012, the EPA proposed revisions to the Electric Utility New Source Performance Standards for stationary combustion turbines. This rule is expected to be finalized in ~~2013~~2014 and, as proposed, will be applicable to Cheyenne Prairie and eventually all of the combustion turbines in our fleet. Among other things, the rule seeks to eliminate startup exemptions and clearly define overhauls for impact on the ~~EPA's~~EPA’s New Source Review regulations, with the intention of eventually bringing all units under the applicability of this rule. The primary impact is expected to be on our older existing units, which will eventually be required to meet tighter NO_x emission limitations.

By May 3, 2013, all of our diesel generator engines ~~must~~were required to comply with ~~EPA's~~EPA’s Stationary Reciprocating Internal Combustion Engine Hazardous Air Pollutant regulations. Evaluations ~~have been~~were completed, ~~and~~ emission control equipment was installed ~~to meet that deadline.~~and emission testing confirmed compliance with those requirements.

In 2011, the State of Wyoming issued a letter requiring Neil Simpson II to include startup and shutdown SO₂ &and NO_x emissions when evaluating compliance with permitted emission limits. This represented a significant change from requirements in the original 1993 air permit. ~~Some minor~~Minor engineered design changes were made to ~~enable improved~~improve scrubber performance during ~~startup and those~~startup. Those changes ~~have been successful in enabling~~enabled the unit to meet the new requirements. The unit was previously fitted with state of the art low NO_x burners that ~~enable~~support compliance with this new requirement. Also in 2014, Neil Simpson II will be converting startup fuel from diesel to natural gas.

Regulatory Accounting

We follow accounting for regulated utility operations and our financial statements reflect the effects of the different rate making principles followed by the various jurisdictions in which we operate. If rate recovery becomes unlikely or uncertain, due to competition or regulatory action, these accounting standards may no longer apply to our regulated operations. In the event we determine that we no longer meet the accounting criteria for regulated operations, the accounting impact to us could be an extraordinary non-cash charge to operations of an amount that could be material.

New Accounting Pronouncements

See Note 21 of our Notes to Financial Statements in this Annual Report on Form 10-K for information on new accounting standards adopted in ~~2012~~2013 or pending adoption.

ITEM 1A. RISK FACTORS

The nature of our business subjects us to a number of uncertainties and risks. The following risk factors and other risk factors that we discuss in our periodic reports filed with the SEC should be considered for a better understanding of our Company. These important factors and other matters discussed herein could cause our actual results or outcomes to differ materially from those discussed in our forward-looking statements, or otherwise.

Regulatory commissions may refuse to approve some or all of the utility rate increases we have requested or may request in the future, or may determine that amounts passed through to customers were not prudently incurred and therefore, are not recoverable which could adversely affect our results of operations, financial position or liquidity.

Our electricity operations are subject to cost-of-service regulation and earnings oversight. This regulatory treatment does not provide any assurance as to achievement of desired earnings levels. Our rates are regulated on a state-by-state basis by the relevant state regulatory authorities based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. The rates that we are allowed to charge may or may not match our related costs and allowed return on invested capital at any given time. Our returns could be threatened by plant outages, machinery failures, increased purchased power costs, acts of nature, acts of terrorism or other unexpected events over which we have no control that could cause our costs to increase and operating margins to decline. While rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that the state public utility commissions will judge all of our costs, including our borrowing and debt service costs, to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce a full recovery of our costs and the return on invested capital allowed by the applicable state public utility commission.

To some degree, we are permitted to recover certain costs (such as increased fuel, purchased power and transmission costs, as applicable) without having to file a rate case. To the extent we pass through such costs to customers and a state public utility commission subsequently determines that such costs should not have been paid by customers, we may be required to refund such costs to customers. Any such costs not recovered through rates, or any such refund, could negatively affect our results of operations, financial position or cash flows.

Our financial performance depends on the successful operations of our facilities. If the risks involved in our operations are not appropriately managed or mitigated, our operations may not be successful and this could adversely affect our results of operations.

Operating electric generating facilities involves risks, including:

Operational limitations imposed by environmental and other regulatory ~~requirements.~~requirements;

Interruptions to supply of fuel and other commodities used in generation and distribution. We purchase fuel from a number of suppliers. Our results of operations could be negatively impacted by disruptions in the delivery of fuel due to various factors, including but not limited to, transportation delays, labor relations, weather, and environmental regulations, which could limit the ability to operate our facilities;

Breakdown or failure of equipment or processes, including those operated by PacifiCorp at the Wyodak ~~plant.~~plant;

Inability to recruit and retain skilled technical ~~labor.~~labor;

Disrupted transmission and distribution. We depend on transmission and distribution facilities, including those operated by unaffiliated parties, to deliver the electricity that we sell to our retail and wholesale customers. If transmission is interrupted, our ability to sell or deliver product and satisfy our contractual obligations may be ~~hindered.~~hindered;

Electricity is dangerous for employees and the general public should they come in contact with power lines or electrical equipment. Natural conditions and other disasters such as wind, lightning and winter storms can cause wildfires, pole failures and associated property damage and ~~outages;~~outages. For example, as described in more detail under “Legal Proceedings,” a fire investigator concluded that a forest and grassland fire in the western Black Hills of Wyoming and South Dakota in 2012 was caused by the failure of a transmission structure owned, operated and maintained by us, and claims have been made against us related to the fire;

Disruption in the functioning of our information technology and network infrastructure which are vulnerable to disability, failures and unauthorized access. If our information technology systems were to fail and we were unable to recover in a timely manner, we would be unable to fulfill critical business ~~functions.~~functions; and

Labor relations.

National and regional economic conditions may cause increased late payments and uncollectible accounts, which could adversely affect our results of operations, financial position or liquidity.

~~The continued recessionary environment and any~~A future recession may lead to an increase in late payments from retail, commercial and industrial utility customers, as well as from our non-regulated customers. If late payments and uncollectible accounts increase, our results of operations, financial position and liquidity could be adversely impacted.

Our credit ratings could be lowered below investment grade in the future. If this were to occur, it could impact our access to capital, our cost of capital and our other operating costs.

Our credit rating on our First Mortgage Bonds is A3A1 by ~~Moody's,~~Moody’s, ~~BBB+~~A- by S&P and A- by Fitch. Any reduction in our ratings by the rating agencies could adversely affect our ability to refinance our existing debt and to complete new financings. In addition, a downgrade in our credit rating would increase our costs of borrowing under some of our existing debt obligations. A downgrade could also result in our business counterparties requiring us to provide additional amounts of collateral under new transactions.

Construction, expansion, refurbishment and operation of power generating and transmission facilities involve significant risks which could ~~lead to lost revenues or increased expenses.~~reduce profitability.

The construction, expansion, refurbishment and operation of power generating and transmission facilities involve many risks, including:

The inability to obtain required governmental permits and approvals along with the cost of complying with or satisfying conditions imposed upon such approvals;

Contract restrictions upon the timing of scheduled outages;

Cost of supplying or securing replacement power during scheduled and unscheduled outages;

The unavailability or increased cost of equipment;

The cost of recruiting and retaining or the unavailability of skilled labor;

Supply interruptions, work stoppages and labor disputes;

~~Capital~~Increased capital and operating costs to comply with increasingly stringent environmental laws and regulations;

Opposition by members of the public or special-interest groups;

Weather interferences;

Unexpected engineering, environmental or geological problems; and

Unanticipated cost overruns.

The ongoing operation of our facilities involves ~~all~~many of the risks described above, in addition to risks relating to the breakdown or failure of equipment or processes and performance below expected levels of output or efficiency. New plants may employ recently developed and technologically complex equipment, especially in the case of newer environmental emission control technology. Any of these risks could cause us to operate below expected capacity levels, which in turn could reduce revenues, increase expenses, or cause us to incur higher maintenance costs and penalties. While we maintain insurance, obtain warranties from vendors and obligate contractors to meet certain performance levels, the proceeds of such insurance and our rights under warranties or performance guarantees may not be timely or adequate to cover lost revenues, increased expenses or liquidated damage payments.

Prices for some of our products and services as well as a portion of our operating costs are volatile and may cause our revenues and expenses to fluctuate significantly.

A portion of the variability of our net income in recent years has been attributable to off-system wholesale electricity sales. The related power prices are influenced by many factors outside our control, including among other things, fuel prices, transmission constraints, supply and demand, weather, general economic conditions and the rules, regulations and actions of the system operators in those markets. Moreover, unlike most other commodities, electricity cannot be stored and therefore must be produced concurrently with its use. As a result, wholesale power markets are subject to significant, unpredictable price fluctuations over relatively short periods of time.

Our energy production, transmission and distribution activities involve numerous risks that may result in accidents and other catastrophic events. These events could disrupt or impair our operations, create additional costs and cause substantial loss to us.

Inherent in our electricity distribution activities are a variety of hazards and operating risks, such as fires, releases of hazardous materials, explosions and mechanical problems that could cause substantial adverse financial impacts. These events could result in injury or loss of human life, significant damage to property or natural resources (including public parks), environmental pollution, impairment of our operations, and substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations. Particularly for our distribution lines located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the damages resulting from any such events could be significant.

Our operating results can be adversely affected by variations from normal weather patterns.

Our utility business is a seasonal business and weather patterns can have a material impact on our operating performance. Demand for electricity is typically greater in the summer and winter months associated with cooling and heating. Accordingly, our utility operations have historically generated less revenues and income when weather conditions are cooler in the summer and warmer in the winter. Unusually mild summers and winters therefore could have an adverse effect on our results of operations, financial position and liquidity.

13Our businesses are located in areas that could be subject to seasonal natural disasters such as severe snow and ice storms, flooding and wildfires. These factors could result in interruption of our business, damage to our property such as power lines and substations, and repair and clean-up costs associated with these storms. We may not be able to recover the costs incurred in restoring transmission and distribution property following these natural disasters through a change in our regulated rates thereby resulting in a negative impact on our results of operations, financial condition and cash flows.

The failure to achieve or maintain compliance with existing or future governmental regulations or requirements could adversely affect our results of operations, financial position or liquidity. Additionally, the potentially high cost of complying with such requirements or addressing environmental liabilities could also adversely affect our results of operations, financial position or liquidity.

Our business is subject to extensive energy, environmental and other laws and regulations of federal, state and local authorities. We generally must obtain and comply with a variety of regulations, licenses, permits and other approvals in order to operate, which could require significant capital expenditures and operating costs. If we fail to comply with these requirements, we could be subject to civil or criminal liability and the imposition of liens or fines; claims for property damage or personal injury; and/ or environmental clean-up costs. In addition, existing regulations may be revised or reinterpreted, new laws and regulations may be adopted or become applicable to us or our facilities, which could require additional unexpected expenditures and have a detrimental effect on our business.

~~We strive to comply with all applicable environmental laws and regulations.~~ Future steps to bring our facilities into compliance, if necessary, could be expensive, and could adversely affect our results of operation and financial condition. We expect our environmental compliance expenditures to be substantial in the future due to the continuing trends toward stricter standards, greater regulation, more extensive permitting requirements and an increase in the number of assets we operate.

Our ability to obtain insurance and the terms of any available insurance coverage could be adversely affected by international, national, state or local events and company-specific events, as well as the financial condition of insurers. Our insurance coverage may not provide protection against all significant losses.

Our ability to obtain insurance, as well as the cost of coverage of such insurance, could be affected by developments affecting company-specific events, international, national, state or local events, as well as the financial condition of insurers. Insurance coverage may not continue to be available at all, or at rates or on terms similar to those presently available to us. A loss for which we are not fully insured could materially and adversely affect our financial results. Our insurance may not be sufficient or effective under all circumstances and against all hazards or liabilities to which the company may be subject, including but not limited to environmental hazards, wildfire-related liability, distribution property losses and cyber risks.

Municipal governments may seek to limit or deny franchise privileges which could inhibit our ability to secure adequate recovery of our investment in assets subject to condemnation.

Municipal governments within our utility service territories possess the power of condemnation, and could seek a municipal utility within a portion of our current service territories by limiting or denying franchise privileges for our operations, and exercising powers of condemnation over all or part of our utility assets within municipal boundaries. Although condemnation is a process that is subject to constitutional protections requiring just compensation, as with any judicial procedure, the outcome is uncertain. If a municipality sought to pursue this course of action, we cannot assure that we would secure adequate recovery of our investment in assets subject to condemnation.

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

We own and operate regulated fossil-fuel generating plants in South Dakota and Wyoming. Recent developments under federal and state laws and regulations governing air emissions from fossil-fuel generating plants will likely result in more stringent emission limitations, which could have a material impact on our costs of operations. Various pending or final state and EPA regulations that will impact our facilities are also discussed in Item 1 of this Annual Report on Form 10-K under the caption “Environmental Regulations.”

On May 20, 2011, with amendments on December 21, 2012, the ~~EPA's~~EPA’s Industrial and Commercial Boiler regulations became effective, which provide for hazardous air pollutant-related emission limits and monitoring requirements. The compliance deadline for this rule is March 21, 2014. Engineering evaluations have been completed and confirm the significant impact on our Neil Simpson I, Osage and Ben French facilities. ~~We anticipate these~~These units will be retired on or before the March 21, 2014 compliance deadline. Although we will seek recovery for the remaining net book values of these plants and prudent decommissioning costs of these units, we cannot be assured of this recovery.

On ~~December~~February 16, ~~2011,~~2012, the EPA ~~signed~~published in the Federal Register the National Emission Standards for Hazardous Air Pollutants from Coal and Oil Fired Electric Utility Steam Generating Units ~~(Utility MATS Rule) which became~~(MATS), with an effective ~~on February~~date of April 16, 2012. Affected units ~~will~~ have ~~three years from the rule effective date to be in~~a compliance deadline of April 16, 2015, with a pathway defined to apply for a one year extension due to certain circumstances. It is expected that all of our plants will be in compliance by the initial 2015 deadline, with the primary impacts to Neil Simpson II, Wygen III and the Wyodak Plant ~~being the addition~~including installation of mercury sorbent injection systems, ~~and~~along with additional monitoring and ~~testing.~~

testing requirements.

The GHG Tailoring Rule, implementing regulations of GHG for permitting purposes, became effective in June 2010. This rule will impact us in the event of a major modification at an existing facility or in the event of a new major ~~source. Existing permitted~~source as defined by EPA regulations. Upon renewal of operating permits for existing facilities ~~will see~~ monitoring and reporting requirements ~~incorporated into their operating permits upon renewal.~~will be implemented. New projects or major modifications to existing projects will result in a Best Available Control Technology review that could ~~result in~~impose more stringent emissions control practices and technologies. The EPA’s GHG New Source Performance Standard for new steam electric generating units was re-proposed in September 2013 and is expected to be final in the ~~first half~~spring of ~~2013 and as~~2014. As proposed, it effectively prohibits new coal fired units until carbon capture and sequestration becomes technically and economically feasible. It also effectively prohibits simple cycle natural gas combustion turbines from generating more than one-third of their capacity, averaged over a three year period. In ~~2013~~2014, we expect the EPA, to ~~issue a proposed rule to regulate~~propose regulations for GHG emissions from existing steam electric generating units. This rule could have a significant impact on our coal and natural gas generating fleet.

Due to uncertainty as to the final outcome of federal climate change legislation, or regulatory changes under the Clean Air Act, we cannot definitively estimate the effect of GHG legislation or regulation on our results of operations, cash flows or financial position. The impact of GHG legislation or regulation on our company will depend upon many factors, including but not limited to the timing of implementation, the GHG sources that are regulated, the overall GHG emissions cap level, and the availability of technologies to control or reduce GHG emissions. If a ~~"cap~~“cap and ~~trade"~~trade” structure is implemented, the impact will depend on the degree to which offsets are allowed, the allocation of emission allowances to specific sources, and the effect of carbon regulation on natural gas and coal prices.

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

Increased risks of regulatory penalties could negatively impact our results of operations, financial position or liquidity.

Business activities in the energy sector are heavily regulated, primarily by agencies of the federal government. Agencies that historically sought voluntary compliance, or issued non-monetary sanctions, now employ mandatory civil penalty structures for regulatory violations. The FERC, EPA, OSHA and SEC can increasingly impose significant civil penalties to enforce compliance requirements relative to our business. In addition, FERC has delegated certain aspects of authority for enforcement of electric system reliability standards to the North American Energy Reliability Corporation, with similar penalty authority for violations. If a serious regulatory violation did occur, and penalties were imposed by FERC or another federal agency, this action could have a material adverse effect on our operations and/or our financial results.

Certain Federal laws, including the Migratory Bird Act and the Endangered Species Act, provide special protection to certain designated species. These laws and any state equivalents provide for significant civil and criminal penalties for non-permitted activities that result in harm to or harassment of certain protected animals, including damage to their habitats. If such species are located in an area in which we conduct operations, or if additional species in those areas become subject to protection, our operations and development projects, particularly transmission, generation and wind, could be restricted or delayed, or we could be required to implement expensive mitigation measures.

An effective system of internal control may not be maintained, leading to material weaknesses in internal control over financial reporting.

Section 404 of the Sarbanes-Oxley Act of 2002 requires management to make an assessment of the design and effectiveness of internal ~~controls. Our independent registered public accounting firm is required to attest to the effectiveness of these~~ controls. During their assessment of these controls, management or our independent registered public accounting firm may identify areas of weakness in control design or effectiveness, which may lead to the conclusion that a material weakness in internal control exists. Any control deficiencies we identify in the future could adversely affect our ability to report our financial results on a timely and accurate basis, which could result in a loss of investor confidence in our financial reports or have a material adverse effect on our ability to operate our business or access sources of liquidity.

Threats of terrorism and catastrophic events that could result from terrorism, cyber-attacks, or individuals and/or groups attempting to disrupt our business, or the businesses of third parties, may impact our operations in unpredictable ways and could adversely affect our results of operations, financial ~~results~~position or liquidity.

We are subject to the potentially adverse operating and financial effects of terrorist acts and threats, as well as cyber-attacks and other disruptive activities of individuals or groups. Our generation, transmission and distribution facilities, fuel storage facilities, information technology systems and other infrastructure facilities and systems and physical assets, could be direct targets of, or indirectly affected by, such activities. Terrorist acts or other similar events could harm our business by limiting our ability to generate, purchase or transmit power and by delaying our development and construction of new generating facilities and capital improvements to existing facilities. These events, and governmental actions in response, could result in a material decrease in revenues and significant additional costs to repair and insure our assets, and could adversely affect our operations by contributing to disruption of supplies and markets for natural gas, oil and other fuels. They could also impair our ability to raise capital by contributing to financial instability and lower economic activity.

We operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. Despite our implementation of security measures, all of our technology systems are vulnerable to disability, failures or unauthorized access, including ~~due to~~ cyber-attacks. If our technology systems were to fail or be breached and be unable to recover in a timely way, we would be unable to fulfill critical business functions, and sensitive confidential and other data could be compromised, which could have material adverse effect not only on our financial ~~results.~~results but on our public reputation as well.

The implementation of security guidelines and measures and maintenance of insurance, to the extent available, addressing such activities could increase costs. These types of events could materially adversely affect our financial results. In addition, these types of events could require significant management attention and resources, and could adversely affect our reputation among customers and the public.

A disruption of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources, could negatively impact our business. Because generation, transmission systems and natural gas pipelines are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the impact of an event on the interconnected system (such as severe weather or a generator or transmission facility outage, pipeline rupture, or a sudden significant increase or decrease in wind generation), within our system or within a neighboring system. Any such disruption could have a material impact on our financial results.

Market performance or changes in other assumptions could require us to make significant unplanned contributions to our pension plans and other postretirement benefit plans. Increasing costs associated with our defined benefit retirement plans may adversely affect our results of operations, financial position or liquidity.

We have a defined benefit pension plan that covers a substantial portion of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements related to these plans. These estimates and assumptions may change based on actual return on plan assets, changes in interest rates and changes in governmental regulations.

Increasing costs associated with our health care plans and other benefits may adversely affect our results of operations, financial position or liquidity.

The costs of providing health care benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise. The increasing costs and funding requirements associated with our health care plans may adversely affect our results of operations, financial position or liquidity.

In March 2010, the President of the United States signed the Patient Protection and Affordable Care Act of 2010 as amended by the Health Care and Education Reconciliation Act of 2010 (collectively the “2010 Acts”). The 2010 Acts will have a substantial impact on health care providers, insurers, employers and individuals. The 2010 Acts will impact employers and businesses differently depending on the size of the organization and the specific impacts on a company’s employees. Certain provisions of the 2010 Acts ~~became~~are effective ~~during our 2010 open enrollment period (November 1, 2010)~~ while other provisions of the 2010 Acts will be effective in future years. ~~Although the constitutional validity of the 2010 Acts is the subject of numerous lawsuits now pending in the federal courts, the outcome of which is uncertain, the~~The 2010 Acts could require, among other things, changes to our current employee benefit plans and in our administrative and accounting ~~processes.~~processes as well as changes to the costs of our plans. The ultimate extent and cost of these changes cannot be determined at this time and are being evaluated and updated as related regulations and interpretations of the 2010 Acts become available.

Our electric utility rates are regulated on a state-by-state basis by the relevant state regulatory authorities based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. Within our utility rates we have generally recovered the cost of providing employee benefits. As benefit costs continue to rise, there can be no assurance that the state public utility commissions will allow recovery.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.


ITEM 3.	LEGAL PROCEEDINGS

Information regarding our legal proceedings is incorporated herein by reference to the ~~"Legal Proceedings"~~“Legal Proceedings” sub caption within Item 8, Note 1211, ~~"Commitments~~“Commitments and Contingencies,"” of our Notes to Financial Statements in this Annual Report on Form 10-K.

PART II


ITEM 5.	MARKET FOR ~~REGISTRANT'S~~REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER

MATTERS

All of our common stock is held by our parent company, Black Hills Corporation. Accordingly, there is no established trading market for our common stock.


ITEM 7.	~~MANAGEMENT'S~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

Non-GAAP Financial Measure

The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, gross margin, that is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Gross margin (revenue less cost of sales) is a non-GAAP financial measure due to the exclusion of depreciation from the measure. The presentation of gross margin is intended to supplement investors’ understanding of our operating performance.

In our Management’s Discussion and Analysis of Results of Operations, 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 and 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.


For the years ended December 31,	2012			Variance			2011			Variance			2010			2013			Variance			2012			Variance			2011
	(in thousands)															(in thousands)
Revenue	$	243,309		$	(2,322	)	$	245,631		$	15,868		$	229,763		$	254,027		$	10,718		$	243,309		$	(2,322	)	$	245,631
Fuel and purchased power	87,519			(5,703		)	93,222			5,465			87,757			89,437			1,918			87,519			(5,703		)	93,222
Gross margin	155,790			3,381			152,409			10,403			142,006			164,590			8,800			155,790			3,381			152,409

Operating expenses	98,209			(248		)	98,457			5,481			92,976			102,246			4,037			98,209			(248		)	98,457
Gain on sale of operating assets	—			768			(768		)	5,470			(6,238		)	—			—			—			768			(768		)
Operating income	57,581			2,861			54,720			(548		)	55,268			62,344			4,763			57,581			2,861			54,720

Interest expense, net	(17,065		)	(926		)	(16,139		)	374			(16,513		)	(19,291		)	(2,226		)	(17,065		)	(926		)	(16,139		)
Other income	879			373			506			(2,748		)	3,254			539			(340		)	879			373			506
Income tax expense	(14,309		)	(2,319		)	(11,990		)	(1,249		)	(10,741		)	(13,419		)	890			(14,309		)	(2,319		)	(11,990		)
Net income	$	27,086		$	(11	)	$	27,097		$	(4,171	)	$	31,268		$	30,173		$	3,087		$	27,086		$	(11	)	$	27,097

1718

The following tables provide certain electric utility operating statistics for the years ended December 31 (dollars in thousands):


Electric Revenue
Revenue											Revenue
Customer Base	2012		Percentage Change		2011		Percentage Change		2010		2013		Percentage Change		2012		Percentage Change		2011
Residential	$	58,523	(2	)%	$	59,826	12	%	$	53,549	$	64,566	10	%	$	58,523	(2	)%	$	59,826
Commercial	73,858		1	%	72,889		10	%	65,997		80,289		9	%	73,858		1	%	72,889
Industrial	25,656		—	%	25,723		14	%	22,621		27,705		8	%	25,656		—	%	25,723
Municipal	3,268		3	%	3,172		5	%	3,029		3,421		5	%	3,268		3	%	3,172
Total retail sales	161,305		—	%	161,610		11	%	145,196		175,981		9	%	161,305		—	%	161,610
Contract wholesale	20,290		12	%	18,105		(21	)%	22,996		21,956		8	%	20,290		12	%	18,105
Wholesale off-system	31,905		(9	)%	34,889		(4	)%	36,354		29,580		(7	)%	31,905		(9	)%	34,889
Total electric sales	213,500		(1	)%	214,604		5	%	204,546		227,517		7	%	213,500		(1	)%	214,604
Other revenue	29,809		(4	)%	31,027		23	%	25,217		26,510		(11	)%	29,809		(4	)%	31,027
Total revenue	$	243,309	(1	)%	$	245,631	7	%	$	229,763	$	254,027	4	%	$	243,309	(1	)%	$	245,631

															Megawatt-Hours Sold
Customer Base	2012	Percentage Change		2011	Percentage Change		2010	2013	Percentage Change		2012	Percentage Change		2011
Residential	532,342	(3	)%	550,935	1	%	547,193	555,204	4	%	532,342	(3	)%	550,935
Commercial	731,785	1	%	720,978	0	%	720,119	730,701	—	%	731,785	1	%	720,978
Industrial	407,301	—	%	408,337	7	%	382,562	404,009	(1	)%	407,301	—	%	408,337
Municipal	35,933	5	%	34,235	1	%	33,908	34,344	(4	)%	35,933	5	%	34,235
Total retail sales	1,707,361	—	%	1,714,485	2	%	1,683,782	1,724,258	1	%	1,707,361	—	%	1,714,485
Contract wholesale	340,036	(3	)%	349,520	(25	)%	468,782	357,193	5	%	340,036	(3	)%	349,520
Wholesale off-system	1,263,457	3	%	1,226,548	5	%	1,163,058	1,002,847	(21	)%	1,263,457	3	%	1,226,548
Total electric sales	3,310,854	1	%	3,290,553	(1	)%	3,315,622	3,084,298	(7	)%	3,310,854	1	%	3,290,553
Losses and company use	197,355	22	%	162,316	24	%	131,263	158,845	(20	)%	197,355	22	%	162,316
Total energy	3,508,209	2	%	3,452,869	0	%	3,446,885	3,243,143	(8	)%	3,508,209	2	%	3,452,869

We own approximately 471 MW of electric utility generating capacity and purchase an additional 50 MW under a long-term agreement expiring in 2023.


Regulated Power Plant Fleet Availability	2012		2011		2010		2013		2012		2011
Coal-fired plants^(a)	91.9	%	88.8	%	93.5	%	96.3	%	91.9	%	88.8	%
Other plants	98.5	%	95.8	%	95.7	%	96.8	%	98.5	%	95.8	%
Total availability	94.5	%	91.5	%	94.4	%	96.5	%	94.5	%	91.5	%

_____________________________


(a)	2011 reflects a planned major outage at the PacifiCorp-operated Wyodak plant.


Resources	2012	Percentage Change		2011	Percentage Change		2010	2013	Percentage Change		2012	Percentage Change		2011
MWh generated:
Coal	1,796,936	5	%	1,717,008	(14	)%	1,987,037	1,768,483	(2	)%	1,796,936	5	%	1,717,008
Gas	33,183	118	%	15,221	(21	)%	19,269	33,374	1	%	33,183	118	%	15,221
	1,830,119	6	%	1,732,229	(14	)%	2,006,306	1,801,857	(2	)%	1,830,119	6	%	1,732,229

MWh purchased	1,678,090	(2	)%	1,720,640	19	%	1,440,579	1,441,286	(14	)%	1,678,090	(2	)%	1,720,640
Total resources	3,508,209	2	%	3,452,869	0	%	3,446,885	3,243,143	(8	)%	3,508,209	2	%	3,452,869

1819


Heating and Cooling Degree Days	2012		2011		2010		2013		2012		2011
Actual
Heating degree days	6,206		7,579		7,272		7,582		6,206		7,579
Cooling degree days	937		700		532		724		937		700

Variance from 30-year average
Heating degree days	(13	)%	5	%	1	%	9	%	(13	)%	5	%
Cooling degree days	47	%	17	%	(11	)%	8	%	47	%	17	%

2013 Compared to 2012

Gross margin increased primarily due to a return on additional investments which increased base electric margins by $5.5 million and $2.7 million from the Cheyenne Prairie construction financing rider.

Operations and maintenanceincreased primarily due to an increase in vegetation management, plant overhaul and maintenance costs, and employee compensation and benefit costs.

Interest expense, net increased primarily due to lower interest income received on affiliate borrowings and increased allocations of corporate debt costs.

Other income, net was comparable to the prior year.

Income tax expense: The effective tax rate decreased in 2013 primarily due to the result of the retroactive reinstatement of research and development credits.

2012 Compared to 2011

Gross marginincreased primarily due to an increase of $1.6 million from the Environmental Improvement Cost Recovery Adjustment rider, a $4.5 million increase in wholesale and transmission margins as a result of increased prices partially offset by $2.5 million from the 2012 expiration of a reserve capacity agreement with PacifiCorp.

Operations and maintenancewere comparable to the prior year. Increased corporate allocations were offset by lower costs related to the suspension of operations at the Ben French plant.

Gain on sale of operating assets in 2011 related to the sale of assets to a related party.

Interest expense, net increased primarily due to a decrease in interest income from lower utility money pool borrowings.

Other income, net was comparable to the prior year.

Income tax expense: The effective tax rate increased primarily due to unfavorable true-up adjustments and lower flow through of the tax benefit attributable to repair and maintenance costs deducted for tax purposes.

~~2011~~ ~~Compared to~~ ~~2010~~
Significant Events

~~Gross marginincreased~~ primarily due to a $16.6 million increase related to the impact of the outcome of our rate cases and increased transmission margins partially offset by lower margins due to the termination of power sales contracts upon a customer's purchase of an ownership interest in the Wygen III generating facility.South Dakota

~~Operations and maintenanceincreased~~ primarily due to additional costs of $1.6 million associated with Wygen III which commenced commercial operation on April 1, 2010, and increased allocation of corporate costs partially offset by lower costs related to the suspension of operations at the Osage plant.

~~Gain on sale of operating assets~~ in 2011 related to the sale of assets to a related party. The gain on sale of operating assets in 2010 represented the sale of a 23% ownership interest in the Wygen III generating facility to the City of Gillette, WY.

~~Interest expense, net~~ ~~decreased~~ primarily due to lower interest expense primarily related to the repayment of higher rate debt during 2010, partially offset by a decrease in AFUDC associated with borrowed funds due to completed construction of Wygen III.

~~Other incomedecreased~~ ~~primarily due to a decrease of $2.0 million in AFUDC-equity due to the placement of Wygen III into commercial operation.~~

~~Income tax expense: The effective tax rate~~ ~~increased~~ ~~from the same period in the prior year due to a prior year tax benefit for a repairs deduction taken for tax purposes and the flow-through treatment of such tax benefit resulting from~~In December 2012, we filed a rate case ~~settlement~~with the SDPUC requesting an electric revenue increase of $13.7 million, or 9.94%, to recover investment in ~~2010.~~distribution and transmission lines, generation plant upgrades, environmental compliance and increased operating costs. On September 17, 2013, the SDPUC approved a rate increase of $8.8 million, or 6.4%, effective June 16, 2013.

1920

~~Significant Events~~Winter Storm

In October 2013, the City of Rapid City, SD, experienced the second most severe blizzard in history which left most of our customers experiencing power outages. Repairing the substantial and widespread damage far exceeded average annual storm-related costs and in December 2013, we submitted an application to the SDPUC for approval to defer the incremental costs of approximately $2.5 million, including labor, materials and supplies, equipment and outside contractors that were incurred in the efforts to restore power to our customers. In January 2014, approval was received and these costs are included in Regulatory assets until the next rate case filing.

Power Plant Suspension/Retirements

In order to comply with environmental regulations, including the new EPA Industrial &and Commercial Boiler Regulations for Area Sources of Hazardous Air Pollutants regulations, operations at our 25 MW coal-fired Ben French power plant were suspended as of August 31, 2012. Operations at our 35 MW coal-fired Osage power plant were suspended as of October 1, 2010. These plants as well as our 22 MW coal-fired plant Neil Simpson I will be retired on or before March 21, 2014. We intend to operate Neil Simpson 1I until the planned retirement date. ~~While the net book value of these plants is estimated to be insignificant at the time of retirement, we would reasonably expect to recover any remaining value of these plants through future rates.~~

Cheyenne Prairie

~~South Dakota~~ The project is expected to be placed into service in the fourth quarter of 2014.

In December 2012, we filed a rate case with the SDPUC requesting electric revenue increases of $13.7 million, or 9.94%, to recover investment in distribution and transmission lines, generation plant upgrades and environmental compliance. We have requested an effective date of April 1, 2013 and a decision is anticipated during the third quarter of 2013. If the SDPUC has not reached a decision within 180 days, interim rates will go into effect June 16, 2013.

We filed a request with the SDPUC to use a construction financing rider during the construction of Cheyenne Prairie in lieu of traditional AFUDC. This rider ~~would be~~is similar to the one approved by the WPSC for Cheyenne Light and Black Hills Power for Wyoming ~~customers.~~customers in 2012. On January 17, 2013, the SDPUC approved a stipulation with interim rates effective April 1, 2013 ~~subject to refund.~~and on Sept. 17, 2013, the SDPUC approved the construction financing rider. The rider ~~will allow us~~allows Black Hills Power to earn and collect a rate of return during the construction period on ~~our~~its approximately ~~40 percent~~40% share of the total project cost ~~relating~~that relates to ~~our~~ South Dakota customers while also saving customers money over the long-term. If approved, this will increase gross margin by approximately $3.6 million and $5.6 million in 2013 and 2014, respectively. We anticipate a final ruling by the SDPUC on this rider during the third quarter of 2013.customers.

In May 2011, the SDPUC approved an Environmental Improvement Cost Recovery Adjustment tariff for Black Hills Power. This tariff, which was implemented to recover Black Hills Power's investment of $25 million for pollution control equipment at the PacifiCorp operated Wyodak plant, went into effect June 1, 2011 with an annual revenue increase of $3.1 million.

~~Wyoming~~

In October 2012, the WPSC approved Cheyenne Prairie’s construction financing rider which allows for recovery of construction financing costs from customers during the construction period in lieu of traditional AFUDC. The rider was implemented November 1, 2012 and will allow Cheyenne Light and Black Hills Power to each earn and collect a rate of return during the construction period on approximately 60% share of the total project cost relating to our Wyoming customers while also saving customers money over the long-term. This will increase gross margin by approximately $0.3 million and $0.4 million in 2013 and 2014, respectively.

Critical Accounting Estimates

We prepare our financial statements in conformity with GAAP. In many cases, the accounting treatment of a particular transaction is specifically dictated by GAAP and does not require ~~management's~~management’s judgment in application. There are also areas which require ~~management's~~management’s judgment in selecting among available GAAP alternatives. We are required to make certain estimates, judgments and assumptions that we believe are reasonable based upon the information available. These estimates and assumptions affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented. Actual results may differ from our estimates and to the extent there are material differences between these estimates, judgments or assumptions and actual results, our financial statements will be affected. We believe the following accounting estimates are the most critical in understanding and evaluating our reported financial results.

The following discussion of our critical accounting estimates should be read in conjunction with Note 1, ~~"Business~~“Business Description and Summary of Significant Accounting ~~Policies"~~Policies ” of our Notes to Financial Statements in this Annual Report on Form 10-K.

Pension and Other Postretirement Benefits

The Company, as described in Note 98 to the Financial Statements in this Annual Report on Form 10-K, has a defined benefit pension plan and post-retirement healthcare plan. As of December 31, 2012, a Master Trust was established for the investment of assets of the Plan and other Employer-sponsored retirement plans. Each participating retirement plan has an undivided interest in the Master Trust.

Accounting for pension and other postretirement benefit obligations involves numerous assumptions, the most significant of which relate to the discount rate for measuring the present value of future plan obligations; expected long-term rates of return on plan assets; rate of future increases in compensation levels; and healthcare cost projections. The determination of our obligation and expenses for pension and other postretirement benefits is dependent on the assumptions determined by management and used by actuaries in calculating the amounts. Although we believe our assumptions are appropriate, significant differences in our actual experience or significant changes in our assumptions may materially affect our pension and other postretirement obligations and our future expense.

The ~~estimated~~ discount rate used to determine annual defined benefit pension costs accruals will be ~~4.3%~~5.1% in ~~2013~~2014 and the discount rate used in ~~2012~~2013 was ~~4.65%~~4.3%. In selecting the discount rate, we consider cash flow durations for each ~~plan's~~plan’s liabilities on high credit fixed income yield curves for comparable durations. We do not pre-fund our non-qualified plans or postretirement healthcare plans.

Income Taxes

We file a federal income tax return with other members of the Parent consolidated group. For financial statement purposes, federal income taxes are allocated to the individual companies based on amounts calculated on a separate return basis.

We use the liability method of accounting for income taxes. Under this method, deferred income taxes are recognized, at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities, as well as operating loss and tax credit carryforwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements. We classify deferred tax assets and liabilities into current and non-current amounts based on the nature of the related assets and liabilities.

In assessing the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized and provides any necessary valuation allowances as required. If we determine that we will be unable to realize all or part of our deferred tax assets in the future, an adjustment to the deferred tax asset would be charged to income in the period such determination was made. Although we believe our assumptions, judgments and estimates are reasonable, changes in tax laws or our interpretations of tax laws and the resolution of current and any future tax audits could significantly impact the amounts provided for income taxes in our ~~consolidated~~ financial statements. With respect to changes in tax law, the ~~recently enacted~~ American Taxpayer Relief Act of 2012, ~~(”Act”) will~~which was enacted January 2, 2013, did not have a material impact on the amounts provided for income taxes including our ability to realize deferred tax assets. Since the date of enactment was January 2, 2013, the Act could not be considered when determining deferred tax liabilities and assets as of December 31, 2012, which resulted in the reclassification of a sizable amount of Federal deferred tax asset related to net operating loss carryforwards from non-current to current. However,As expected, certain provisions of the ~~Act~~ATRA involving primarily the extension of 50% bonus depreciation ~~are currently expected to result~~resulted in minimal utilization of ~~such carryforwards~~Federal net operating loss carryforwards. In fact, the 50% bonus depreciation was a contributing factor to the generation of a net operating loss for Federal income tax purposes in 2013.

21In addition, on September 13, 2013, the U.S. Treasury issued final regulations addressing the tax consequences associated with amounts paid to acquire, produce, or improve tangible property. The regulations have the effect of a change in law and as a result the impact should be taken into account in the period of adoption. In general, such regulations apply to tax years beginning on or after January 1, 2014, with early adoption permitted. We expect to implement most, if not all, of the provisions of the final regulations in 2014. Procedural guidance is expected from IRS in early 2014 to facilitate implementation. Analysis performed to date indicates no material impact to our financial statements. See Note 6 in our Notes to Financial Statements in this Annual Report on Form 10-K for additional information.

Contingencies

When it is probable that an environmental or other legal liability has been incurred, a loss is recognized when the amount of the loss can be reasonably estimated. Estimates of the probability and the amount of loss are made based on currently available facts. Accounting for contingencies requires significant judgment regarding the estimated probabilities and ranges of exposure to potential liability. Our assessment of our exposure to contingencies could change to the extent there are additional future developments, or as more information becomes available. If actual obligations incurred are different from our estimates, the recognition of the actual amounts could have a material impact on our financial position, results of operations and cash flows. ~~The Company describes~~We describe any contingencies in Note 1211 of the Financial Statements in this Annual Report on Form 10-K.



ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS



	Page

Management’s Report on Internal Controls Over Financial Reporting	24

Report of Independent Registered Public Accounting Firm	2425

Statements of Income for the three years ended December 31, ~~2012~~2013	2526

Statements of Comprehensive Income (Loss) for the three years ended December 31, ~~2012~~2013	2527

Balance Sheets as of December 31, ~~2012~~2013 and ~~2011~~2012	2728

Statements of Cash Flows for the three years ended December 31, ~~2012~~2013	2830

Statements of Common ~~Stockholder's~~Stockholder’s Equity for the three years ended December 31, ~~2012~~2013	2931

Notes to Financial Statements	3032

Management’s Report on Internal Control over Financial Reporting

Management of Black Hills Power is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is a process designed 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.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2013, based on the criteria set forth in Internal Control - Integrated Framework (1992)issued by the Committee of Sponsoring Organizations of the Treadway Commission. This evaluation included review of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls and a conclusion on this evaluation. Based on our evaluation, we have concluded that our internal control over financial reporting was effective as of December 31, 2013.

This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting because this requirement is inapplicable to companies such as ours which are known as non-accelerated filers.

Black Hills Power

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of

Black Hills Power, Inc.

Rapid City, South Dakota

We have audited the accompanying balance sheets of Black Hills Power, Inc. (the ~~"Company"~~“Company”) as of December 31, ~~2012~~2013 and ~~2011~~2012, and the related statements of income, comprehensive income (loss), common stockholder’s equity and cash flows ~~and common stockholder's equity~~ for each of the three years in the period ended December 31, ~~2012~~2013. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the ~~Company's~~Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the ~~Company's~~Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Black Hills Power, Inc. as of December 31, ~~2012~~2013 and ~~2011~~2012, and the results of its operations and its cash flows for each of the three years in the period ended December 31, ~~2012~~2013, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

~~March 6, 2013~~February 27, 2014

2425

BLACK HILLS POWER, INC.

STATEMENTS OF INCOME


Years ended December 31,	2012			2011			2010			2013			2012			2011
	(in thousands)									(in thousands)

Revenue	$	243,309		$	245,631		$	229,763		$	254,027		$	243,309		$	245,631

Operating expenses:
Fuel and purchased power	87,519			93,222			87,757			89,437			87,519			93,222
Operations and maintenance	65,835			66,683			68,884			68,857			65,835			66,683
Gain on sale of operating assets	—			(768		)	(6,238		)	—			—			(768		)
Depreciation and amortization	27,621			27,217			22,030			28,125			27,621			27,217
Taxes - property	4,753			4,557			2,062			5,264			4,753			4,557
Total operating expenses	185,728			190,911			174,495			191,683			185,728			190,911

Operating income	57,581			54,720			55,268			62,344			57,581			54,720

Other income (expense):
Interest expense	(17,602		)	(16,712		)	(18,737		)	(19,725		)	(17,602		)	(16,712		)
AFUDC - borrowed	161			419			2,224			186			161			419
Interest income	376			154			318			248			376			154
AFUDC - equity	325			705			2,748			368			325			705
Other expense	—			(344		)	(35		)	(196		)	—			(344		)
Other income	554			145			223			367			554			145
Total other income (expense)	(16,186		)	(15,633		)	(13,259		)	(18,752		)	(16,186		)	(15,633		)

Income from continuing operations before income taxes	41,395			39,087			42,009			43,592			41,395			39,087
Income tax expense	(14,309		)	(11,990		)	(10,741		)	(13,419		)	(14,309		)	(11,990		)

Net income	$	27,086		$	27,097		$	31,268		$	30,173		$	27,086		$	27,097

The accompanying notes to financial statements are an integral part of these financial statements.

2526

BLACK HILLS POWER, INC.

STATEMENTS OF COMPREHENSIVE INCOME (LOSS)


Years ended December 31,	2012			2011			2010			2013		2012			2011
(in thousands)
										(in thousands)

Net income	$	27,086		$	27,097		$	31,268		$	30,173	$	27,086		$	27,097

Other comprehensive income (loss), net of tax:
Benefit plan liability adjustments - net gain (loss) (net of tax of $93, $38 and $51, respectively)	(171		)	(70		)	(94		)
Fair value adjustment on derivatives designated as cash flow hedges (net of tax of $(2))	—			—			4
Benefit plan liability adjustments - net gain (loss) (net of tax of ($73), $93 and $38, respectively)										139		(171		)	(70		)
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax of $(23), $0 and $0)										43		—			—

Reclassification adjustment of cash flow hedges settled and included in net income (loss) (net of tax of $(23), $(23) and $(23), respectively)	41			42			41			41		41			42

Other comprehensive income (loss), net of tax	(130		)	(28		)	(49		)	223		(130		)	(28		)

Comprehensive income (loss), net of tax	$	26,956		$	27,069		$	31,219		$	30,396	$	26,956		$	27,069

See Note 87 for additional disclosure related to comprehensive income.

~~The accompanying notes to financial statements are an integral part of these financial statements.~~

~~BLACK HILLS POWER, INC.~~

~~BALANCE SHEETS~~

As of December 31, 2012 2011
(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents $ 3,805
$ 2,812
Receivables - customers, net 23,867
24,668
Receivables - affiliates 5,027
6,998
Other receivables, net 673
786
Money pool notes receivable 31,645
50,477
Materials, supplies and fuel 20,633
22,074
Deferred income tax assets, net, current 16,631
—
Regulatory assets, current 4,998
6,605
Other current assets 5,781
4,255
Total current assets 113,060
118,675

Investments 4,359
4,592

Property, plant and equipment 1,024,768
995,772
Less accumulated depreciation and amortization (322,830 ) (313,581 )
Total property, plant and equipment, net 701,938
682,191

Other assets:
Regulatory assets, non-current 48,244
45,160
Other, non-current assets 5,322
3,812
Total other assets 53,566
48,972
TOTAL ASSETS $ 872,923
$ 854,430

LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities:
Current maturities of long-term debt $ —
$ 37
Accounts payable 14,318
12,560
Accounts payable - affiliates 21,896
18,598
Accrued liabilities 15,477
16,448
Regulatory liabilities, current 37
853
Deferred income tax liabilities, net, current —
848
Total current liabilities 51,728
49,344

Long-term debt, net of current maturities 269,944
276,390

Deferred credits and other liabilities:
Deferred income tax liabilities, net, non-current 158,918
113,320
Regulatory liabilities, non-current 43,849
39,621
Benefit plan liabilities 25,888
31,097
Other, non-current liabilities 3,138
8,172
Total deferred credits and other liabilities 231,793
192,210

Commitments and contingencies (Notes 5, 9, 10 and 12)

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 257,887
274,785
Accumulated other comprehensive loss (1,420 ) (1,290 )
Total stockholder's equity 319,458
336,486
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY $ 872,923
$ 854,430

The accompanying notes to financial statements are an integral part of these financial statements.

BLACK HILLS POWER, INC.

BALANCE SHEETS



As of December 31,	2013			2012
	(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	2,259		$	3,805
Receivables - customers, net	25,799			23,867
Receivables - affiliates	4,934			5,027
Other receivables, net	579			673
Money pool notes receivable	17,292			31,645
Materials, supplies and fuel	23,278			20,633
Deferred income tax assets, net, current	2,170			16,631
Regulatory assets, current	4,891			4,998
Other current assets	4,933			5,781
Total current assets	86,135			113,060

Investments	4,431			4,359

Property, plant and equipment	1,095,884			1,024,768
Less accumulated depreciation and amortization	(334,174		)	(322,830		)
Total property, plant and equipment, net	761,710			701,938

Other assets:
Regulatory assets, non-current	40,373			48,244
Other, non-current assets	8,524			5,322
Total other assets	48,897			53,566
TOTAL ASSETS	$	901,173		$	872,923


The accompanying notes to financial statements are an integral part of these financial statements.



BLACK HILLS POWER, INC.
BALANCE SHEETS
(Continued)

As of December 31,	2013			2012
	(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Accounts payable	$	26,144		$	14,318
Accounts payable - affiliates	21,082			21,896
Accrued liabilities	14,966			15,477
Regulatory liabilities, current	161			37
Total current liabilities	62,353			51,728

Long-term debt	269,948			269,944

Deferred credits and other liabilities:
Deferred income tax liabilities, net, non-current	167,309			158,918
Regulatory liabilities, non-current	43,357			43,849
Benefit plan liabilities	12,105			25,888
Other, non-current liabilities	4,247			3,138
Total deferred credits and other liabilities	227,018			231,793

Commitments and contingencies (Notes 4, 8, 9 and 11)

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	280,060			257,887
Accumulated other comprehensive loss	(1,197		)	(1,420		)
Total stockholder’s equity	341,854			319,458
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	901,173		$	872,923

The accompanying notes to financial statements are an integral part of these financial statements.

BLACK HILLS POWER, INC.

STATEMENTS OF CASH FLOWS


Years ended December 31,	2012			2011			2010			2013			2012			2011
	(in thousands)									(in thousands)
Operating activities:
Net income	$	27,086		$	27,097		$	31,268		$	30,173		$	27,086		$	27,097
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation and amortization	27,621			27,217			22,030			28,125			27,621			27,217
Deferred income taxes	24,628			(2,931		)	25,626			13,582			24,628			(2,931		)
AFUDC - equity	(325		)	(705		)	(2,748		)	(368		)	(325		)	(705		)
Gain on sale of operating assets	—			(768		)	(6,238		)	—			—			(768		)
Employee benefits	3,828			2,406			4,030			3,094			3,828			2,406
Other adjustments	1,187			617			(4,335		)	1,400			1,187			617
Change in operating assets and liabilities -
Accounts receivable and other current assets	2,125			3,378			(14,541		)	(5,175		)	2,916			(973		)
Accounts payable and other current liabilities	(903		)	989			(5,525		)	1,180			(903		)	989
Regulatory assets	(443		)	(1,211		)	3,883
Regulatory liabilities	(153		)	(1,964		)	3,562
Contributions to defined benefit pension plan	(6,835		)	—			(8,798		)	(2,299		)	(6,835		)	—
Other operating activities	(5,238		)	(2,691		)	2,389			(3,149		)	(6,625		)	(1,515		)
Net cash provided by (used in) operating activities	72,578			51,434			50,603			66,563			72,578			51,434

Investing activities:
Property, plant and equipment additions	(40,415		)	(40,910		)	(78,602		)	(74,390		)	(40,415		)	(40,910		)
Proceeds from sale of operating assets	—			1,135			62,000			—			—			1,135
Notes receivable from affiliate companies, net	(25,152		)	(10,615		)	17,875			6,353			(25,152		)	(10,615		)
Other investing activities	469			(197		)	2,202			(72		)	469			(197		)
Net cash provided by (used in) investing activities	(65,098		)	(50,587		)	3,475			(68,109		)	(65,098		)	(50,587		)

Financing activities:
Long-term debt - repayments	(6,487		)	(80		)	(52,566		)	—			(6,487		)	(80		)
Other financing activities	—			—			(1,176		)
Net cash provided by (used in) financing activities	(6,487		)	(80		)	(53,742		)	—			(6,487		)	(80		)

Net change in cash and cash equivalents	993			767			336			(1,546		)	993			767

Cash and cash equivalents:
Beginning of year	2,812			2,045			1,709			3,805			2,812			2,045
End of year	$	3,805		$	2,812		$	2,045		$	2,259		$	3,805		$	2,812

See Note 1110 for Supplemental Cash Flows information.

The accompanying notes to financial statements are an integral part of these financial statements.

2830

BLACK HILLS POWER, INC.

STATEMENTS OF COMMON ~~STOCKHOLDER'S~~STOCKHOLDER’S EQUITY


	2012			2011			2010			2013			2012			2011
	(in thousands)									(in thousands)
Common stock shares:
Balance beginning of year	23,416			23,416			23,416			23,416			23,416			23,416
Issuance of common stock	—			—			—			—			—			—
Balance end of year	23,416			23,416			23,416			23,416			23,416			23,416

Common stock amounts:
Balance beginning of year	$	23,416		$	23,416		$	23,416		$	23,416		$	23,416		$	23,416
Issuance of common stock	—			—			—			—			—			—
Balance end of year	$	23,416		$	23,416		$	23,416		$	23,416		$	23,416		$	23,416

Additional paid-in capital:
Balance beginning of year	$	39,575		$	39,575		$	39,575		$	39,575		$	39,575		$	39,575
Issuance of common stock	—			—			—			—			—			—
Balance end of year	$	39,575		$	39,575		$	39,575		$	39,575		$	39,575		$	39,575

Retained earnings:
Balance beginning of year	$	274,785		$	247,688		$	216,420		$	257,887		$	274,785		$	247,688
Net income	27,086			27,097			31,268			30,173			27,086			27,097
Non-cash dividend to Parent company	(43,984		)	—			—			(8,000		)	(43,984		)	—
Balance end of year	$	257,887		$	274,785		$	247,688		$	280,060		$	257,887		$	274,785

Accumulated other comprehensive loss:
Balance beginning of year	$	(1,290	)	$	(1,262	)	$	(1,213	)	$	(1,420	)	$	(1,290	)	$	(1,262	)
Other comprehensive (loss) income, net of tax	(130		)	(28		)	(49		)	223			(130		)	(28		)
Balance end of year	$	(1,420	)	$	(1,290	)	$	(1,262	)	$	(1,197	)	$	(1,420	)	$	(1,290	)

Total stockholder's equity	$	319,458		$	336,486		$	309,417
Total stockholder’s equity										$	341,854		$	319,458		$	336,486

The accompanying notes to financial statements are an integral part of these financial statements.

2931

NOTES TO FINANCIAL STATEMENTS

December 31, ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011

(1) BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Business Description

Black Hills Power, Inc. (the Company, ~~"we," "us"~~“we,” “us” or ~~"our"~~“our”) is an electric utility serving customers in South Dakota, Wyoming and Montana. We are a wholly-owned subsidiary of BHC or the Parent, a public registrant listed on the New York Stock Exchange.

Basis of Presentation

The financial statements include the accounts of Black Hills Power, Inc. and also our ownership interests in the assets, liabilities and expenses of our jointly owned facilities (Note 43) and are prepared in accordance with GAAP.

Use of Estimates and Basis of Presentation

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Cash Equivalents

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.

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 FERC.

Our regulated utility operations follow accounting standards for regulated operations and our financial statements reflect the effects of the different rate making principles followed by the various jurisdictions regulating our electric operations. If rate recovery becomes unlikely or uncertain due to competition or regulatory action, these accounting standards may no longer apply to our regulated operations. In the event we determine that we no longer meet the criteria for following accounting standards for regulated operations, the accounting impact to us could be an extraordinary non-cash charge to operations in an amount that could be material.

Regulatory assets are included in Regulatory assets, current and Regulatory assets, non-current on the accompanying Balance Sheets. Regulatory liabilities are included in Regulatory liabilities, current and Regulatory liabilities, non-current on the accompanying Balance Sheets.

3032

We had the following regulatory assets and liabilities as follows as of December 31 (in thousands):


	Maximum Recovery Period (in years)	2012		2011		Maximum Recovery Period (in years)	2013		2012
Regulatory assets:
Unamortized loss on reacquired debt^(a)	14	$	2,501	$	2,765	14	$	2,257	$	2,501
AFUDC^(b)	45	8,460		8,552		45	8,327		8,460
Employee benefit plans^(c)	13	27,001		27,602		13	15,233		27,001
Deferred energy costs^(a)	1	6,892		6,605		1	7,711		6,892
Flow through accounting^(a)	35	8,019		5,789		35	9,723		8,019
Other^(a)	2	369		452
Other regulatory assets^(a)						2	2,013		369
Total regulatory assets		$	53,242	$	51,765		$	45,264	$	53,242

Regulatory liabilities:
Cost of removal for utility plant^(a)	53	$	26,630	$	23,347	53	$	30,467	$	26,630
Employee benefit plans^(d)	13	15,689		15,282		13	10,177		15,689
Other^(e)	13	1,567		1,845
Other regulatory liabilities^(e)						13	2,874		1,567
Total regulatory liabilities		$	43,886	$	40,474		$	43,518	$	43,886

____________________

(a)Recovery of costs but not allowed a rate of return.


(b)	In addition to recovery of costs, we are allowed a rate of return.


(c)	In addition to recovery of costs, we are allowed a return on approximately $24 million according to the approved rate case.

~~(c) In addition to recovery of costs, we are allowed a return on approximately~~ ~~$23.5 million~~.


(d)	Approximately $~~13.2~~13 million is included in our rate base calculation as a reduction to rate base.


(e)	Approximately $0.8 million is included in our rate base calculation as a reduction to rate base.

Regulatory assets represent items we expect to recover from customers through probable future rates.

Unamortized Loss on Reacquired Debt- The early redemption premium on reacquired bonds is being amortized over the remaining term of the original bonds.

AFUDC - The equity component of AFUDC is considered a permanent difference for tax purposes with the tax benefit being flowed through to customers as prescribed or allowed by regulators. If, based on a ~~regulator's~~regulator’s action, it is probable the utility will recover the future increase in taxes payable represented by this flow-through treatment through a rate revenue increase, a regulatory asset is recognized. This regulatory asset itself is a temporary difference for which a deferred tax liability must be recognized. Accounting standards for income taxes specifically address AFUDC-equity, and require a gross-up of such amounts to reflect the revenue requirement associated with a rate-regulated environment.

Employee Benefit Plans - Employee benefit plans include the unrecognized prior service costs and net actuarial loss associated with our defined benefit pension plans and post-retirement benefit plans in regulatory assets rather than in accumulated other comprehensive income.

Deferred Energy Costs - Deferred energy and fuel cost adjustments represent the cost of electricity delivered to our utility customers that are either higher or lower than the current rates and will be recovered or refunded in future rates. Deferred energy and fuel cost adjustments are recorded and recovered or amortized as approved by the appropriate state commission.

Flow-Through Accounting - Under flow-through accounting, the income tax effects of certain tax items are reflected in our cost of service for the customer in the year in which the tax benefits are realized and result in lower utility rates. This regulatory treatment was applied to the tax benefit generated by repair costs that were previously capitalized for tax purposes in a rate case settlement that was reached in 2010. In this instance, the agreed upon rate increase was less than it would have been absent the flow-through treatment. A regulatory asset established to reflect the future increases in income taxes payable will be recovered from customers as the temporary differences reverse.

3133

Regulatory liabilities represent items we expect to refund to customers through probable future decreases in rates.

Cost of Removal for Utility Plant - Cost of removal for utility plant represents the estimated cumulative net provisions for future removal costs included in depreciation expense for which there is no legal obligation for removal.

Employee Benefit Plans - Employee benefit plans represent the cumulative excess of pension and retiree healthcare costs recovered in rates over pension expense recorded in accordance with accounting standards for compensation - retirement benefits. In addition, this regulatory liability includes the income tax effect of the adjustment required under accounting for compensation - defined benefit plans, to record the full pension and post-retirement benefit obligations. Such income tax effect has been grossed-up to account for the revenue requirement aspect of a rate regulated environment.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable consist of sales to residential, commercial, industrial, municipal and other customers all of which do not bear interest. These accounts receivable are stated at billed and unbilled amounts net of write-offs or payment received.

We maintain an allowance for doubtful accounts which reflects our best estimate of uncollectible trade receivables. We regularly review our trade receivable allowances by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect collectibility. The allowance is calculated by applying estimated write-off factors to various classes of outstanding receivables, including unbilled revenue. The write-off factors used to estimate uncollectible accounts are based upon consideration of both historical collections experience and ~~management's~~management’s best estimate of future collection success given the existing collections environment.

Following is a summary of accounts receivable at December 31 (in thousands):


	2012			2011			2013			2012
Accounts receivable trade	$	14,965		$	16,447		$	16,300		$	14,965
Unbilled revenues	9,004			8,364			9,719			9,004
Total accounts receivable - customers	23,969			24,811
Allowance for doubtful accounts	(102		)	(143		)	(220		)	(102		)
Net accounts receivable	$	23,867		$	24,668		$	25,799		$	23,867

Revenue Recognition

Revenue is recognized when there is persuasive evidence of an arrangement with a fixed or determinable price, delivery has occurred or services have been rendered, and collectibility is reasonably assured. Taxes collected from our customers are recorded on a net basis (excluded from Revenue).

Utility revenues are based on authorized rates approved by the state regulatory agencies and the FERC. Revenues related to the sale, transmission and distribution of energy, and delivery of service are generally recorded when service is rendered or energy is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, we accrue an estimate of the revenue since the latest billing. This estimate is calculated based upon several factors including billings through the last billing cycle in a month, and prices in effect in our jurisdictions. Each month the estimated unbilled revenue amounts are trued-up and recorded in Receivables- customers, net on the accompanying Balance Sheets.

Materials, Supplies and Fuel

Materials, supplies and fuel used for construction, operation and maintenance purposes are generally stated on a weighted-average cost basis.

Deferred Financing Costs

Deferred financing costs are amortized using the effective interest method over the term of the related debt.

3234

Property, Plant and Equipment

Additions to property, plant and equipment are recorded at cost when placed in service. Included in the cost of regulated construction projects is AFUDC, which represents the approximate composite cost of borrowed funds and a return on equity used to finance a regulated utility project. The cost of regulated electric property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage, is charged to accumulated depreciation. Removal costs associated with non-legal obligations are reclassified from accumulated depreciation and reflected as regulatory liabilities. Ordinary repairs and maintenance of property, except as allowed under rate regulations, are charged to operations as incurred.

Depreciation provisions for regulated electric property, plant and equipment are computed on a straight-line basis using an annual composite rate of ~~2.2%~~2.1% in ~~2012~~2013, 2.2% in ~~2011~~2012 and 2.2% in ~~2010~~2011.

Derivatives and Hedging Activities

From time to time we utilize risk management contracts including forward purchases and sales to hedge the price of fuel for our combustion turbines and fixed-for-float swaps to fix the interest on any variable rate debt. Contracts that qualify as derivatives under accounting standards for derivatives, and that are not exempted such as normal purchase/normal sale, are required to be recorded in the balance sheet as either an asset or liability, measured at its fair value. Accounting standards for derivatives require that changes in the derivative ~~instrument's~~instrument’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met.

Accounting standards for derivatives allow hedge accounting for qualifying fair value and cash flow hedges. Gain or loss on a derivative instrument designated and qualifying as a fair value hedging instrument as well as the offsetting loss or gain on the hedged item attributable to the hedged risk should be recognized currently in earnings in the same accounting period. Conversely, the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument should be reported as a component of other comprehensive income and be reclassified into earnings or as a regulatory asset or regulatory liability, net of tax, in the same period or periods during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, is recognized currently in earnings.

Fair Value Measurements

Accounting standards for fair value measurements provide a single definition of fair value 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 and also requires disclosures and establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The fair value hierarchy ranks the quality and reliability of the information used to determine fair values giving the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).

Financial assets and liabilities carried at fair value are classified and disclosed in one of the following three categories:

Level 1 - Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities.

Level 2 - Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means.

Level 3 - Pricing inputs include significant inputs that are generally less observable from objective sources.

3335

Impairment of Long-Lived Assets

We periodically evaluate whether events and circumstances have occurred which may affect the estimated useful life or the recoverability of the remaining balance of our long-lived assets. If such events or circumstances were to indicate that the carrying amount of these assets was not recoverable, we would estimate the future cash flows expected to result from the use of the assets and their eventual disposition. If the sum of the expected future cash flows (undiscounted and without interest charges) was less than the carrying amount of the long-lived assets, we would recognize an impairment loss.

Income Taxes

We file a federal income tax return with other members of the ~~Parent's~~Parent’s consolidated group. For financial statement purposes, federal income taxes are allocated to the individual companies based on amounts calculated on a separate return basis.

We use the liability method in accounting for income taxes. Under the liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities, as well as operating loss and tax credit carryforwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements. We classify deferred tax assets and liabilities into current and non-current amounts based on the classification of the related assets and liabilities.

It is the ~~Parent's~~Parent’s policy to apply the flow-through method of accounting for investment tax credits. Under the flow-through method, investment tax credits are reflected in net income as a reduction to income tax expense in the year they qualify. Another acceptable accounting method and an exception to this general policy is to apply the deferral method whereby the credit is amortized as a reduction of income tax expense over the useful lives of the related property which gave rise to the credits.

We recognize interest income or interest expense and penalties related to income tax matters in Income tax (expense) benefit on the Statements of Income. We account for uncertainty in income taxes recognized in the financial statements in accordance with accounting standards for income taxes. The unrecognized tax benefit is classified in Other - non-current liabilities on the accompanying Balance Sheets. See Note 76 for additional information.

(2~~) RECENTLY ADOPTED AND RECENTLY ISSUED ACCOUNTING STANDARDS~~

Recently Adopted Accounting Standards

Other Comprehensive Income: Presentation of Comprehensive Income, ASU 2011-05 and Deferral of the Effective Date for Amendments to the Presentation of Reclassification of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update 2011-05 and ASU 2011-12

FASB issued an accounting standards update amending ASC 220 to improve the comparability, consistency and transparency of reporting of comprehensive income. It amends existing guidance by allowing only two options for presenting the components of net income and other comprehensive income: (1) in a single continuous financial statement, statement of comprehensive income or (2) in two separate but consecutive financial statements, consisting of an income statement followed by a separate statement of other comprehensive income. Also, items that are reclassified from other comprehensive income to net income must be presented on the face of the financial statements. ASU No. 2011-05 requires retrospective application, and it is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011, with early adoption permitted. In December 2011, FASB issued ASU 2011-12. ASU 2011-12 indefinitely deferred the provisions of ASU 2011-05 requiring the presentation of reclassification adjustments for items reclassified from other comprehensive income to net income be presented on the face of the financial statements. Ultimately FASB chose not to reinstate the reclassification adjustment requirements in ASU 2011-05 but instead issued ASU 2013-02 in February 2013.

~~We have elected to early adopt the provisions of ASU 2011-05 as amended by ASU 2011-12.~~ The adoption ~~changed the presentation~~ of ~~certain financial statements and provided additional details in notes to the financial statements, but~~this standard did not have ~~any other~~an impact on our financial ~~statements. See the accompanying Comprehensive Income Statement and additional disclosures in Note~~ 8.

position, results of operations or cash flows.

3436

~~Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements, ASU 2011-04~~

In May 2011, FASB issued an accounting standards update amending ASC 820, Fair Value Measurements and Disclosures, to achieve common fair value measurement and disclosure requirements between GAAP and IFRS. Additional disclosure requirements in the update include: (1) for Level 3 fair value measurements - quantitative information about unobservable inputs used, a description of the valuation processes used by the entity, and a qualitative discussion about the sensitivity of the measurements to changes in the unobservable inputs; (2) for an entity’s use of a non-financial asset that is different from the asset’s highest and best use - the reason for the difference; (3) for financial instruments not measured at fair value but for which disclosure of fair value is required - the fair value hierarchy level in which the fair value measurements were determined; and (4) the disclosure of all transfers between Level 1 and Level 2 of the fair value hierarchy. ASU 2011-04 is effective for fiscal years, and interim periods within those years, beginning after December 31, 2011. The amendment required additional details in notes to financial statements, but did not have any other impact on our financial statements. The additional disclosures are included in Note 9.

~~Recently Issued Accounting Pronouncements and Legislation~~

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income, ASU 2013-02

In February 2013, the FASB issued new disclosure requirements for items reclassified out of AOCI to expand the disclosure requirements in ASC 220, Comprehensive Income, for presentation of changes in AOCI. ASU 2013-02 requires disclosure of (1) changes in components of other comprehensive income, (2) for items reclassified out of AOCI and into net income in their entirety, the effect of the reclassification on each affected net income line item and (3) cross references to other disclosures that provide additional detail for components of other comprehensive income that are not reclassified in their entirety to net income. Disclosures are required either on the face of the statements of income or as a separate disclosure in the notes to the financial statements. The new disclosure requirements are effective for interim and annual periods beginning after ~~Dec.~~December 15, 2012. The adoption of this standard ~~will~~did not have an impact on our financial position, results of operations or cash flows.

Recently Issued Accounting Pronouncements and Legislation

Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists

In July 2013, the FASB issued an amendment to accounting for income taxes which provides guidance on financial statement presentation of an unrecognized tax benefit when an NOL carryforward, a similar tax loss, or a tax credit carryforward exists. The objective in issuing this amendment is to eliminate diversity in practice resulting from a lack of guidance on this topic in current GAAP. Under the amendment, an entity must present an unrecognized tax benefit, or a portion of an unrecognized tax benefit, in the financial statements as a reduction to a deferred tax asset for an NOL carryforward, a similar tax loss, or a tax credit carryforward except under certain conditions. The amendment is effective for fiscal years beginning after December 15, 2013, and interim periods within those years and should be applied to all unrecognized tax benefits that exist as of the effective date. The adoption of this standard is not expected to have an impact on our financial position, results of operations or cash flows.

Final Tangible Personal Property Regulations, IRS Treasury Decision 9636

In September 2013, the U.S. Treasury issued final regulations addressing the tax consequences associated with amounts paid to acquire, produce, or improve tangible property. The regulations have the effect of a change in law and as a result the impact should be taken into account in the period of adoption. In general, such regulations apply to tax years beginning on or after January 1, 2014, with early adoption permitted. We expect that implementation of most, if not all, of the provisions of the final regulations to occur in 2014. Procedural guidance is expected from IRS in early 2014 to facilitate implementation. Analysis performed to date indicates no material impact to our financial statements.

(32) PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment at December 31 consisted of the following (dollars in thousands):


				2012				2011						2013				2012
				Weighted				Weighted						Weighted				Weighted
				Average				Average	Lives (in years)					Average				Average	Lives (in years)
	2012			Useful Life (in years)	2011			Useful Life (in years)	Minimum	Maximum	2013			Useful Life (in years)	2012			Useful Life (in years)	Minimum	Maximum
Electric plant:
Production	$	510,674		51	$	504,088		51	45	65	$	512,444		51	$	510,674		51	45	65
Transmission	115,092			46	115,063			47	40	60	115,149			46	115,092			46	40	60
Distribution	304,113			38	289,833			39	16	45	315,971			39	304,113			38	16	45
Plant acquisition adjustment ^(a)	4,870			32	4,870			32	32		4,870			32	4,870			32
General	71,802			22	72,045			21	8	45	70,228			22	71,802			22	8	45
Total plant-in-service											1,018,662				1,006,551
Construction work in progress	18,217				9,873						77,222				18,217
Total electric plant	1,024,768				995,772						1,095,884				1,024,768
Less accumulated depreciation and amortization	(322,830		)		(313,581		)				(334,174		)		(322,830		)
Electric plant net of accumulated depreciation and amortization	$	701,938			$	682,191					$	761,710			$	701,938

__________________


(a)	The plant acquisition adjustment is included in rate base and is being recovered with 1817 years remaining.

(43) JOINTLY OWNED FACILITIES

We use the proportionate consolidation method to account for our percentage interest in the assets, liabilities and expenses of the following facilities:

We own a 20% interest in the Wyodak Plant (the ~~"Plant"~~“Plant”), a coal-fired electric generating station located in Campbell County, Wyoming. PacifiCorp owns the remaining ownership percentage and is the operator of the Plant. We receive our proportionate share of the ~~Plant's~~Plant’s capacity and are committed to pay our share of its additions, replacements and operating and maintenance expenses.

We own a 35% interest in, and are the operator of, the Converter Station Site and South Rapid City Interconnection (the transmission tie), an AC-DC-AC transmission tie. Basin Electric owns the remaining ownership percentage. The transmission tie provides an interconnection between the Western and Eastern transmission grids, which provides us with access to both the WECC region and the MAPP region. The total transfer capacity of the transmission tie is 400 MW - 200 MW West to East and 200 MW from East to West. We are committed to pay our proportionate share of the additions, replacements and operating and maintenance expenses.

We own a 52% interest in the Wygen III power plant. MDU and the City of Gillette each owns an undivided ownership interest in Wygen III and are obligated to make payments for costs associated with administrative services and a proportionate share of the costs of operating the plant for the life of the facility. We retain responsibility for plant operations.

The investments in our jointly owned plants and accumulated depreciation are included in the corresponding captions in the accompanying Balance Sheets. Our share of direct expenses of the Plant is included in the corresponding categories of operating expenses in the accompanying Statements of Income. Each of the respective owners is responsible for providing its own financing.

As of December 31, ~~2012~~2013, our interests in jointly-owned generating facilities and transmission systems included on our Balance Sheets were as follows (in thousands):


Interest in jointly-owned facilities	Plant in Service		Construction Work in Progress		Accumulated Depreciation		Plant in Service		Construction Work in Progress		Accumulated Depreciation
Wyodak Plant	$	109,465	$	451	$	47,776	$	109,800	$	192	$	50,595
Transmission Tie	$	19,648	$	—	$	4,414	$	19,648	$	—	$	4,741
Wygen III	$	130,267	$	565	$	8,376	$	131,468	$	713	$	10,593

(54) LONG-TERM DEBT

Long-term debt outstanding at December 31 was as follows (in thousands):

Maturity Date Interest Rate 2012 2011
First Mortgage Bonds due 2032 August 15, 2032 7.23 % $ 75,000
$ 75,000
First Mortgage Bonds due 2039 November 1, 2039 6.125 % 180,000
180,000
Unamortized discount, First Mortgage Bonds due 2039 (111 ) (115 )
Pollution control revenue bonds due 2014^(a)
October 1, 2014 4.80 % —
6,450
Pollution control revenue bonds due 2024 October 1, 2024 5.35 % 12,200
12,200
Series 94A Debt^(b)
June 1, 2024 1.35 % 2,855
2,855
Other May 25, 2012 13.66 % —
37
Total long-term debt 269,944
276,427
Less current maturities —
(37 )
Net long-term debt $ 269,944
$ 276,390



	Maturity Date	Interest Rate		2013			2012
First Mortgage Bonds due 2032	August 15, 2032	7.23	%	$	75,000		$	75,000
First Mortgage Bonds due 2039	November 1, 2039	6.125	%	180,000			180,000
Unamortized discount, First Mortgage Bonds due 2039				(107		)	(111		)
Pollution control revenue bonds due 2024	October 1, 2024	5.35	%	12,200			12,200
Series 94A Debt^(a)	June 1, 2024	0.75	%	2,855			2,855
Long-term debt				$	269,948		$	269,944

___________________


^(a)	On ~~May 15, 2012~~ ~~we repaid in full~~ ~~$6.5 million~~ ~~principal and interest on the Pollution Control Revenue Bonds originally due to mature on October 1, 2014.~~


^(b)	Variable interest rate ~~of 1.35%~~ at December 31, ~~2012.~~2013.

Net deferred financing costs of approximately $~~2.9~~2.8 million and $~~3.1~~2.9 million were recorded on the accompanying Balance Sheets in Other, non-current assets at December 31, ~~2012~~2013 and ~~2011~~2012, respectively, and are being amortized over the term of the debt. Amortization of deferred financing costs of approximately $~~0.2~~0.1 million, $~~0.5~~0.2 million and $~~0.4~~0.5 million for the years ended December 31, ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011, respectively, are included in Interest expense on the accompanying Statements of Income.

Substantially all of our property is subject to the lien of the indenture securing our first mortgage bonds. First mortgage bonds may be issued in amounts limited by property, earnings and other provisions of the mortgage indentures. We were in compliance with our debt covenants at December 31, ~~2012~~2013.

Long-term Debt Maturities

Scheduled maturities of our outstanding long-term debt (excluding unamortized discounts) are as follows (in thousands):


2013	$	—
2014	$	—	$	—
2015	$	—	$	—
2016	$	—	$	—
2017	$	—	$	—
2018			$	—
Thereafter	$	270,055	$	270,055

3739

(65) FAIR VALUE OF FINANCIAL INSTRUMENTS

The estimated fair values of our financial instruments at December 31 were as follows (in thousands):


	2012				2011				2013				2012
	Carrying Value		Fair Value		Carrying Value		Fair Value		Carrying Value		Fair Value		Carrying Value		Fair Value
Cash and cash equivalents ^(a)	$	3,805	$	3,805	$	2,812	$	2,812	$	2,259	$	2,259	$	3,805	$	3,805
Long-term debt, including current maturities ^(b)	$	269,944	$	359,567	$	276,427	$	362,055	$	269,948	$	317,531	$	269,944	$	359,567

_______________


(a)	Fair value approximates carrying 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. For additional information on our long-term debt, see Note 4 to the Financial Statements.

~~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. For additional information on our long-term debt, see Note 5 to the Financial Statements.~~

The following methods and assumptions were used to estimate the fair value of each class of our financial instruments.

Cash and Cash Equivalents

Included in cash and cash equivalents is cash and overnight repurchase agreement accounts. As part of our cash management process, excess operating cash is invested in overnight repurchase agreements with our bank. Repurchase agreements are not deposits and are not insured by the U.S. Government, the FDIC or any other government agency and involve investment risk including possible loss of principal. We believe however, that the market risk arising from holding these financial instruments is minimal.

(76) INCOME TAXES

Income tax expense (benefit) from continuing operations for the years ended December 31 ~~was~~were as follows (in thousands):


	2012			2011			2010			2013			2012			2011
Current	$	(10,319	)	$	14,921		$	(14,885	)	$	(163	)	$	(10,319	)	$	14,921
Deferred	24,628			(2,931		)	25,626			13,582			24,628			(2,931		)
Total income tax expense	$	14,309		$	11,990		$	10,741		$	13,419		$	14,309		$	11,990

3840

The temporary differences which gave rise to the net deferred tax liability, for the years ended December 31 were as follows (in thousands):


	2012			2011			2013			2012
Deferred tax assets:
Employee benefits	$	5,094		$	5,008		$	4,567		$	5,094
Net operating loss	10,441			28,072			4,197			10,441
Regulatory liabilities	13,433			14,644			6,398			13,433
Other	2,381			3,049			2,193			2,381
Valuation allowance	—			—
Total deferred tax assets	31,349			50,773			17,355			31,349

Deferred tax liabilities:
Accelerated depreciation and other plant related differences	(154,989		)	(148,254		)	(161,990		)	(154,989		)
AFUDC	(5,499		)	(5,559		)	(8,190		)	(5,499		)
Regulatory assets	(5,767		)	(5,019		)	(3,540		)	(5,767		)
Employee benefits	(3,610		)	(2,356		)	(3,467		)	(3,610		)
Deferred costs							(4,240		)	(2,608		)
Other	(3,771		)	(3,753		)	(1,067		)	(1,163		)
Total deferred tax liabilities	(173,636		)	(164,941		)	(182,494		)	(173,636		)

Net deferred tax assets (liabilities)	$	(142,287	)	$	(114,168	)	$	(165,139	)	$	(142,287	)

The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows:


	2012		2011		2010		2013		2012		2011
Federal statutory rate	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%
Amortization of excess deferred and investment tax credits	(0.3	)	(0.4	)	(0.6	)	(0.3	)	(0.3	)	(0.4	)
Equity AFUDC	(0.1	)	(0.6	)	(2.0	)	—		(0.1	)	(0.6	)
Flow through adjustments *	(3.5	)	(3.4	)	(7.4	)	(2.5	)	(3.5	)	(3.4	)
Prior year deferred adjustment	3.6		—		—
Prior year deferred adjustment ^**							—		3.6		—
Tax credits							(0.8	)	—		—
Other	(0.1	)	0.1		0.6		(0.6	)	(0.1	)	0.1
	34.6	%	30.7	%	25.6	%	30.8	%	34.6	%	30.7	%

_________________________

The flow-through adjustments relate primarily to an accounting method change for tax purposes that ~~was filed with the 2008 tax return and for which consent was received from the IRS in September 2009. The effect of the change~~ allows us to take a current tax deduction for repair costs that ~~were previously capitalized for tax purposes. These costs will~~ continue to be capitalized for book purposes. We recorded a deferred income tax liability in recognition of the temporary difference created between book and tax treatment and we flowed the tax benefit through to our customers in the form of lower rates as a result of a rate case settlement that occurred during 2010. A regulatory asset was established to reflect the recovery of future increases in taxes payable from customers as the temporary differences reverse. ~~Due to~~As a result of this regulatory treatment, we ~~recorded an income tax benefit in 2010 that was attributable to the 2008 through 2010 tax years. We~~ continue to record a tax benefit consistent with the flow through ~~method in accordance with~~method.


**	The adjustment was a non-recurring unfavorable true-up attributable to property related deferred income taxes. The removal of the impact of such ~~regulatory treatment.~~an adjustment is more appropriately reflective of the effective rate on a recurring basis.

The following table reconciles the total amounts of unrecognized tax benefits, atwithout interest, included in Other deferred credits and other liabilities on the ~~beginning and end of the period~~accompanying Balance Sheet (in thousands):


	2012			2011			2013			2012
Unrecognized tax benefits at January 1	$	3,595		$	3,094		$	2,078		$	3,595
Additions for prior year tax positions	—			795
Reductions for prior year tax positions	(1,586		)	(294		)	(155		)	(1,586		)
Additions for current year tax positions	69			—			520			69
Unrecognized tax benefits at December 31	$	2,078		$	3,595		$	2,443		$	2,078

3941

The reductions for prior year tax positions relate to the reversal ~~attributable to~~through otherwise allowed tax depreciation. The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $~~0.7~~0.5 million. ~~The unrecognized tax benefit is classified in Other, non-current liabilities on the accompanying Balance Sheets.~~

~~During the year ended~~ ~~December 31, 2012~~ ~~and~~ ~~2011, the~~It is our continuing practice to recognize interest ~~expense recognized~~and/or penalties related to income tax matters in income tax expense. During the years ended December 31, 2013 and 2012, the interest expense recognized was not material to our financial results.

We file income tax returns in the United States federal jurisdictions as a member of the BHC consolidated group. We do not anticipate that total unrecognized tax benefits will significantly change due to ~~the~~ settlement of any audits or the expiration of statutes of limitations prior to December 31, ~~2013~~.2014.

At December 31, ~~2012~~2013, we have federal NOL carry forward of $~~30.5~~14 million, expiring in ~~2031~~.2031. Ultimate usage of this NOL depends upon our ability to generate future taxable income, which is expected to occur within the prescribed carryforward period.

(87) ~~ACCUMULATED OTHER~~ COMPREHENSIVE INCOME

~~Balances by classification~~The components of the reclassification adjustments for the period, net of tax, included ~~within Accumulated other comprehensive loss on the accompanying Balance Sheets~~in Other Comprehensive Income were as follows (in thousands):

Derivatives Designated as Cash Flow Hedges Employee Benefit Plans Total
As of December 31, 2011 $ (801 ) $ (489 ) $ (1,290 )
Other comprehensive income (loss) 41
(171 ) (130 )
As of December 31, 2012 $ (760 ) $ (660 ) $ (1,420 )

As of December 31, 2010 $ (843 ) $ (419 ) $ (1,262 )
Other comprehensive income (loss) 42
(70 ) (28 )
As of December 31, 2011 $ (801 ) $ (489 ) $ (1,290 )



	Derivatives Designated as Cash Flow Hedges	Amounts Reclassified from AOCI
		2013			2012
Gains and Losses on cash flow hedges
Interest rate swaps	Interest expense	$	64		$	64
Income tax	Income tax benefit (expense)	(23		)	(23		)
Total reclassification adjustments related to cash flow hedges, net of tax		$	41		$	41

Amortization of defined benefit plans:
Actuarial gain (loss)	Operations and maintenance	$	66		$	—
Income tax	Income tax benefit (expense)	(23		)	—
Total reclassification adjustments related to defined benefit plans, net of tax		$	43		$	—

Derivatives designated as cash flow hedges relate to a treasury lock entered into in August 2002 to hedge ~~a portion~~$50 million of ~~the~~ ~~$75.0 million~~our First Mortgage Bonds due on August 15, 2032. The treasury lock cash settled on August 8, 2002, the bond pricing date, and resulted in a $1.8 million loss. The treasury lock is treated as a cash flow hedge and the resulting loss is carried in Accumulated Other Comprehensive Loss and is being amortized over the life of the related bonds.

Balances by classification included within Accumulated other comprehensive loss on the accompanying Balance Sheets were as follows (in thousands):



	Derivatives Designated as Cash Flow Hedges
	Interest Rate Swaps			Employee Benefit Plans			Total

As of December 31, 2012	$	(760	)	$	(660	)	$	(1,420	)
Other comprehensive income (loss)	41			182			223
As of December 31, 2013	$	(719	)	$	(478	)	$	(1,197	)

	Derivatives Designated as Cash Flow Hedges
	Interest Rate Swaps			Employee Benefit Plans			Total

As of December 31, 2011	$	(801	)	$	(489	)	$	(1,290	)
Other comprehensive income (loss)	41			(171		)	(130		)
As of December 31, 2012	$	(760	)	$	(660	)	$	(1,420	)

(98) EMPLOYEE BENEFIT PLANS

Funded Status of Benefit Plans

The funded status of the postretirement benefit plan is required to be recognized in the statement of financial position. The funded status for the pension plan is measured as the difference between the projected benefit obligation and the fair value of plan assets. The funded status for all other benefit plans is measured as the difference between the accumulated benefit obligation and the fair value of plan assets. A liability is recorded for an amount by which the benefit obligation exceeds the fair value of plan assets or an asset is recorded for any amount by which the fair value of plan assets exceeds the benefit obligation. The measurement date of the plans is December 31, our year-end balance sheet date. As of December 31, ~~2012~~2013, the ~~funded~~unfunded status of our Defined Benefit Pension Plan was $~~(16.4)~~3.8 million, the ~~funded~~unfunded status of our Supplemental Non-qualified Defined Benefit Plans was $~~(3.4)~~3.1 million and the ~~funded~~unfunded status of our Non-pension Defined Benefit Postretirement Healthcare Plans was $~~(6.8)~~5.9 million.

We apply accounting standards for regulated operations, and accordingly, the unrecognized net periodic benefit cost that would have been reclassified to Accumulated other comprehensive income (loss) was alternatively recorded as a regulatory asset or regulatory liability, net of tax.

Defined Benefit Pension Plan

We have a noncontributory defined benefit pension plan ("(“Pension ~~Plan"~~Plan”) covering employees who meet certain eligibility requirements. The benefits are based on years of service and compensation levels during the highest five consecutive years of the last ten years of service. Our funding policy is in accordance with the federal ~~government's~~government’s funding requirements. The Pension ~~Plan's~~Plan’s assets are held in trust and consist primarily of equity and fixed income investments.

The Pension Plan has been frozen to new employees and certain employees who did not meet age and service based criteria at the time the Plan was frozen. Plan benefits are based on years of service and calculations of average earnings during a specific time period prior to retirement.

As of December 31, 2012, certain Plan investments were transferred to a Master Trust that was established for the investment of assets of the Plan and other Employer-sponsored retirement plans. Each participating retirement plan has an undivided interest in the Master Trust.

On October 29, 2012, the Board of Directors approved a new Investment Policy. The objective of the Investment Policy is to manage assets in such a way that will allow the eventual settlement of our obligations to the Plans’ beneficiaries. To meet this objective, our pension plan assets are managed by an outside adviser using a ~~structured~~ portfolio strategy that will provide liquidity to meet the Plans’ benefit payment obligations and an asset allocation that will comprise a mix of return-seeking and liability-hedging assets. Our Pension Plan funding policy is in accordance with the federal government’s funding requirements. The Pension ~~Plan's~~Plan’s assets are held in trust and consist primarily of equity, ~~and~~ fixed income and hedged investments. The expected long-term rate of return for investments was 7.25% and ~~8.75%~~7.25% for the ~~2012~~2013 and ~~2011~~2012 plan years, respectively.

Pension Plan Assets

The percentages of total plan asset fair value by investment category of our Pension Plan assets at December 31 were as follows:


	2012		2011		2013		2012
Equity securities	51	%	69	%	26	%	51	%
Real estate					4	%	—	%
Fixed income funds	48	%	28	%	58	%	48	%
Cash and cash equivalents	1	%	3	%	1	%	1	%
Hedge funds					11	%	—	%
Total	100	%	100	%	100	%	100	%

Supplemental Non-qualified Defined Benefit Retirement Plans

We have various supplemental retirement plans ("(“Supplemental ~~Plans"~~Plans”) for key executives. The Supplemental Plans are non-qualified defined benefit plans. The Supplemental Plans are subject to various vesting schedules.

Supplemental Plan Assets

We do not fund our Supplemental Plans. We fund on a cash basis as benefits are paid.

Non-pension Defined Benefit Postretirement Healthcare Plan

Employees who are participants in our Non-Pension Postretirement Healthcare Plan ("(“Healthcare ~~Plan"~~Plan”) and who retire on or after attaining minimum age and years of service requirements are entitled to postretirement healthcare benefits. These benefits are subject to premiums, deductibles, co-payment provisions and other limitations. We may amend or change the Healthcare Plan periodically. We are not pre-funding our retiree medical plan. We have determined that the Healthcare ~~Plan's~~Plan’s post-65 retiree prescription drug plans are actuarially equivalent and qualify for the Medicare Part D subsidy.

Plan Assets

We do not fund our Healthcare Plans. We fund on a cash basis as benefits are paid.

4144

Plan Contributions and Estimated Cash Flows

Contributions made to the Pension Plans are cash contributions made directly to the Pension Plan Trust accounts. Healthcare and Supplemental Plan contributions are made in the form of benefit payments. Contributions for the years ended December 31 were as follows (in thousands):


	2012		2011		2013		2012
Defined Benefit Plans
Defined Benefit Pension Plan	$	6,835	$	—	$	2,299	$	6,835
Non-pension Defined Benefit Postretirement Healthcare Plan	$	835	$	428	$	578	$	835
Supplemental Non-qualified Defined Benefit Plan	$	256	$	130	$	217	$	256

Defined Contribution Plans
Company Retirement Contribution	$	404	$	371	$	421	$	404
Matching Contributions	$	1,328	$	1,296	$	1,301	$	1,328

We ~~expect~~do not intend to make a contribution of ~~$1.6 million~~ to our employee defined benefit pension plan in ~~2013~~2014.

Fair Value Measurements

As required by accounting standards for fair value measurements, assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect their placement within the fair value hierarchy levels. The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value on a recurring basis as of December 31 (in thousands):


Defined Benefit Pension Plan	2012								2013
	Level 1		Level 2		Level 3		Total Fair Value		Level 1		Level 2		Level 3		Total Fair Value
Cash and cash equivalents	$	535	$	—	$	—	$	535
AXA Equitable General Fixed Income									$	—	$	213	$	—	$	213
Common Collective Trust - Cash and Cash Equivalents									—		252		—		252
Common collective trust - equity	—		27,267		—		27,267		—		14,833		—		14,833
Common collective trust - fixed income	—		21,127		—		21,127		—		32,742		—		32,742
Insurance contracts	—		—		—		—
Structured products	—		4,536		—		4,536
Common collective trust - real estate									—		682		1,718		2,400
Hedge funds									—		—		5,965		5,965
Total investments measured at fair value	$	535	$	52,930	$	—	$	53,465	$	—	$	48,722	$	7,683	$	56,405


Defined Benefit Pension Plan	2011								2012
	Level 1		Level 2		Level 3		Total Fair Value		Level 1		Level 2		Level 3		Total Fair Value
Cash and cash equivalents	$	40	$	—	$	—	$	40	$	535	$	—	$	—	$	535
Registered investment companies - equity	12,743		—		—		12,743
Registered investment companies - fixed income	12,603		—		—		12,603
Common collective trust - equity	—		16,143		—		16,143		—		27,267		—		27,267
Insurance contracts	—		1,288		—		1,288
Common collective trust - fixed income									—		21,127		—		21,127
Structured products	—		2,200		—		2,200		—		4,536		—		4,536
Total investments measured at fair value	$	25,386	$	19,631	$	—	$	45,017	$	535	$	52,930	$	—	$	53,465

~~Registered Investment Companies:~~ ~~Investments are valued at the closing price reported on the active market on which the individual securities are traded.~~

4245

Cash and Cash Equivalents: This category is comprised of theAXA Equitable General Fixed Income Fundwand Common Collective Trusts - cash and cash equivalents. The AXA Equitable General Fixed Income Fund is a fund of diversified portfolios, primarily composed of fixed income instruments. Assets are invested in long-term holdings, such as commercial, agricultural and residential mortgages, publicly traded and privately place bonds and real estate as well as short-term bonds. Fair values of mortgage loans are measured by discounting future contractual cash flows to be received on the mortgage loans using interest rates at which loans with similar characteristics. The discount rate is derived from taking the appropriate U.S. Treasury rate with a like term. The fair value of public fixed maturity securities are generally based on prices obtained from independent valuation service provides with reasonableness prices compared with directly observable market trades. The fair value of privately placed securities are determined using a discounted cash flow model. These models use observable inputs with a discount rate based upon the average of spread surveys collected from private market intermediaries and industry sector of the issuer.

Common Collective Trust: The Pension Plan owns units of the Common Collective Trust funds that they are utilizing in their portfolio. The value of each unit of any fund as of any valuation date shall be determined by calculating the total value of such ~~fund's~~fund’s assets as of the close of business on such valuation date, deducting its total liabilities as of such time and date, and then dividing the so-determined net asset value of such fund by the total number of units of such fund outstanding on the date of valuation.

~~Insurance Contract:~~ Common Collective Trust-Real Estate Fund~~These~~: This fund is valued based on various factors of the underlying real estate properties, including market rent, market rent growth, occupancy levels, etc. As part of the trustee’s valuation process, properties are externally appraised generally on an annual basis. The appraisals are conducted by reputable independent appraisal firms and signed by appraisers that are members of the Appraisal Institute, with professional designation of Member, Appraisal Institute. All external appraisals are performed in accordance with the Uniform Standards of Professional Appraisal Practices. We receive monthly statements from the trustee, along with the annual schedule of investments, and rely on these reports for pricing the units of the fund. Certain of the funds’ assets contain participant withdrawal policy and, therefore, are ~~valued~~categorized as Level 3. The funds without participant withdrawal limitations are categorized as Level 2.

Hedge Funds: Hedge funds represent investments in other investment funds that seek a return utilizing a number of diverse investment strategies. The strategies, when combined aim to reduce volatility and risk while attempting to deliver positive returns under all market conditions. Amounts are reported on a ~~cash basis~~one-month lag. The fair value of hedge funds is determined using net asset value per share based on ~~any given valuation date which approximates~~the fair ~~value.~~value of the hedge fund’s underlying investments. Generally, shares may be redeemed at the end of each quarter, after a lockup period of one-year, with a 65 day notice and is limited to a percentage of total net asset value of the fund. The net asset values are based on the fair value of each fund’s underlying investments. There are no unfunded commitments related to these hedge funds.

Structured Products: Investments are created through the process of financial engineering (that is, by combining underlying securities like equity, bonds, or indices with derivatives). The value of derivative securities, such as options, forwards and swaps is determined by (respectively, derives from) the prices of the underlying securities.

The following table sets forth a summary of changes in the fair value of the Defined Benefit Pension Plans’ Level 3 assets for the period ended December 31 (in thousands):



	2013
Balance, beginning of period	$	—
Transfers	1,550
Purchase	5,834
Unrealized gain (loss)	317
Realized gain (loss)	(3		)
Settlements	(15		)
Balance, end of period	$	7,683

The following table presents the quantitative information about Level 3 fair value measurements (dollars in thousands):



	Fair Value at		Valuation	Level 3	Range (Weighted)
	December 31, 2013		Technique	Input	Average
Assets:
Common Collective Trust - Real Estate ^(a)	$	1,718	Market Approach	Redemption Restriction	N/A
Hedge Funds ^(b)	$	5,965	Market Approach	Redemption Restriction	N/A

_____________

(a)

The underlying net asset value in the Common Collective Trust - Real Estate fund is determined by appraisal of the properties held in the Trust. As part of the Trustee's valuation process, properties are externally appraised generally on an annual basis. The appraisals are conducted by reputable independent appraisal firms and signed by appraisers that are members of the Appraisal Institute, with the professional designation of Member, Appraisal Institute. All external appraisals are performed in accordance with the Uniform Standards of Professional Appraisal Practices. We receive monthly statements from the Trustee along with the annual schedule of investments and rely on these reports for pricing the units of the fund. The fund does contain a participant withdrawal policy.

(b)

The fair value of Level 3 is determined based on pricing provided or reviewed by third-party administrator to our investment managers. While the input amounts used by the pricing vendor in determining fair value are not provided, and therefore, unavailable for our review, the asset results are reviewed and monitored to ensure the fair values are reasonable and in line with market experience in similar asset classes. Additionally, the audited financial statements of the funds will be reviewed at the time they are issued.

Plan Reconciliations

The following tables provide a reconciliation of the Employee Benefit ~~Plan's~~Plan’s obligations and fair value of assets, components of the net periodic expense and elements of regulatory assets and liabilities and AOCI (in thousands):

Benefit Obligations


	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Healthcare Plan						Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Healthcare Plan
	2012			2011			2012			2011			2012			2011			2013			2012			2013			2012			2013			2012
Change in benefit obligation:
Projected benefit obligation at beginning of year	$	65,557		$	57,753		$	2,292		$	2,152		$	8,207		$	7,517		$	69,820		$	65,557		$	3,427		$	2,292		$	6,766		$	8,207
Service cost	765			798			—			—			214			210			852			765			—			—			216			214
Interest cost	2,969			3,092			104			114			343			365			2,969			2,969			133			104			239			343
Actuarial loss (gain)	4,510			852			1,287			(30		)	(1,748		)	(308		)	(7,818		)	4,510			(212		)	1,287			(459		)	(1,748		)
Amendments(a)	—			—			—			—			—			—			—			—			—			—			(342		)	—
Change in participant assumptions	—			—			—			—			—			171
Discount rate change	—			6,668			—			186			—			433
Benefits paid	(2,850		)	(2,899		)	(256		)	(130		)	(835		)	(707		)	(4,850		)	(2,850		)	(217		)	(256		)	(1,045		)	(835		)
Asset transfer (to) from affiliate	(1,131		)	(707		)	—			—			26			(40		)	(750		)	(1,131		)	—			—			(75		)	26
Plan curtailment reduction	—			—			—			—			—			—			—			—			—			—			—			—
Medicare Part D adjustment	—			—			—			—			71			67			—			—			—			—			82			71
Plan participants' contributions	—			—			—			—			488			499
Plan participants’ contributions																			—			—			—			—			468			488

Projected benefit obligation at end of year	$	69,820		$	65,557		$	3,427		$	2,292		$	6,766		$	8,207		$	60,223		$	69,820		$	3,131		$	3,427		$	5,850		$	6,766

_______________


(a)	Reflects Board of Directors approval of increase to Company’s contribution to RMSA account.

A reconciliation of the fair value of Plan assets (as of the December 31 measurement date) is as follows (in thousands):


	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Retirement Plans				Non-pension Defined Benefit Postretirement Healthcare Plan				Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Retirement Plans				Non-pension Defined Benefit Postretirement Healthcare Plan
	2012			2011			2012		2011		2012		2011		2013			2012			2013		2012		2013		2012
Beginning market value of plan assets	$	45,017		$	48,228		$	—	$	—	$	—	$	—	$	53,465		$	45,017		$	—	$	—	$	—	$	—
Investment income	5,240			66			—		—		—		—		6,070			5,240			—		—		—		—
Benefits paid	(2,850		)	(2,899		)	—		—		—		—		(4,850		)	(2,850		)	—		—		—		—
Employer contributions	6,835			—			—		—		—		—		2,299			6,835			—		—		—		—
Asset transfer to affiliate	(777		)	(378		)	—		—		—		—		(579		)	(777		)	—		—		—		—
Ending market value of plan assets	$	53,465		$	45,017		$	—	$	—	$	—	$	—	$	56,405		$	53,465		$	—	$	—	$	—	$	—

Amounts recognized in the Balance Sheets at December 31 consist of (in thousands):


	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Plan						Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Plan
	2012			2011			2012			2011			2012			2011			2013			2012			2013			2012			2013			2012
Regulatory asset (liability)	$	26,683		$	27,284		$	—		$	—		$	(2,174	)	$	(590	)	$	13,735		$	26,683		$	—		$	—		$	2,781		$	(2,174	)
Current (liability)	$	—		$	—		$	(216	)	$	(154	)	$	(438	)	$	(658	)	$	—		$	—		$	(216	)	$	(216	)	$	(491	)	$	(438	)
Non-current (liability)	$	(16,356	)	$	(20,540	)	$	(3,211	)	$	(3,060	)	$	(6,321	)	$	(7,497	)	$	(3,818	)	$	(16,356	)	$	(2,915	)	$	(3,211	)	$	(5,372	)	$	(6,321	)

Accumulated Benefit Obligation (dollars in thousands)

Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Retirement Plans Non-pension Defined Benefit Postretirement Healthcare Plan
2012 2011 2012 2011 2012 2011
Accumulated benefit obligation $ 63,417
$ 59,823
$ 3,427
$ 2,292
$ 6,766
$ 8,207



	Defined Benefit Pension Plan				Supplemental Non-qualified Defined Benefit Retirement Plans				Non-pension Defined Benefit Postretirement Healthcare Plan
	2013		2012		2013		2012		2013		2012
Accumulated benefit obligation	$	55,283	$	63,417	$	3,131	$	3,427	$	5,850	$	6,766

Components of Net Periodic Expense (dollars in thousands)


	Defined Benefit Pension Plan									Supplemental Non-qualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Healthcare Plan									Defined Benefit Pension Plan									Supplemental Non-qualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Healthcare Plan
	2012			2011			2010			2012		2011		2010		2012			2011			2010			2013			2012			2011			2013		2012		2011		2013			2012			2011
Service cost	$	765		$	798		$	1,214		$	—	$	—	$	—	$	214		$	210		$	340		$	852		$	765		$	798		$	—	$	—	$	—	$	216		$	214		$	210
Interest cost	2,969			3,092			3,280			104		114		100		343			365			547			2,969			2,969			3,092			133		104		114		239			343			365
Expected return on assets	(3,139		)	(3,619		)	(3,008		)	—		—		—		—			—			—			(3,764		)	(3,139		)	(3,619		)	—		—		—		—			—			—
Amortization of prior service cost (credits)	57			62			62			—		—		—		(278		)	(314		)	(141		)	43			57			62			—		—		—		(278		)	(278		)	(314		)
Amortization of transition obligation	—			—			—			—		—		—		—			—			171			2,609			—			—			—		—		—		—			—			—
Recognized net actuarial loss (gain)	2,599			1,486			1,378			55		48		30		139			163			—			—			2,599			1,486			66		55		48		9			139			163
Curtailment expense	—			—			57			—		—		—		—			—			—			—			—			—			—		—		—		—			—			—
Net periodic expense	$	3,251		$	1,819		$	2,983		$	159	$	162	$	130	$	418		$	424		$	917		$	2,709		$	3,251		$	1,819		$	199	$	159	$	162	$	186		$	418		$	424

Accumulated Other Comprehensive Income (Loss)

Amounts included in AOCI, after-tax, that have not yet been recognized as components of net periodic benefit cost at December 31 were as follows (in thousands):


	Defined Benefit Pension Plan				Supplemental Non-qualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Healthcare Plan				Defined Benefit Pension Plan				Supplemental Non-qualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Healthcare Plan
	2012		2011		2012			2011			2012		2011		2013		2012		2013			2012			2013		2012
Net loss	$	—	$	—	$	(660	)	$	(489	)	$	—	$	—	$	—	$	—	$	(479	)	$	(660	)	$	—	$	—
Prior service cost	—		—		—			—			—		—		—		—		—			—			—		—

Total accumulated other comprehensive income (loss)	$	—	$	—	$	(660	)	$	(489	)	$	—	$	—	$	—	$	—	$	(479	)	$	(660	)	$	—	$	—

The amounts in AOCI, regulatory assets or regulatory liabilities, after-tax, expected to be recognized as a component of net periodic benefit cost during calendar year ~~2013~~2014 were as follows (in thousands):


	Defined Benefits Pension Plan		Supplemental Non-qualified Defined Benefit Retirement Plans		Non-pension Defined Benefit Postretirement Healthcare Plan			Defined Benefits Pension Plan		Supplemental Non-qualified Defined Benefit Retirement Plans		Non-pension Defined Benefit Postretirement Healthcare Plan
Net loss	$	1,696	$	43	$	6		$	611	$	29	$	—
Prior service cost	27		—		(181		)	28		—		(206		)

Total net periodic benefit cost expected to be recognized during calendar year 2013	$	1,723	$	43	$	(175	)
Total net periodic benefit cost expected to be recognized during calendar year 2014								$	639	$	29	$	(206	)

Assumptions


	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Healthcare Plan						Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Healthcare Plan
	2012		2011		2010		2012		2011		2010		2012		2011		2010		2013		2012		2011		2013		2012		2011		2013		2012		2011
Weighted-average assumptions used to determine benefit obligations:
Discount rate	4.35	%	4.65	%	5.50	%	4.25	%	4.70	%	5.50	%	3.65	%	4.35	%	5.00	%	5.10	%	4.35	%	4.65	%	4.68	%	4.25	%	4.70	%	4.45	%	3.65	%	4.35	%
Rate of increase in compensation levels	3.91	%	3.67	%	3.70	%	N/A		N/A		5.00	%	N/A		N/A		N/A		3.86	%	3.91	%	3.67	%	N/A		N/A		N/A		N/A		N/A		N/A

Weighted-average assumptions used to determine net periodic benefit cost for plan year:
Discount rate	4.65	%	5.50	%	6.05	%	4.70	%	5.00	%	6.10	%	4.35	%	5.00	%	5.90	%	4.35	%	4.65	%	5.50	%	3.88	%	4.70	%	5.00	%	3.65	%	4.35	%	5.00	%
Expected long-term rate of return on assets*	7.25	%	7.75	%	8.00	%	N/A		N/A		N/A		N/A		N/A		N/A		7.25	%	7.25	%	7.75	%	N/A		N/A		N/A		N/A		N/A		N/A
Rate of increase in compensation levels	3.67	%	3.70	%	4.25	%	N/A		N/A		5.00	%	N/A		N/A		N/A		3.91	%	3.67	%	3.70	%	N/A		N/A		N/A		N/A		N/A		N/A

_____________________________


*	The expected rate of return on plan assets is ~~7.25%~~6.75% for the calculation of the ~~2013~~2014 net periodic pension cost.

The healthcare benefit obligation was determined at December 31 as follows:


	2012		2011		2013		2012
Healthcare trend rate pre-65
Trend for next year	7.75	%	9.01	%	7.50	%	7.75	%
Ultimate trend rate	4.50	%	4.50	%	4.50	%	4.50	%
Year Ultimate Trend Reached	2027		2027		2027		2027

Healthcare trend rate post-65
Trend for next year	6.50	%	9.01	%	6.25	%	6.50	%
Ultimate trend rate	4.50	%	4.50	%	4.50	%	4.50	%
Year Ultimate Trend Reached	2026		2027		2026		2026

We do not pre-fund our post-retirement benefit plan. The table below shows the estimated impacts of an increase or decrease to our healthcare trend rate for our Retiree Health Care Plan (dollars in thousands):


Change in Assumed Trend Rate	Service and Interest Costs			Accumulated Periodic Postretirement Benefit Obligation			Service and Interest Costs			Accumulated Periodic Postretirement Benefit Obligation
1% increase	$	11		$	278		$	9		$	179
1% decrease	$	(10	)	$	(250	)	$	(9	)	$	(165	)

The following benefit payments, which reflect future service, are expected to be paid (in thousands):


	Defined Benefit Pension Plan		Supplemental Non-qualified Defined Benefit Retirement Plans		Non-pension Defined Benefit Postretirement Healthcare Plan		Defined Benefit Pension Plan		Supplemental Non-qualified Defined Benefit Retirement Plans		Non-pension Defined Benefit Postretirement Healthcare Plan
2013	$	3,150	$	216	$	438
2014	$	3,227	$	215	$	489	$	3,177	$	217	$	491
2015	$	3,325	$	212	$	455	$	3,227	$	214	$	432
2016	$	3,417	$	181	$	469	$	3,270	$	184	$	410
2017	$	3,516	$	212	$	498	$	3,367	$	213	$	418
2018-2021	$	20,144	$	1,187	$	2,728
2018							$	3,483	$	210	$	473
2019-2023							$	20,002	$	1,271	$	2,483

Defined Contribution Plan

The Parent sponsors a 401(k) retirement savings plan in which our employees may participate. Participants may elect to invest up to 50% of their eligible compensation on a pre-tax or after-tax basis, up to a maximum amount established by the Internal Revenue Service. The plan provides for company matching contributions and company retirement contributions. Employer contributions vest at 20% per year and are fully vested when the participant has 5 years of service.

(109) RELATED-PARTY TRANSACTIONS

Non-Cash Dividend to Parent

We have recorded a non-cash dividend to our Parent for approximately $8.0 million and $~~44.0~~44 million in 2013 and 2012 and decreased the utility money pool note receivable, net for ~~the amount of~~approximately $8.0 million and $~~44.0~~44 million., in 2013 and 2012 respectively.

Receivables and Payables

We have accounts receivable and accounts payable balances related to transactions with other BHC subsidiaries. These balances as of December 31 were as follows (in thousands):


	2012		2011		2013		2012
Receivable - affiliates	$	5,027	$	6,998	$	4,934	$	5,027
Accounts payable - affiliates	$	21,896	$	18,598	$	21,082	$	21,896

Money Pool Notes Receivable and Notes Payable

We have a Utility Money Pool Agreement (the Agreement) with ~~the Parent.~~BHC, Cheyenne Light and Black Hills Energy. Under the agreement, we may borrow from BHC however the ~~Parent. The~~ Agreement restricts us from loaning funds to ~~the Parent~~BHC or to any of ~~the Parent's~~BHCs’ non-utility ~~subsidiaries; the~~subsidiaries. The Agreement does not restrict us from making dividends to ~~the Parent.~~BHC. Borrowings under the agreement bear interest at the weighted average daily cost of ~~external funds~~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 rate plus 1%1.0%.

~~Advances~~The cost of borrowing under ~~this notes receivable bear interest at~~the Utility Money Pool was ~~1.50%~~ ~~above the daily LIBOR rate (1.71%~~1.60% at December 31, ~~2012~~2013).

We had the following balances with the Utility Money Pool as of ~~and~~December 31 (in thousands):

Net interest income (expense) relating to the Utility Money Pool for the years ended December 31, was as follows (in thousands):

Utility Money Pool 2012 2011 2010
Notes receivable (payable), net $ 31,645
$ 50,477
$ 39,862

Net interest income (expense) $ 617
$ 1,414
$ 467



	2013		2012		2011
Net interest income (expense)	$	505	$	617	$	1,414

Other Balances and Transactions

We have the following Power Purchase and Transmission Services Agreements with affiliated entities:

Cheyenne Light entered into a PPA with Happy Jack. Under a separate inter-company agreement expiring on September 3, 2028, Cheyenne Light has agreed to sell up to 15 MW of the facility output from Happy Jack to us.

Cheyenne Light entered into a PPA with Silver Sage. Under a separate inter-company agreement expiring on September 30, 2029, Cheyenne Light has agreed to sell 20 MW of energy from Silver Sage to us.

A Generation Dispatch Agreement with Cheyenne Light that requires us to purchase all of Cheyenne ~~Light's~~Light’s excess energy.

We had the following related party transactions for the years ended December 31 included in the corresponding captions in the accompanying Statements of Income:


	2012		2011		2010		2013		2012		2011
	(in thousands)						(in thousands)
Revenues:
Energy sold to Cheyenne Light	$	2,372	$	957	$	1,200	$	1,338	$	2,372	$	957
Rent from electric properties	$	2,661	$	7,523	$	7,884	$	3,627	$	2,661	$	7,523

Purchases:
Purchase of coal from WRDC	$	20,690	$	21,319	$	13,569	$	18,542	$	20,690	$	21,319
Purchase of excess energy from Cheyenne Light	$	3,139	$	4,127	$	4,126	$	3,640	$	3,139	$	4,127
Purchase of renewable wind energy from Cheyenne Light - Happy Jack	$	1,988	$	1,955	$	2,815	$	1,886	$	1,988	$	1,955
Purchase of renewable wind energy from Cheyenne Light - Silver Sage	$	3,269	$	3,281	$	1,723	$	3,207	$	3,269	$	3,281
Purchase of natural gas - other	$	7	$	647	$	1,652
Corporate support services from Parent, Black Hills Service Company and Black Hills Utility Holdings	$	24,163	$	18,567	$	17,145	$	30,738	$	24,163	$	18,567

(1110) SUPPLEMENTAL CASH FLOW INFORMATION


Years ended December 31,	2012			2011			2010			2013			2012			2011
	(in thousands)									(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment financed with accrued liabilities	$	3,969		$	1,882		$	7,188
Property, plant and equipment acquired with accrued liabilities										$	13,590		$	3,969		$	1,882
Non-cash decrease to money pool note receivable, net	$	(43,984	)	$	—		$	—		$	(8,000	)	$	(43,984	)	$	—
Non-cash dividend to Parent company	$	43,984		$	—		$	—		$	8,000		$	43,984		$	—

Supplemental disclosure of cash flow information:
Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(17,099	)	$	(16,294	)	$	(19,554	)	$	(19,174	)	$	(17,099	)	$	(16,294	)
Income taxes	$	7,176		$	(15,347	)	$	15,805		$	219		$	7,176		$	(15,347	)

(1211) COMMITMENTS AND CONTINGENCIES

~~Partial Sale of Wygen III~~

On ~~July 14, 2010, we sold a~~ ~~23%~~ ~~ownership interest in Wygen III to the City of Gillette for~~ ~~$62.0 million~~. The purchase terminated the then current PPA with the City of Gillette, and the Wygen III Participation Agreement has been amended to include the City of Gillette. The Participation Agreement provides that the City of Gillette will pay us for administrative services and share in the costs of operating the plant for the life of the facility. The amount of net fixed assets sold totaled ~~$55.8 million. We recognized a gain on the sale of~~ ~~$6.2 million~~.

Power Purchase and Transmission Services Agreements

We have the following power purchase and transmission agreements, not including related party agreements, as of December 31, ~~2012~~2013 (see Note 109 for information on related party agreements):

A PPA with PacifiCorp expiring on December 31, 2023, which provides for the purchase by us of 50 MW of electric capacity and energy. The price paid for the capacity and energy is based on the operating costs of one of ~~PacifiCorp's~~PacifiCorp’s coal-fired electric generating plants;

A firm point-to-point transmission access agreement to deliver up to 50 MW of power on ~~PacifiCorp's~~PacifiCorp’s transmission system to wholesale customers in the western region through December 31, 2023; and

An agreement with Thunder Creek for gas transport capacity, expiring in October 31, 2019.

Costs incurred under these agreements were as follows for the years ended December 31 (in thousands):


Contract	Contract Type	2012		2011		2010		Contract Type	2013		2012		2011
PacifiCorp	Electric capacity and energy	$	13,224	$	12,515	$	12,936	Electric capacity and energy	$	13,026	$	13,224	$	12,515
PacifiCorp	Transmission access	$	1,215	$	1,215	$	1,215	Transmission access	$	1,384	$	1,215	$	1,215
Thunder Creek	Gas transport capacity	$	633	$	633	$	633	Gas transport capacity	$	633	$	633	$	633

Future Contractual Obligations

The following is a schedule of future minimum payments required under the power purchase, transmission services, facility and vehicle leases, and gas supply agreements (in thousands):


2013	$	11,909
2014	$	11,904	$	12,451
2015	$	11,903	$	12,443
2016	$	11,899	$	12,443
2017	$	11,895	$	12,443
2018			$	6,133
Thereafter	$	30,884	$	28,764

Long-Term Power Sales Agreements

We have the following power sales agreements as of December 31, ~~2012~~2013:

During periods of reduced production at Wygen III in which MDU owns a portion of the capacity, or during periods when Wygen III is off-line, MDU will be provided with 25 MW from our other generation facilities or from system purchases with reimbursement of costs by MDU;

During periods of reduced production at Wygen III in which the City of Gillette owns a portion of the capacity, or during periods when Wygen III is off-line, we will provide the City of Gillette with its first 23 MW from our other generating facilities or from system purchases with reimbursement of costs by the City of Gillette. Under this agreement, Black Hills Power will also provide the City of Gillette their operating component of spinning reserves;

An agreement under which we supply energy and capacity to MEAN expiring on May 31, 2023. This contract is unit-contingent based on up to 10 MW from our Neil Simpson II and up to 10 MW from our Wygen III plants. The energy and capacity purchase requirements decrease over the term of the agreement; and

A PPA with MEAN, expiring on April 1, 2015. Under this contract, MEAN purchases 5 MW of unit-contingent energy and capacity from Neil Simpson II and 5 MW of unit-contingent capacity from Wygen III.

Oil Creek Fire

On June 29, 2012, a forest and grassland fire occurred in the western Black ~~Hills. It is alleged~~Hills of Wyoming. A fire investigator concluded that the fire ~~occurred when~~was caused by the failure of a ~~high voltage electrical~~ transmission ~~line~~structure owned, operated and maintained by ~~us fell to the ground, and that electrical arcing from the downed line ignited dry grass or brush. The fire burned approximately 60,000 acres of land owned by~~us. On April 16, 2013, thirty-five private ~~landowners as well as~~parties filed suit in the United States ~~Bureau~~District Court for the District of ~~Land Management~~Wyoming, asserting claims for damages against us based upon allegations of negligence, negligence per se, common law nuisance, and trespass. Although not currently included in the lawsuit, we also received written damage claims from an additional landowner and from the State of Wyoming. ~~We have received written~~Altogether the claims ~~from the State of Wyoming~~seek recovery for fire suppression, reclamation and ~~a landowner seeking recovery of damages for~~rehabilitation costs, damage to fencing and other personal property, alleged injury to timber, grass ~~fencing, fire suppression~~or hay, livestock and ~~rehabilitation costs. The~~related operations, and diminished value of real estate, for a current total amount of ~~damages currently claimed by the State of Wyoming and the landowners is approximately~~ $815 million. ~~We have been notified that additional private landowner~~In addition to claims ~~are forthcoming.~~for these compensatory damages, the lawsuit seeks recovery of punitive damages. Our investigation ~~into~~of the cause and origin of the fire is ~~still pending. Based upon information developed in our investigation to date, we expect to deny~~ongoing. We have denied and will vigorously defend all claims arising out of the ~~fire.~~fire, pending the completion of our investigation. Given the uncertainty of litigation, however, a loss ~~relating~~related to the fire, ~~and~~ the litigation and related claims, is reasonably possible. We cannot reasonably estimate the amount of a potential loss because our investigation is ongoing, and because ~~we expect further~~damage claims toare currently incomplete or undocumented. Further claims may be presented by these and other parties. ~~Although we~~We cannot predict the outcome of our investigation, or the viability of ~~potential~~alleged claims ~~based on~~or the outcome of the litigation. Based upon information currently available, however, management ~~believes that any such~~does not expect the claims, if determined adversely to us, ~~will not~~to have a material adverse effect onupon our financial ~~statements.~~condition, results of operations or cash flows.

4953

Legal Proceedings

We are subject to various legal proceedings, claims and litigation which arise in the ordinary course of operations. In the opinion of management, the amount of liability, if any, with respect to these actions would not materially affect our financial position, results of operations or cash flows.

In the normal course of business, we enter into agreements that include indemnification in favor of third parties, such as information technology agreements, purchase and sale agreements and lease contracts. We have also agreed to indemnify our directors, officers and employees in accordance with our articles of incorporation, as amended. Certain agreements do not contain any limits on our liability and therefore, it is not possible to estimate our potential liability under these indemnifications. In certain cases, we have recourse against third parties with respect to these indemnities. Further, we maintain insurance policies that may provide coverage against certain claims under these indemnities.

Environmental Matters

We are subject to costs resulting from a number of federal, state and local laws and regulations which affect future planning and existing operations. They can result in increased capital expenditures, operating and other costs as a result of compliance, remediation and monitoring obligations. Due to the environmental issues discussed below, we may be required to modify, curtail, replace or cease operating certain facilities or operations to comply with statutes, regulations and other requirements of regulatory bodies.

Air

Our generation facilities are subject to federal, state and local laws and regulations relating to the protection of air quality. These laws and regulations cover, among other pollutants, carbon monoxide, SO₂, NO_x, mercury particulate matter and GHG. Power generating facilities burning fossil fuels emit each of the foregoing pollutants and, therefore, are subject to substantial regulation and enforcement oversight by various governmental agencies.

Title IV of the Clean Air Act applies to several of our generation facilities, including the Neil Simpson II, Neil Simpson CT II, Lange CT, Wygen III and Wyodak plants. Title IV of the Clean Air Act created an SO₂ allowance trading program as part of the federal acid rain program. Without purchasing additional allowances, we currently hold sufficient allowances to satisfy Title IV at all such plants through 2042.

The EPA issued the Industrial and Commercial Boiler Regulations for Area Sources of Hazardous Air Pollutants, with updates which impose emission limits, fuel requirements and monitoring requirements. The rule has a compliance deadline of March 21, 2014. In anticipation of this rule, we suspended operations at the Osage plant on October 1, 2010 and as a result of this rule, we suspended operations at the Ben French facility on August 31, 2012 with plans to retire Osage, Ben French and Neil Simpson I on or before March 21, 2014. While the net book value of these plants is estimated to be insignificant at the time of retirement, we would reasonably expect any remaining value to be recovered through future rates.

Solid Waste Disposal

Various materials used at our facilities are subject to disposal regulations. Our Osage plant, at which operations have been suspended, has an on-site ash impoundment that is near capacity. An application to close the impoundment was approved by the State of Wyoming on April 13, 2012. Site closure work ~~is underway with~~was completed in 2013 and post closure monitoring activities will continue for 30 years. In September 2013, Osage also received a permit to close the small industrial rubble landfill. Site work was completed and post closure monitoring will continue for 30 years.

5054

(1312) QUARTERLY HISTORICAL DATA (Unaudited)

We operate on a calendar year basis. The following table sets forth selected unaudited historical operating results data for each quarter (in thousands):


									First Quarter		Second Quarter		Third Quarter		Fourth Quarter
2013
Operating revenues									$	59,817	$	60,832	$	67,268	$	66,110
Operating income									$	12,503	$	14,293	$	18,704	$	16,844
Net income									$	5,582	$	6,652	$	9,298	$	8,641
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
2012
Operating revenues	$	62,270	$	58,372	$	61,134	$	61,533	$	62,270	$	58,372	$	61,134	$	61,533
Operating income	$	12,742	$	13,859	$	15,361	$	15,619	$	12,742	$	13,859	$	15,361	$	15,619
Net income	$	6,053	$	6,727	$	8,147	$	6,159	$	6,053	$	6,727	$	8,147	$	6,159

2011
Operating revenues	$	59,194	$	56,098	$	64,940	$	65,399
Operating income	$	11,917	$	9,181	$	19,175	$	14,447
Net income	$	5,881	$	3,741	$	10,510	$	6,965


ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND

FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (Exchange Act)) as of December 31, ~~2012.~~2013. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

Management’s Report on Internal Control over Financial Reporting is presented on Page 24 of this Annual Report on Form 10-K.

During ~~the~~our fourth fiscal quarter, ~~ended December 31, 2012,~~ there have been no changes in our internal ~~control~~controls over financial reporting that have materially affected or are reasonably likely to materially affect our internal ~~control~~controls over financial reporting, except that we completed execution of our remediation plan to address a material weakness in internal controls surrounding accounting for income taxes, previously reported in our 2011 Annual Report on Form 10-K and 2012 Quarterly Reports on Form 10-Q.reporting.

In response to the identified material weakness, management conducted an investigation and review of the processes and controls surrounding the material weakness. Management, with oversight from our Audit Committee, developed a plan of remediation in the first quarter of 2012 that included changes to processes to prevent or detect similar future occurrences. As a result of this plan, the following control remediation steps were taken during 2012:

Increased tax department resources to ensure completion and documentation of a more thorough analysis that supports our calculation of the effective tax rate and valuation of deferred tax assets and liabilities.

~~Enhanced processes and controls related to income tax accounting and reporting.~~

~~Utilized a quarterly “Executive Tax Dashboard” to ensure a comprehensive assessment of each quarter's tax status.~~

~~Implemented formal periodic meetings among the Chief Financial Officer, Controller and the tax department to ensure adequate consideration of items that may impact income tax accounting.~~

~~Management's Report on Internal Control over Financial Reporting~~

Under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2012, based on the criteria set forth in Internal Control - Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. This evaluation included review of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls and a conclusion on this evaluation. Based on our evaluation, we have concluded that our internal control over financial reporting was effective as of December 31, 2012.

~~Black Hills Power~~

ITEM 9B. OTHER INFORMATION

None.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The following table sets forth the aggregate fees for services provided to us for the fiscal years ended December 31 by our independent registered public accounting firm, Deloitte & Touche LLP (in thousands):


Deloitte & Touche LLP	2012		2011		2013		2012
Audit Fees	$	128	$	336	$	345	$	128
Tax Fees	94		22		4		94
Audit-related fees	—		—		—		—
Total	$	222	$	358	$	349	$	222

Audit Fees. Fees for professional services rendered for the audits of our financial statements, review of the interim financial statements included in quarterly reports and services that generally only the independent auditor can reasonably provide, such as comfort letters, statutory audits, consents and assistance with and review of documents filed with the Securities and Exchange Commission.

Tax Fees. Fees for services related to tax compliance, and tax planning and advice including tax assistance with tax audits. These services include assistance regarding federal and state tax compliance and advice, review of tax returns, and federal and state tax planning.

Audit-Related Fees. Fees for assurance and related services that are reasonably related to the performance of the audit or review of our financial statements and are not reported under ~~"Audit~~“Audit Fees."” These services may include internal control reviews; attest services that are not required by statute or regulation; employee benefit plan audits; due diligence, consultations and audits related to mergers and acquisitions; and consultations concerning financial accounting and reporting standards.

The services performed by Deloitte & Touche LLP were pre-approved in accordance with the Black Hills Corporation Audit ~~Committee's~~Committee’s pre-approval policy whereby the Audit Committee pre-approves all audit and permissible non-audit services provided by the independent registered public accountants. The Audit Committee annually reviews the services expected to be provided by the independent auditors and establishes pre-approval fee levels for each category of services to be provided, including audit, audit-related, tax and other services. Any service that is not included in the approved list of services must be separately pre-approved by the Audit Committee.



ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES



(a)	1.	Financial Statements

		Financial statements required by Item 15 are listed in the index included in Item 8 of Part II.

	2.	Schedules

Schedule II - Valuation and Qualifying Accounts for the years ended December 31, ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011



		All other schedules have been omitted because of the absence of the conditions under which they are required or because the required information is included elsewhere in the financial statements incorporated by reference in this Form 10-K.

~~3. Exhibits~~

SCHEDULE II


BLACK HILLS POWER, INC. VALUATION AND QUALIFYING ACCOUNTS YEARS ENDED DECEMBER 31, 2012, 2011 AND 2010
BLACK HILLS POWER, INC. VALUATION AND QUALIFYING ACCOUNTS YEARS ENDED DECEMBER 31,										BLACK HILLS POWER, INC. VALUATION AND QUALIFYING ACCOUNTS YEARS ENDED DECEMBER 31,

Description	Balance at beginning of year		Additions charged to costs and expenses		Deductions charged to costs and expenses			Balance at end of year		Balance at beginning of year		Additions charged to costs and expenses		Deductions charged to costs and expenses			Balance at end of year
	(in thousands)									(in thousands)
Allowance for doubtful accounts:
2013										$	102	$	754	$	(636	)	$	220
2012	$	143	$	503	$	(544	)	$	102	$	143	$	503	$	(544	)	$	102
2011	$	230	$	551	$	(638	)	$	143	$	230	$	551	$	(638	)	$	143
2010	$	259	$	499	$	(528	)	$	230


3.	Exhibits



Exhibit Number	Description

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

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

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

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~~Registrant’s Post-Effective Amendment No. 1 to the ~~Registrant's~~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~~Registrant’s Post-Effective Amendment No. 1 to the ~~Registrant's~~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)).

10.1*	Restated and Amended Coal Supply Agreement for NS II dated February 12, 1993 (filed as Exhibit 10.1 to the ~~Registrant's~~Registrant’s Post-Effective Amendment No. 1 to the ~~Registrant's~~Registrant’s Registration Statement on Form S-3 (No. 333-150669-01)).

10.2*	Second Restated and Amended Power Sales Agreement dated September 29, 1997, between PacifiCorp and Black Hills Power, Inc. (filed as Exhibit 10.2 to the ~~Registrant's~~Registrant’s Post-Effective Amendment No. 1 to the ~~Registrant's~~Registrant’s Registration Statement on Form S-3 (No. 333-150669-01)).

31.1	Certification of Chief Executive Officer pursuant to Rule13a-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2	Certification of Chief Financial Officer pursuant to Rule13a-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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.

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.

101	Financials for XBRL Format

_________________________


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


(a)	See (a) 3. Exhibits above.


(b)	See (a) 2. Schedules above.

SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT.

The Registrant is not required to send an Annual Report or Proxy to its sole security holder and parent company, Black Hills Corporation.

5558

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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.

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

Dated:	~~March 6, 2013~~February 27, 2014

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.



/s/ DAVID R. EMERY	Director and	~~March 6, 2013~~February 27, 2014
David R. Emery, Chairman and	Principal Executive Officer
Chief Executive Officer

/s/ ANTHONY S. CLEBERG	Principal Financial and	~~March 6, 2013~~February 27, 2014
Anthony S. Cleberg, Executive Vice President	Accounting Officer
and Chief Financial Officer

/s/ JACK W. EUGSTER	Director	~~March 6, 2013~~February 27, 2014
Jack W. Eugster

/s/ MICHAEL H. MADISON	Director	~~March 6, 2013~~February 27, 2014
Michael H. Madison

/s/ STEVEN R. MILLS	Director	~~March 6, 2013~~February 27, 2014
Stephen R. Mills

/s/ STEPHEN D. NEWLIN	Director	~~March 6, 2013~~February 27, 2014
Stephen D. Newlin

/s/ GARY L. PECHOTA	Director	~~March 6, 2013~~February 27, 2014
Gary L. Pechota

/s/ REBECCA B. ROBERTS	Director	~~March 6, 2013~~February 27, 2014
Rebecca B. Roberts

/s/ WARREN L. ROBINSON	Director	~~March 6, 2013~~February 27, 2014
Warren L. Robinson

/s/ JOHN B. VERING	Director	~~March 6, 2013~~February 27, 2014
John B. Vering

/s/ THOMAS J. ZELLER	Director	~~March 6, 2013~~February 27, 2014
Thomas J. Zeller

5659

INDEX TO EXHIBITS



Exhibit Number	Description

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

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

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

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~~Registrant’s Post-Effective Amendment No. 1 to the ~~Registrant's~~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~~Registrant’s Post-Effective Amendment No. 1 to the ~~Registrant's~~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)).

10.1*	Restated and Amended Coal Supply Agreement for NS II dated February 12, 1993 (filed as Exhibit 10.1 to the ~~Registrant's~~Registrant’s Post-Effective Amendment No. 1 to the ~~Registrant's~~Registrant’s Registration Statement on Form S-3 (No. 333-150669-01)).

10.2*	Second Restated and Amended Power Sales Agreement dated September 29, 1997, between PacifiCorp and Black Hills Power, Inc. (filed as Exhibit 10.2 to the ~~Registrant's~~Registrant’s Post-Effective Amendment No. 1 to the ~~Registrant's~~Registrant’s Registration Statement on Form S-3 (No. 333-150669-01)).

31.1	Certification of Chief Executive Officer pursuant to Rule13a-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2	Certification of Chief Financial Officer pursuant to Rule13a-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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.

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.

101	Financial Statements for XBRL Format

_________________________


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

5760



Utility Money Pool	2012		2011		2010
Notes receivable (payable), net	$	31,645	$	50,477	$	39,862

Net interest income (expense)	$	617	$	1,414	$	467

Notes receivable (payable), net