ITEM 1A.
RISK FACTORS
The following specific 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 factors and other matters discussed herein are important factors that could cause our actual results or outcomes to differ materially from those discussed in the forward looking statements included elsewhere in this document.
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.
Our regulated 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, 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 revenues, cash flows and results of operations.
The recent global financial crisis made the credit markets less accessible and created a shortage of available credit. Should a similar financial crisis occur in the future, we may be unable to obtain the financing needed to refinance debt, fund planned capital expenditures or otherwise execute our operating strategy.
Our ability to execute our operating strategy is highly dependent upon our access to capital. Historically, we have addressed our liquidity needs (including funds required to make scheduled principal and interest payments, refinance debt and fund working capital and planned capital expenditures) with operating cash flow, borrowings under credit facilities, proceeds of debt offerings and proceeds from asset sales. Our ability to access the capital markets and the costs and terms of available financing depend on many factors, including changes in our credit ratings, changes in the Federal or state regulatory environment affecting energy companies, volatility in commodity or electricity prices and general economic and market conditions.
Our financial performance depends on the successful operations of our facilities.
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.
·
Breakdown or failure of equipment or processes.
·
Inability to recruit and retain skilled technical labor.
·
Labor relations. Renewal negotiations of the collective bargaining agreement are planned in early 2010.
·
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.
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 are, therefore, not recoverable.
Our regulated electricity operations are subject to cost-of-service regulation and earnings oversight from federal and state utility commissions. 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. 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 and purchased power costs, as applicable) without having to file a rate case. To the extent we are able to pass through such costs to our customers and a state public utility commission subsequently determines that such costs should not have been paid by our customers; we may be required to refund such costs to our customers. Any such costs not recovered through rates, or any such refund, could negatively affect our revenues, cash flows and results of operations.
The global financial crisis has affected our counterparty credit risk.
As a consequence of the global financial crisis, the creditworthiness of many of our contractual counterparties (particularly financial institutions) has deteriorated.
We have established guidelines, controls and limits to manage and mitigate credit risk. For our energy marketing, production and generation activities, we seek to mitigate our credit risk by conducting a majority of our business with investment grade companies, setting tenor and credit limits commensurate with counterparty financial strength, obtaining netting agreements and securing our credit exposure with less creditworthy counterparties through parent company guarantees, prepayments, letters of credit and other security agreements. Although we aggressively monitor and evaluate changes 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 exposure to contractual counterparties to increase materially, such increased exposure could have a material adverse effect on our results of operations, cash flows and financial condition.
National and regional economic conditions may cause increased late payments and uncollectible accounts, which would reduce earnings and cash flows.
A prolonged recession may lead to an increase in late payments from retail and commercial utility customers, as well as our non-utility customers (including marketing counterparties). If late payments and uncollectible accounts increase, earnings and cash flows from our continuing operations may be reduced.
Our credit ratings could be lowered below investment grade in the future. If this were to occur, our access to capital and our cost of capital and other costs would be negatively affected.
Our credit rating on our First Mortgage Bonds is "A3" by Moody's, "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;
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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 inability and cost of recruiting and retaining 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;
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Weather interferences;
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Unexpected engineering, environmental and 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.
Because prices in the wholesale power markets are volatile, our revenues and expenses may fluctuate.
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.
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 financial condition and results of operations.
Our business is subject to substantial governmental regulation and permitting requirements as well as environmental liabilities. We may be adversely affected if we fail to achieve or maintain compliance with existing or future regulations or requirements, or the potentially high cost of complying with such requirements or addressing environmental liabilities.
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; 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.
Federal and state laws concerning climate change and air emissions, including emission reduction mandates and renewable energy portfolio standards, may materially increase our generation and production costs and could render some of our generating units uneconomical to operate and maintain.
We own and operate regulated and non-regulated fossil-fuel generating plants in South Dakota and Wyoming. We are near completion of another fossil-fuel generating plant in Wyoming. Air emissions of fossil-fuel generating plants are subject to federal and state regulation. Recent developments under federal and state laws and regulation governing air emissions from fossil-fuel generating plants will likely result in more stringent emission limitations.
On October 22, 2009, the EPA filed a consent decree with environmentalists in the U.S. District Court for the District of Columbia, requiring the agency to propose a rule directed at coal and oil-fired power plants, setting maximum achievable control technology limits for air toxins, including mercury, by March 2011 and issue a final rule by November 2011. While we expect this rule will be applicable to certain of our coal-fired units, we are unable to ascertain the full impact until the provisions of the proposed rule are known.
On April 2, 2007, the U.S. Supreme Court issued a decision in the case of Massachusetts v. U.S. Environmental Protection Agency, holding that CO2 and other GHG emissions are pollutants subject to regulation under the motor vehicle provisions of the Clean Air Act. The case was remanded to the EPA for further rulemaking to determine whether GHG emissions may reasonably be anticipated to endanger public health or welfare, or alternatively, to explain why GHG emissions should not be regulated. On April 17, 2009, the EPA signed its proposed Endangerment and Cause or Contribute Finding for Greenhouse Gases under Section 202 of the Clean Air Act. Although this proposal does not specifically address stationary sources, such as power generation plants, the general endangerment finding relative to GHGs could support such a proposal by the EPA for stationary sources. On October 30, 2009, the EPA published final rules regarding a mandatory GHG reporting regimen, the purpose of which would be to collect data to inform future policy and regulatory decisions.
In addition, the EPA published in the October 27, 2009, Federal Register a proposed rule that would tailor the major source applicability thresholds for GHG emissions under the PSD and Title V programs of the Clean Air Act and set a PSD significance level for GHG emissions. EPA states this rule is necessary because they expect to soon promulgate regulations under the Clean Air Act to control GHG emissions and as a result, trigger PSD and Title V applicability requirements. This proposed rule would phase in the applicability thresholds for both the PSD and Title V programs for sources of GHG emissions. The first phase, which would last six years, would establish a temporary level for the PSD and Title V applicability thresholds at 25,000 tons per year on a carbon dioxide equivalent basis and would also establish temporary PSD significance levels. All our generating units would exceed this threshold and if the pending rule to control GHG emissions is published and finalized, we would be required upon Title V permit renewal, to evaluate options for reducing GHG emissions, to possibly include a Best Available Control Technology review that could result in more stringent emissions control practices and technologies. In the second phase of this proposed rule, EPA would within five years of the rule being final, review the first phase and promulgate revised applicability and significance level thresholds as appropriate.
Finally, federal legislation is currently under consideration in the U.S. Congress, including H.R. 2454, "the American Clean Energy and Security Act of 2009," which was approved by the U.S. House of Representatives on June 26, 2009. This legislation would affect electric generation and electric and natural gas distribution companies. H.R. 2454 also proposes a national renewable electricity standard, which would implement a phased process ultimately mandating that 20% of electricity sold by retail suppliers be met by energy efficiency improvements and renewable energy resources by 2020.
The climate bill under consideration in the U.S. Senate is S.1733, "the Clean Energy Jobs and American Power Act." S.1733 was passed by the Environment and Public Works Committee November 5, 2009, but is not expected to be brought to the Senate floor in its current form. Other committees with jurisdiction include Finance, Energy and Natural Resources, Commerce, Agriculture, and Foreign Relations. The Senate Energy and Natural Resources Committee passed S.1462, "the American Clean Energy Leadership Act of 2009," on July 16, 2009, which would establish a 15% Renewable Electricity Standard by 2021. If the Senate were to act in 2010, it is likely the climate change and renewable electricity standard portions would be combined into one bill.
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 upon 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 also be affected by the degree to which offsets are allowed, the allocation of emission allowances to specific sources, and the affect of carbon regulation on natural gas and coal prices.
More stringent GHG emissions limitations or other energy efficiency requirements, however, 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. Black Hills Non-regulated Holdings would also attempt to recover the emission compliance costs of their non-regulated fossil-fuel generating plants from utility and other purchasers of the power generated by the affiliated 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.
We own regulated electric utilities that serve customers in South Dakota, Wyoming and Montana. Montana has adopted mandatory renewable portfolio standards that require electric utilities to supply a minimum percentage of the power delivered to customers from renewable resources (e.g., wind, solar, biomass) by a certain date in the future. These renewable energy portfolio standards have increased the power supply costs of our electric operations. If these states increase their renewable energy portfolio standards, our power supply costs will further increase. Although we will seek to recover these higher costs in rates, any unrecovered costs could have a material negative impact on our results of operations and financial condition.
We may be vulnerable to cyber attacks and terrorism.
Man-made problems such as computer viruses, terrorism, theft and sabotage, may disrupt our operations and harm our operating results. We operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. Our technology systems may be vulnerable to disability, failures or unauthorized access due to hacking, viruses, acts of war or terrorism and other causes. If our technology systems were to fail or be breached and we were unable to recover in a timely manner, we may be unable to fulfill critical business functions and sensitive, confidential and other data could be compromised, which could have a material adverse effect on our results of operations, financial condition and cash flows. In addition, our generation plants, fuel storage facilities, transmission and distribution facilities may be targets of terrorist activities that could disrupt our ability to produce or distribute some portion of our energy products.
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 profitability.
The United States electric utility industry is currently experiencing increasing competitive pressures as a result of:
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The Energy Policy Act of 2005 and the repeal of the PUHCA;
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Industry consolidation;
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Consumer demands;
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Transmission constraints;
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Renewable resource supply requirements;
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Resistance to the siting of utility infrastructure or to the granting of right-of-ways;
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Technological advances; and
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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 financial condition or results of operations.
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.
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.
Increased risks of regulatory penalties could negatively impact our business.
The Energy Policy Act of 2005 increased FERC's civil penalty authority for violation of FERC statutes, rules and orders. FERC can now impose penalties of $1.0 million per violation, per day. Many rules that were historically subject to voluntary compliance are now mandatory and subject to potential civil penalties for violations. If a serious violation did occur, and penalties were imposed by FERC, it could have a material adverse effect on our operations or our financial results.
Increasing costs associated with our defined benefit retirement plans may adversely affect our results of operations, financial position or liquidity.
We have defined benefit pension plans that cover 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 any changes in governmental regulations. In addition, the Pension Protection Act of 2006 changed the minimum funding requirements for defined benefit pension plans beginning in 2008.
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 and funding requirements associated with our health care plans may adversely affect our results of operations, financial position or liquidity.
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. During their assessment of these controls, management or our independent auditors may identify areas of weakness in control design or effectiveness, which may lead to the conclusion that a material weakness in internal control exists.
ITEM 1B.
ITEM 1B.
UNRESOLVED STAFF COMMENTS
None.
ITEM 3.
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.
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.
ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
The following tables provide certain electric utility operating statistics:
We established a new summer peak load of 430 MW in July 2007 and a new winter peak load of 407 MW in December 2008. We own 434 MW of electric utility generating capacity and purchase an additional 50 MW under a long-term agreement expiring in 2023.
Regulated power plant fleet availability:
Coal-fired plants
90.3%
93.5%
95.4%
Other plants
97.7%
89.2%
99.4%
Total availability
93.5%
91.6%
97.2%
Heating and cooling degree days:
Actual
Heating degree days
7,753
7,676
6,627
Cooling degree days
1,033
Variance from 30-year average:
Heating degree days
8%
6%
(7)%
Cooling degree days
(41)%
(19)%
74%
2009 Compared to 2008
Net income increased $0.4 million or 2% primarily due to:
·
$6.5 million increase in other margins primarily due to an increase in transmission rates effective January 1, 2009;
·
Increased other income primarily due to a $2.2 million increase of AFUDC-equity, attributable to the ongoing construction of Wygen III; and
·
Income tax expense decreased $1.2 million primarily due to a decrease in pre-tax net income and the favorable tax impact as a result of the increase in AFUDC-equity.
Partially offsetting the increases to earnings was the following:
·
Margins from wholesale off-system sales decreased $7.6 million due to a 46% decrease in energy prices and a 6% decrease in total MWh sold in the power markets;
·
Increase in net interest expense of $1.1 million primarily due to a new debt issuance; and
·
A $1.0 million decrease in retail and wholesale margins primarily due to increased coal costs and a 2% decrease in MWh sold related to lower cooling degree days.
2008 Compared to 2007
Net income decreased $2.1 million or 9% primarily due to:
·
A $2.6 million reduction in retail and wholesale sales margins due to increased fuel and purchased power costs, primarily due to increased coal costs and scheduled and unscheduled outages at Ben French, Osage and Neil Simpson I coal-fired plants. The duration of the Ben French outage was three months as we accelerated the completion of maintenance projects that were originally scheduled for this plant in 2009;
·
Increased operating expenses due to increased repairs and maintenance expenses and labor overhead costs; and
·
Increased administrative and general expenses of $1.9 million due to an increase in the workers' compensation reserve.
Partially offsetting the decreases to earnings was the following:
·
Margins from wholesale off-system sales increased $1.3 million. Total MWh increased 58% as we were able to take advantage of favorable market conditions and high MIDC pricing due to below normal temperatures; and
·
Income related to a $5.3 million increase of AFUDC, primarily attributable to the ongoing construction of Wygen III.
Rate Increase Requests. 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. We are seeking a $3.8 million, or approximately 38.95%, increase in annual utility revenues and anticipate that the new rates will be effective for our Wyoming customers on or around July 1, 2010, although recovery could be delayed until August 2010 as part of the regulatory process. The proposed rate increase is subject to approval by the WPSC and we cannot predict the outcome of this rate filing request.
On September 30, 2009, we filed a rate case with the SDPUC requesting an electric revenue increase to recover costs associated with Wygen III and other generation, transmission and distribution assets and increased operating expenses incurred during the past four years. We are seeking a $32.0 million, or approximately 26.6%, increase in annual utility revenues. The final order from the SDPUC is not expected by April 1, 2010. On March 1, 2010, we filed a petition with the SDPUC requesting an interim rate increase of $24.0 million, or 20%, for South Dakota utility customers. The SDPUC approved the request for interim rates on March 9, 2010 effective April 1, 2010. The proposed rate increase is subject to approval by the SDPUC and we cannot predict the outcome of this rate filing request.
Rate Increase Settlement. On February 10, 2009, FERC approved a formulaic approach to the method used to determine the revenue component of our open access transmission tariff, and increased our annual transmission revenue requirement by approximately $3.8 million. The revenue requirement is based on an equity return of 10.8%, and a capital structure consisting of 57% equity and 43% debt. The new rates had an effective date of January 1, 2009.
In December 2006, we received an order from the SDPUC, effective January 1, 2007, approving a 7.8% increase in retail rates and the addition of tariff provisions for automatic cost adjustments. The cost adjustments require us to absorb a portion of power cost increases partially depending on earnings from certain short-term wholesale sales of electricity. Absent certain conditions, the order also restricts us from requesting an increase in base rates that would go into effect prior to January 1, 2010. South Dakota retail customers account for approximately 90% of our total retail revenues.
Wygen III Power Plant Project
In March 2008, we received final regulatory approval for construction of Wygen III. Construction began immediately and the 110 MW coal-fired base load electric generation facility is expected to be completed by April 2010. The expected cost of construction is approximately $255 million, which includes estimates of 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 will continue to reimburse us monthly for its 25% of the total costs paid to complete the project. We will retain responsibility for operation of the facility with a life-of-plant site lease, and operations and coal supply agreements in place with MDU.
ITEM 8.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Management's Report on Internal Control over Financial Reporting
Report of Independent Registered Public Accounting Firm
Statements of Income for the three years ended December 31, 2009
Balance Sheets as of December 31, 2009 and 2008
Statements of Cash Flows for the three years ended December 31, 2009
Statements of Common Stockholder's Equity and Comprehensive Income for the three years ended December 31, 2009
Notes to Financial Statements
32 - 57
Management's Report on Internal Control over Financial Reporting
We are responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2009, based on the criteria set forth in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. This evaluation included review of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls and a conclusion on this evaluation. Based on our evaluation we have concluded that our internal control over financial reporting was effective as of December 31, 2009.
This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management's report was not subject to attestation by our registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit us to provide only management's report in this annual report.
Black Hills Power
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholder of
Black Hills Power, Inc.
Rapid City, South Dakota
We have audited the accompanying balance sheets of Black Hills Power, Inc. (the "Company") as of December 31, 2009 and 2008, and the related statements of income, common stockholder's equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2009. 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, 2009 and 2008, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, 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 10, 2010
BLACK HILLS POWER, INC.
STATEMENTS OF INCOME
The accompanying notes to financial statements are an integral part of these financial statements.
BLACK HILLS POWER, INC.
BALANCE SHEETS
The accompanying notes to financial statements are an integral part of these financial statements.
BLACK HILLS POWER, INC.
STATEMENTS OF CASH FLOWS
The accompanying notes to financial statements are an integral part of these financial statements.
BLACK HILLS POWER, INC.
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
AND COMPREHENSIVE INCOME
The accompanying notes to financial statements are an integral part of these financial statements.
NOTES TO FINANCIAL STATEMENTS
December 31, 2009, 2008 and 2007
(1)
BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Business Description
Black Hills Power, Inc. (the Company) 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 3). Certain prior years' data presented in the financial statement have been reclassified to conform to the current year presentation. The Balance Sheet has been modified to reflect "Regulatory assets, current," which had been previously included in Other current assets and "Regulatory liabilities, current," which was previously included in Accrued liabilities. The Statement of Cash Flows for December 31, 2008 and 2007 has been modified within Net cash provided by operating activities to reflect "Regulatory assets," which was previously included in Other operating activities and "Regulatory liabilities," which was previously included in Other operating activities. The Statement of Cash Flows for December 31, 2008 and 2007 has been modified within Net cash provided by operating activities to reflect “Other non-cash” which was previously included in Other operating activities.
Use of Estimates
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. The most significant estimates relate to allowance for uncollectible accounts receivable, unbilled revenues, long-lived asset values and useful lives, asset retirement obligations, employee benefits plans and contingency accruals. Actual results could differ from those estimates.
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 ratemaking 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 generation 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.
As of December 31, 2009 and 2008, we had $22.6 million and $24.6 million, respectively, in net regulatory assets for which we recover the costs, but we do not earn a return.
On December 31, 2009 and 2008, we had the following regulatory assets and liabilities (in thousands):
Regulatory assets are primarily recorded for the probable future revenue to recover the costs associated with defined benefit postretirement plans, future income taxes related to the deferred tax liability for the equity component of AFUDC of utility assets and unamortized losses on reacquired debt. To the extent that energy costs are under-recovered or over-recovered during the year, they are recorded as a regulatory asset or liability, respectively. Regulatory liabilities include the probable future decrease in rate revenues related to a decrease in deferred tax liabilities for prior reductions in statutory federal income tax rates, gains associated with regulated utilities' defined benefit postretirement plans and the cost of removal for utility plant, recovered through our electric utility rates. Regulatory assets are included in Regulatory assets, current and Regulatory assets, non-current on the accompanying Balance Sheet. Regulatory liabilities are included in Regulatory liabilities, current and Regulatory liabilities, non-current on the accompanying Balance Sheet.
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. AFUDC for the years ended December 31, 2009, 2008 and 2007 was $10.2 million, $6.2 million and $0.9 million, respectively. The equity component of AFUDC for 2009, 2008 and 2007 was $5.8 million, $3.6 million and $0.6 million, respectively. The borrowed funds component of AFUDC for 2009, 2008 and 2007 was $4.4 million, $2.6 million and $0.3 million, respectively. The equity component of AFUDC is included in Other income, and the borrowed funds component of AFUDC is netted in Interest expense on the accompanying Statements of Income.
Cash Equivalents
We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Allowance for Doubtful Accounts
We maintain an allowance for doubtful accounts which reflects our best estimate of potentially uncollectible trade receivables. We regularly review our trade receivables 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.
Following is a summary of receivables at December 31 (in thousands):
Materials, Supplies and Fuel
Materials, supplies and fuel used for construction, operation and maintenance purposes are generally stated on a weighted-average cost basis. To the extent fuel has been designated as the underlying hedged item in a "fair value" hedge transaction, those volumes are stated at market value using published industry quotations. As of December 31, 2009 and 2008, there were no market adjustments related to fuel.
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. 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 are charged to operations as incurred.
Depreciation provisions for regulated electric property, plant and equipment is computed on a straight-line basis using an annual composite rate of 2.8% in 2009, 3.2% in 2008 and 3.1% in 2007. Based on a rate study, the new composite rate of 2.8% went into effect August 2009.
Derivatives and Hedging Activities
From time to time we utilize risk management contracts including forward purchases and sales and fixed-for-float swaps to hedge the price of fuel for our combustion turbines, maximize the value of our natural gas storage or fix the interest on our 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 allows 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, net of tax, and be reclassified into earnings 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.
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. No impairment loss was recorded during 2009, 2008 or 2007.
Income Taxes
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.
Revenue Recognition
Revenue is recognized when there is persuasive evidence of an arrangement with a fixed or determinable price, delivery has occurred or services have been rendered, and collectibility is reasonably assured.
Recently Adopted Accounting Standards
FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles, ASC 105
On July 1, 2009, the FASB Accounting Standards CodificationTM became the source of authoritative GAAP recognized by the FASB to be applied by non-governmental entities. On the effective date of this Statement, the Codification superseded all then-existing non-SEC accounting and reporting standards. All other non-SEC accounting literature not included or grandfathered in the Codification became non-authoritative. This Statement is effective for financial statements issued for interim and annual periods ending after September 15, 2009.
Following this Statement, the FASB will not issue new standards in the form of Statements, FASB Staff Positions, or Emerging Task Force Abstracts. Instead, it will issue Accounting Standards Updates. The FASB will not consider Accounting Standards Updates as authoritative in their own right. Accounting Standards Updates will serve only to update the Codification, provide background information about the guidance, and provide the basis for conclusions on the change(s) in the Codification.
Business Combinations, ASC 805
The ASC for Business Combinations requires that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. It also establishes principles and requirements for how the acquirer (i) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any non-controlling interest in the acquiree, (ii) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase and (iii) discloses the nature and financial effects of the business combination; and requires restructuring and acquisition-related costs to be expensed. In addition, if income tax liabilities are settled for an amount other than as previously recorded, such adjustments could affect income tax expense in the period of adjustment. Effective January 1, 2009, any impact the standard will have on our consolidated financial statements will depend on the nature and magnitude of any future acquisitions we consummate including any tax-related adjustments.
Derivative and Hedging, ASC 815
The ASC for Derivative and Hedging Disclosures includes requirements for enhanced disclosures about derivative and hedging activities and their affect on an entity's financial position, financial performance and cash flows. Accounting standards for derivatives and hedging encourages, but does not require, disclosures for earlier periods presented for comparative purposes at initial adoption. Required disclosures for periods subsequent to January 1, 2009 are provided in Note 4.
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 disclosures about 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 commodity derivatives.
Financial Instruments, ASC 825
The ASC for Financial Instruments requires public companies to provide more frequent disclosures about the fair value of their financial instruments for interim and annual periods ending after June 15, 2009. These disclosures are included in Note 6.
Subsequent Events, ASC 855
The ASC for Subsequent Events establishes general standards of accounting for and disclosures of events that occur after the balance sheet date, but before financial statements are issued or are available to be issued. These standards and disclosures were applied to our financial statements issued after June 15, 2009.
Employers Accounting for Defined Benefit Pension and Other Postretirement Plans, ASC 715
The ASC for Employer's Accounting for Defined Benefit Pension and Other Postretirement Plans requires the recognition of the overfunded or underfunded status of defined benefit postretirement plans as an asset or liability in the statement of financial position, recognition of changes in the funded status in comprehensive income, measurement of the funded status of a plan as of the date of the year-end statement of financial position and provides for related disclosures. Effective for fiscal years ending after December 15, 2008, this accounting standard required the measurement of the funded status of the plan to coincide with the date of the year-end statement of financial position. Therefore, the measurement date for the funded status of our pension and other postretirement benefit plans was changed to December 31 from September 30. ASC 715 also provides guidance on an employer's disclosure about plan assets for a defined benefit pension or other postretirement plans. These disclosures are effective for fiscal years ending after December 15, 2009. See Note 9 for additional information.
Recently Issued Accounting Standards
Consolidation of Variable Interest Entities, ASC 810-10-15
In June 2009, the FASB issued a revision regarding consolidations. The revised accounting guidance requires a company to consider whether an entity that is insufficiently capitalized or is not controlled through voting should be consolidated. It will require additional disclosures about the involvement with variable interest entities and any significant changes in risk exposure due to that involvement. This standard is effective for annual periods that begin after November 15, 2009. We are currently assessing the impact that the adoption of this standard will have on our financial condition, results of operations, and cash flows.
Fair Value Measurements, ASC 820
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 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 shall be presented separately. These disclosures are required for interim and annual reporting periods and were effective for the Company on January 1, 2010, except for the disclosures related to the purchases, sales, issuances and settlements in the roll forward activity of Level 3 fair value measurements, which are effective on January 1, 2011. The guidance will require additional disclosures, but will not impact our financial position or results of operations.
(2)
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment at December 31, consisted of the following (in thousands):
(3)
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 and PacifiCorp owns an 80% interest in the Wyodak Plant (Plant), a 362 MW coal-fired electric generating station located in Campbell County, Wyoming. PacifiCorp is the operator of the Plant. We receive 20% of the Plant's capacity and are committed to pay 20% of its additions, replacements and operating and maintenance expenses. As of December 31, 2009 and 2008, our investment in the Plant included $79.8 million and $79.1 million, respectively, in electric plant and $52.2 million and $50.8 million, respectively, in accumulated depreciation, and is included in the corresponding captions in the accompanying Balance Sheets. Our share of direct expenses of the Plant was $8.0 million, $8.0 million and $7.3 million for the years ended December 31, 2009, 2008 and 2007, respectively, and is included in the corresponding categories of operating expenses in the accompanying Statements of Income.
·
We also own a 35% interest and Basin Electric owns a 65% interest in the Converter Station Site and South Rapid City Interconnection (the transmission tie), an AC-DC-AC transmission tie. 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 35% of the additions, replacements and operating and maintenance expenses. Our share of direct expenses was $0.1 million for each of the years ended December 31, 2009, 2008 and 2007. As of December 31, 2009 and 2008, our investment in the transmission tie was $19.6 million and $19.8 million, with $3.8 million and $2.5 million, respectively, of accumulated depreciation and is included in the corresponding captions in the accompanying Balance Sheets.
·
The Balance Sheet includes our ownership interest in the assets and liabilities of the Wygen III facility currently under construction. We own 75% of Wygen III and MDU owns 25%. Wygen III is expected to commence operations by April 1, 2010. Included in the December 31, 2009 Balance Sheet in Construction Work in Progress was $175.6 million. During 2009, we were reimbursed $48.4 million for the construction. Our share of direct expenses of the jointly-owned facility is included in Operating expenses in the Statements of Income.
(4)
RISK MANAGEMENT
We hold natural gas in storage for use as fuel for generating electricity with our gas-fired combustion turbines. To minimize associated price risk and seasonal storage level requirements, we utilize various derivative instruments in managing these risks. As of December 31, 2008, there were no derivative contracts outstanding. As of December 31, 2009, we had the following derivatives and related balances included in Accrued liabilities on the accompanying Balance Sheet (dollars, in thousands):
___________________________
*
Gas in MMbtus.
(5)
LONG-TERM DEBT
Long-term debt outstanding at December 31 is as follows (in thousands):
On October 27, 2009, we completed a $180 million first mortgage bond issuance. The bonds were priced at 99.931% of par and a reoffer yield of 6.13%. The bonds mature November 1, 2039 and carry an annual interest rate of 6.125%, which is scheduled to be paid semi-annually. We received proceeds net of underwriting fees of $178.3 million which were used to repay intercompany borrowings from BHC, primarily incurred to fund the construction of Wygen III. Deferred finance costs of approximately $2.2 million were capitalized and will be amortized over the term of the bonds.
Substantially all of our property is subject to the lien of the indenture securing our first mortgage bonds. First mortgage bonds may be issued in amounts limited by property, earnings and other provisions of the mortgage indentures.
Scheduled maturities are approximately $32.0 million in 2010; $2.0 million a year for the years 2011, 2012 and 2013; $8.4 million in 2014; and $282.7 million thereafter.
(6)
FAIR VALUE OF FINANCIAL INSTRUMENTS
The estimated fair values of our financial instruments at December 31 are as follows (in thousands):
The following methods and assumptions were used to estimate the fair value of each class of our financial instruments.
Cash and Cash Equivalents
The carrying amount approximates fair value due to the short maturity of these instruments.
Derivative Financial Instruments
These instruments are carried at fair value. Descriptions of the instruments we use are included in Note 4.
Long-Term Debt
The fair value of our long-term debt is estimated based on quoted market rates for debt instruments having similar maturities and similar debt ratings. Our outstanding first mortgage bonds are either currently not callable or are subject to make-whole provisions which would eliminate any economic benefits for us to call and refinance the first mortgage bonds.
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INCOME TAXES
Income tax expense (benefit) from continuing operations for the years ended December 31 was (in thousands):
The temporary differences which gave rise to the net deferred tax liability were as follows (in thousands):
The following table reconciles the change in the net deferred income tax liability from December 31, 2008, to December 31, 2009, to the deferred income tax expense (in thousands):
The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows:
We adopted the accounting standards for uncertain tax positions on January 1, 2007 which clarifies the accounting for uncertainty in income taxes recognized in an enterprise's financial statements in accordance with accounting standards for income taxes. The accounting standards prescribe a recognition threshold and measurement attributes for the financial statement recognition and measurement of a tax position taken or expected to be taken. The impact of this implementation had no effect on our financial statements.
The following table reconciles the total amounts of unrecognized tax benefits at the beginning and end of the period (in thousands):
The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $0.3 million.
It is our continuing practice to recognize interest and/or penalties related to income tax matters in income tax expense. During the year ended December 31, 2009, the interest expense recognized was not material to our financial results.
We file income tax returns in the United States federal jurisdiction. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of any audits or the expiration of statutes of limitations prior to December 31, 2010.
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COMPREHENSIVE INCOME
The following tables display each component of Other Comprehensive Income (Loss) and the related tax effects for the years ended December 31, (in thousands):
Balances by classification included within Accumulated other comprehensive loss on the accompanying Balance Sheets at December 31 are as follows (in thousands):
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EMPLOYEE BENEFIT PLANS
Funded Status of Benefit Plans
The funded status of postretirement benefit plans is required to be recognized in the statement of financial position. The funded status for pension plans is measured as the difference between the projected benefit obligation and the fair value of plan assets. The funded status for all other benefit plans is measured as the difference between the accumulated benefit obligation and the fair value of plan assets. A liability is recorded for an amount by which the benefit obligation exceeds the fair value of plan assets or an asset is recorded for any amount by which the fair value of plan assets exceeds the benefit obligation.
We apply accounting standards for regulated operations, and accordingly, the unrecognized net periodic benefit cost that would have been reclassified to Accumulated other comprehensive income (loss) was alternatively recorded as a regulatory asset or regulatory liability, net of tax.
The measurement date of plans should be the date of our year-end balance sheet. We had used a September 30 measurement date. During 2008, we changed the measurement date to December 31. Therefore, $0.2 million, net of tax, was recognized as an adjustment to retained earnings.
Defined Benefit Pension Plan
We have a noncontributory defined benefit pension plan (Plan) covering the employees who meet certain eligibility requirements. The benefits are based on years of service and compensation levels during the highest five consecutive years of the last ten years of service. Our funding policy is in accordance with the federal government's funding requirements. The Plan's assets are held in trust and consist primarily of equity and fixed income investments. We use a December 31 measurement date for the Plan.
In July 2009, the Board of Directors approved a freeze to our Defined Benefit Pension Plan (with the exception of bargaining unit participants). The freeze is effective January 1, 2010 and eliminates new non-bargaining unit employees from participation in the plan, and freezes the benefits of current non-bargaining unit participants except for the following group: those non-bargaining participants who are both 1) are age 45 or older as of December 31, 2009 and have 10 years or more of credited service as of January 1, 2010; and 2) elect to continue to accrue additional benefits under the pension plan and consequently forego the additional age- and points-based employer contribution under our 401(k) retirement savings plan. Plan assets and obligations were revalued July 31, 2009 in conjunction with the freeze, and we recognized a pre-tax curtailment expense of approximately $0.2 million in the third quarter of 2009.
The Plan's expected long-term rate of return on assets assumption is based upon the weighted average expected long-term rate of returns for each individual asset class. The asset class weighting is determined using the target allocation for each asset class in the Plan portfolio. The expected long-term rate of return for each asset class is determined primarily from adjusted long-term historical returns for the asset class. It is anticipated that long-term future returns will not achieve historical results.
The expected long-term rate of return for equity investments was 9.5% for the 2009 and 2008 plan years. For determining the expected long-term rate of return for equity assets, we reviewed interest rate trends and annual 20-, 30-, 40-, and 50-year returns on the S&P 500 Index, which were, at December 31, 2009, 8.1%, 11.1%, 9.7% and 9.3%, respectively. Fund management fees were estimated to be 0.18% for S&P 500 Index assets and 0.45% for other assets. The expected long-term rate of return on fixed income investments was 6.0%; the return was based upon historical returns on 10-year treasury bonds of 6.9% from 1962 to 2009, and adjusted for recent declines in interest rates. The expected long-term rate of return on cash investments was estimated to be 1.0%, which was based upon current one-year LIBOR rates.
Plan Assets
Percentage of fair value of Plan assets at December 31:
Equity
72%
68%
Fixed income
Cash
Total
100%
100%
The Investment Policy for the Pension Plans is to seek to achieve the following long-term objectives: 1) a rate of return in excess of the annualized inflation rate based on a five-year moving average; 2) a rate of return that meets or exceeds the assumed actuarial rate of return that meets or exceeds the assumed actuarial rate of return as stated in the Plan’s actuarial report; 3) a rate of return on investments, net of expenses, that is equal to or exceeds various benchmark rates on a moving three-year average, and 4) maintenance of sufficient income and liquidity to pay monthly retirement benefits. The policy strategy seeks to prudently invest in a diversified portfolio of predominately equity and fixed income assets.
The policy contains certain prohibitions on transactions in separately managed portfolios in which the Plan may invest, including prohibitions on short sales.
Cash Flows
We made no contributions to the Plan in 2009 and expect no contributions to the Plan in 2010.
Supplemental Non-qualified Defined Benefit Retirement Plans
We have various supplemental retirement plans for key executives. The Plans are non-qualified defined benefit plans. We use a December 31 measurement date for the Plans. Effective January 1, 2010, we eliminated a non-qualified pension plan in which some of our officers participated due to the partial freeze of our qualified pension plans. We also amended the NQDC, which was adopted in 1999. The NQDC is a non-qualified deferred compensation plan that provides executives with an opportunity to elect to defer compensation and receive benefits without reference to the limitations on contributions in the Plan or those imposed by the IRS. The amended NQDC provides for non-elective non-qualified restoration benefits to certain officers who are not eligible to continue accruing benefits under the Defined Benefit Pension Plans and associated non-qualified pension restoration plans. All contributions to the non-qualified plans are subject to a graded vesting schedule of 20% per year over five years with vesting credit beginning with service in the Plan on and after January 1, 2010.
Plan Assets
The Plan has no assets. We fund on a cash basis as benefits are paid.
Estimated Cash Flows
The estimated employer contribution is expected to be $0.1 million in 2010. Contributions are expected to be made in the form of benefit payments.
Non-pension Defined Benefit Postretirement Plan
Employees who are participants in our Postretirement Healthcare Plan and who retire on or after attaining age 55 after completing at least five years of service are entitled to postretirement healthcare benefits. These benefits are subject to premiums, deductibles, co-payment provisions and other limitations. We may amend or change the Plan periodically. We are not pre-funding our retiree medical plan. We use a December 31 measurement date for the Plan. In July 2009, the Board of Directors approved a freeze to the Plan which changed the structure of the Plan for non-union employees to a Retiree Medical Savings Account structure and expanded eligibility of Plan participants, effective January 1, 2010.
It has been determined that the Plan's post-65 retiree prescription drug plans are actuarially equivalent and qualify for the Medicare Part D subsidy. The effect of the Medicare Part D subsidy on the accumulated postretirement benefit obligation for the fiscal year ending December 31, 2009, was an actuarial gain of approximately $0.9 million. The effect on 2009 net periodic postretirement benefit cost was a decrease of approximately $0.1 million.
Plan Assets
The Plan has no assets. We fund on a cash basis as benefits are paid.
Estimated Cash Flows
The estimated employer contributions are expected to be $0.4 million in 2010. Contributions are expected to be made in the form of benefit payments.
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). The pension plan is able to classify fair value balances based on the observability of inputs.
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.
As required by accounting standards for fair value measurements, assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect their placement within the fair value hierarchy levels. The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value on a recurring basis as of December 31, 2009 and 2008 (in thousands):
Plan Reconciliations
The following tables provide a reconciliation of the Employee Benefit Plan's obligations and fair value of assets for 2009 and 2008, components of the net periodic expense for the years ended 2009, 2008 and 2007 and elements of regulatory assets and liabilities and AOCI for 2009 and 2008 (in thousands):
Benefit Obligations
A reconciliation of the fair value of Plan assets (as of the December 31 measurement date) is as follows (in thousands):
Amounts recognized in the statement of financial position consist of (in thousands):
Accumulated Benefit Obligation
Components of Net Periodic Expense
Accumulated Other Comprehensive Income (Loss)
Amounts included in AOCI, after-tax, that have not yet been recognized as components of net periodic benefit cost at December 31, are as follows (in thousands):
The amounts in AOCI, regulatory assets or regulatory liabilities, after-tax, expected to be recognized as a component of net periodic benefit cost during calendar year 2010 are as follows (in thousands):
Assumptions
_____________________________
*
The expected rate of return on plan assets changed to 8.00% for the calculation of the 2010 net periodic pension cost.
The healthcare cost trend rate assumption for 2009 fiscal year benefit obligation determination and 2010 fiscal year expense is a 10% increase for 2009 grading down until a 4.5% ultimate trend rate is reached in fiscal year 2027. The healthcare cost trend rate assumption for the 2008 fiscal year benefit obligation determination and 2009 fiscal year expense was a 9% increase for 2009 grading down 1% per year until a 5% ultimate trend rate is reached in fiscal year 2013.
The healthcare cost trend rate assumption has a significant effect on the amounts reported. A 1% increase in the healthcare cost trend assumption would increase the service and interest cost $0.1 million or 22% and the accumulated periodic postretirement benefit obligation $1.3 million or 14%. A 1% decrease would reduce the service and interest cost by $0.1 million or 17% and the accumulated periodic postretirement benefit obligation $1.0 million or 11%.
The following benefit payments, which reflect future service, are expected to be paid (in thousands):
Defined Contribution Plan
The Parent sponsors a 401(k) retirement savings plan in which employees may participate. Participants may elect to invest up to 50% of their eligible compensation on a pre-tax basis, up to a maximum amount established by the Internal Revenue Service. We provide a matching contribution of 100% of the employee's annual contribution up to a maximum of 3% of eligible compensation. Matching contributions vest at 20% per year and are fully vested when the participant has 5 years of service. Our matching contributions were $0.7 million for 2009, $0.7 million for 2008 and $0.6 million for 2007.
Effective January 1, 2010 in conjunction with the partial freeze of our defined benefit pension plan, we amended our 401(k) Retirement Savings Plan. This freeze covers all employees with the exception of the bargaining unit employees and certain other employees grandfathered under a prior defined benefit plan election. The amendment provides for a matching contribution of 100% of the eligible employee's annual contribution up to a maximum of 6% of eligible compensation. The amendment also provides certain eligible participants an age and service-based employer contribution.
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RELATED-PARTY TRANSACTIONS
Receivables and Payables
We have accounts receivable balances related to transactions with other BHC subsidiaries. The balances were $4.1 million and $12.6 million as of December 31, 2009 and 2008, respectively. We also have accounts payable balances related to transactions with other BHC subsidiaries. The balances were $10.0 million and $10.4 million as of December 31, 2009 and 2008, respectively.
Money Pool Notes Receivable and Notes Payable
We have a Utility Money Pool Agreement with the Parent, Cheyenne Light and Black Hills Utility Holdings. Under the agreement, we may borrow from the Parent. The Agreement restricts us from loaning funds to the Parent or to any of the Parent's non-utility subsidiaries; the Agreement does not restrict us from making dividends to the Parent. Borrowings under the agreement bear interest at the daily cost of external funds as defined under the Agreement, or if there are no external funds outstanding on that date, then the rate will be the daily one month LIBOR rate plus 100 basis points.
Through the Utility Money Pool, we have a net note receivable balance to the Parent of $57.7 million as of December 31, 2009 and a net note payable balance of $70.2 million as of December 31, 2008. Advances under this note bear interest at 0.70% above the daily LIBOR rate (0.93% at December 31, 2009). Net interest expense of $1.1 million and $0.9 million was recorded for the years ended December 31, 2009 and 2008, respectively. During 2007, we had a note receivable of $10.3 million for which we received $0.9 million of interest income.
Other Balances and Transactions
We received revenues of approximately $0.9 million, $1.2 million and $1.9 million for the years ended December 31, 2009, 2008 and 2007, respectively, from Black Hills Wyoming, Inc. for the transmission of electricity.
We received revenues of approximately $1.8 million and $2.8 million for the years ended December 31, 2009 and 2008, respectively, from Cheyenne Light for the sale of electricity and dispatch services.
We recorded revenues of $0.2 million and $1.4 million for the years ending December 31, 2008 and 2007, respectively, relating to payments received pursuant to a natural gas swap entered into with Enserco.
We purchase coal from WRDC. The amount purchased during the years ended December 31, 2009, 2008 and 2007 was $16.3 million, $15.5 million and $12.6 million, respectively. These amounts are included in Fuel and purchased power on the accompanying Statements of Income.
We purchase excess power generated by Cheyenne Light. The amount purchased during the years ended December 31, 2009 and 2008 was $8.6 million and $6.4 million, respectively.
In order to fuel our combustion turbine, we purchase natural gas from Enserco. The amount purchased during the years ended December 31, 2009, 2008 and 2007 was approximately $2.3 million, $8.0 million and $4.5 million, respectively. These amounts are included in Fuel and purchased power on the accompanying Statements of Income.
In addition, we also pay the Parent for allocated corporate support service cost incurred on our behalf. Corporate costs allocated from the Parent were $15.0 million, $12.4 million and $11.3 million for the years ended December 31, 2009, 2008 and 2007, respectively.
We have funds on deposit from Black Hills Wyoming for transmission system reserve in the amount of $2.0 million and $1.9 million at December 31, 2009 and 2008, respectively, which is included in Deferred credits and other liabilities, Other on the accompanying Balance Sheets. Interest on the deposit accrues quarterly at an average prime rate (3.25% at December 31, 2009). We paid interest expense of $0.1 million for each of the years ended December 31, 2009, 2008 and 2007, respectively.
We have two contracts with Cheyenne Light under which Cheyenne Light sells up to 40 MW of wind-generated, renewable energy to us. Purchases from these agreements during 2009 were $2.8 million and $0.6 million in 2008.
(11)
SUPPLEMENTAL CASH FLOWS INFORMATION
(12)
COMMITMENTS AND CONTINGENCIES
Partial Sale of Wygen III to MDU
On April 9, 2009, we sold to MDU a 25% ownership interest in our Wygen III generation facility currently under construction. At closing, MDU made a payment to us for its 25% share of the costs to date on the ongoing construction of the facility. Proceeds of $32.8 million were received of which $30.2 million was used to pay down a portion of the Acquisition Facility. MDU will continue to reimburse us for its 25% of the total costs paid to complete the project. In conjunction with the sales transaction, we also modified a 2004 PPA between us and MDU.
Power Purchase and Transmission Services Agreements
We have the following purchase power and transmission agreements as of December 31, 2009:
·
A PPA with PacifiCorp expiring in 2023, which provides for the purchase by us of 50 MW of electric capacity and energy. The price paid for the capacity and energy is based on the operating costs of one of PacifiCorp's coal-fired electric generating plants. Costs incurred under this agreement were $11.8 million in 2009, $11.6 million in 2008 and $10.9 million in 2007.
·
A firm point-to-point transmission access agreement to deliver up to 50 MW of power on PacifiCorp's transmission system to wholesale customers in the western region through 2023. Costs incurred under this agreement were $1.2 million in each of the years ended 2009, 2008 and 2007, respectively.
·
Cheyenne Light entered into a 20-year PPA with Happy Jack for 29.4 MW of energy. Under a separate inter-company agreement, Cheyenne Light has agreed to sell 20 MW of energy from Happy Jack to us;
·
Cheyenne Light entered into a 20-year PPA with Silver Sage for 30 MW of energy. Commercial operations commenced on October 1, 2009. Under a separate inter-company agreement, Cheyenne Light has agreed to sell 20 MW of energy from Silver Sage to us; and
·
A Generation Dispatch Agreement with Cheyenne Light that requires us to purchase all of Cheyenne Light's excess energy.
Long-Term Power Sales Agreements
We have the following power sales agreements as of December 31, 2009:
·
A contract with the City of Gillette, Wyoming, expiring in 2012, to provide the city's first 23 MW of capacity and energy. The agreement renews automatically and requires a seven-year notice of termination. This contract is integrated into our control area and is treated as part of our firm native load. As of December 31, 2009, neither party to the agreement had given notice of termination;
·
An agreement under which we supply up to 74 MW of capacity and energy to MDU for the Sheridan, Wyoming electric service territory through the end of 2016. The sales to MDU have been integrated into our control area and are considered part of our firm native load. In accordance with the terms of the agreement, MDU exercised its option to participate in the ownership of the Wygen III plant that is currently being constructed. Under an agreement entered into in April 2009, MDU purchased a 25% undivided interest in the Wygen III plant. We retain responsibility for operations of the facility with a life-of-plant lease and agreements with MDU for operations and coal supply. In conjunction with the sales transaction, we also modified the 2004 PPA under which we supplied MDU with 74 MW of capacity and energy through 2016. The PPA with MDU will be supplied from its ownership interest in Wygen III. During periods of reduced production at Wygen III, or during periods when Wygen III is offline, we will provide MDU with its first 25 MW from our other generation facilities or from system purchases; and
·
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, with capacity purchase decreasing to 15 MW in 2018, 12 MW in 2020 and 10 MW in 2022. The unit-contingent capacity amounts from Wygen III and Neil Simpson II are as follows:
2010-2017 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
·
A five-year PPA with MEAN which commences the month following the onset of commercial operations of Wygen III. Under this contract, MEAN will purchase 5 MW of unit-contingent capacity from Neil Simpson II and 5 MW of unit-contingent capacity from Wygen III.
Legal Proceedings
Ongoing Litigation
We are subject to various legal proceedings, claims and litigation which arise in the ordinary course of operations. In the opinion of management, the amount of liability, if any, with respect to these actions would not materially affect our financial position, results of operations or cash flows.
(13)
QUARTERLY HISTORICAL DATA (Unaudited)
We operate on a calendar year basis. The following table sets forth selected unaudited historical operating results data for each quarter of 2009 and 2008 (in thousands):
(14)
SUBSEQUENT EVENT
In February 2010, we provided notice to the bondholders of our intent to call the BHP Series Y bonds in full. These bonds were originally due in 2018. The balance of $2.5 million plus an early redemption premium of 2.6% will be paid on March 31, 2010.
ITEM 9.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A.
CONTROLS AND PROCEDURES
Evaluation of disclosure controls and procedures
Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (Exchange Act)) as of December 31, 2009. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective.
Internal control over financial reporting
Management's Report on Internal Control over Financial Reporting is presented on Page 26 of this Annual Report on Form 10-K.
During our fourth fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
ITEM 9B.
ITEM 9B.
OTHER INFORMATION
None.
ITEM 15.
ITEM 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a)
1.
Financial Statements
Financial statements required by Item 15 are listed in the index included in Item 8 of Part II.
2.
Schedules
Valuation and Qualifying Accounts for the years ended December 31, 2009, 2008 and 2007.
All other schedules have been omitted because of the absence of the conditions under which they are required or because the required information is included elsewhere in the financial statements incorporated by reference in this Form 10-K.
3.
Exhibits
Exhibit Number
Description
3.1*
Restated Articles of Incorporation of the Registrant (filed as an exhibit to the Registrant's Form 8-K dated June 7, 1994 (No. 1-7978)).
3.2*
Articles of Amendment to the Articles of Incorporation of the Registrant, as filed with the Secretary of State of the State of South Dakota on December 22, 2000 (filed as an exhibit to the Registrant's Form 10-K for 2000).
3.3*
Bylaws of the Registrant (filed as an exhibit to the Registrant's Registration Statement on Form S-8 dated July 13, 1999).
4.1*
Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as Exhibit 4.19 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)). First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to JPMorgan Chase Bank), as Trustee (filed as Exhibit 4.20 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)). Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 4.21 to the Registration Statement on Form S-3 (No. 333-150669-01)).
10.1*
Restated and Amended Coal Supply Agreement for NS II dated February 12, 1993 (filed as Exhibit 10.1 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)).
10.2*
Second Restated and Amended Power Sales Agreement dated September 29, 1997, between PacifiCorp and Black Hills Power, Inc. (filed as Exhibit 10.2 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)).
10.3*
Reserve Capacity Integration Agreement dated May 5, 1987, between Pacific Power & Light Company and Black Hills Power, Inc. (filed as Exhibit 10.3 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)).
Independent Auditors' Consent
31.1
Certification of Chief Executive Officer pursuant to Rule13a-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2
Certification of Chief Financial Officer pursuant to Rule13a-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
__________________________
*
Previously filed as part of the filing indicated and incorporated by reference herein.
(b)
See (a) 3. Exhibits above.
(c)
See (a) 2. Schedules above.
SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT.
The Registrant is not required to send an Annual Report or Proxy to its sole security holder and parent company, Black Hills Corporation.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
/s/ DAVID R. EMERY
Director and
March 10, 2010
David R. Emery, Chairman and
Principal Executive Officer
Chief Executive Officer
/s/ ANTHONY S. CLEBERG
Principal Financial and
March 10, 2010
Anthony S. Cleberg, Executive Vice President
Accounting Officer
and Chief Financial Officer
/s/ DAVID C. EBERTZ
Director
March 10, 2010
David C. Ebertz
/s/ JACK W. EUGSTER
Director
March 10, 2010
Jack W. Eugster
/s/ JOHN R. HOWARD
Director
March 10, 2010
John R. Howard
/s/ KAY S. JORGENSEN
Director
March 10, 2010
Kay S. Jorgensen
/s/ STEPHEN D. NEWLIN
Director
March 10, 2010
Stephen D. Newlin
/s/ GARY L. PECHOTA
Director
March 10, 2010
Gary L. Pechota
/s/ WARREN L. ROBINSON
Director
March 10, 2010
Warren L. Robinson
/s/ JOHN B. VERING
Director
March 10, 2010
John B. Vering
/s/ THOMAS J. ZELLER
Director
March 10, 2010
Thomas J. Zeller
INDEX TO EXHIBITS
Exhibit Number
Description
3.1*
Restated Articles of Incorporation of the Registrant (filed as an exhibit to the Registrant's Form 8-K dated June 7, 1994 (No. 1-7978)).
3.2*
Articles of Amendment to the Articles of Incorporation of the Registrant, as filed with the Secretary of State of the State of South Dakota on December 22, 2000 (filed as an exhibit to the Registrant's Form 10-K for 2000).
3.3*
Bylaws of the Registrant (filed as an exhibit to the Registrant's Registration Statement on Form S-8 dated July 13, 1999).
4.1*
Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as Exhibit 4.19 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)). First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to JPMorgan Chase Bank), as Trustee (filed as Exhibit 4.20 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)). Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 4.21 to the Registration Statement on Form S-3 (No. 333-150669-01)).
10.1*
Restated and Amended Coal Supply Agreement for NS II dated February 12, 1993 (filed as Exhibit 10.1 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)).
10.2*
Second Restated and Amended Power Sales Agreement dated September 29, 1997, between PacifiCorp and Black Hills Power, Inc. (filed as Exhibit 10.2 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)).
10.3*
Reserve Capacity Integration Agreement dated May 5, 1987, between Pacific Power & Light Company and Black Hills Power, Inc. (filed as Exhibit 10.3 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)).
Independent Auditors’ Consent
31.1
Certification of Chief Executive Officer pursuant to Rule13a-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2
Certification of Chief Financial Officer pursuant to Rule13a-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1
Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2
Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
__________________________
*
Previously filed as part of the filing indicated and incorporated by reference herein.