SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549



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

For the fiscal year ended December 31, ~~2011~~2012

BLACK HILLS POWER, INC.



Class	Outstanding at February ~~29, 2012~~28, 2013
Common stock, $1.00 par value	23,416,396 shares

GLOSSARY OF TERMS AND ABBREVIATIONS

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

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.

ITEMS 1 and 2. BUSINESS AND PROPERTIES

~~Safe Harbor for Forward Looking Information~~

This Annual Report on Form 10-K includes "forward-looking statements" as defined by the SEC. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this Form 10-K that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. These forward-looking statements are based on assumptions that we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. Whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including without limitation, the Risk Factors set forth in Item 1A of this Form 10-K and the other reports we file with the SEC from time to time, and the following:

~~renewable energy portfolio standards, which may materially increase our generation and production costs and could render some of our generating units uneconomical to operate and maintain;~~

New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. We assume no obligation to update publicly any such forward-looking statements, whether as a result of new information, future events, or otherwise.

~~We are~~Black Hills Power ("the Company," "we," "us" and "our") is a regulated electric utility incorporated in South Dakota and serving customers in South Dakota, Wyoming and Montana. We ~~are incorporated in South Dakota and~~ began providing electric utility service in 1941. We are a wholly-owned subsidiary of the publicly traded Black Hills Corporation.

~~Unless the context otherwise requires, references in this Form 10-K to "the Company," "we," "us" and "our" refer to Black Hills Power, Inc.~~

~~We engage~~ Engaging in the generation, transmission and distribution of ~~electricity. We have~~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, ~~2011~~2012, our ownership interests in electric generation plants were as follows:

_______________________

(1) 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. The WRDC coal mine furnishes all of the coal fuel supply for the plant.

(2) 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 the WRDC coal mine furnishes all of the coal fuel supply for the plant.

(3) Operations at the Osage plant were suspended October 1, 2010 due to the availability of more economical generation alternatives. The Osage plant will remain in our generation portfolio with all operating permits so it can resume full operations if needed.

~~(4) Upon expiration of the contract with PacifiCorp in June 2012, the capacity available under these units will be decreased to 80 MW.~~

Distribution and Transmission. Our distribution and transmission system serves approximately ~~68,200~~69,000 electric customers, with an electric transmission system of ~~618~~592 miles of high voltage lines (greater than 69 KV) and ~~2,999~~3,059 miles of lower voltage lines. In addition, we jointly own 47 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 ~~2011~~2012 were generated in South Dakota. We are subject to regulation by the SDPUC, the WPSC and the MTPSC.

The following are characteristics of our distribution and transmission ~~businesses:~~business:

We have a diverse customer and revenue base. Our revenue mix for the year ended December 31, ~~2011~~2012 was comprised of 30% commercial, 24% residential, 7%8% contract wholesale, ~~14%~~13% wholesale off-system, 11% industrial, ~~and~~ 14% municipal ~~sales~~ and other revenue.

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 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.

•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:



~~2010-2017~~2013-2017	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; and~~II.

Regulated Power Plants and Purchased Power. Our electric load is primarily served by our generating facilities in South Dakota and Wyoming, which provide ~~491~~471 MW of generating capacity, with the balance supplied under purchased power and capacity contracts. We generated approximately ~~50%~~52% of our energy requirements in ~~2011~~2012 and purchased approximately ~~50%~~48% which was supplied under the following ~~purchased power~~ contracts:

Since 1995, we have been a net producer of energy. Our ~~2011~~2012 winter peak system load was ~~408~~362 MW and our ~~2011~~2012 summer peak load was ~~452~~449 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.~~Agreement - During 2010, we entered into 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.

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

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.

9We 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 ~~Increase Settlement~~Matters

Power Plant Suspension/Retirements

On August 6, 2012, we announced that in order to comply with environmental regulations, including the new EPA Industrial & 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.

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 in spring 2013 with commercial operation in 2014.

~~On September 30, 2009,~~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 ~~costs associated with Wygen III~~investment in distribution and ~~other~~transmission lines, generation ~~transmission and distribution assets~~plant upgrades, environmental compliance and increased operating expenses incurred during the past four years. In March 2010, the SDPUC approved a 20% increase in interim revenues, subject to refund, effective April 1, 2010 for South Dakota customers. On July 7, 2010, the SDPUC approved a final revenue increase of $15.2 million, or 12.7%, and a base rate increase of $22 million, or 19.4% withcosts. We have requested an effective date of April 1, ~~2010. The approved capital structure~~2013 and ~~return on equity are confidential. A refund was provided to customers in~~a decision is anticipated during the third quarter of ~~2010.~~2013. If the SDPUC has not reached a decision within 180 days, interim rates will go into effect June 16, 2013.

~~As part of the settlement stipulation, we agreed (1) to credit customers 65% of power marketing operating income~~We filed a request with a minimum of $2.0 million per year; (2) that rates will include a South Dakota Surplus Energy Credit of $2.5 million in year one (fiscal year ending March 2011), $2.25 million in year two, $2.0 million in year three and zero thereafter; and (3) a moratorium until April 2013 for any base rate increases excluding any extraordinary events as defined in the stipulation agreement; while (4) the SDPUC ~~agreed~~ to ~~adjust~~use a construction financing rider during the ~~power marketing sales portion~~construction of ~~the Fuel and Purchased Power Adjustment clause to directly assign renewable resources and firm purchases~~Cheyenne Prairie in lieu of traditional AFUDC. This rider would be similar to the ~~customer load.~~

~~In May 2011,~~one approved by the WPSC for Cheyenne Light and Black Hills Power's Wyoming customers. On January 17, 2013, the SDPUC approved ~~an Environmental Improvement Cost Recovery Adjustment tariff for Black Hills Power. This tariff, which was implemented~~a stipulation with interim rates effective April 1, 2013, subject to ~~recover Black Hills Power's investment~~refund. The rider will allow us to earn and collect a rate of ~~$25~~return during the construction period on our approximately 40 percent share of the total project cost relating 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 ~~for pollution control equipment at~~and $5.6 million in 2013 and 2014, respectively. We anticipate a final ruling by the ~~PacifiCorp operated Wyodak plant, went into effect June 1, 2011 with an annual revenue increase~~SDPUC on this rider during the third quarter of ~~$3.1 million.~~2013.

On October 19, 2009, we filed a rate case with the WPSC requesting an electric revenue increase to recover costs associated with Wygen III and other generation, transmission and distribution assets and increased operating expenses incurred since 1995. On May 4, 2010, we filed a settlement stipulation agreement with the WPSC for a $3.1 million increase in annual revenues. On May 13, 2010, WPSC approved these new rates based on a return on equity of 10.5% with a capital structure of 52% equity and 48% debt. Rates went into effect on June 1, 2010.

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, ~~2011~~2012, 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. 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 ~~2010-2014~~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.~~standards and our current strategy is to incorporate renewable energy as required to comply with the standard.

Wyoming. Wyoming is ~~also~~ 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 ~~an effective date of May 20, 2011 and~~ a compliance deadline of March 21, 2014. ~~This~~In anticipation of this rule ~~has~~and our evaluation of costs to retrofit these plants, we suspended operations at the Osage plant in October 1, 2010 and as a ~~significant impact~~result of this rule, we suspended operations at the Ben French facility on ~~our~~August 31, 2012 with plans to retire Ben French, Osage and Neil Simpson I Osage and Ben French facilities. Engineering evaluations have been completed as to the economic viability of continued operations of these units. It is our expectation that the Neil Simpson I, Osage and Ben French units will be closed prior to theon or before March 21, ~~2014 compliance deadline.~~2014.

On ~~December~~February 16, ~~2011,~~2012, the EPA signed the National Emission Standards for Hazardous Air Pollutants from Coal and Oil Fired Electric Utility Steam Generating Units ~~(Utility Maximum Achievable Control Technology Rule)~~(MATS), which became effective on ~~February~~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 compliance, with a pathway defined to apply for a one year extension due to certain circumstances. ~~Certain~~The current state air permits for Wygen III provide mercury emission limits and monitoring requirements ~~of that regulation could have significant impacts on the~~with which we are in compliance. In 2009, we added mercury monitors to our Neil Simpson II plant. The Wygen III ~~and Wyodak plants.~~plant, which commenced operations in 2010, also has mercury monitors. Neil Simpson II, Wygen III and the Wyodak plant are expected to be in compliance within the compliance time frame. Significant modifications may be required to ensure compliance at Neil Simpson II and we are working toward that goal. Preliminary estimates of capital requirements to comply with this rule are $30 million to $50 million.frame, without incurring significant costs.

~~In June 2011,~~

On April 13, 2012, the EPA ~~was scheduled to issue~~ proposed Electric Utility New Source Performance Standards for GHG. ~~That publication date has been extended~~These standards will apply to ~~mid-2012. As~~Cheyenne Prairie. They are scheduled to be final in the ~~regulations are~~first half of 2013 and, as proposed, would not ~~yet proposed,~~have a significant impact on this project. However, until we can evaluate the final version of these standards, we cannot ~~ascertain their impacts but we anticipate they may~~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 and as proposed, will be applicable to ~~Wygen III. In 2011, it was anticipated the EPA would expedite the issuance of a more stringent ozone ambient air standard. However, the President~~Cheyenne Prairie and eventually all of the ~~United States postponed~~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 New Source Review regulations, with the intention of eventually bringing all units under the applicability of this ~~revision and placed it back~~rule. The primary impact is expected to be on ~~its normal review cycle,~~our older existing units, which ~~is scheduled~~will eventually be required to occur in 2013. If the lower range of the proposed standard is selected, it is anticipated that Campbell County, Wyoming would be a non-attainment area. Under those conditions, the State of Wyoming may evaluate Neil Simpson II and Wygen III for further reductions inmeet tighter NO_x ~~emissions.~~emission limitations.

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

In 2011 the State of Wyoming issued a letter ~~addressing~~requiring Neil Simpson II to include startup and shutdown SO₂ & NO_xemissions ~~at Neil Simpson II, requiring the facility to include those emissions in consideration of~~when evaluating compliance with ~~the~~ permitted emission limits. This ~~represents~~represented a significant change infrom requirements ~~from~~in the original 1993 air ~~permit issued~~permit. Some minor engineered design changes were made to enable improved scrubber performance during startup and those changes have been successful in ~~1993. As~~enabling the unit to meet the new requirements. The unit was previously fitted with state of the art low NO_x burners that enable compliance with this ~~facility was not designed and built according to those requirements, we are currently undergoing engineering evaluations to determine methods and costs of compliance.~~new requirement.

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 2 of our Notes to Financial Statements in this Annual Report on Form 10-K for information on new accounting standards adopted in ~~2011~~2012 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.

We may not raise our retail rates without prior approval of the SDPUC, WPSC or the MTPSC. If we seek rate relief, we could experience delays, reduced or partial rate recovery, or disallowances in rate proceedings. 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 ~~therefore,~~ 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 ~~costs~~ 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 ~~liquidity.~~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.

Interruptions to supply of fuel and other commodities used in ~~generation.~~generation and distribution.

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

Inability to recruit and retain skilled technical labor.

~~Labor relations.~~

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.

~~The global financial situation has affected our counterparty credit risk which could have an adverse effect on our results of operations, financial position~~Electricity is dangerous for employees and the general public should they come in contact with power lines or ~~liquidity.~~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;

~~As a consequence of~~Disruption in the ~~global financial crisis in recent years, the creditworthiness of many~~functioning of our ~~contractual counterparties (particularly financial institutions) has deteriorated. Although~~information technology and network infrastructure which are vulnerable to disability, failures and unauthorized access. If our information technology systems were to fail and we ~~aggressively monitor and evaluate changes~~were unable to recover in our counterparties' credit quality and adjust the credit limits based upon such changes, our credit guidelines, controls and limits may not protect us from increasing counterparty credit risk. To the extent the financial crisis causes our credit exposurea timely manner, we would be unable to ~~contractual counterparties to increase materially, such increased exposure could have an adverse effect on our results of operations, financial position or liquidity.~~fulfill critical business functions.

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 future recession may lead to an increase in late payments from retail, commercial and industrial utility customers, as well as from our ~~non-utility~~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 ~~"A3"~~A3 by Moody's, ~~"BBB+"~~BBB+ by S&P and A- by Fitch. Any reduction in our ratings by the rating agencies could adversely affect our ability to refinance ~~or repay~~ 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.

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 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 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 operating results can be adversely affected by ~~milder weather.~~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.

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 ~~climate change~~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.~~

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 ~~operations.~~

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 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 units will be ~~closed prior to~~retired on or before the March 21, 2014 compliance deadline.

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

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 facilities will see monitoring reporting requirements incorporated into their operating permits upon renewal. New projects or major modifications to existing projects will result in a Best Available Control Technology review that could result in more stringent emissions control practices and technologies. The EPA’s GHG New Source Performance Standard for new steam electric generating units is expected to be final in the first half of 2013 and as proposed, effectively prohibits new coal fired units until carbon capture and sequestration becomes technically and economically feasible. In 2013 we expect the EPA to issue a proposed rule to regulate GHG emissions from existing steam electric generating units. This rule could have a significant impact on our coal 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 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 and 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; 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 ~~business.~~results of operations, financial position or liquidity.

~~The Energy Policy Act~~Business activities in the energy sector are heavily regulated, primarily by agencies of ~~2005 increased~~ the ~~FERC~~federal government. Agencies that historically sought voluntary compliance, or issued non-monetary sanctions, now employ mandatory civil penalty ~~authority~~structures for ~~violation of~~regulatory violations. The FERC, ~~statutes, rules~~EPA, OSHA and ~~orders. FERC~~SEC can ~~now~~increasingly impose significant civil penalties ~~of $1.0 million per violation, per day, and other regulatory agencies that impose~~to enforce compliance requirements relative to our ~~business also have civil penalty authority.~~business. In addition, FERC has delegated certain aspects of authority for enforcement of electric system reliability standards to the North American ~~Electric~~Energy Reliability Corporation, with similar penalty authority for violations. ~~Many rules that were historically subject to voluntary compliance are now mandatory and subject to potential civil penalties 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.

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 ~~businesses,~~business, or the businesses of third parties, may impact our operations in unpredictable ways and could adversely affect our financial results 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 ~~businesses~~business by limiting ~~their~~our ability to generate, purchase or transmit power and by delaying ~~their~~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 on our financial results.

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.

Ongoing changes in the United States electric utility industry, including state and federal regulatory changes, a potential increase in the number or geographic scale of our competitors or the imposition of price limitations to address market volatility, could adversely affect our results of operations, financial position or liquidity.

~~The United States electric utility industry is currently experiencing increasing competitive pressures as a result of:~~

~~The Energy Policy Act of 2005 and the repeal of the Public Utility Holding Company Act of 1935;~~

~~Industry consolidation;~~

~~Consumer demands;~~

~~Transmission constraints;~~

~~Renewable resource supply requirements;~~

~~Resistance to the siting of utility infrastructure or to the granting of right-of-ways;~~

~~Technological advances; and~~

~~Greater availability of natural gas-fired power generation, and other factors.~~

FERC has implemented and continues to propose regulatory changes to increase access to the nationwide transmission grid by utility and non-utility purchasers and sellers of electricity. In addition, a number of states have implemented or are considering or currently implementing methods to introduce and promote retail competition. Industry deregulation in some states has led to the disaggregation of some vertically integrated utilities into separate generation, transmission and distribution businesses. Deregulation initiatives in a number of states may encourage further disaggregation. As a result, significant additional competitors could become active in the generation, transmission and distribution segments of our industry, which could adversely affect our results of operations, financial position or liquidity.

In addition, the independent system operators who oversee many of the wholesale power markets have in the past imposed, and may in the future continue to impose price limitations and other mechanisms to address some of the volatility in these markets. These types of price limitations and other mechanisms may adversely affect the profitability of generating facilities that sell energy into the wholesale power markets. Given the extreme volatility and lack of meaningful long-term price history in some of these markets and the imposition of price limitations by independent system operators, we may not be able to operate profitably in all wholesale power markets.

Governmental authorities may assess penalties on us if it is determined that we have not complied with environmental laws and regulations which could affect our results of operations, financial position or liquidity.

If we fail to comply with environmental laws and regulations, even if caused by factors beyond our control, that failure may result in the assessment of civil or criminal penalties and fines against us. Recent lawsuits by the EPA and various states filed against others within industries in which we operate highlight the environmental risks faced by generating facilities, in general, and coal-fired generating facilities in particular.

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 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 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 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 2010 Acts could require, among other things, changes to our current employee benefit plans and in our administrative and accounting processes. 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, and as the results of pending litigation become final.~~available.

We have disclosed a material weakness in our internal control over financial reporting, and if we do not adequately remediate this weakness or if we have other material weaknesses or significant deficiencies in our internal control over financial reporting our business and financial condition may be adversely affected.

Our ~~management is responsible for establishing~~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 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. As disclosed in Item 9A, management identified a material weakness in our internal control over financial reporting relating to accounting for income taxes. A material weakness is a deficiency, or combination of deficiencies, that resultapproved in a ~~reasonable possibility~~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 ~~a material misstatement of a company's annual or interim financial statements~~the state public utility commissions will not be prevented or detected on a timely basis. As a result of this material weakness, our management concluded that our internal control over financial reporting and our disclosure controls and procedures were not effective as of December 31, 2011. Management is taking measures to remediate the material weakness and to enhance our internal controls over financial reporting. If our remedial measures are insufficient to address the material weakness, or if additional material weaknesses or significant deficiencies in our internal control occur in the future, our financial statements may contain material misstatements or other errors and we could be required to restate our financial results. If we cannot produce reliable financial reports, we may be unable to obtain additional financing, and our business and financial condition could be harmed.

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" sub caption within Item 8, Note 12, "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 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 DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS


For the years ended December 31,	2011			2010			2009			2012			Variance			2011			Variance			2010
	(in thousands)
										(in thousands)
Revenue	$	245,631		$	229,763		$	207,079		$	243,309		$	(2,322	)	$	245,631		$	15,868		$	229,763
Fuel and purchased power	93,222			87,757			91,349			87,519			(5,703		)	93,222			5,465			87,757
Gross margin	152,409			142,006			115,730			155,790			3,381			152,409			10,403			142,006

Operating expenses	98,457			92,976			80,925			98,209			(248		)	98,457			5,481			92,976
Gain on sale of operating assets	(768		)	(6,238		)	—			—			768			(768		)	5,470			(6,238		)
Operating income	54,720			55,268			34,805			57,581			2,861			54,720			(548		)	55,268

Interest expense, net	(16,139		)	(16,513		)	(11,164		)	(17,065		)	(926		)	(16,139		)	374			(16,513		)
Other income	506			3,254			7,802			879			373			506			(2,748		)	3,254
Income tax expense	(11,990		)	(10,741		)	(8,304		)	(14,309		)	(2,319		)	(11,990		)	(1,249		)	(10,741		)
Net income	$	27,097		$	31,268		$	23,139		$	27,086		$	(11	)	$	27,097		$	(4,171	)	$	31,268

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



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

Electric Revenue
Customer Base 2011 Percentage Change 2010 Percentage Change 2009
Residential $ 59,826
12 % $ 53,549
10 % $ 48,586
Commercial 72,889
10 % 65,997
10 % 59,897
Industrial 25,723
14 % 22,621
13 % 20,014
Municipal 3,172
5 % 3,029
11 % 2,735
Total retail sales 161,610
11 % 145,196
11 % 131,232
Contract wholesale 18,105
(21 )% 22,996
(9 )% 25,358
Wholesale off-system 34,889
(4 )% 36,354
13 % 32,212
Total electric sales 214,604
5 % 204,546
8 % 188,802
Other revenue 31,027
23 % 25,217
38 % 18,277
Total revenue $ 245,631
7 % $ 229,763
11 % $ 207,079

															Megawatt-Hours Sold
Customer Base	2011	Percentage Change		2010	Percentage Change		2009	2012	Percentage Change		2011	Percentage Change		2010
Residential	550,935	1	%	547,193	3	%	529,825	532,342	(3	)%	550,935	1	%	547,193
Commercial	720,978	—	%	720,119	0	%	723,360	731,785	1	%	720,978	0	%	720,119
Industrial	408,337	7	%	382,562	8	%	353,041	407,301	—	%	408,337	7	%	382,562
Municipal	34,235	1	%	33,908	0	%	33,948	35,933	5	%	34,235	1	%	33,908
Total retail sales	1,714,485	2	%	1,683,782	3	%	1,640,174	1,707,361	—	%	1,714,485	2	%	1,683,782
Contract wholesale	349,520	(25	)%	468,782	(27	)%	645,297	340,036	(3	)%	349,520	(25	)%	468,782
Wholesale off-system	1,226,548	5	%	1,163,058	15	%	1,009,574	1,263,457	3	%	1,226,548	5	%	1,163,058
Total electric sales	3,290,553	(1	)%	3,315,622	1	%	3,295,045	3,310,854	1	%	3,290,553	(1	)%	3,315,622
Losses and company use	162,316	24	%	131,263	(18	)%	159,207	197,355	22	%	162,316	24	%	131,263
Total energy	3,452,869	—	%	3,446,885	0	%	3,454,252	3,508,209	2	%	3,452,869	0	%	3,446,885

We own approximately ~~491~~471 MW of electric utility generating capacity and purchase an additional 50 MW under a long-term agreement expiring in 2023.

_____________________________

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 maintenance were 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, netincreased 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

Gross marginincreased~~$10.4 million~~ 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.

Operations and maintenanceincreased~~$5.5 million~~ 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 ~~relates~~related to the sale of assets to a related party. The gain on sale of operating assets in 2010 ~~represents~~represented the sale of a 23% ownership interest in the Wygen III generating facility to the City of Gillette, WY.

Interest expense, netdecreased~~$0.4 million~~ 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 income ~~net~~decreased~~$2.7 million~~ 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 a rate case settlement in 2010.

~~Gross margin~~ ~~increased~~ ~~$26.3 million~~ ~~primarily due~~Power Plant Suspension/Retirements

In order to ~~an $18.5 million increase related~~comply with environmental regulations, including the new EPA Industrial & 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 1 until the ~~impact~~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.

As a result of the ~~outcome~~planned plant retirements for some of our ~~rate cases, an increase of $3.0 million in off-system sales margin resulting from~~older coal-fired power plants discussed above, Cheyenne Light and Black Hills Power filed a ~~change in methodology used~~joint CPCN to ~~allocate the lowest cost resource, and increased intercompany revenues of $2.4 million due to~~construct a new ~~shared services agreement related to resources utilized by affiliated entities.~~

~~Operations and maintenance~~ ~~increased~~ ~~$12.1~~$222 million primarily due to additional costs of $6.8 million associated with Wygen III which commenced commercial operation on April 1, 2010, and costs of $2.0 million associated with a major overhaul at the Ben French plant.

~~Gain on sale of operating assets:~~ A ~~$6.2 million~~ ~~gain on sale was recognized on the sale of a 23% ownership interest~~ 132 MW natural gas-fired electric generation facility in ~~the Wygen III generating~~Cheyenne, Wyoming. The facility ~~to the City of Gillette, WY.~~

~~Interest expense, net~~ ~~increased~~ ~~$5.3 million~~ primarily due to higher net interest expense of $2.9 million compared to the same period in the prior year resulting from higher rates on long-term debt compared to rates on short-term debt and a decrease of $2.1 million in AFUDC-borrowed.

~~Other income~~ ~~decreased~~ ~~$4.5 million~~ ~~primarily due to a decrease of $3.1 million in AFUDC-equity associated with the~~will include construction of ~~our Wygen III facility. Additionally, 2009 included a gain of $1.1 million from the sale of SO~~₂ ~~emission credits~~one simple-cycle, 37 MW combustion turbine that will be wholly owned by Cheyenne Light and ~~a gain of $0.5 million on the sale of a 25% ownership interest in the Wygen III facility.~~

~~Income tax expense: The effective tax rate for~~ ~~2010~~ ~~was comparable to the same period in the prior year.~~

~~Rate Increase Settlement~~one combined cycle 95 MW unit that will be jointly owned by Cheyenne Light (40 MW) and Black Hills Power (55 MW).

~~On September 30, 2009,~~In December 2012, we filed a rate case with the SDPUC requesting an electric revenue ~~increase~~increases of $13.7 million, or 9.94%, to recover ~~costs associated with Wygen III~~investment in distribution and ~~other~~transmission lines, generation ~~transmission~~plant upgrades and distribution assets and increased operating expenses incurred during the past four years. In March 2010, the SDPUC approved a $24.1 million increase in interim rates, subject to refund, effective April 1, 2010 for South Dakota customers. On July 7, 2010, the SDPUC approved a final revenue increase of $15.2 million and a base rate increase of $22.0 million withenvironmental compliance. We have requested an effective date of April 1, ~~2010. The approved capital structure~~2013 and ~~return on equity are confidential. A refund of $2.6 million was provided to customers in~~a decision is anticipated during the third quarter of ~~2010.~~2013. If the SDPUC has not reached a decision within 180 days, interim rates will go into effect June 16, 2013.

~~As part~~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 similar to the one approved by the WPSC for Cheyenne Light and Black Hills Power for Wyoming customers. On January 17, 2013, the SDPUC approved a stipulation with interim rates effective April 1, 2013, subject to refund. The rider will allow us to earn and collect a rate of return during the construction period on our approximately 40 percent share of the ~~settlement stipulation, we agreed (1)~~total project cost relating to ~~credit customers 65% of power marketing operating income with a minimum of $2.0 million per year; (2) that rates will include a~~our South Dakota ~~Surplus Energy Credit of $2.5~~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 ~~year one (fiscal year ending March 2011), $2.25 million in fiscal year two, $2.0 million in fiscal year three~~2013 and ~~zero thereafter; and (3)~~2014, respectively. We anticipate a ~~moratorium until April 2013 for any base rate increase excluding any extraordinary events as defined in the stipulation agreement; while (4)~~final ruling by the SDPUC ~~agreed to adjust~~on this rider during the ~~power marketing sales portion~~third quarter of ~~the Fuel and Purchased Power Adjustment clause to directly assign renewable resources and firm purchases to the customer load.~~2013.

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.

OnIn October ~~19, 2009, we filed~~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 ~~case with~~of return during the WPSC requesting an electric revenue increase to recover costs associated with Wygen III and other generation, transmission and distribution assets and increased operating expenses incurred since 1995. On May 4, 2010, we filed a settlement stipulation agreement with the WPSC for a $3.1 million increase in annual revenues. On May 13, 2010, WPSC approved these new rates basedconstruction period on ~~a return on equity of 10.5% with a capital structure of 52% equity and 48% debt. Rates went into effect on June 1, 2010.~~

~~Wygen III Power Plant Project~~

~~The 110 MW coal-fired electric generation facility was completed and commenced commercial operations on April 1, 2010. Total cost of construction was~~ approximately $232.3 million, which includes AFUDC. In April 2009, we sold a 25% ownership interest to MDU. At closing, MDU made a payment to us for its 25% share of the costs to date for the on-going construction of the facility. MDU reimbursed us monthly for its 25%60% share of the total ~~costs paid~~project cost relating to ~~complete~~our Wyoming customers while also saving customers money over the ~~project. In July 2010, we sold an additional 23% ownership interest~~long-term. This will increase gross margin by approximately $0.3 million and $0.4 million in ~~Wygen III to the City of Gillette for $62.0 million. Under both agreements, we retain responsibility for operation of the facility with a life-of-plant site lease. MDU~~2013 and 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. We have a coal supply agreement in place with WRDC and WRDC has coal supply agreements with MDU and the City of Gillette for their share of the plant.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 judgment in application. There are also areas which require 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 Description and Summary of Significant Accounting Policies" of our Notes to Financial Statements in this Annual Report on Form 10-K.

~~Impairment of Long-lived Assets~~

~~We evaluate for impairment, the carrying values of our long-lived assets whenever indicators of impairment exist.~~

For long-lived assets with finite lives, this evaluation is based upon our projections of anticipated future cash flows (undiscounted and without interest charges) from the assets being evaluated. If the sum of the anticipated future cash flows over the expected useful life of the assets is less than the assets' carrying value, then a permanent non-cash write-down equal to the difference between the assets' carrying value and the assets' fair value is required to be charged to earnings. In estimating future cash flows, we generally use a probability weighted average expected cash flow method with assumptions based on those used for internal budgets. The determination of future cash flows, and, if required, fair value of a long-lived asset is by its nature a highly subjective judgment. Significant assumptions are required in the forecast of future operating results used in the preparation of the long-term estimated cash flows. Changes in these estimates could have a material effect on the evaluation of our long-lived assets. There have been no impairments taken in ~~2011~~, ~~2010~~ or ~~2009~~.

Pension and Other Postretirement Benefits

The Company, as described in Note 9 to the Financial Statements in this Annual Report on Form 10-K, has a defined benefit pension plan and post-retirement healthcare plan. 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 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% in 2013 and the discount rate used in 2012 was 4.65%. In ~~July 2009,~~selecting the ~~Board of Directors froze~~discount rate, we consider cash flow durations for each plan's liabilities on high credit fixed income yield curves for comparable durations. We do not pre-fund our Defined Benefit Pension Plan to certain new participants and transferred certain existing participants to an age and service based defined contribution plan, effective January 1, 2010. Plan assets and obligations for the Black Hills Corporation Plan which covers eligible employees of Black Hills Power were revalued as of July 31, 2009 in conjunctionnon-qualified plans or postretirement healthcare plans.

We file a federal income tax return with ~~the curtailment~~other members of the plan. As a result, we recognized a pre-tax curtailment expense of approximately $0.2 million in the third quarter of 2009. In July 2009, the Board of Directors of Black Hills Corporation also approved amendmentsParent consolidated group. For financial statement purposes, federal income taxes are allocated to the BHC Retiree Healthcare Plan. This plan covers eligible employees of Black Hills Power. Effective January 1, 2010, the amendment changed the plan from a cost sharing plan to an RMSA for non-union employees.

In September 2010, the bargaining unit participants in the Defined Benefit Pension Plan voted to freeze all new bargaining unit employees from participation in the Plan and to freeze the benefits of current bargaining unit participants except for the following group: those bargaining unit participants who are both 1) age 45 or older as of December 31, 2010 and have 10 years or more of credited service as of January 1, 2011; and 2) elect to continue to accrue additional benefits under the pension plan and consequently fore-go the additional age and points based employer contribution under the Company's 401(k) retirement savings plan. As a result of this freeze, we recognized a pre-tax curtailment expense of less than $0.1 million in the fourth quarter of 2010. Pension Plan benefits areindividual companies based on ~~years of service and compensation levels during the highest five consecutive years of the last ten years of service. These changes were effective January 1, 2011.~~

~~Valuation of Deferred Tax Assets~~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. ~~The amount~~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 ~~recognized is limited to~~and liabilities into current and non-current amounts based on the ~~amount~~nature of the ~~benefit that is more likely than not to be realized.~~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 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, certain provisions of the Act primarily the extension of 50% bonus depreciation are currently expected to result in minimal utilization of such carryforwards in 2013.

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, ~~and~~ results of ~~operations.~~operations and cash flows. The Company describes any contingencies in Note 12 of the Financial Statements in this Annual Report on Form 10-K.

INDEX TO FINANCIAL STATEMENTS

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") as of December 31, ~~2011~~2012 and ~~2010~~2011, and the related statements of income, ~~statements of~~ comprehensive income (loss), cash flows, and common stockholder's equity ~~and cash flows~~ for each of the three years in the period ended December 31, ~~2011~~2012. 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 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 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, ~~2011~~2012 and ~~2010~~2011, and the results of its operations and its cash flows for each of the three years in the period ended December 31, ~~2011~~2012, 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 ~~__, 2012~~6, 2013

BLACK HILLS POWER, INC.

STATEMENTS OF INCOME

BLACK HILLS POWER, INC.

STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

BLACK HILLS POWER, INC.

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

BLACK HILLS POWER, INC.

STATEMENTS OF CASH FLOWS

BLACK HILLS POWER, INC.

STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

NOTES TO FINANCIAL STATEMENTS

(1) BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Business Description

Black Hills Power, Inc. (the Company, "we," "us" or "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 ~~4).~~4) 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.

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.

~~Our~~We had the following regulatory assets and liabilities ~~for which we recover the costs, but we do not earn a return were~~ as follows as of December 31 (in thousands):

____________________

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

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

Approximately $13.2 million is included in our rate base calculation as a reduction to rate base.

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 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 ~~electric~~ utility customers ~~in excess of~~that are either higher or lower than the current rates and ~~which~~ 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 ~~with respect to Black Hills Power~~ 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.

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. ~~Liabilities will be settled and trued up following completion of the related activities.~~

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 - ~~retirements.~~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.

~~Allowance for Funds Used During Construction~~

~~AFUDC represents the approximate composite cost of borrowed funds and a return on capital used to finance a project.~~

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 ~~receivables~~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 ~~potentially~~ 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 ~~the ability to pay.~~

~~The allowance for doubtful accounts represents our best estimate of existing accounts receivable that will ultimately be uncollected.~~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 best estimate of future collection success given the existing collections environment.

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

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.

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% in ~~2011~~2012, 2.2% in ~~2010~~2011 and ~~2.8%~~2.2% in ~~2009~~2010.

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 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.

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.

We file a federal income tax return with other members of the 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.

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

It is ~~our~~the 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 ~~currently in our regulated businesses~~ 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 7 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 did not have any other impact on our financial statements. See the accompanying Comprehensive Income Statement and additional disclosures in Note 8.

~~Fair Value Measurements and Disclosures, ASC 820~~

The ASC for Fair Value Measurements and Disclosures defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosure requirements related to fair value measurements. This does not expand the application of fair value accounting to any new circumstances, but applies the framework to other applicable GAAP that requires or permits fair value measurement. We apply fair value measurements to certain assets and liabilities, primarily employee benefit plan assets and other miscellaneous financial instruments.

In January 2010, the FASB issued guidance related to improving disclosures about fair value measurements. The guidance requires separate disclosures of the amounts of transfers in and out of Level 1 and Level 2 fair value measurements, disclosure of inputs and techniques used in valuation and a description of the reason for such transfers. In the reconciliation for Level 3 fair value measurements using significant unobservable inputs, information about purchases, sales, issuances and settlements are required to be presented separately. These disclosures are required for interim and annual reporting periods and were effective for us January 1, 2010, except the disclosures related to purchases, sales, issuances and settlements in the roll forward activity of Level 3 fair value measurements, which were effective January 1, 2011. The guidance requires additional disclosures, but did not impact our financial position, results of operations or cash flows. The additional disclosures are included in Note 9.

~~Recently Issued Accounting Standards and Legislation~~

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. ~~This amendment changes~~Additional disclosure requirements in the ~~wording used to describe~~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 ~~disclosures. We do~~detail for components of other comprehensive income that are not ~~expect this amendment, which is~~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 ~~December 31, 2011, to~~Dec. 15, 2012. The adoption of this standard will not have an impact on our financial position, results of operations or cash flows.

(3) PROPERTY, PLANT AND EQUIPMENT

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

The plant acquisition adjustment is included in rate base and is being recovered with 18 years remaining.

(4) 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"), 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 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 ~~the~~ Wygen III ~~generation facility~~ 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.



¨	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



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

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



TABLE OF CONTENTS

		Page

	GLOSSARY OF TERMS AND ABBREVIATIONS	3

ITEMS 1. and 2.	BUSINESS AND PROPERTIES	5
	~~Safe Harbor for Forward Looking Information~~	5
	~~General and Regulations~~	7

ITEM 1A.	RISK FACTORS	11

ITEM 1B.	UNRESOLVED STAFF COMMENTS	17

ITEM 3.	LEGAL PROCEEDINGS	17

ITEM 5.	MARKET FOR REGISTRANT'S COMMON EQUITY RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	1817

ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS	1817

ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	23

ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	5051

ITEM 9A.	CONTROLS AND PROCEDURES	5052

ITEM 9B.	OTHER INFORMATION	52

ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	52

ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	5253

	SIGNATURES	56

	INDEX TO EXHIBITS	57



AFUDC	Allowance for Funds Used During Construction
AOCI	Accumulated Other Comprehensive Income
ASC	Accounting Standards Codification
~~ASC 220~~ASU	~~ASC 220, "Comprehensive Income"~~
~~ASC 310-10-50~~	~~ASC 310-10-50, "Disclosure About the Credit Quality of Financing Receivables and the Allowance for Credit Losses"~~
~~ASC 820~~	~~ASC 820 "Fair Value Measurements and Disclosures"~~
~~ASU 2011- 04~~	~~ASU 2011-04 "Fair Value Measurements"~~
~~ASU 2011- 05~~	~~ASU 2011-05 "Other Comprehensive Income"~~
~~ASU 2011- 12~~	~~ASU 2011-12 "Other Comprehensive Income"~~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 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.
~~Enserco~~CPCN	~~Enserco~~ Certificate of Public Convenience and Necessity
DSM	Demand Side Management
ECA	Energy ~~Inc., a wholly-owned subsidiary~~Cost Adjustment -- adjustments that allow us to pass the prudently-incurred cost of ~~Black Hills Non-Regulated Holdings, LLC. Black Hills Non-regulated Holdings divested of Enserco Energy Inc. on February 29, 2012~~fuel and ~~was presented in discontinued operations throughout the Parent Annual Report filed on Form 10-K.~~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 Investor Services, Inc.
MTPSC	Montana Public Service Commission
MW	Megawatts
MWh	Megawatt-hours
NA	Not Applicable
NOL	Net operating loss
NO_x	Nitrogen oxide
NQDC	Non-Qualified Deferred Compensation Plan
PPA	Power Purchase Agreement
~~RMSA~~	~~Retiree 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 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.
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


Unit	Fuel Type	Location	Ownership Interest %		Owned Capacity (MW)	Year Installed	Fuel Type	Location	Ownership Interest %	Owned Capacity (MW)	Year Installed
Wygen III⁽¹⁾	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⁾	Coal	Gillette, WY	20	%	72.4	1978	Coal	Gillette, WY	20%	72.4	1978
Osage ⁽³⁾	Coal	Osage, WY	100	%	34.5	1948-1952	Coal	Osage, WY	100%	34.5	1948-1952
Ben French(3)	Coal	Rapid City, SD	100	%	25.0	1960	Coal	Rapid City, SD	100%	25.0	1960
Neil Simpson I(3)	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 ⁽⁴⁾	Gas/Oil	Rapid City, SD	100	%	100.0	1977-1979	Gas/Oil	Rapid City, SD	100%	80.0	1977-1979
					490.9					470.9


(1)	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)	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.



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
SD	Global Settlement	8.60%	Global Settlement	4/2010	ECA,TCA, Energy Efficiency Cost Recovery/ DSM	65%
SD		8.16%		6/2011	Environmental Improvement Cost Recovery Adjustment Tariff	NA
WY	10.5%	8.60%	48%/52%	6/2010	TCA, ECA	NA
MT	15.0%	11.73%	47%/53%	1983	ECA	NA
FERC	10.8%	9.12%	43%/57%	2/2009	FERC Transmission Tariff	NA


Regulated Power Plant Fleet Availability	2011			2010		2009		2012		2011		2010
Coal-fired plants(a)	88.8	%	^(a)	93.5	%	90.3	%	91.9	%	88.8	%	93.5	%
Other plants	95.8	%		95.7	%	97.7	%	98.5	%	95.8	%	95.7	%
Total availability	91.5	%		94.4	%	93.5	%	94.5	%	91.5	%	94.4	%


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


Resources	2011	Percentage Change		2010	Percentage Change		2009	2012	Percentage Change		2011	Percentage Change		2010
MWh generated:
Coal	1,717,008	(14	)%	1,987,037	15	%	1,721,074	1,796,936	5	%	1,717,008	(14	)%	1,987,037
Gas	15,221	(21	)%	19,269	(59	)%	46,723	33,183	118	%	15,221	(21	)%	19,269
	1,732,229	(14	)%	2,006,306	13	%	1,767,797	1,830,119	6	%	1,732,229	(14	)%	2,006,306

MWh purchased	1,720,640	19	%	1,440,579	(15	)%	1,686,455	1,678,090	(2	)%	1,720,640	19	%	1,440,579
Total resources	3,452,869	—	%	3,446,885	0	%	3,454,252	3,508,209	2	%	3,452,869	0	%	3,446,885


Heating and Cooling Degree Days	2011		2010		2009		2012		2011		2010

Actual
Heating degree days	7,579		7,272		7,753		6,206		7,579		7,272
Cooling degree days	700		532		354		937		700		532

Variance from 30-year average
Heating degree days	5	%	1	%	8	%	(13	)%	5	%	1	%
Cooling degree days	17	%	(11	)%	(41	)%	47	%	17	%	(11	)%



	Page

Report of Independent Registered Public Accounting Firm	24

Statements of Income for the three years ended December 31, ~~2011~~2012	25

Statements of Comprehensive Income (Loss) for the three years ended December 31, ~~2011~~2012	2625

Balance Sheets as of December 31, ~~2011~~2012 and ~~2010~~2011	27

Statements of Cash Flows for the three years ended December 31, ~~2011~~2012	28

Statements of Common Stockholder's Equity for the three years ended December 31, ~~2011~~2012	29

Notes to Financial Statements	30


Years ended December 31,	2011			2010			2009			2012			2011			2010
	(in thousands)									(in thousands)

Revenue	$	245,631		$	229,763		$	207,079		$	243,309		$	245,631		$	229,763

Operating expenses:
Fuel and purchased power	93,222			87,757			91,349			87,519			93,222			87,757
Operations and maintenance	66,683			68,884			57,116			65,835			66,683			68,884
Gain on sale of operating assets	(768		)	(6,238		)	—			—			(768		)	(6,238		)
Depreciation and amortization	27,217			22,030			19,465			27,621			27,217			22,030
Taxes - property	4,557			2,062			4,344			4,753			4,557			2,062
Total operating expenses	190,911			174,495			172,274			185,728			190,911			174,495

Operating income	54,720			55,268			34,805			57,581			54,720			55,268

Other income (expense):
Interest expense	(16,712		)	(18,737		)	(15,779		)	(17,602		)	(16,712		)	(18,737		)
AFUDC - borrowed	419			2,224			4,357			161			419			2,224
Interest income	154			318			258			376			154			318
AFUDC - equity	705			2,748			5,831			325			705			2,748
Other expense	(344		)	(35		)	—			—			(344		)	(35		)
Other income	145			223			1,971			554			145			223
Total other income (expense)	(15,633		)	(13,259		)	(3,362		)	(16,186		)	(15,633		)	(13,259		)

Income from continuing operations before income taxes	39,087			42,009			31,443			41,395			39,087			42,009
Income tax expense	(11,990		)	(10,741		)	(8,304		)	(14,309		)	(11,990		)	(10,741		)

Net income	$	27,097		$	31,268		$	23,139		$	27,086		$	27,097		$	31,268


At December 31,	2011			2010
As of December 31,							2012			2011
	(in thousands, except share amounts)						(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	2,812		$	2,045		$	3,805		$	2,812
Receivables - customers, net	24,668			28,716			23,867			24,668
Receivables - affiliates	6,998			6,891			5,027			6,998
Other receivables, net	786			2,077			673			786
Money pool notes receivable	50,477			39,862			31,645			50,477
Materials, supplies and fuel	22,074			21,259			20,633			22,074
Deferred income tax assets, net, current							16,631			—
Regulatory assets, current	6,605			3,584			4,998			6,605
Other current assets	4,255			3,712			5,781			4,255
Total current assets	118,675			108,146			113,060			118,675

Investments	4,592			4,396			4,359			4,592

Property, plant and equipment	995,772			962,640			1,024,768			995,772
Less accumulated depreciation and amortization	(313,581		)	(304,800		)	(322,830		)	(313,581		)
Total property, plant and equipment, net	682,191			657,840			701,938			682,191

Other assets:
Regulatory assets, non-current	45,160			37,740			48,244			45,160
Other, non-current assets	3,812			3,610			5,322			3,812
Total other assets	48,972			41,350			53,566			48,972
TOTAL ASSETS	$	854,430		$	811,732		$	872,923		$	854,430

LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities:
Current maturities of long-term debt	$	37		$	81		$	—		$	37
Accounts payable	12,560			14,828			14,318			12,560
Accounts payable - affiliates	18,598			12,562			21,896			18,598
Accrued liabilities	16,448			15,541			15,477			16,448
Regulatory liabilities, current	853			1,932			37			853
Deferred income tax liabilities, net, current	848			859			—			848
Total current liabilities	49,344			45,803			51,728			49,344

Long-term debt, net of current maturities	276,390			276,422			269,944			276,390


	2011			2010			2009			2012			2011			2010
	(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	$	247,688		$	216,420		$	193,281		$	274,785		$	247,688		$	216,420
Net income available for common stock	27,097			31,268			23,139
Net income										27,086			27,097			31,268
Non-cash dividend to Parent company										(43,984		)	—			—
Balance end of year	$	274,785		$	247,688		$	216,420		$	257,887		$	274,785		$	247,688

Accumulated other comprehensive loss:
Balance beginning of year	$	(1,262	)	$	(1,213	)	$	(1,349	)	$	(1,290	)	$	(1,262	)	$	(1,213	)
Other comprehensive (loss) income, net of tax	(28		)	(49		)	136			(130		)	(28		)	(49		)
Balance end of year	$	(1,290	)	$	(1,262	)	$	(1,213	)	$	(1,420	)	$	(1,290	)	$	(1,262	)

Total stockholder's equity	$	336,486		$	309,417		$	278,198		$	319,458		$	336,486		$	309,417


	Maximum Recovery Period	2011		2010		Maximum Recovery Period (in years)	2012		2011
Regulatory assets:
Unamortized loss on reacquired debt(a)	14 years	$	2,765	$	3,016	14	$	2,501	$	2,765
AFUDC(b)	45 years	8,552		9,489		45	8,460		8,552
Employee benefit plans	13 years	27,602		18,049
Employee benefit plans^(c)						13	27,001		27,602
Deferred energy costs(a)	1 year	6,605		3,584		1	6,892		6,605
Flow through accounting(a)	35 years	5,789		4,772		35	8,019		5,789
Other		452		2,414
Other^(a)						2	369		452
Total regulatory assets		$	51,765	$	41,324		$	53,242	$	51,765

Regulatory liabilities:
Cost of removal for utility plant(a)	53 years	$	23,347	$	15,429	53	$	26,630	$	23,347
Employee benefit plans	13 years	15,282		10,204
Other		1,845		4,575
Employee benefit plans^(d)						13	15,689		15,282
Other^(e)						13	1,567		1,845
Total regulatory liabilities		$	40,474	$	30,208		$	43,886	$	40,474


	2011			2010			2012			2011
Accounts receivable trade	$	16,447		$	21,365		$	14,965		$	16,447
Unbilled revenues	8,364			7,581			9,004			8,364
Total accounts receivable - customers	24,811			28,946			23,969			24,811
Allowance for doubtful accounts	(143		)	(230		)	(102		)	(143		)
Net accounts receivable	$	24,668		$	28,716		$	23,867		$	24,668


				December 31, 2011				December 31, 2010						2012				2011
				Weighted				Weighted						Weighted				Weighted
				Average				Average	Lives (in years)					Average				Average	Lives (in years)
	December 31, 2011			Useful Life (in years)	December 31, 2010			Useful Life (in years)	Minimum	Maximum	2012			Useful Life (in years)	2011			Useful Life (in years)	Minimum	Maximum
Electric plant:
Production	$	504,088		51	$	475,762		50	45	65	$	510,674		51	$	504,088		51	45	65
Transmission	115,063			47	116,056			43	40	60	115,092			46	115,063			47	40	60
Distribution	289,833			39	271,470			37	16	45	304,113			38	289,833			39	16	45
Plant acquisition adjustment(a)	4,870			32	4,870			32	32	32	4,870			32	4,870			32	32
General	72,045			21	58,777			22	8	45	71,802			22	72,045			21	8	45
Construction work in progress	9,873				35,705						18,217				9,873
Total electric plant	995,772				962,640						1,024,768				995,772
Less accumulated depreciation and amortization	(313,581		)		(304,800		)				(322,830		)		(313,581		)
Electric plant net of accumulated depreciation and amortization	$	682,191			$	657,840					$	701,938			$	682,191


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	$	109,007	$	718	$	46,104	$	109,465	$	451	$	47,776
Transmission Tie	$	19,648	$	—	$	4,061	$	19,648	$	—	$	4,414
Wygen III	$	129,791	$	249	$	5,328	$	130,267	$	565	$	8,376


	Maturity Date	Fixed Interest Rate		December 31, 2011			December 31, 2010			Maturity Date	Interest Rate		2012			2011
First Mortgage Bonds due 2032	August 15, 2032	7.23	%	75,000			75,000			August 15, 2032	7.23	%	$	75,000		$	75,000
First Mortgage Bonds due 2039	November 1, 2039	6.125	%	180,000			180,000			November 1, 2039	6.125	%	180,000			180,000
Unamortized discount, First Mortgage Bonds due 2039				(115		)	(119		)				(111		)	(115		)
Pollution control revenue bonds due 2014(a)	October 1, 2014	4.80	%	6,450			6,450			October 1, 2014	4.80	%	—			6,450
Pollution control revenue bonds due 2024	October 1, 2024	5.35	%	12,200			12,200			October 1, 2024	5.35	%	12,200			12,200
Series 94A Debt	June 1, 2024	3.00	%	2,855			2,855
Series 94A Debt^(b)										June 1, 2024	1.35	%	2,855			2,855
Other	May 12, 2012	13.66	%	37			117			May 25, 2012	13.66	%	—			37

Total long-term debt				276,427			276,503						269,944			276,427
Less current maturities				(37		)	(81		)				—			(37		)
Net long-term debt				$	276,390		$	276,422					$	269,944		$	276,390


^(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.


2012	$	37
2013	$	—	$	—
2014	$	6,450	$	—
2015	$	—	$	—
2016	$	—	$	—
2017			$	—
Thereafter	$	270,055	$	270,055


(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


	December 31, 2011			December 31, 2010			December 31, 2009			2012			2011			2010
Current	$	14,921		$	(14,885	)	$	(3,296	)	$	(10,319	)	$	14,921		$	(14,885	)
Deferred	(2,931		)	25,626			11,600			24,628			(2,931		)	25,626
Total income tax expense	$	11,990		$	10,741		$	8,304		$	14,309		$	11,990		$	10,741



	December 31, 2011			December 31, 2010
Deferred tax assets, current:
Asset valuation reserve	$	491		$	217
Employee benefits	1,086			803
Rate refund	360			428
Total deferred tax assets, current	1,937			1,448

Deferred tax liabilities, current:
Prepaid expenses	(256		)	(251		)
Deferred costs	(2,529		)	(2,056		)
Total deferred tax liabilities, current	(2,785		)	(2,307		)

Net deferred tax assets (liabilities), current	$	(848	)	$	(859	)

Deferred tax assets, non-current:
Plant related differences	$	—		$	909
Regulatory liabilities	14,644			10,074
Employee benefits	3,922			3,547
Net operating loss	28,072			9,147
Items of other comprehensive income	263			225
Research and development credit	780			1,613
Other	1,155			—
Total deferred tax assets, non-current	48,836			25,515

Deferred tax liabilities, non-current:
Accelerated depreciation and other plant related differences	(148,254		)	(132,338		)
AFUDC	(5,559		)	(6,168		)
Regulatory assets	(5,019		)	(5,557		)
Employee benefits	(2,356		)	(2,983		)
Other	(968		)	(788		)
Total deferred tax liabilities, non-current	(162,156		)	(147,834		)

Net deferred tax assets (liabilities), non-current	$	(113,320	)	$	(122,319	)

Net deferred tax assets (liabilities)	$	(114,168	)	$	(123,178	)



	2011			2010
Change in deferred income tax assets (liabilities)	$	(9,010	)	$	25,118
Deferred taxes related to regulatory assets and liabilities	4,968			9,272
Deferred taxes associated with other comprehensive income	15			(2,141		)
Deferred taxes related to property basis differences	156			(4,713		)
Deferred taxes related to AFUDC	937			(1,910		)
Other	3			—
Deferred income tax expense (benefit) for the period	$	(2,931	)	$	25,626



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

Deferred tax liabilities:
Accelerated depreciation and other plant related differences	(154,989		)	(148,254		)
AFUDC	(5,499		)	(5,559		)
Regulatory assets	(5,767		)	(5,019		)
Employee benefits	(3,610		)	(2,356		)
Other	(3,771		)	(3,753		)
Total deferred tax liabilities	(173,636		)	(164,941		)

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



	December 31, 2011
	Pre-tax Amount			Tax (Expense) Benefit			Net-of-tax Amount
Minimum pension liability adjustment - net gain (loss)	$	(108	)	$	38		$	(70	)
Reclassification adjustments of cash flow hedges settled and included in net income	65			(23		)	42
Net change in fair value of derivatives designated as cash flow hedges	—			—			—
Other comprehensive income (loss)	$	(43	)	$	15		$	(28	)



	December 31, 2011			December 31, 2010
Derivatives designated as cash flow hedges	$	(801	)	$	(843	)
Employee benefit plans	(489		)	(419		)
Total accumulated other comprehensive loss	$	(1,290	)	$	(1,262	)



	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	)



	2012		2011
Equity securities	51	%	69	%
Fixed income funds	48	%	28	%
Cash and cash equivalents	1	%	3	%
Total	100	%	100	%



	2012
Defined Benefit Plans
Defined Benefit Pension Plan	$	—
Non-pension Defined Benefit Postretirement Healthcare Plan	$	658
Supplemental Non-qualified Defined Benefit Plan	$	154


��	Defined Benefit Pension Plans						Supplemental Non-qualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Plans
																			Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Healthcare Plan
	2011			2010			2011			2010			2011			2010			2012			2011			2012			2011			2012			2011
Change in benefit obligation:
Projected benefit obligation at beginning of year	$	57,753		$	55,615		$	2,152		$	1,690		$	7,517		$	9,432		$	65,557		$	57,753		$	2,292		$	2,152		$	8,207		$	7,517
Service cost	798			1,215			—			—			210			340			765			798			—			—			214			210
Interest cost	3,092			3,280			114			100			365			547			2,969			3,092			104			114			343			365
Actuarial loss (gain)	852			4,129			(30		)	54			(308		)	(88		)	4,510			852			1,287			(30		)	(1,748		)	(308		)
Amendments	—			260			—			—			—			(2,270		)	—			—			—			—			—			—
Change in participant assumptions	—			—			—			—			171			—			—			—			—			—			—			171
Discount rate change	6,668			—			186			—			433			—			—			6,668			—			186			—			433
Benefits paid	(2,899		)	(2,472		)	(130		)	(109		)	(707		)	(658		)	(2,850		)	(2,899		)	(256		)	(130		)	(835		)	(707		)
Asset transfer (to) from affiliate	(707		)	(3,300		)	—			417			(40		)	(328		)	(1,131		)	(707		)	—			—			26			(40		)
Plan curtailment reduction	—			(974		)	—			—			—			—			—			—			—			—			—			—
Medicare Part D adjustment	—			—			—			—			67			88			—			—			—			—			71			67
Plan participants' contributions	—			—			—			—			499			454			—			—			—			—			488			499
Net increase (decrease)	7,804			2,138			140			462			690			(1,915		)

Projected benefit obligation at end 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


	Defined Benefits Pension Plans		Supplemental Non-qualified Defined Benefit Retirement Plans		Non-pension Defined Benefit Postretirement Plans			Defined Benefits Pension Plan		Supplemental Non-qualified Defined Benefit Retirement Plans		Non-pension Defined Benefit Postretirement Healthcare Plan
Net loss	$	1,689	$	36	$	90		$	1,696	$	43	$	6
Prior service cost	37		—		(181		)	27		—		(181		)
Transition obligation	—		—		—
Total net periodic benefit cost expected to be recognized during calendar year 2011	$	1,726	$	36	$	(90	)

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


*	The expected rate of return on plan assets ~~changed to~~ is 7.25% for the calculation of the ~~2012~~2013 net periodic pension cost.



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

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