ITEM 1A. RISK FACTORS
The nature of our business subjects us to a number of uncertainties and risks. The following risk factors and other risk factors that we discuss in our periodic reports filed with the SEC should be considered for a better understanding of our Company. These important factors and other matters discussed herein could cause our actual results or outcomes to differ materially from those discussed in our forward-looking statements, or otherwise.
Regulatory commissions may refuse to approve some or all of the utility rate increases we have requested or may request in the future, or may determine that amounts passed through to customers were not prudently incurred and therefore, are not recoverable which could adversely affect our results of operations, financial position or liquidity.
Our electricity operations are subject to cost-of-service regulation and earnings oversight. This regulatory treatment does not provide any assurance as to achievement of desired earnings levels. Our rates are regulated on a state-by-state basis by the relevant state regulatory authorities based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. The rates that we are allowed to charge may or may not match our related costs and allowed return on invested capital at any given time. Our returns could be threatened by plant outages, machinery failures, increased purchased power costs, acts of nature, acts of terrorism or other unexpected events over which we have no control that could cause our costs to increase and operating margins to decline. While rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that the state public utility commissions will judge all of our costs, including our borrowing and debt service costs, to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce a full recovery of our costs and the return on invested capital allowed by the applicable state public utility commission.
To some degree, we are permitted to recover certain costs (such as increased fuel, purchased power and transmission costs, as applicable) without having to file a rate case. To the extent we pass through such costs to customers and a state public utility commission subsequently determines that such costs should not have been paid by customers, we may be required to refund such costs to customers. Any such costs not recovered through rates, or any such refund, could negatively affect our results of operations, financial position or cash flows.
Our financial performance depends on the successful operations of our facilities. If the risks involved in our operations are not appropriately managed or mitigated, our operations may not be successful and this could adversely affect our results of operations.
Operating electric generating facilities involves risks, including:
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Operational limitations imposed by environmental and other regulatory requirements.
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Interruptions to supply of fuel and other commodities used in generation and distribution.
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Breakdown or failure of equipment or processes, including those operated by PacifiCorp at the Wyodak plant.
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Inability to recruit and retain skilled technical labor.
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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.
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Electricity is dangerous for employees and the general public should they come in contact with power lines or electrical equipment. Natural conditions and other disasters such as wind, lightning and winter storms can cause wildfires, pole failures and associated property damage and outages;
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Disruption in the functioning of our information technology and network infrastructure which are vulnerable to disability, failures and unauthorized access. If our information technology systems were to fail and we were unable to recover in a timely manner, we would be unable to fulfill critical business functions.
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Labor relations.
National and regional economic conditions may cause increased late payments and uncollectible accounts, which could adversely affect our results of operations, financial position or liquidity.
The continued recessionary environment and any future recession may lead to an increase in late payments from retail, commercial and industrial utility customers, as well as from our non-regulated customers. If late payments and uncollectible accounts increase, our results of operations, financial position and liquidity could be adversely impacted.
Our credit ratings could be lowered below investment grade in the future. If this were to occur, it could impact our access to capital, our cost of capital and our other operating costs.
Our credit rating on our First Mortgage Bonds is A3 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 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:
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The inability to obtain required governmental permits and approvals along with the cost of complying with or satisfying conditions imposed upon such approvals;
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Contract restrictions upon the timing of scheduled outages;
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Cost of supplying or securing replacement power during scheduled and unscheduled outages;
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The unavailability or increased cost of equipment;
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The cost of recruiting and retaining or the unavailability of skilled labor;
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Supply interruptions, work stoppages and labor disputes;
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Capital and operating costs to comply with increasingly stringent environmental laws and regulations;
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Opposition by members of the public or special-interest groups;
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Weather interferences;
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Unexpected engineering, environmental or geological problems; and
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Unanticipated cost overruns.
The ongoing operation of our facilities involves all of the risks described above, in addition to risks relating to the breakdown or failure of equipment or processes and performance below expected levels of output or efficiency. New plants may employ recently developed and technologically complex equipment, especially in the case of newer environmental emission control technology. Any of these risks could cause us to operate below expected capacity levels, which in turn could reduce revenues, increase expenses, or cause us to incur higher maintenance costs and penalties. While we maintain insurance, obtain warranties from vendors and obligate contractors to meet certain performance levels, the proceeds of such insurance and our rights under warranties or performance guarantees may not be timely or adequate to cover lost revenues, increased expenses or liquidated damage payments.
Prices for some of our products and services as well as a portion of our operating costs are volatile and may cause our revenues and expenses to fluctuate significantly.
A portion of the variability of our net income in recent years has been attributable to off-system wholesale electricity sales. The related power prices are influenced by many factors outside our control, including among other things, fuel prices, transmission constraints, supply and demand, weather, general economic conditions and the rules, regulations and actions of the system operators in those markets. Moreover, unlike most other commodities, electricity cannot be stored and therefore must be produced concurrently with its use. As a result, wholesale power markets are subject to significant, unpredictable price fluctuations over relatively short periods of time.
Our operating results can be adversely affected by variations from normal weather patterns.
Our utility business is a seasonal business and weather patterns can have a material impact on our operating performance. Demand for electricity is typically greater in the summer and winter months associated with cooling and heating. Accordingly, our utility operations have historically generated less revenues and income when weather conditions are cooler in the summer and warmer in the winter. Unusually mild summers and winters therefore could have an adverse effect on our results of operations, financial position and liquidity.
The failure to achieve or maintain compliance with existing or future governmental regulations or requirements could adversely affect our results of operations, financial position or liquidity. Additionally, the potentially high cost of complying with such requirements or addressing environmental liabilities could also adversely affect our results of operations, financial position or liquidity.
Our business is subject to extensive energy, environmental and other laws and regulations of federal, state and local authorities. We generally must obtain and comply with a variety of regulations, licenses, permits and other approvals in order to operate, which could require significant capital expenditures and operating costs. If we fail to comply with these requirements, we could be subject to civil or criminal liability and the imposition of liens or fines; claims for property damage or personal injury; and/ or environmental clean-up costs. In addition, existing regulations may be revised or reinterpreted, new laws and regulations may be adopted or become applicable to us or our facilities, which could require additional unexpected expenditures and have a detrimental effect on our business.
We strive to comply with all applicable environmental laws and regulations. Future steps to bring our facilities into compliance, if necessary, could be expensive, and could adversely affect our results of operation and financial condition. We expect our environmental compliance expenditures to be substantial in the future due to the continuing trends toward stricter standards, greater regulation, more extensive permitting requirements and an increase in the number of assets we operate.
Our ability to obtain insurance and the terms of any available insurance coverage could be adversely affected by international, national, state or local events and company-specific events, as well as the financial condition of insurers. Our insurance coverage may not provide protection against all significant losses.
Our ability to obtain insurance, as well as the cost of coverage of such insurance, could be affected by developments affecting company-specific events, international, national, state or local events, as well as the financial condition of insurers. Insurance coverage may not continue to be available at all, or at rates or on terms similar to those presently available to us. A loss for which we are not fully insured could materially and adversely affect our financial results. Our insurance may not be sufficient or effective under all circumstances and against all hazards or liabilities to which the company may be subject, including but not limited to environmental hazards, wildfire-related liability, distribution property losses and cyber risks.
Municipal governments may seek to limit or deny franchise privileges which could inhibit our ability to secure adequate recovery of our investment in assets subject to condemnation.
Municipal governments within our utility service territories possess the power of condemnation, and could seek a municipal utility within a portion of our current service territories by limiting or denying franchise privileges for our operations, and exercising powers of condemnation over all or part of our utility assets within municipal boundaries. Although condemnation is a process that is subject to constitutional protections requiring just compensation, as with any judicial procedure, the outcome is uncertain. If a municipality sought to pursue this course of action, we cannot assure that we would secure adequate recovery of our investment in assets subject to condemnation.
Federal and state laws concerning greenhouse gas regulations and air emissions may materially increase our generation and production costs and could render some of our generating units uneconomical to operate and maintain.
We own and operate regulated fossil-fuel generating plants in South Dakota and Wyoming. Recent developments under federal and state laws and regulations governing air emissions from fossil-fuel generating plants will likely result in more stringent emission limitations, which could have a material impact on our costs of operations. Various pending or final state and EPA regulations that will impact our facilities are also discussed in Item 1 of this Annual Report on Form 10-K under the caption “Environmental Regulations.”
On May 20, 2011, with amendments on December 21, 2012, the EPA's Industrial and Commercial Boiler regulations became effective, which provide for hazardous air pollutant-related emission limits and monitoring requirements. The compliance deadline for this rule is March 21, 2014. Engineering evaluations have been completed and confirm the significant impact on our Neil Simpson I, Osage and Ben French facilities. We anticipate these units will be retired on or before the March 21, 2014 compliance deadline.
On December 16, 2011, the EPA signed the National Emission Standards for Hazardous Air Pollutants from Coal and Oil Fired Electric Utility Steam Generating Units, (Utility MATS Rule) which became effective on February 16, 2012. Affected units will have three years from the rule effective date to be in compliance, with a pathway defined to apply for a one year extension due to certain circumstances. It is expected that all our plants will be in compliance by the initial 2015 deadline, with the primary impacts to Neil Simpson II, Wygen III and the Wyodak Plant being the addition of mercury sorbent injection systems and additional monitoring and testing.
The GHG Tailoring Rule, implementing regulations of GHG for permitting purposes, became effective in June 2010. This rule will impact us in the event of a major modification at an existing facility or in the event of a new major source. Existing permitted facilities will see monitoring reporting requirements incorporated into their operating permits upon renewal. New projects or major modifications to existing projects will result in a Best Available Control Technology review that could result in more stringent emissions control practices and technologies. The EPA’s GHG New Source Performance Standard for new steam electric generating units is expected to be final in the first half of 2013 and as proposed, effectively prohibits new coal fired units until carbon capture and sequestration becomes technically and economically feasible. In 2013 we expect the EPA to issue a proposed rule to regulate GHG emissions from existing steam electric generating units. This rule could have a significant impact on our coal generating fleet.
Due to uncertainty as to the final outcome of federal climate change legislation, or regulatory changes under the Clean Air Act, we cannot definitively estimate the effect of GHG regulation on our results of operations, cash flows or financial position. The impact of GHG legislation or regulation on our company will depend upon many factors, including but not limited to the timing of implementation, the GHG sources that are regulated, the overall GHG emissions cap level, and the availability of technologies to control or reduce GHG emissions. If a "cap and trade" structure is implemented, the impact will depend on the degree to which offsets are allowed, the allocation of emission allowances to specific sources, and the effect of carbon regulation on natural gas and coal prices.
New or more stringent regulations or other energy efficiency requirements could require us to incur significant additional costs relating to, among other things, the installation of additional emission control equipment, the acceleration of capital expenditures, the purchase of additional emissions allowances or offsets, the acquisition or development of additional energy supply from renewable resources, and the closure of certain generating facilities. To the extent our regulated fossil-fuel generating plants are included in rate base; we will attempt to recover costs associated with complying with emission standards or other requirements. We will also attempt to recover the emission compliance costs of our non-regulated fossil-fuel generating plants from utility and other purchasers of the power generated by those non-regulated power plants. Any unrecovered costs could have a material impact on our results of operations and financial condition. In addition, future changes in environmental regulations governing air emissions could render some of our power generating units more expensive or uneconomical to operate and maintain.
Increased risks of regulatory penalties could negatively impact our results of operations, financial position or liquidity.
Business activities in the energy sector are heavily regulated, primarily by agencies of the federal government. Agencies that historically sought voluntary compliance, or issued non-monetary sanctions, now employ mandatory civil penalty structures for regulatory violations. The FERC, EPA, OSHA and SEC can increasingly impose significant civil penalties to enforce compliance requirements relative to our business. In addition, FERC has delegated certain aspects of authority for enforcement of electric system reliability standards to the North American Energy Reliability Corporation, with similar penalty authority for violations. If a serious regulatory violation did occur, and penalties were imposed by FERC or another federal agency, this action could have a material adverse effect on our operations and/or our financial results.
An effective system of internal control may not be maintained, leading to material weaknesses in internal control over financial reporting.
Section 404 of the Sarbanes-Oxley Act of 2002 requires management to make an assessment of the design and effectiveness of internal controls. Our independent registered public accounting firm is required to attest to the effectiveness of these controls. During their assessment of these controls, management or our independent registered public accounting firm may identify areas of weakness in control design or effectiveness, which may lead to the conclusion that a material weakness in internal control exists. Any control deficiencies we identify in the future could adversely affect our ability to report our financial results on a timely and accurate basis, which could result in a loss of investor confidence in our financial reports or have a material adverse effect on our ability to operate our business or access sources of liquidity.
Threats of terrorism and catastrophic events that could result from terrorism, cyber-attacks, or individuals and/or groups attempting to disrupt our business, or the businesses of third parties, may impact our operations in unpredictable ways and could adversely affect our financial results or liquidity.
We are subject to the potentially adverse operating and financial effects of terrorist acts and threats, as well as cyber-attacks and other disruptive activities of individuals or groups. Our generation, transmission and distribution facilities, fuel storage facilities, information technology systems and other infrastructure facilities and systems and physical assets, could be direct targets of, or indirectly affected by, such activities. Terrorist acts or other similar events could harm our business by limiting our ability to generate, purchase or transmit power and by delaying our development and construction of new generating facilities and capital improvements to existing facilities. These events, and governmental actions in response, could result in a material decrease in revenues and significant additional costs to repair and insure our assets, and could adversely affect our operations by contributing to disruption of supplies and markets for natural gas, oil and other fuels. They could also impair our ability to raise capital by contributing to financial instability and lower economic activity.
We operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. Despite our implementation of security measures, all of our technology systems are vulnerable to disability, failures or unauthorized access, including due to cyber-attacks. If our technology systems were to fail or be breached and be unable to recover in a timely way, we would be unable to fulfill critical business functions, and sensitive confidential and other data could be compromised, which could have material adverse effect on our financial results.
The implementation of security guidelines and measures and maintenance of insurance, to the extent available, addressing such activities could increase costs. These types of events could materially adversely affect our financial results. In addition, these types of events could require significant management attention and resources, and could adversely affect our reputation among customers and the public.
A disruption of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources, could negatively impact our business. Because generation, transmission systems and natural gas pipelines are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the impact of an event on the interconnected system (such as severe weather or a generator or transmission facility outage, pipeline rupture, or a sudden significant increase or decrease in wind generation), within our system or within a neighboring system. Any such disruption could have a material impact on our financial results.
Market performance or changes in other assumptions could require us to make significant unplanned contributions to our pension plans and other postretirement benefit plans. Increasing costs associated with our defined benefit retirement plans may adversely affect our results of operations, financial position or liquidity.
We have a defined benefit pension plan that covers a substantial portion of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements related to these plans. These estimates and assumptions may change based on actual return on plan assets, changes in interest rates and changes in governmental regulations.
Increasing costs associated with our health care plans may adversely affect our results of operations, financial position or liquidity.
The costs of providing health care benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise. The increasing costs associated with our health care plans may adversely affect our results of operations, financial position or liquidity.
In March 2010, the President of the United States signed the Patient Protection and Affordable Care Act of 2010 as amended by the Health Care and Education Reconciliation Act of 2010 (collectively the “2010 Acts”). The 2010 Acts will have a substantial impact on health care providers, insurers, employers and individuals. The 2010 Acts will impact employers and businesses differently depending on the size of the organization and the specific impacts on a company’s employees. Certain provisions of the 2010 Acts became effective during our 2010 open enrollment period (November 1, 2010) while other provisions of the 2010 Acts will be effective in future years. Although the constitutional validity of the 2010 Acts is the subject of numerous lawsuits now pending in the federal courts, the outcome of which is uncertain, the 2010 Acts could require, among other things, changes to our current employee benefit plans and in our administrative and accounting processes. The ultimate extent and cost of these changes cannot be determined at this time and are being evaluated and updated as related regulations and interpretations of the 2010 Acts become available.
Our electric utility rates are regulated on a state-by-state basis by the relevant state regulatory authorities based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. Within our utility rates we have generally recovered the cost of providing employee benefits. As benefit costs continue to rise, there can be no assurance that the state public utility commissions will allow recovery.
ITEM 1B.
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 for the years ended December 31 (dollars in thousands):
We own approximately 471 MW of electric utility generating capacity and purchase an additional 50 MW under a long-term agreement expiring in 2023.
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(a)
2011 reflects a planned major outage at the PacifiCorp-operated Wyodak plant.
2012 Compared to 2011
Gross margin increased primarily due to an increase of $1.6 million from the Environmental Improvement Cost Recovery Adjustment rider, a $4.5 million increase in wholesale and transmission margins as a result of increased prices partially offset by $2.5 million from the 2012 expiration of a reserve capacity agreement with PacifiCorp.
Operations and maintenance were comparable to the prior year. Increased corporate allocations were offset by lower costs related to the suspension of operations at the Ben French plant.
Gain on sale of operating assets in 2011 related to the sale of assets to a related party.
Interest expense, net increased primarily due to a decrease in interest income from lower utility money pool borrowings.
Other income, net was comparable to the prior year.
Income tax expense: The effective tax rate increased primarily due to unfavorable true-up adjustments and lower flow through of the tax benefit attributable to repair and maintenance costs deducted for tax purposes.
2011 Compared to 2010
Gross margin increased primarily due to a $16.6 million increase related to the impact of the outcome of our rate cases and increased transmission margins partially offset by lower margins due to the termination of power sales contracts upon a customer's purchase of an ownership interest in the Wygen III generating facility.
Operations and maintenance increased primarily due to additional costs of $1.6 million associated with Wygen III which commenced commercial operation on April 1, 2010, and increased allocation of corporate costs partially offset by lower costs related to the suspension of operations at the Osage plant.
Gain on sale of operating assets in 2011 related to the sale of assets to a related party. The gain on sale of operating assets in 2010 represented the sale of a 23% ownership interest in the Wygen III generating facility to the City of Gillette, WY.
Interest expense, net decreased primarily due to lower interest expense primarily related to the repayment of higher rate debt during 2010, partially offset by a decrease in AFUDC associated with borrowed funds due to completed construction of Wygen III.
Other income decreased primarily due to a decrease of $2.0 million in AFUDC-equity due to the placement of Wygen III into commercial operation.
Income tax expense: The effective tax rate increased from the same period in the prior year due to a prior year tax benefit for a repairs deduction taken for tax purposes and the flow-through treatment of such tax benefit resulting from a rate case settlement in 2010.
Significant Events
Power Plant Suspension/Retirements
In order to comply with environmental regulations, including the new EPA Industrial & Commercial Boiler Regulations for Area Sources of Hazardous Air Pollutants regulations, operations at our 25 MW coal-fired Ben French power plant were suspended as of August 31, 2012. Operations at our 35 MW coal-fired Osage power plant were suspended as of October 1, 2010. These plants as well as our 22 MW coal-fired plant Neil Simpson I will be retired on or before March 21, 2014. We intend to operate Neil Simpson 1 until the planned retirement date. While the net book value of these plants is estimated to be insignificant at the time of retirement, we would reasonably expect to recover any remaining value of these plants through future rates.
Cheyenne Prairie
As a result of the planned plant retirements for some of our older coal-fired power plants discussed above, Cheyenne Light and Black Hills Power filed a joint CPCN to construct a new $222 million 132 MW natural gas-fired electric generation facility in Cheyenne, Wyoming. The facility will include construction of one simple-cycle, 37 MW combustion turbine that will be wholly owned by Cheyenne Light and one combined cycle 95 MW unit that will be jointly owned by Cheyenne Light (40 MW) and Black Hills Power (55 MW).
South Dakota
In December 2012, we filed a rate case with the SDPUC requesting electric revenue increases of $13.7 million, or 9.94%, to recover investment in distribution and transmission lines, generation plant upgrades and environmental compliance. We have requested an effective date of April 1, 2013 and a decision is anticipated during the third quarter of 2013. If the SDPUC has not reached a decision within 180 days, interim rates will go into effect June 16, 2013.
We filed a request with the SDPUC to use a construction financing rider during the construction of Cheyenne Prairie in lieu of traditional AFUDC. This rider would be similar to the one approved by the WPSC for Cheyenne Light and Black Hills Power for Wyoming customers. On January 17, 2013, the SDPUC approved a stipulation with interim rates effective April 1, 2013, subject to refund. The rider will allow us to earn and collect a rate of return during the construction period on our approximately 40 percent share of the total project cost relating to our South Dakota customers while also saving customers money over the long-term. If approved, this will increase gross margin by approximately $3.6 million and $5.6 million in 2013 and 2014, respectively. We anticipate a final ruling by the SDPUC on this rider during the third quarter of 2013.
In May 2011, the SDPUC approved an Environmental Improvement Cost Recovery Adjustment tariff for Black Hills Power. This tariff, which was implemented to recover Black Hills Power's investment of $25 million for pollution control equipment at the PacifiCorp operated Wyodak plant, went into effect June 1, 2011 with an annual revenue increase of $3.1 million.
Wyoming
In October 2012, the WPSC approved Cheyenne Prairie’s construction financing rider which allows for recovery of construction financing costs from customers during the construction period in lieu of traditional AFUDC. The rider was implemented November 1, 2012 and will allow Cheyenne Light and Black Hills Power to each earn and collect a rate of return during the construction period on approximately 60% share of the total project cost relating to our Wyoming customers while also saving customers money over the long-term. This will increase gross margin by approximately $0.3 million and $0.4 million in 2013 and 2014, respectively.
Critical Accounting Estimates
We prepare our financial statements in conformity with GAAP. In many cases, the accounting treatment of a particular transaction is specifically dictated by GAAP and does not require management's judgment in application. There are also areas which require management's judgment in selecting among available GAAP alternatives. We are required to make certain estimates, judgments and assumptions that we believe are reasonable based upon the information available. These estimates and assumptions affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented. Actual results may differ from our estimates and to the extent there are material differences between these estimates, judgments or assumptions and actual results, our financial statements will be affected. We believe the following accounting estimates are the most critical in understanding and evaluating our reported financial results.
The following discussion of our critical accounting estimates should be read in conjunction with Note 1, "Business Description and Summary of Significant Accounting Policies" of our Notes to Financial Statements in this Annual Report on Form 10-K.
Pension and Other Postretirement Benefits
The Company, as described in Note 9 to the Financial Statements in this Annual Report on Form 10-K, has a defined benefit pension plan and post-retirement healthcare plan. Accounting for pension and other postretirement benefit obligations involves numerous assumptions, the most significant of which relate to the discount rate for measuring the present value of future plan obligations; expected long-term rates of return on plan assets; rate of future increases in compensation levels; and healthcare cost projections. The determination of our obligation and expenses for pension and other postretirement benefits is dependent on the assumptions used by actuaries in calculating the amounts. Although we believe our assumptions are appropriate, significant differences in our actual experience or significant changes in our assumptions may materially affect our pension and other postretirement obligations and our future expense.
The estimated discount rate used to determine annual defined benefit pension costs accruals will be 4.3% in 2013 and the discount rate used in 2012 was 4.65%. In selecting the discount rate, we consider cash flow durations for each plan's liabilities on high credit fixed income yield curves for comparable durations. We do not pre-fund our non-qualified plans or postretirement healthcare plans.
Income Taxes
We file a federal income tax return with other members of the Parent consolidated group. For financial statement purposes, federal income taxes are allocated to the individual companies based on amounts calculated on a separate return basis.
We use the liability method of accounting for income taxes. Under this method, deferred income taxes are recognized, at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities, as well as operating loss and tax credit carryforwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements. We classify deferred tax assets and liabilities into current and non-current amounts based on the nature of the related assets and liabilities.
In assessing the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized and provides any necessary valuation allowances as required. If we determine that we will be unable to realize all or part of our deferred tax assets in the future, an adjustment to the deferred tax asset would be charged to income in the period such determination was made. Although we believe our assumptions, judgments and estimates are reasonable, changes in tax laws or our interpretations of tax laws and the resolution of current and any future tax audits could significantly impact the amounts provided for income taxes in our consolidated financial statements. With respect to changes in tax law, the recently enacted American Taxpayer Relief Act of 2012 (”Act”) will not have a material impact on the amounts provided for income taxes including our ability to realize deferred tax assets. Since the date of enactment was January 2, 2013, the Act could not be considered when determining deferred tax liabilities and assets as of December 31, 2012, which resulted in the reclassification of a sizable amount of Federal deferred tax asset related to net operating loss carryforwards from non-current to current. However, certain provisions of the Act primarily the extension of 50% bonus depreciation are currently expected to result in minimal utilization of such carryforwards in 2013.
Contingencies
When it is probable that an environmental or other legal liability has been incurred, a loss is recognized when the amount of the loss can be reasonably estimated. Estimates of the probability and the amount of loss are made based on currently available facts. Accounting for contingencies requires significant judgment regarding the estimated probabilities and ranges of exposure to potential liability. Our assessment of our exposure to contingencies could change to the extent there are additional future developments, or as more information becomes available. If actual obligations incurred are different from our estimates, the recognition of the actual amounts could have a material impact on our financial position, results of operations and cash flows. The Company describes any contingencies in Note 12 of the Financial Statements in this Annual Report on Form 10-K.
ITEM 8.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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, 2012 and 2011, and the related statements of income, comprehensive income (loss), cash flows, and common stockholder's equity for each of the three years in the period ended December 31, 2012. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of Black Hills Power, Inc. as of December 31, 2012 and 2011, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.
/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
March 6, 2013
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.
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
See Note 8 for additional disclosure related to comprehensive income.
The accompanying notes to financial statements are an integral part of these financial statements.
BLACK HILLS POWER, INC.
BALANCE SHEETS
The accompanying notes to financial statements are an integral part of these financial statements.
BLACK HILLS POWER, INC.
STATEMENTS OF CASH FLOWS
See Note 11 for Supplemental Cash Flows information.
The accompanying notes to financial statements are an integral part of these financial statements.
BLACK HILLS POWER, INC.
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
The accompanying notes to financial statements are an integral part of these financial statements.
NOTES TO FINANCIAL STATEMENTS
December 31, 2012, 2011 and 2010
(1) BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Business Description
Black Hills Power, Inc. (the Company, "we," "us" or "our") is an electric utility serving customers in South Dakota, Wyoming and Montana. We are a wholly-owned subsidiary of BHC or the Parent, a public registrant listed on the New York Stock Exchange.
Basis of Presentation
The financial statements include the accounts of Black Hills Power, Inc. and also our ownership interests in the assets, liabilities and expenses of our jointly owned facilities (Note 4) and are prepared in accordance with GAAP.
Use of Estimates and Basis of Presentation
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Cash Equivalents
We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Regulatory Accounting
Our regulated electric operations are subject to regulation by various state and federal agencies. The accounting policies followed are generally subject to the Uniform System of Accounts of FERC.
Our regulated utility operations follow accounting standards for regulated operations and our financial statements reflect the effects of the different rate making principles followed by the various jurisdictions regulating our electric operations. If rate recovery becomes unlikely or uncertain due to competition or regulatory action, these accounting standards may no longer apply to our regulated operations. In the event we determine that we no longer meet the criteria for following accounting standards for regulated operations, the accounting impact to us could be an extraordinary non-cash charge to operations in an amount that could be material.
Regulatory assets are included in Regulatory assets, current and Regulatory assets, non-current on the accompanying Balance Sheets. Regulatory liabilities are included in Regulatory liabilities, current and Regulatory liabilities, non-current on the accompanying Balance Sheets.
We had the following regulatory assets and liabilities as follows as of December 31 (in thousands):
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(a) Recovery of costs but not allowed a rate of return.
(b)
In addition to recovery of costs, we are allowed a rate of return.
(c) In addition to recovery of costs, we are allowed a return on approximately $23.5 million.
(d)
Approximately $13.2 million is included in our rate base calculation as a reduction to rate base.
(e)
Approximately $0.8 million is included in our rate base calculation as a reduction to rate base.
Regulatory assets represent items we expect to recover from customers through probable future rates.
Unamortized Loss on Reacquired Debt - The early redemption premium on reacquired bonds is being amortized over the remaining term of the original bonds.
AFUDC - The equity component of AFUDC is considered a permanent difference for tax purposes with the tax benefit being flowed through to customers as prescribed or allowed by regulators. If, based on a regulator's action, it is probable the utility will recover the future increase in taxes payable represented by this flow-through treatment through a rate revenue increase, a regulatory asset is recognized. This regulatory asset itself is a temporary difference for which a deferred tax liability must be recognized. Accounting standards for income taxes specifically address AFUDC-equity, and require a gross-up of such amounts to reflect the revenue requirement associated with a rate-regulated environment.
Employee Benefit Plans - Employee benefit plans include the unrecognized prior service costs and net actuarial loss associated with our defined benefit pension plans and post-retirement benefit plans in regulatory assets rather than in accumulated other comprehensive income.
Deferred Energy Costs - Deferred energy and fuel cost adjustments represent the cost of electricity delivered to our utility customers that are either higher or lower than the current rates and will be recovered or refunded in future rates. Deferred energy and fuel cost adjustments are recorded and recovered or amortized as approved by the appropriate state commission.
Flow-Through Accounting - Under flow-through accounting, the income tax effects of certain tax items are reflected in our cost of service for the customer in the year in which the tax benefits are realized and result in lower utility rates. This regulatory treatment was applied to the tax benefit generated by repair costs that were previously capitalized for tax purposes in a rate case settlement that was reached in 2010. In this instance, the agreed upon rate increase was less than it would have been absent the flow-through treatment. A regulatory asset established to reflect the future increases in income taxes payable will be recovered from customers as the temporary differences reverse.
Regulatory liabilities represent items we expect to refund to customers through probable future decreases in rates.
Cost of Removal for Utility Plant - Cost of removal for utility plant represents the estimated cumulative net provisions for future removal costs included in depreciation expense for which there is no legal obligation for removal.
Employee Benefit Plans - Employee benefit plans represent the cumulative excess of pension and retiree healthcare costs recovered in rates over pension expense recorded in accordance with accounting standards for compensation - retirement benefits. In addition, this regulatory liability includes the income tax effect of the adjustment required under accounting for compensation - defined benefit plans, to record the full pension and post-retirement benefit obligations. Such income tax effect has been grossed-up to account for the revenue requirement aspect of a rate regulated environment.
Accounts Receivable and Allowance for Doubtful Accounts
Accounts receivable consist of sales to residential, commercial, industrial, municipal and other customers all of which do not bear interest. These accounts receivable are stated at billed and unbilled amounts net of write-offs or payment received.
We maintain an allowance for doubtful accounts which reflects our best estimate of uncollectible trade receivables. We regularly review our trade receivable allowances by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect collectibility. The allowance is calculated by applying estimated write-off factors to various classes of outstanding receivables, including unbilled revenue. The write-off factors used to estimate uncollectible accounts are based upon consideration of both historical collections experience and management's best estimate of future collection success given the existing collections environment.
Following is a summary of accounts receivable at December 31 (in thousands):
Revenue Recognition
Revenue is recognized when there is persuasive evidence of an arrangement with a fixed or determinable price, delivery has occurred or services have been rendered, and collectibility is reasonably assured. Taxes collected from our customers are recorded on a net basis (excluded from Revenue).
Utility revenues are based on authorized rates approved by the state regulatory agencies and the FERC. Revenues related to the sale, transmission and distribution of energy, and delivery of service are generally recorded when service is rendered or energy is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, we accrue an estimate of the revenue since the latest billing. This estimate is calculated based upon several factors including billings through the last billing cycle in a month, and prices in effect in our jurisdictions. Each month the estimated unbilled revenue amounts are trued-up and recorded in Receivables- customers, net on the accompanying Balance Sheets.
Materials, Supplies and Fuel
Materials, supplies and fuel used for construction, operation and maintenance purposes are generally stated on a weighted-average cost basis.
Deferred Financing Costs
Deferred financing costs are amortized using the effective interest method over the term of the related debt.
Property, Plant and Equipment
Additions to property, plant and equipment are recorded at cost when placed in service. Included in the cost of regulated construction projects is AFUDC, which represents the approximate composite cost of borrowed funds and a return on equity used to finance a regulated utility project. The cost of regulated electric property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage, is charged to accumulated depreciation. Removal costs associated with non-legal obligations are reclassified from accumulated depreciation and reflected as regulatory liabilities. Ordinary repairs and maintenance of property, except as allowed under rate regulations, are charged to operations as incurred.
Depreciation provisions for regulated electric property, plant and equipment are computed on a straight-line basis using an annual composite rate of 2.2% in 2012, 2.2% in 2011 and 2.2% in 2010.
Derivatives and Hedging Activities
From time to time we utilize risk management contracts including forward purchases and sales to hedge the price of fuel for our combustion turbines and fixed-for-float swaps to fix the interest on any variable rate debt. Contracts that qualify as derivatives under accounting standards for derivatives, and that are not exempted such as normal purchase/normal sale, are required to be recorded in the balance sheet as either an asset or liability, measured at its fair value. Accounting standards for derivatives require that changes in the derivative instrument's fair value be recognized currently in earnings unless specific hedge accounting criteria are met.
Accounting standards for derivatives allow hedge accounting for qualifying fair value and cash flow hedges. Gain or loss on a derivative instrument designated and qualifying as a fair value hedging instrument as well as the offsetting loss or gain on the hedged item attributable to the hedged risk should be recognized currently in earnings in the same accounting period. Conversely, the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument should be reported as a component of other comprehensive income and be reclassified into earnings or as a regulatory asset or regulatory liability, net of tax, in the same period or periods during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, is recognized currently in earnings.
Fair Value Measurements
Accounting standards for fair value measurements provide a single definition of fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date and also requires disclosures and establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The fair value hierarchy ranks the quality and reliability of the information used to determine fair values giving the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).
Financial assets and liabilities carried at fair value are classified and disclosed in one of the following three categories:
Level 1 - Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities.
Level 2 - Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means.
Level 3 - Pricing inputs include significant inputs that are generally less observable from objective sources.
Impairment of Long-Lived Assets
We periodically evaluate whether events and circumstances have occurred which may affect the estimated useful life or the recoverability of the remaining balance of our long-lived assets. If such events or circumstances were to indicate that the carrying amount of these assets was not recoverable, we would estimate the future cash flows expected to result from the use of the assets and their eventual disposition. If the sum of the expected future cash flows (undiscounted and without interest charges) was less than the carrying amount of the long-lived assets, we would recognize an impairment loss.
Income Taxes
We file a federal income tax return with other members of the Parent's consolidated group. For financial statement purposes, federal income taxes are allocated to the individual companies based on amounts calculated on a separate return basis.
We use the liability method in accounting for income taxes. Under the liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities, as well as operating loss and tax credit carryforwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements. We classify deferred tax assets and liabilities into current and non-current amounts based on the classification of the related assets and liabilities.
It is the Parent's policy to apply the flow-through method of accounting for investment tax credits. Under the flow-through method, investment tax credits are reflected in net income as a reduction to income tax expense in the year they qualify. Another acceptable accounting method and an exception to this general policy is to apply the deferral method whereby the credit is amortized as a reduction of income tax expense over the useful lives of the related property which gave rise to the credits.
We recognize interest income or interest expense and penalties related to income tax matters in Income tax (expense) benefit on the Statements of Income. We account for uncertainty in income taxes recognized in the financial statements in accordance with accounting standards for income taxes. The unrecognized tax benefit is classified in Other - non-current liabilities on the accompanying Balance Sheets. See Note 7 for additional information.
(2) RECENTLY ADOPTED AND RECENTLY ISSUED ACCOUNTING STANDARDS
Recently Adopted Accounting Standards
Other Comprehensive Income: Presentation of Comprehensive Income, ASU 2011-05 and Deferral of the Effective Date for Amendments to the Presentation of Reclassification of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update 2011-05 and ASU 2011-12
FASB issued an accounting standards update amending ASC 220 to improve the comparability, consistency and transparency of reporting of comprehensive income. It amends existing guidance by allowing only two options for presenting the components of net income and other comprehensive income: (1) in a single continuous financial statement, statement of comprehensive income or (2) in two separate but consecutive financial statements, consisting of an income statement followed by a separate statement of other comprehensive income. Also, items that are reclassified from other comprehensive income to net income must be presented on the face of the financial statements. ASU No. 2011-05 requires retrospective application, and it is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011, with early adoption permitted. In December 2011, FASB issued ASU 2011-12. ASU 2011-12 indefinitely deferred the provisions of ASU 2011-05 requiring the presentation of reclassification adjustments for items reclassified from other comprehensive income to net income be presented on the face of the financial statements. Ultimately FASB chose not to reinstate the reclassification adjustment requirements in ASU 2011-05 but instead issued ASU 2013-02 in February 2013.
We have elected to early adopt the provisions of ASU 2011-05 as amended by ASU 2011-12. The adoption changed the presentation of certain financial statements and provided additional details in notes to the financial statements, but did not have any other impact on our financial statements. See the accompanying Comprehensive Income Statement and additional disclosures in Note 8.
Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements, ASU 2011-04
In May 2011, FASB issued an accounting standards update amending ASC 820, Fair Value Measurements and Disclosures, to achieve common fair value measurement and disclosure requirements between GAAP and IFRS. Additional disclosure requirements in the update include: (1) for Level 3 fair value measurements - quantitative information about unobservable inputs used, a description of the valuation processes used by the entity, and a qualitative discussion about the sensitivity of the measurements to changes in the unobservable inputs; (2) for an entity’s use of a non-financial asset that is different from the asset’s highest and best use - the reason for the difference; (3) for financial instruments not measured at fair value but for which disclosure of fair value is required - the fair value hierarchy level in which the fair value measurements were determined; and (4) the disclosure of all transfers between Level 1 and Level 2 of the fair value hierarchy. ASU 2011-04 is effective for fiscal years, and interim periods within those years, beginning after December 31, 2011. The amendment required additional details in notes to financial statements, but did not have any other impact on our financial statements. The additional disclosures are included in Note 9.
Recently Issued Accounting Pronouncements and Legislation
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income, ASU 2013-02
In February 2013, the FASB issued new disclosure requirements for items reclassified out of AOCI to expand the disclosure requirements in ASC 220, Comprehensive Income, for presentation of changes in AOCI. ASU 2013-02 requires disclosure of (1) changes in components of other comprehensive income, (2) for items reclassified out of AOCI and into net income in their entirety, the effect of the reclassification on each affected net income line item and (3) cross references to other disclosures that provide additional detail for components of other comprehensive income that are not reclassified in their entirety to net income. Disclosures are required either on the face of the statements of income or as a separate disclosure in the notes to the financial statements. The new disclosure requirements are effective for interim and annual periods beginning after Dec. 15, 2012. The adoption of this standard will not have an impact on our financial position, results of operations or cash flows.
(3) PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment at December 31 consisted of the following (dollars in thousands):
__________________
(a)
The plant acquisition adjustment is included in rate base and is being recovered with 18 years remaining.
(4) JOINTLY OWNED FACILITIES
We use the proportionate consolidation method to account for our percentage interest in the assets, liabilities and expenses of the following facilities:
•
We own a 20% interest in the Wyodak Plant (the "Plant"), a coal-fired electric generating station located in Campbell County, Wyoming. PacifiCorp owns the remaining ownership percentage and is the operator of the Plant. We receive our proportionate share of the Plant's capacity and are committed to pay our share of its additions, replacements and operating and maintenance expenses.
•
We own a 35% interest in, and are the operator of, the Converter Station Site and South Rapid City Interconnection (the transmission tie), an AC-DC-AC transmission tie. Basin Electric owns the remaining ownership percentage. The transmission tie provides an interconnection between the Western and Eastern transmission grids, which provides us with access to both the WECC region and the MAPP region. The total transfer capacity of the transmission tie is 400 MW - 200 MW West to East and 200 MW from East to West. We are committed to pay our proportionate share of the additions, replacements and operating and maintenance expenses.
•
We own a 52% interest in the Wygen III power plant. MDU and the City of Gillette each owns an undivided ownership interest in Wygen III and are obligated to make payments for costs associated with administrative services and a proportionate share of the costs of operating the plant for the life of the facility. We retain responsibility for plant operations.
The investments in our jointly owned plants and accumulated depreciation are included in the corresponding captions in the accompanying Balance Sheets. Our share of direct expenses of the Plant is included in the corresponding categories of operating expenses in the accompanying Statements of Income. Each of the respective owners is responsible for providing its own financing.
As of December 31, 2012, our interests in jointly-owned generating facilities and transmission systems included on our Balance Sheets were as follows (in thousands):
(5) LONG-TERM DEBT
Long-term debt outstanding at December 31 was as follows (in thousands):
___________________
(a)
On May 15, 2012 we repaid in full $6.5 million principal and interest on the Pollution Control Revenue Bonds originally due to mature on October 1, 2014.
(b)
Variable interest rate of 1.35% at December 31, 2012.
Net deferred financing costs of approximately $2.9 million and $3.1 million were recorded on the accompanying Balance Sheets in Other, non-current assets at December 31, 2012 and 2011, respectively, and are being amortized over the term of the debt. Amortization of deferred financing costs of approximately $0.2 million, $0.5 million and $0.4 million for the years ended December 31, 2012, 2011 and 2010, respectively, are included in Interest expense on the accompanying Statements of Income.
Substantially all of our property is subject to the lien of the indenture securing our first mortgage bonds. First mortgage bonds may be issued in amounts limited by property, earnings and other provisions of the mortgage indentures. We were in compliance with our debt covenants at December 31, 2012.
Long-term Debt Maturities
Scheduled maturities of our outstanding long-term debt (excluding unamortized discounts) are as follows (in thousands):
(6) FAIR VALUE OF FINANCIAL INSTRUMENTS
The estimated fair values of our financial instruments at December 31 were as follows (in thousands):
_______________
(a)
Fair value approximates carrying value due to either short-term length of maturity or variable interest rates that approximate prevailing market rates and therefore is classified in Level 1 in the fair value hierarchy.
(b)
Long-term debt is valued using the market approach based on observable inputs of quoted market prices and yields available for debt
instruments either directly or indirectly for similar maturities and debt ratings in active markets and therefore is classified in Level 2 in
the fair value hierarchy. The carrying amount of our variable rate debt approximates fair value due to the variable interest rates with
short reset periods. For additional information on our long-term debt, see Note 5 to the Financial Statements.
The following methods and assumptions were used to estimate the fair value of each class of our financial instruments.
Cash and Cash Equivalents
Included in cash and cash equivalents is cash and overnight repurchase agreement accounts. As part of our cash management process, excess operating cash is invested in overnight repurchase agreements with our bank. Repurchase agreements are not deposits and are not insured by the U.S. Government, the FDIC or any other government agency and involve investment risk including possible loss of principal. We believe however, that the market risk arising from holding these financial instruments is minimal.
(7) 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, for the years ended December 31 were as follows (in thousands):
The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows:
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*
The flow-through adjustments relate primarily to an accounting method change for tax purposes that was filed with the 2008 tax return and for which consent was received from the IRS in September 2009. The effect of the change allows us to take a current tax deduction for repair costs that were previously capitalized for tax purposes. These costs will continue to be capitalized for book purposes. We recorded a deferred income tax liability in recognition of the temporary difference created between book and tax treatment and we flowed the tax benefit through to our customers in the form of lower rates as a result of a rate case settlement that occurred during 2010. A regulatory asset was established to reflect the recovery of future increases in taxes payable from customers as the temporary differences reverse. Due to this regulatory treatment, we recorded an income tax benefit in 2010 that was attributable to the 2008 through 2010 tax years. We continue to record a tax benefit consistent with the flow through method in accordance with such regulatory treatment.
The following table reconciles the total amounts of unrecognized tax benefits at the beginning and end of the period (in thousands):
The reductions for prior year tax positions relate to the reversal attributable to otherwise allowed tax depreciation. The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $0.7 million. The unrecognized tax benefit is classified in Other, non-current liabilities on the accompanying Balance Sheets.
During the year ended December 31, 2012 and 2011, the interest expense recognized related to income tax matters was not material to our financial results.
We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of any audits or the expiration of statutes of limitations prior to December 31, 2013.
At December 31, 2012, we have federal NOL carry forward of $30.5 million, expiring in 2031. Ultimate usage of this NOL depends upon our ability to generate future taxable income, which is expected to occur within the prescribed carryforward period.
(8) ACCUMULATED OTHER COMPREHENSIVE INCOME
Balances by classification included within Accumulated other comprehensive loss on the accompanying Balance Sheets were as follows (in thousands):
Derivatives designated as cash flow hedges relate to a treasury lock entered into in August 2002 to hedge a portion of the $75.0 million First Mortgage Bonds due on August 15, 2032. The treasury lock cash settled on August 8, 2002, the bond pricing date, and resulted in a $1.8 million loss. The treasury lock is treated as a cash flow hedge and the resulting loss is carried in Accumulated Other Comprehensive Loss and is being amortized over the life of the related bonds.
(9) EMPLOYEE BENEFIT PLANS
Funded Status of Benefit Plans
The funded status of the postretirement benefit plan is required to be recognized in the statement of financial position. The funded status for the pension plan is measured as the difference between the projected benefit obligation and the fair value of plan assets. The funded status for all other benefit plans is measured as the difference between the accumulated benefit obligation and the fair value of plan assets. A liability is recorded for an amount by which the benefit obligation exceeds the fair value of plan assets or an asset is recorded for any amount by which the fair value of plan assets exceeds the benefit obligation. The measurement date of the plans is December 31, our year-end balance sheet date. As of December 31, 2012, the funded status of our Defined Benefit Pension Plan was $(16.4) million, the funded status of our Supplemental Non-qualified Defined Benefit Plans was $(3.4) million and the funded status of our Non-pension Defined Benefit Postretirement Healthcare Plans was $(6.8) million.
We apply accounting standards for regulated operations, and accordingly, the unrecognized net periodic benefit cost that would have been reclassified to Accumulated other comprehensive income (loss) was alternatively recorded as a regulatory asset or regulatory liability, net of tax.
Defined Benefit Pension Plan
We have a noncontributory defined benefit pension plan ("Pension Plan") covering employees who meet certain eligibility requirements. The benefits are based on years of service and compensation levels during the highest five consecutive years of the last ten years of service. Our funding policy is in accordance with the federal government's funding requirements. The Pension Plan's assets are held in trust and consist primarily of equity and fixed income investments.
The Pension Plan has been frozen to new employees and certain employees who did not meet age and service based criteria at the time the Plan was frozen. Plan benefits are based on years of service and calculations of average earnings during a specific time period prior to retirement.
On October 29, 2012, the Board of Directors approved a new Investment Policy. The objective of the Investment Policy is to manage assets in such a way that will allow the eventual settlement of our obligations to the Plans’ beneficiaries. To meet this objective, our pension plan assets are managed by an outside adviser using a structured portfolio strategy that will provide liquidity to meet the Plans’ benefit payment obligations and an asset allocation that will comprise a mix of return-seeking and liability-hedging assets. Our Pension Plan funding policy is in accordance with the federal government’s funding requirements. The Pension Plan's assets are held in trust and consist primarily of equity and fixed income investments. The expected long-term rate of return for investments was 7.25% and 8.75% for the 2012 and 2011 plan years, respectively.
Pension Plan Assets
The percentages of total plan asset fair value by investment category of our Pension Plan assets at December 31 were as follows:
Supplemental Non-qualified Defined Benefit Retirement Plans
We have various supplemental retirement plans ("Supplemental Plans") for key executives. The Supplemental Plans are non-qualified defined benefit plans. The Supplemental Plans are subject to various vesting schedules.
Supplemental Plan Assets
We do not fund our Supplemental Plans. We fund on a cash basis as benefits are paid.
Non-pension Defined Benefit Postretirement Healthcare Plan
Employees who are participants in our Non-Pension Postretirement Healthcare Plan ("Healthcare Plan") and who retire on or after attaining minimum age and years of service requirements are entitled to postretirement healthcare benefits. These benefits are subject to premiums, deductibles, co-payment provisions and other limitations. We may amend or change the Healthcare Plan periodically. We are not pre-funding our retiree medical plan. We have determined that the Healthcare Plan's post-65 retiree prescription drug plans are actuarially equivalent and qualify for the Medicare Part D subsidy.
Plan Assets
We do not fund our Healthcare Plans. We fund on a cash basis as benefits are paid.
Plan Contributions and Estimated Cash Flows
Contributions made to the Pension Plans are cash contributions made directly to the Pension Plan Trust accounts. Healthcare and Supplemental Plan contributions are made in the form of benefit payments. Contributions for the years ended December 31 were as follows (in thousands):
We expect to make a contribution of $1.6 million to our employee defined benefit pension plan in 2013.
Fair Value Measurements
As required by accounting standards for fair value measurements, assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect their placement within the fair value hierarchy levels. The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value on a recurring basis as of December 31 (in thousands):
Registered Investment Companies: Investments are valued at the closing price reported on the active market on which the individual securities are traded.
Common Collective Trust: The Pension Plan owns units of the Common Collective Trust funds that they are utilizing in their portfolio. The value of each unit of any fund as of any valuation date shall be determined by calculating the total value of such fund's assets as of the close of business on such valuation date, deducting its total liabilities as of such time and date, and then dividing the so-determined net asset value of such fund by the total number of units of such fund outstanding on the date of valuation.
Insurance Contract: These investments are valued on a cash basis on any given valuation date which approximates fair value.
Structured Products: Investments are created through the process of financial engineering (that is, by combining underlying securities like equity, bonds, or indices with derivatives). The value of derivative securities, such as options, forwards and swaps is determined by (respectively, derives from) the prices of the underlying securities.
Plan Reconciliations
The following tables provide a reconciliation of the Employee Benefit Plan's obligations and fair value of assets, components of the net periodic expense and elements of regulatory assets and liabilities and AOCI (in thousands):
Benefit Obligations
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 Balance Sheets at December 31 consist of (in thousands):
Accumulated Benefit Obligation (dollars in thousands)
Components of Net Periodic Expense (dollars in thousands)
Accumulated Other Comprehensive Income (Loss)
Amounts included in AOCI, after-tax, that have not yet been recognized as components of net periodic benefit cost at December 31 were as follows (in thousands):
The amounts in AOCI, regulatory assets or regulatory liabilities, after-tax, expected to be recognized as a component of net periodic benefit cost during calendar year 2013 were as follows (in thousands):
Assumptions
_____________________________
*
The expected rate of return on plan assets is 7.25% for the calculation of the 2013 net periodic pension cost.
The healthcare benefit obligation was determined at December 31 as follows:
We do not pre-fund our post-retirement benefit plan. The table below shows the estimated impacts of an increase or decrease to our healthcare trend rate for our Retiree Health Care Plan (dollars in thousands):
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 our employees may participate. Participants may elect to invest up to 50% of their eligible compensation on a pre-tax or after-tax basis, up to a maximum amount established by the Internal Revenue Service. The plan provides for company matching contributions and company retirement contributions. Employer contributions vest at 20% per year and are fully vested when the participant has 5 years of service.
(10) RELATED-PARTY TRANSACTIONS
Non-Cash Dividend to Parent
We have recorded a non-cash dividend to our Parent for $44.0 million in 2012 and decreased the utility money pool note receivable, net for the amount of $44.0 million.
Receivables and Payables
We have accounts receivable and accounts payable balances related to transactions with other BHC subsidiaries. These balances as of December 31 were as follows (in thousands):
Money Pool Notes Receivable and Notes Payable
We have a Utility Money Pool Agreement (the Agreement) with the Parent. 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 1%.
Advances under this notes receivable bear interest at 1.50% above the daily LIBOR rate (1.71% at December 31, 2012). We had the following balances with the Utility Money Pool as of and for the years ended December 31 (in thousands):
Other Balances and Transactions
We have the following Power Purchase and Transmission Services Agreements with affiliated entities:
•
Cheyenne Light entered into a PPA with Happy Jack. Under a separate inter-company agreement expiring on September 3, 2028, Cheyenne Light has agreed to sell up to 15 MW of the facility output from Happy Jack to us.
•
Cheyenne Light entered into a PPA with Silver Sage. Under a separate inter-company agreement expiring on September 30, 2029, Cheyenne Light has agreed to sell 20 MW of energy from Silver Sage to us.
•
A Generation Dispatch Agreement with Cheyenne Light that requires us to purchase all of Cheyenne Light's excess energy.
We had the following related party transactions for the years ended December 31 included in the corresponding captions in the accompanying Statements of Income:
(11) SUPPLEMENTAL CASH FLOW INFORMATION
(12) COMMITMENTS AND CONTINGENCIES
Partial Sale of Wygen III
On July 14, 2010, we sold a 23% ownership interest in Wygen III to the City of Gillette for $62.0 million. The purchase terminated the then current PPA with the City of Gillette, and the Wygen III Participation Agreement has been amended to include the City of Gillette. The Participation Agreement provides that the City of Gillette will pay us for administrative services and share in the costs of operating the plant for the life of the facility. The amount of net fixed assets sold totaled $55.8 million. We recognized a gain on the sale of $6.2 million.
Power Purchase and Transmission Services Agreements
We have the following power purchase and transmission agreements, not including related party agreements, as of December 31, 2012 (see Note 10 for information on related party agreements):
•
A PPA with PacifiCorp expiring on December 31, 2023, which provides for the purchase by us of 50 MW of electric capacity and energy. The price paid for the capacity and energy is based on the operating costs of one of PacifiCorp's coal-fired electric generating plants;
•
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 December 31, 2023; and
•
An agreement with Thunder Creek for gas transport capacity, expiring in October 31, 2019.
Costs incurred under these agreements were as follows for the years ended December 31 (in thousands):
Future Contractual Obligations
The following is a schedule of future minimum payments required under the power purchase, transmission services, facility and vehicle leases, and gas supply agreements (in thousands):
Long-Term Power Sales Agreements
We have the following power sales agreements as of December 31, 2012:
•
During periods of reduced production at Wygen III in which MDU owns a portion of the capacity, or during periods when Wygen III is off-line, MDU will be provided with 25 MW from our other generation facilities or from system purchases with reimbursement of costs by MDU;
•
During periods of reduced production at Wygen III in which the City of Gillette owns a portion of the capacity, or during periods when Wygen III is off-line, we will provide the City of Gillette with its first 23 MW from our other generating facilities or from system purchases with reimbursement of costs by the City of Gillette. Under this agreement, Black Hills Power will also provide the City of Gillette their operating component of spinning reserves;
•
An agreement under which we supply energy and capacity to MEAN expiring on May 31, 2023. This contract is unit-contingent based on up to 10 MW from our Neil Simpson II and up to 10 MW from our Wygen III plants. The energy and capacity purchase requirements decrease over the term of the agreement; and
•
A PPA with MEAN, expiring on April 1, 2015. Under this contract, MEAN purchases 5 MW of unit-contingent energy and capacity from Neil Simpson II and 5 MW of unit-contingent capacity from Wygen III.
Oil Creek Fire
On June 29, 2012, a forest and grassland fire occurred in the western Black Hills. It is alleged the fire occurred when a high voltage electrical transmission line maintained by us fell to the ground, and that electrical arcing from the downed line ignited dry grass or brush. The fire burned approximately 60,000 acres of land owned by private landowners as well as the United States Bureau of Land Management and the State of Wyoming. We have received written claims from the State of Wyoming and a landowner seeking recovery of damages for alleged injury to timber, grass, fencing, fire suppression and rehabilitation costs. The total amount of damages currently claimed by the State of Wyoming and the landowners is approximately $8 million. We have been notified that additional private landowner claims are forthcoming. Our investigation into the cause and origin of the fire is still pending. Based upon information developed in our investigation to date, we expect to deny and will vigorously defend all claims arising out of the fire. Given the uncertainty of litigation, however, a loss relating to the fire and the litigation is reasonably possible. We cannot reasonably estimate the amount of a potential loss because our investigation is ongoing, and because we expect further claims to be presented by other parties. Although we cannot predict the outcome of our investigation or the viability of potential claims, based on information currently available, management believes that any such claims, if determined adversely to us, will not have a material effect on our financial statements.
Legal Proceedings
We are subject to various legal proceedings, claims and litigation which arise in the ordinary course of operations. In the opinion of management, the amount of liability, if any, with respect to these actions would not materially affect our financial position, results of operations or cash flows.
In the normal course of business, we enter into agreements that include indemnification in favor of third parties, such as information technology agreements, purchase and sale agreements and lease contracts. We have also agreed to indemnify our directors, officers and employees in accordance with our articles of incorporation, as amended. Certain agreements do not contain any limits on our liability and therefore, it is not possible to estimate our potential liability under these indemnifications. In certain cases, we have recourse against third parties with respect to these indemnities. Further, we maintain insurance policies that may provide coverage against certain claims under these indemnities.
Environmental Matters
We are subject to costs resulting from a number of federal, state and local laws and regulations which affect future planning and existing operations. They can result in increased capital expenditures, operating and other costs as a result of compliance, remediation and monitoring obligations. Due to the environmental issues discussed below, we may be required to modify, curtail, replace or cease operating certain facilities or operations to comply with statutes, regulations and other requirements of regulatory bodies.
Air
Our generation facilities are subject to federal, state and local laws and regulations relating to the protection of air quality. These laws and regulations cover, among other pollutants, carbon monoxide, SO2, NOx, mercury particulate matter and GHG. Power generating facilities burning fossil fuels emit each of the foregoing pollutants and, therefore, are subject to substantial regulation and enforcement oversight by various governmental agencies.
Title IV of the Clean Air Act applies to several of our generation facilities, including the Neil Simpson II, Neil Simpson CT II, Lange CT, Wygen III and Wyodak plants. Title IV of the Clean Air Act created an SO2 allowance trading program as part of the federal acid rain program. Without purchasing additional allowances, we currently hold sufficient allowances to satisfy Title IV at all such plants through 2042.
The EPA issued the Industrial and Commercial Boiler Regulations for Area Sources of Hazardous Air Pollutants, with updates which impose emission limits, fuel requirements and monitoring requirements. The rule has a compliance deadline of March 21, 2014. In anticipation of this rule we suspended operations at the Osage plant on October 1, 2010 and as a result of this rule, we suspended operations at the Ben French facility on August 31, 2012 with plans to retire Osage, Ben French and Neil Simpson I on or before March 21, 2014. While the net book value of these plants is estimated to be insignificant at the time of retirement, we would reasonably expect any remaining value to be recovered through future rates.
Solid Waste Disposal
Various materials used at our facilities are subject to disposal regulations. Our Osage plant, at which operations have been suspended, has an on-site ash impoundment that is near capacity. An application to close the impoundment was approved by the State of Wyoming on April 13, 2012. Site closure work is underway with post closure monitoring to continue for 30 years.
(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 (in thousands):
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, 2012. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective.
Changes in Internal Control over Financial Reporting
During the quarter ended December 31, 2012, 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, except that we completed execution of our remediation plan to address a material weakness in internal controls surrounding accounting for income taxes, previously reported in our 2011 Annual Report on Form 10-K and 2012 Quarterly Reports on Form 10-Q.
In response to the identified material weakness, management conducted an investigation and review of the processes and controls surrounding the material weakness. Management, with oversight from our Audit Committee, developed a plan of remediation in the first quarter of 2012 that included changes to processes to prevent or detect similar future occurrences. As a result of this plan, the following control remediation steps were taken during 2012:
•
Increased tax department resources to ensure completion and documentation of a more thorough analysis that supports our calculation of the effective tax rate and valuation of deferred tax assets and liabilities.
•
Enhanced processes and controls related to income tax accounting and reporting.
•
Utilized a quarterly “Executive Tax Dashboard” to ensure a comprehensive assessment of each quarter's tax status.
•
Implemented formal periodic meetings among the Chief Financial Officer, Controller and the tax department to ensure adequate consideration of items that may impact income tax accounting.
Management's Report on Internal Control over Financial Reporting
Management of Black Hills Power is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2012, 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, 2012.
This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting because this requirement is inapplicable to companies such as ours which are known as non-accelerated filers.
Black Hills Power
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The following table sets forth the aggregate fees for services provided to us for the fiscal years ended December 31 by our independent registered public accounting firm, Deloitte & Touche LLP (in thousands):
Audit Fees. Fees for professional services rendered for the audits of our financial statements, review of the interim financial statements included in quarterly reports and services that generally only the independent auditor can reasonably provide, such as comfort letters, statutory audits, consents and assistance with and review of documents filed with the Securities and Exchange Commission.
Tax Fees. Fees for services related to tax compliance, and tax planning and advice including tax assistance with tax audits. These services include assistance regarding federal and state tax compliance and advice, review of tax returns, and federal and state tax planning.
Audit-Related Fees. Fees for assurance and related services that are reasonably related to the performance of the audit or review of our financial statements and are not reported under "Audit Fees." These services may include internal control reviews; attest services that are not required by statute or regulation; employee benefit plan audits; due diligence, consultations and audits related to mergers and acquisitions; and consultations concerning financial accounting and reporting standards.
The services performed by Deloitte & Touche LLP were pre-approved in accordance with the Black Hills Corporation Audit Committee's pre-approval policy whereby the Audit Committee pre-approves all audit and permissible non-audit services provided by the independent registered public accountants. The Audit Committee annually reviews the services expected to be provided by the independent auditors and establishes pre-approval fee levels for each category of services to be provided, including audit, audit-related, tax and other services. Any service that is not included in the approved list of services must be separately pre-approved by the Audit Committee.
ITEM 15.
ITEM 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a)
1.
Financial Statements
Financial statements required by Item 15 are listed in the index included in Item 8 of Part II.
2.
Schedules
Schedule II - Valuation and Qualifying Accounts for the years ended December 31, 2012, 2011 and 2010
All other schedules have been omitted because of the absence of the conditions under which they are required or because the required information is included elsewhere in the financial statements incorporated by reference in this Form 10-K.
3. Exhibits
SCHEDULE II
3.
Exhibits
_________________________
*
Previously filed as part of the filing indicated and incorporated by reference herein.
(a)
See (a) 3. Exhibits above.
(b)
See (a) 2. Schedules above.
SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT.
The Registrant is not required to send an Annual Report or Proxy to its sole security holder and parent company, Black Hills Corporation.
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.
INDEX TO EXHIBITS
_________________________
*
Previously filed as part of the filing indicated and incorporated by reference herein.