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.
OPERATING RISKS
Our current or future development, expansion and acquisition activities may not be successful, which could impair our ability to execute our growth strategy.
Execution of our future growth plan is dependent on successful ongoing and future development, expansion and acquisition activities. We can provide no assurance that we will be able to complete development projects or acquisitions we undertake or continue to develop attractive opportunities for growth. Factors that could cause our activities to be unsuccessful include:
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Our inability to obtain required governmental permits and approvals or the imposition of adverse conditions upon the approval of any acquisition;
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Our inability to secure adequate rates through regulatory proceedings;
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Our inability to obtain financing on acceptable terms, or at all;
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The possibility that one or more credit rating agencies would downgrade our issuer credit rating to below investment grade, thus increasing our cost of doing business;
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Our inability to successfully integrate any businesses we acquire;
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Our inability to retain management or other key personnel;
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Our inability to negotiate acceptable acquisition, construction, fuel supply, power sales or other material agreements;
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The trend of utilities building their own generation or looking for developers to develop and build projects for sale to utilities under turnkey arrangements;
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Reduced growth in the demand for utility services in the markets we serve;
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Changes in federal, state, local or tribal laws and regulations, particularly those which would make it more difficult or costly to fully develop our coal reserves, our oil and gas reserves and our generation capacity;
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Fuel prices or fuel supply constraints;
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Pipeline capacity and transmission constraints; and
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Competition within our industry and with producers of competing energy sources.
Our financial performance depends on the successful operation 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, oil and gas properties, the coal mine and electric and natural gas distribution systems 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. The Utilities Group purchases fuel from a number of suppliers. Our results of operations could be negatively impacted by disruptions in the delivery of fuel due to various factors, including but not limited to, transportation delays, labor relations, weather, and environmental regulations, which could limit the Utilities Groups’ ability to operate their facilities;
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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 and gas 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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Operating hazards such as leaks, mechanical problems and accidents, including explosions, affecting our natural gas distribution system which could impact public safety, reliability and customer confidence;
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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; and
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Labor relations. Approximately 33 percent of our employees are represented by a total of six collective bargaining agreements.
Construction, expansion, refurbishment and operation of power generating and transmission and resource extraction facilities involve significant risks which could reduce profitability.
The construction, expansion, refurbishment and operation of power generating and transmission and resource extraction 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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Contractual 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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Increased capital and operating costs to comply with increasingly stringent environmental laws and regulations;
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Opposition by members of public or special-interest groups;
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Weather interferences;
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Availability and cost of fuel supplies;
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Unexpected engineering, environmental and geological problems; and
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Unanticipated cost overruns.
The ongoing operation of our facilities involves many of the risks described above, in addition to risks relating to the breakdown or failure of equipment or processes and performance below expected levels of output or efficiency. New plants may employ recently developed and technologically complex equipment, including 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 operating and 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.
Operating results can be adversely affected by variations from normal weather conditions.
Our utility businesses are seasonal businesses, 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. Because natural gas is primarily used for residential and commercial heating, the demand for this product depends heavily upon winter weather patterns throughout our service territory and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating seasons. Accordingly, our utility operations have historically generated lower revenues and income when weather conditions are cooler than normal in the summer and warmer than normal in the winter. Unusually mild summers and winters therefore could have an adverse effect on our financial condition and results of operations.
Our coal mining operations are subject to operating risks that are beyond our control which could affect our profitability and production levels. Our surface mining operations could be disrupted or materially affected due to adverse weather or natural disasters such as heavy snow, rain or flooding. Additionally, weather patterns can also affect electricity demand. Extreme temperatures, both hot and cold, cause increased power usage, and therefore, increased generating requirements and the use of coal. Conversely, mild temperatures could result in lower electrical demand.
Weather conditions can also limit or temporarily halt our drilling and producing activities and other crude oil and natural gas operations. Primarily in the winter and spring, our operations can be curtailed because of cold, snow, and wet conditions. Severe weather could further curtail these operations, including drilling of new wells or production from existing wells. In addition, weather conditions and other events could temporarily impair our ability to transport our crude oil and natural gas production.
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 our net income is attributable to sales of contract and off-system wholesale electricity and natural gas. Energy 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 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.
The success of our crude oil and natural gas operations is affected by the prevailing market prices of crude oil and natural gas. Crude oil and natural gas prices and markets historically have also been, and are likely to continue to be, unpredictable. A decrease in crude oil or natural gas prices would not only reduce revenues and profits, but would also reduce the quantities of reserves that are commercially recoverable, and may result in charges to earnings for impairment of the net capitalized cost of these assets. Crude oil and natural gas prices are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for crude oil and natural gas, market uncertainty, and a variety of additional factors that are beyond our control.
The proliferation of domestic crude oil and natural gas shale plays in recent years has provided the market with an abundant new supply of crude oil and natural gas. Combined with lower demand from the economic downturn, this new and abundant supply source has created record volumes of natural gas in storage, and reduced domestic natural gas prices. In fact, the ratio of crude oil to natural gas prices is at an all-time high, far in excess of the six to one heating value equivalent ratio. This trend is likely to continue for the foreseeable future given the expected further development of domestic shale gas reserves.
Our mining operation requires reliable supplies of replacement parts, explosives, fuel, tires and steel-related products. If the cost of these increase significantly, or if sources of supplies and mining equipment become unavailable to meet our replacement demands, our productivity and profitability could be lower than our current expectations. In recent years, industry-wide demand growth exceeded supply growth for certain surface mining equipment and off-the-road tires. As a result, lead times for procuring some items generally increased to several months and prices for these items increased significantly.
Our operations rely on storage and transportation assets owned by third parties to satisfy our obligations. If storage capacity is inadequate or transportation is disrupted, our ability to satisfy our obligations may be hindered.
Our Utilities Group and Power Generation segment rely on pipeline companies and other owners of gas storage facilities to deliver natural gas to ratepayers, to supply our natural gas-fired power plants and to hedge commodity costs. If storage capacity is inadequate or transportation is disrupted, our ability to satisfy our obligations may be hindered. As a result, we may be responsible for damages incurred by our counterparties, such as the additional cost of acquiring alternative supply at then-current market rates, or for penalties imposed by state regulatory authorities.
Threats of terrorism and catastrophic events that could result from terrorism, cyber-attacks, or individuals and/or groups attempting to disrupt our businesses, or the businesses of third parties, may impact our operations in unpredictable ways and could adversely affect our results of operations, financial position and liquidity.
We are subject to the potentially adverse operating and financial effects of terrorist acts and threats, as well as cyber-attacks and other disruptive activities of individuals or groups. Our generation, transmission and distribution facilities, fuel storage facilities, information technology systems and other infrastructure facilities and systems and physical assets, could be direct targets of, or indirectly affected by, such activities. Terrorist acts or other similar events could harm our businesses by limiting their ability to generate, purchase or transmit power and by delaying their 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 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 a 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.
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, CFTC, EPA, OSHA, SEC and MSHA 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 NERC, 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.
Our energy production, transmission and distribution activities involve numerous risks that may result in accidents and other catastrophic events. These events could disrupt or impair our operations, create additional costs and cause substantial loss to us.
Inherent in our natural gas and electricity distribution activities, as well as our production, transportation and storage of crude oil and natural gas and our coal mining operations, are a variety of hazards and operating risks, such as leaks, blow-outs, fires, releases of hazardous materials, explosions and mechanical problems that could cause substantial adverse financial impacts. These events could result in injury or loss of human life, significant damage to property or natural resources (including public parks), environmental pollution, impairment of our operations, and substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations. Particularly for our distribution lines located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the damages resulting from any such events could be significant.
Utilities
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 regulated electric and gas utility operations are subject to cost-of-service regulation and earnings oversight from federal and state utility commissions. This regulatory treatment does not provide any assurance as to achievement of desired earnings levels. Our retail electric and gas 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. The rates that we are allowed to charge may or may not match our related costs and allowed return on invested capital at any given time. While rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that the state public utility commissions will judge all of our costs, including our direct and allocated 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 produce a full recovery of our costs and the return on invested capital allowed by the applicable state public utility commission.
To some degree, each of our gas and electric utilities are permitted to recover certain costs (such as increased fuel and purchased power costs) without having to file a rate case. To the extent we are able to pass through such costs to our customers and a state public utility commission subsequently determines that such costs should not have been paid by the customers; we may be required to refund such costs. Any such costs not recovered through rates, or any such refund, could adversely affect our results of operations, financial position or cash flow.
If market or other conditions adversely affect operations or require us to make changes to our business strategy in any of our utility businesses, we may be forced to record a non-cash goodwill impairment charge. Any significant impairment of our goodwill related to these utilities would cause a decrease in our assets and a reduction in our net income and shareholders’ equity.
We had approximately $353.4 million of goodwill on our consolidated balance sheet as of December 31, 2012. A substantial portion of the goodwill is related to the Aquila Transaction. If we make changes in our business strategy or if market or other conditions adversely affect operations in any of our businesses, we may be forced to record a non-cash impairment charge, which would reduce our reported assets, net income and shareholders’ equity. Goodwill is tested for impairment annually or whenever events or changes in circumstances indicate impairment may have occurred. If the testing performed indicates that impairment has occurred, we are required to record an impairment charge for the difference between the carrying value of the goodwill and the implied fair value of the goodwill in the period the determination is made. The testing of goodwill for impairment requires us to make significant estimates about our future performance and cash flows, as well as other assumptions. These estimates can be affected by numerous factors, including future business operating performance, changes in economic and interest rates, regulatory, industry or market conditions, changes in business operations, changes in competition or changes in technologies. Any changes in key assumptions, or actual performance compared with key assumptions, about our business and its future prospects could affect the fair value of one or more business segments, which may result in an impairment charge.
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 establish 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 and fair 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.
Coal Mining
If the assumptions underlying our reclamation and mine closure obligations are materially inaccurate, our costs could be significantly greater than anticipated or be incurred sooner than anticipated.
Our mining consists of surface mining operations. The Surface Mining Control and Reclamation Act and similar state laws and regulation establish operations, reclamation and closure standards for all aspects of surface mining. We estimate our total reclamation liabilities based on permit requirements, engineering studies, and our engineering expertise related to these requirements. The estimate of ultimate reclamation liability is reviewed periodically by our management and engineers, and by government regulators. The estimated liability can change significantly if actual costs vary from our original assumptions or if government regulations change significantly. GAAP requires that asset retirement obligations be recorded as a liability based on fair value, which reflects the present value of the estimated future cash flows. In estimating future cash flows, we consider the estimated current cost of reclamation and apply inflation rates. The resulting estimated reclamation obligations could change significantly if actual amounts or the timing of these expenses change significantly from our assumptions, which could have a material adverse effect on our results of operations and financial condition.
Estimates of the quality and quantity of our coal reserves may change materially due to numerous uncertainties inherent in three dimensional structural modeling. Significant inaccuracies in interpretation or modeling could materially affect the estimated quantity and quality of our reserve which could adversely affect our results of operations.
There are many uncertainties inherent in estimating quantities of coal reserves. The process of coal volume estimation requires interpretations of drill hole log data and subsequent computer modeling of the intersected deposit. Significant inaccuracies in interpretation or modeling could materially affect the quantity and quality of our reserve estimates. The accuracy of reserve estimates is a function of engineering and geological interpretation, conditions encountered during actual reserve recovery and undetected deposit anomalies. Variance from the assumptions used and drill hole modeling density could result in additions or deletions from our volume estimates. In addition, future environmental, economic or geologic changes may occur or become known that require reserve revisions either upward or downward from prior reserve estimates.
Oil and Gas
Estimates of the quantity and value of our proved oil and gas reserves may change materially due to numerous uncertainties inherent in estimating oil and natural gas reserves. Significant inaccuracies in interpretations or assumptions could materially affect the estimated quantities and present value of our reserves which could adversely affect our results of operations.
There are many uncertainties inherent in estimating quantities of proved reserves and their associated value. The process of estimating crude oil and natural gas reserves requires interpretation of available technical data and various assumptions, including assumptions relating to economic factors. Significant inaccuracies in interpretations or assumptions could materially affect the estimated quantities and present value of our reserves. The accuracy of reserve estimates is a function of the quality of available data, engineering and geological interpretations and judgment, and the assumptions used regarding quantities of recoverable oil and gas reserves, future capital expenditures and prices for crude oil and natural gas. Actual prices, production, development expenditures, operating expenses and quantities of recoverable crude oil and natural gas reserves may vary from those assumed in our estimates. These variances may be significant. Any significant variance from the assumptions used could cause the actual quantity of our reserves, and future net cash flow, to be materially different from our estimates. In addition, results of drilling, testing and production, changes in future capital expenditures and fluctuations in crude oil and natural gas prices after the date of the estimate may result in substantial upward or downward revisions.
The potential adoption of federal and state legislative and regulatory initiatives related to hydraulic fracturing could result in restrictions which could increase costs and cause delays to the completion of certain oil and gas wells, and potentially preclude the economic drilling and completion of wells in certain reservoirs.
Hydraulic fracturing is an essential and common practice in the oil and gas industry used extensively for decades to stimulate production of natural gas and/or oil from dense subsurface rock formations. We routinely apply hydraulic fracturing techniques on our crude oil and natural gas properties. Hydraulic fracturing involves using mostly water, sand, and a small amount of certain chemicals to fracture the hydrocarbon-bearing rock formation to enhance flow of hydrocarbons into the well-bore. The process is typically regulated by state crude oil and natural gas commissions; however, the EPA does assert federal regulatory authority over certain hydraulic fracturing activities when diesel comprises part of the fracturing fluid. In addition several agencies of the federal government including the EPA and the BLM are conducting studies of the fracturing stimulation process which may result in additional regulations. In 2012 the BLM has proposed regulations governing the use of hydraulic fracturing. In addition, legislation has been introduced before Congress, called the Fracturing Responsibility and Awareness of Chemicals Act, to provide the federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process.
Certain states have adopted or are considering adopting regulations that could impose more stringent permitting, public disclosure, and well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether. In the event federal, state, local or municipal legal restrictions are adopted in areas where we are conducting or in the future plan to conduct operations, we may incur additional costs to comply with such regulations that may be significant, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from utilizing fracture stimulation and effectively preclude the drilling of wells.
Exploratory and development drilling are speculative activities that may not result in commercially productive reserves. Lack of drilling success could result in uneconomical investments and could have an adverse effect on our financial condition and results of operations.
Drilling activities are subject to many risks, including the risk that no commercially productive oil or gas reservoirs will be encountered. There can be no assurance that new wells drilled by us or in which we have an interest will be productive or that we will recover all or any portion of our investment. Drilling for oil and gas may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. The cost of drilling, completing and operating wells is often uncertain. Our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, many of which are beyond our control, including economic conditions, mechanical problems, pressure or irregularities in formations, title problems, weather conditions, compliance with governmental rules and regulations and shortages in or delays in the delivery of equipment and services. Such equipment shortages and delays are caused by the high demand for rigs and other needed equipment by a large number of companies in active drilling basins. High activity in some basins may cause shortages of rigs and equipment in other basins. Our future drilling activities may not be successful. Lack of drilling success could have a material adverse effect on our financial condition and results of operations.
We could incur additional and substantial write-downs of the carrying value of our natural gas and oil properties, which would cause a decrease in our assets and stockholders' equity and could adversely impact our results of operations.
We review the carrying value of our natural gas and oil properties under the full cost accounting rules of the SEC on a quarterly basis. This quarterly review is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. In calculating future net revenues, SEC-defined commodity prices and recent costs are utilized. Such prices and costs are utilized except when different prices and costs are fixed and determinable from applicable contracts for the remaining term of those contracts. Two primary factors in the ceiling test are natural gas and crude oil reserve quantities and SEC-defined crude oil and gas prices, both of which impact the present value of estimated future net revenues. Revisions to estimates of natural gas and crude oil reserves, or an increase or decrease in prices, can have a material impact on the present value of estimated future net revenues. Any excess of the net book value, less deferred income taxes, is generally written off as an expense.
We recorded a non-cash impairment charge in the second quarter of 2012 due to the full cost ceiling limitations. We may have to record additional non-cash impairment charges in the future if commodity prices drive the SEC-defined prices below levels that precipitated the 2012 impairment. See Note 12 to the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
FINANCING RISKS
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 issuer credit rating is Baa3 (Positive outlook) by Moody’s; BBB- (Positive outlook) by S&P; and BBB- (Stable outlook) by Fitch. Reduction of our credit ratings could impair our ability to refinance or repay our existing debt and to complete new financings on acceptable terms, or at all. A downgrade could also result in counterparties requiring us to post additional collateral under existing or new contracts or trades. In addition, a ratings downgrade would increase our interest expense under some of our existing debt obligations, including borrowings under our credit facilities.
Derivatives regulations included in current financial reform legislation could impede our ability to manage business and financial risks by restricting our use of derivative instruments as hedges against fluctuating commodity prices and interest rates.
In July 2010, Dodd-Frank was passed by Congress and signed into law. Dodd-Frank contains significant derivatives regulations, including a requirement that certain transactions be cleared resulting in a requirement to post cash collateral (commonly referred to as “margin”) for such transactions. Dodd-Frank provides for a potential exception from these clearing and cash collateral requirements for commercial end-users such as utilities and it includes a number of defined terms that will be used in determining how this exception applies to particular derivative transactions and the parties to those transactions.
We use crude oil and natural gas derivative instruments for our hedging activities for our oil and gas production activities and our gas utility operations. We also use interest rate derivative instruments to minimize the impact of interest rate fluctuations. As a result of Dodd-Frank regulations promulgated by the CFTC, we may be required to post collateral to clearing entities for certain swap transactions we enter into. In addition, many of the transactions which were previously classified as swaps have been converted to exchange-traded futures contracts, which are subject to futures margin posting requirements. Such a requirement could have a significant impact on our business by reducing our ability to execute derivative transactions to reduce commodity price and interest rate uncertainty and to protect cash flows. Requirements to post collateral may cause significant liquidity issues by reducing our ability to use cash for investment or other corporate purposes, or may require us to increase our level of debt. In addition, a requirement for our counterparties to post collateral could result in additional costs being passed on to us, thereby decreasing our profitability.
Our hedging activities that are designed to protect against commodity price and financial market risks may cause fluctuations in reported financial results due to accounting requirements associated with such activities.
We use various financial contracts and derivatives, including futures, forwards, options and swaps to manage commodity price and financial market risks. The timing of the recognition of gains or losses on these economic hedges in accordance with GAAP does not always match up with the gains or losses on the commodities or assets being hedged. The difference in accounting can result in volatility in reported results, even though the expected profit margin may be essentially unchanged from the dates the transactions were consummated.
Our use of derivative financial instruments could result in material financial losses.
From time to time, we have sought to limit a portion of the potential adverse effects resulting from changes in commodity prices and interest rates by using derivative financial instruments and other hedging mechanisms. To the extent that we hedge our commodity price and interest rate exposures, we forgo the benefits we would otherwise experience if commodity prices or interest rates were to change in our favor. In addition, even though they are closely monitored by management, our hedging activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the hedge arrangement, the hedge is economically imperfect, commodity prices or interest rates move unfavorably related to our physical or financial positions, or hedging policies and procedures are not followed.
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 two defined benefit pension plans and three non-pension postretirement plans that cover certain eligible employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements and the expense recognized related to these plans. These estimates and assumptions may change based on actual return on plan assets, changes in interest rates and any changes in governmental regulations.
We rely on cash distributions from our subsidiaries to make and maintain dividends and debt payments. Our subsidiaries may not be allowed or may be unable to make dividend payments or loan funds to us, which could adversely affect our ability to meet our financial obligations or pay dividends to our shareholders.
We are a holding company. Our investments in our subsidiaries are our primary assets. Our operating cash flow and ability to service our indebtedness depend on the operating cash flow of our subsidiaries and the payment of funds by them to us in the form of dividends or advances. Our subsidiaries are separate legal entities that have no obligation to make any funds available for that purpose, whether by dividends or otherwise. In addition, each subsidiary’s ability to pay dividends to us depends on any applicable contractual or regulatory restrictions that may include requirements to maintain minimum levels of cash, working capital or debt service funds.
We expect to continue our policy of paying regular cash dividends. However, there is no assurance as to the amount of future dividends because they depend on our future earnings, capital requirements, and financial conditions, and are subject to declaration by the Board of Directors. Our operating subsidiaries have certain restrictions on their ability to transfer funds in the form of dividends or loans to us. See “Liquidity and Capital Resources” within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K for further information regarding these restrictions and their impact on our liquidity.
We may be unable to obtain the financing needed to refinance debt, fund planned capital expenditures or otherwise execute our operating strategy. Lack of credit at reasonable rates would have an adverse effect on our results of operations, financial position and liquidity.
Our ability to execute our operating strategy is highly dependent upon our access to capital. Historically, we have addressed our liquidity needs (including funds required to make scheduled principal and interest payments, refinance debt and fund working capital and planned capital expenditures) with operating cash flow, borrowings under credit facilities, proceeds of debt and equity offerings and proceeds from asset sales. Our ability to access the capital markets and the costs and terms of available financing depend on many factors, including changes in our credit ratings, changes in the federal or state regulatory environment affecting energy companies, volatility in commodity or electricity prices and general economic and market conditions.
In addition, given that we are a holding company and that our utility assets are owned by our subsidiaries, if we are unable to adequately access the credit markets, we could be required to take additional measures designed to ensure that our utility subsidiaries are adequately capitalized to provide safe and reliable service. Possible additional measures would be evaluated in the context of then-prevailing market conditions, prudent financial management and any applicable regulatory requirements.
National and regional economic conditions may cause increased counterparty credit risk, late payments and uncollectible accounts, which could adversely affect our results of operations, financial position and 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 our non-utility customers. If late payments and uncollectible accounts increase, earnings and cash flows from our continuing operations may be reduced.
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 such insurance, could be affected by developments affecting insurance businesses, 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, risks associated with our oil and gas exploration and production activities, distribution property losses, cyber-security risks and dangers that exist in the gathering and transportation in pipelines.
Our operations are also subject to all the hazards and risks normally incident to the development, exploitation, production and transportation of, and the exploration for, oil and gas, including unusual or unexpected geologic formations, pressures, down hole fires, mechanical failures, blowouts, explosions, uncontrollable flows of oil, gas or well fluids, pollution and other environmental risks. These hazards could result in substantial losses to us due to injury and loss of life, severe damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations. We maintain insurance coverage for our operated wells and we participate in insurance coverage maintained by the operators of our wells, although there can be no assurances that such coverage will be sufficient to prevent a material adverse effect to us if any of the foregoing events occur.
Increasing costs associated with our health care plans may adversely affect our results of operations, financial position or liquidity.
The costs of providing health care benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise. The increasing costs and funding requirements associated with our health care plans may adversely affect our results of operations, financial position or liquidity.
In March 2010, the President of the United States signed PPACA 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 are effective while other provisions of the 2010 Acts will be effective in future years. The 2010 Acts could require, among other things, changes to our current employee benefit plans and in our administrative and accounting processes, as well as changes to the cost of our plans. The ultimate extent and cost of these changes cannot be determined at this time and are being evaluated and updated as related regulations and interpretations of the 2010 Acts become available.
Our electric and gas 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.
We have deferred a substantial amount of income tax related to various tax planning strategies, including the deferral of a gain associated with the assets sold in the IPP Transaction. If the Internal Revenue Service successfully challenges these tax positions, our results of operations, financial position or liquidity could be adversely affected.
We have deferred a substantial amount of tax payments through various tax planning strategies including the deferral of approximately $125 million in income taxes associated with the IPP Transaction and the Aquila Transaction.
The IRS has challenged our position with respect to the like-kind exchange. As currently stated in a Notice of Proposed Adjustment received from the IRS in January 2013, their position is to disallow a significant portion of the gain deferred as reported on our originally filed 2008 tax return. We disagree with such a position and will pursue all available IRS and/or legal channels to challenge the proposed adjustment. In the event we are unsuccessful in our challenge, the amount of deferred income tax on a worst case basis that could be accelerated into a current tax payable would be approximately $125 million. However, we would be entitled to a tax benefit associated with the additional tax depreciation that would result from increasing the depreciable cost for tax purposes in the assets acquired. This net current tax liability would accrue interest, which is estimated to be approximately $20 million before income tax effect.
In certain circumstances, the IRS may assess penalties when challenging our tax positions. If we were unsuccessful in defending against these penalties, it may have a material impact on our results of operations. No penalties have been assessed by the IRS in connection with the like-kind exchange transaction.
Our ability to successfully resolve the purchase price adjustments in question from the sale of Enserco.
On Feb. 29, 2012, we sold the outstanding stock of Enserco, our Energy Marketing segment. Pursuant to the provisions of the Stock Purchase Agreement, disputes regarding post-closing purchase price adjustments are subject to arbitration before a nationally-recognized accounting firm and all other disputes are subject to the indemnification procedures in the agreement. The buyer originally demanded an amount totaling $7.2 million characterizing all claims in such demand as purchase price adjustments. We contested certain claims in the buyer's demand, including whether certain claims were properly characterized as purchase price adjustments, but reached a partial settlement and paid the buyer the sum of $1.4 million. The parties were unable to reach a negotiated agreement regarding the balance of the claims.
In December 2012, we agreed to arbitrate the claims that we believe are properly characterized as purchase price adjustments, but objected to the arbitration of the claims that we believe are not properly characterized as purchase price adjustments. After joint discussions of the parties with the arbitrator, in January 2013 the arbitrator advised the parties that it would not arbitrate the claims to which we objected. On Feb. 7, 2013, the buyer filed a petition in the United States District Court for the District of Colorado applying for an order compelling arbitration on all of the disputed claims. We will respond to this litigation, requesting the court to deny the buyer's application.
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.
ENVIRONMENTAL RISKS
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 and non-regulated fossil-fuel generating plants in South Dakota, Wyoming, and Colorado. 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 Matters.”
On May 20, 2011, with amendments on Dec. 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 March 21, 2014 compliance deadline.
On Dec. 16, 2011, with updates on Dec. 21, 2012, the EPA signed the National Emission Standards for Hazardous Air Pollutants from Coal and Oil Fired Electric Utility Steam Generating Units (MATS), which became effective on April 16, 2012. Affected units 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 of our plants will be in compliance by the initial 2015 deadline, with the primary impacts to Neil Simpson II, Wygen I, Wygen II, Wygen III and the Wyodak Plant with the need to install mercury sorbent injection systems and the need to meet 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 as defined by EPA regulations. 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 to see a proposed rule from the EPA, to regulate GHG emissions from existing steam electric generating units. This rule could have a significant impact on our coal generating fleet.
In 2010, the State of Colorado enacted House Bill 1365, the Colorado Clean Air, Clean Jobs Act, a coordinated utility plan to reduce air emissions from coal fired power plants and promoting the use of natural gas and other lower emitting resources. This act has a significant impact on our W.N. Clark facility and in October 2010, Colorado Electric filed testimony with the CPUC that recommended retirement of the W.N. Clark facility to comply with House Bill 1365. In December 2010, the CPUC issued an order approving the closure of the W.N. Clark generation facility by Dec. 31, 2013, and granted a presumption of need for replacement of the plant. On July 30, 2012, Colorado Electric filed its electric resource plan with the CPUC seeking to develop and own replacement capacity for the retirement of the coal-fired W.N. Clark power plant. The CPUC dismissed the initial filing without prejudice. It directed Colorado Electric to refile the resource plan and address alternatives for not just the replacement capacity for its coal-fired W.N. Clark power plant, but also for the retirement of the aging natural gas-fired steam turbines at Pueblo Units 5 and 6. On review, the CPUC confirmed Colorado Electric’s right to own the replacement capacity for the W.N. Clark power plant and extended the date to refile the resource plan to May 1, 2013.
Due to uncertainty as to the final outcome of federal climate change legislation, or regulatory changes under the Clean Air Act, we cannot definitively estimate the effect of GHG legislation or regulation on our results of operations, cash flows or financial position. The impact of GHG legislation or regulation on our company will depend upon many factors, including but not limited to the timing of implementation, the GHG sources that are regulated, the overall GHG emissions cap level, and the availability of technologies to control or reduce GHG emissions. If a “cap 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.
The failure to achieve or maintain compliance with existing or future governmental laws, 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, tribal and local authorities. We generally must obtain and comply with a variety of regulations, licenses, permits and other approvals in order to operate, which can require significant capital expenditure and operating costs. If we fail to comply with these requirements, we could be subject to civil or criminal liability and the imposition of penalties, liens or fines, claims for property damage or personal injury, or environmental clean-up costs. In addition, existing regulations may be revised or reinterpreted, and new laws and regulations may be adopted or become applicable to us or our facilities, which could require additional unexpected expenditures or cause us to reevaluate the feasibility of continued operations at certain sites, and have a detrimental effect on our business.
In connection with certain acquisitions, we assumed liabilities associated with the environmental condition of certain properties, regardless of when such liabilities arose, whether known or unknown, and in some cases agreed to indemnify the former owners of those properties for environmental liabilities. Future steps to bring our facilities into compliance or to address contamination from legacy operations, 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.
The characteristics of coal may make it difficult for coal users to comply with various environmental standards related to coal combustion or utilization and the use of alternative energy sources for power generation as mandated by states could reduce coal consumption. As a result, coal users may switch to other fuels, which could affect the volume of our sales and the price of our products.
Coal contains impurities, including but not limited to sulfur, mercury, chlorine, carbon and other elements or compounds, many of which are released into the air when coal is burned. More stringent environmental regulations of emissions from coal-fueled power plants could increase the costs of using coal, thereby reducing demand for coal as a fuel source and the volume and price of our coal sales. Renewable energy requirements and changes to regulations could make coal a less attractive fuel alternative in the planning and building of power plants in the future.
Proposed reductions in emissions of mercury, sulfur dioxides, nitrogen oxides, particulate matter, or greenhouse gases may require the installation of costly emission control technology or the implementation of other measures. For example, in order to meet the federal Clean Air Act limits for SO2 emission from power plants, coal users may need to install scrubbers, use SO2 emission allowances (some of which they may purchase), blend high-sulfur coal with low-sulfur coal or switch to other fuels. Reductions in mercury emission required by certain states and the EPA will likely require some power plants to install new equipment, at substantial cost, or discourage the use of certain coals containing higher levels of mercury. Existing or proposed legislation focusing on emissions enacted by the United States or individual states could make coal a less attractive fuel alternative for our customers and could impose a tax or fee on the producer of the coal. If our customers decrease the volume of coal they purchase from us or switch to alternative fuels as a result of existing or future environmental regulations aimed at reducing emissions, our operations and financial results could be adversely impacted.
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 19, “Commitments and Contingencies”, of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
ITEM 4.
ITEM 4. SPECIALIZED DISCLOSURES
Information concerning mine safety violations or other regulatory matters required by Sections 1503(a) of Dodd-Frank is included in Exhibit 95 of this Annual Report.
PART II
ITEM 5.
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock is traded on the New York Stock Exchange under the symbol BKH. As of Dec. 31, 2012, we had 4,517 common shareholders of record and approximately 29,000 beneficial owners, representing all 50 states, the District of Columbia and 8 foreign countries.
We have paid a regular quarterly cash dividend each year since the incorporation of our predecessor company in 1941 and expect to continue paying a regular quarterly dividend for the foreseeable future. At its Jan. 31, 2013 meeting, our Board of Directors declared a quarterly dividend of $0.38 per share, equivalent to an annual dividend of $1.52 per share, marking 2013 as the 43rd consecutive annual dividend increase for the Company.
For additional discussion of our dividend policy and factors that may limit our ability to pay dividends, see “Liquidity and Capital Resources” under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this Annual Report on Form 10-K.
Quarterly dividends paid and the high and low prices for our common stock, as reported in the New York Stock Exchange Composite Transactions, for the last two years were as follows:
UNREGISTERED SECURITIES ISSUED
There were no unregistered securities sold during 2012.
ISSUER PURCHASES OF EQUITY SECURITIES
The following table contains information about our acquisitions of equity securities for the three months ended December 31, 2012:
_________________________
*
Shares were acquired from certain officers and key employees under the share withholding provisions of the Omnibus Incentive Plan for payment of taxes associated with the vesting of restricted stock and the exercise of stock options.
ITEM 6.
ITEM 6.
SELECTED FINANCIAL DATA
SELECTED FINANCIAL DATA continued
SELECTED FINANCIAL DATA continued
____________________________________
(1)
All years have been reclassified to include our Energy Marketing segment in Discontinued Operations. 2008 includes electric and gas utilities acquired on July 14, 2008.
(2)
Includes $938.4 million for the Aquila acquisition.
(3)
2011, 2010 and 2008 include a $27.3 million, a $9.9 million and a $61.4 million, non-cash after-tax unrealized mark-to-market loss, respectively, related to certain interest rate swaps; while 2012 and 2009 include a $1.2 million and a $36.2 million non-cash after-tax unrealized mark-to-market gain, respectively, related to certain interest rate swaps.
(4)
2012 includes a non-cash after-tax ceiling test impairment loss of $17.3 million offset by an after-tax gain on sale of $18.9 million of our Williston Basin assets (see Notes 12 and 22 of the Notes to the Consolidated Financial Statements of this Annual Report on Form 10-K.)
(5)
Includes a $27.8 million non-cash after-tax ceiling test impairment charge to our crude oil and natural gas properties taken in 2009 and a $16.9 million after-tax gain on sale of 23.5 percent ownership interest in Wygen I.
(6)
Includes a $59.0 million non-cash after-tax ceiling test impairment charge to our crude oil and natural gas properties taken in 2008.
(7)
Discontinued operations include the operations of the Energy Marketing segment in 2012, 2011, 2010, 2009 and 2008, and the assets sold in the IPP Transaction for 2009 and 2008.
(8)
During November 2011, we issued 4.4 million shares of common stock which diluted our earnings per share in subsequent periods.
(9)
Excludes Cheyenne Light.
(10)
Tons of coal decreased in 2012 due to the expiration of an unprofitable train load-out contract.
For additional information on our business segments see Item 7.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Black Hills Corporation
Rapid City, South Dakota
We have audited the accompanying consolidated balance sheets of Black Hills Corporation and subsidiaries (the “Company”) as of December 31, 2012 and 2011, and the related consolidated statements of income, comprehensive income (loss), cash flows, and common stockholders’ equity for each of the three years in the period ended December 31, 2012. Our audits also included the financial statement schedules listed in the Index at Item 15. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedules 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes 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 consolidated financial statements present fairly, in all material respects, the financial position of Black Hills Corporation and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their 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 schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 25, 2013 expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 25, 2013
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
See Note 15 for additional disclosures related to Comprehensive Income.
The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.
BLACK HILLS CORPORATION
CONSOLIDATED BALANCE SHEETS
The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.
BLACK HILLS CORPORATION
CONSOLIDATED BALANCE SHEETS
(Continued)
The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
____________________
*
Cash and cash equivalents include cash of discontinued operations of $37.1 million, $16.0 million and $97.5 million at Dec. 31, 2011, 2010 and 2009, respectively.
See Note 16 for supplemental disclosure of cash flow information.
The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY
Dividends per share paid were $1.48, $1.46 and $1.44 for the years ended Dec. 31, 2012, 2011 and 2010, respectively.
The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.
BLACK HILLS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012, 2011 and 2010
(1)
BUSINESS DESCRIPTION AND SIGNIFICANT ACCOUNTING POLICIES
Business Description
Black Hills Corporation is a diversified energy company headquartered in Rapid City, South Dakota. We are a holding company that, through our subsidiaries, operates in two primary business groups: Utilities and Non-regulated Energy.
The Utilities Group includes our Electric Utilities and Gas Utilities segments. Electric Utilities include the operating results of the regulated electric utility operations of Black Hills Power and Colorado Electric, and the electric and natural gas utility operations of Cheyenne Light, which supply regulated electric utility services to areas in South Dakota, Wyoming, Colorado and Montana and natural gas utility services to Cheyenne, Wyo. and vicinity. Gas Utilities consist of the operating results of the regulated natural gas utility operations of Colorado Gas, Nebraska Gas, Iowa Gas, and Kansas Gas.
The Non-regulated Energy Group includes our Power Generation, Coal Mining and Oil and Gas segments. Power Generation, which is conducted through Black Hills Electric Generation and its subsidiaries, engages in independent power generation activities in Wyoming and Colorado. Coal Mining, which is conducted through WRDC, engages in coal mining activities located near Gillette, Wyo. Oil and Gas, which is conducted through BHEP and its subsidiaries, engages in crude oil and natural gas exploration and production activities located in Colorado, Louisiana, Montana, Oklahoma, New Mexico, North Dakota, Wyoming, Texas and California. These businesses are aggregated for reporting purposes as Non-regulated Energy.
On Feb. 29, 2012, we sold Enserco, our Energy Marketing segment, which resulted in this segment being classified as discontinued operations. See Note 23 for additional information.
For further descriptions of our reportable business segments, see Note 17.
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 certain 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. Changes in facts and circumstances or additional information may result in revised estimates and actual results could differ materially from those estimates.
Principles of Consolidation
The consolidated financial statements include the accounts of Black Hills Corporation and its wholly-owned and majority-owned and controlled subsidiaries. Investment in non-controlled entities over which we have the ability to exercise significant influence over operating and financial policies are accounted for using the equity method of accounting. In applying the equity method of accounting, the investments are initially recognized at cost, and subsequently adjusted for our proportionate share of earnings and losses and distributions. Under this method, a proportionate share of pretax income is recorded as Equity earnings (loss) of unconsolidated subsidiaries. All inter-company balances and transactions have been eliminated in consolidation. For additional information on inter-company revenues, see Note 17.
Our Consolidated Statements of Income include operating activity of acquired companies beginning with their acquisition date. We use the proportionate consolidation method to account for our working interests in oil and gas properties and for our ownership interest in any jointly-owned electric utility generating facility, wind project or transmission tie and the BHEP gas processing plant. See Note 7 for additional information.
As a result of the sale of our Energy Marketing segment, amounts associated with this segment have been reclassified as discontinued operations on the accompanying Consolidated Financial Statements. See Note 23 for additional information.
Cash and Cash Equivalents
We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Restricted Cash and Equivalents
The Black Hills Wyoming project financing requires that we maintain cash accounts for various specified purposes. We do not readily have access to these accounts and can only withdraw funds upon meeting certain requirements. Therefore, we have classified these amounts as restricted cash.
Accounts Receivable and Allowance for Doubtful Accounts
Accounts receivable for our Utilities Group primarily consists 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 and allowance for doubtful accounts. Accounts receivable for our Non-regulated Energy Group consists of amounts due from sales of coal, crude oil and natural gas, electric energy and capacity.
We maintain an allowance for doubtful accounts which reflects our estimate of uncollectible trade receivables. We regularly review our trade receivable allowance by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect collectibility.
In specific cases where we are aware of a customer’s inability or reluctance to pay, we record an allowance for doubtful accounts against amounts due to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of commodity prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible or the time allowed for dispute under the contract has expired.
We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty.
Following is a summary of accounts receivable as of Dec. 31 (in thousands):
Revenue Recognition
Revenue is recognized when there is persuasive evidence of an arrangement with a fixed or determinable price and delivery has occurred or services have been rendered. Sales tax collected from our customers is 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, our utilities 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 Accounts receivable, net on the accompanying Consolidated Balance Sheets.
For long-term non-regulated power sales agreements, revenue is recognized either in accordance with accounting standards for revenue recognition, or in accordance with accounting standards for leases, as appropriate. Under accounting standards for revenue recognition, revenue is generally recognized as the lesser of the amount billed or the average rate expected over the life of the agreement.
Natural gas and crude oil sales are recognized when the products are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectibility of the revenue is reasonably assured. Our Oil and Gas segment records its share of revenues based on production volumes and contracted sales prices. The sales price for natural gas, crude oil, condensate and NGLs is adjusted for transportation costs and other related deductions when applicable. The transportation costs and other deductions are based on contractual or historical data and do not require significant judgment.
Materials, Supplies and Fuel
The following amounts by major classification are included in Materials, supplies and fuel on the accompanying Consolidated Balance Sheets as of (in thousands):
Materials and supplies represent parts and supplies for all of our business segments. Fuel - Electric Utilities represent oil, gas, and coal on hand used to produce power. Natural gas in storage primarily represents gas purchased for use by our gas customers. All of our Materials, supplies and fuel are valued using weighted-average cost. The value of our natural gas in storage fluctuates with seasonal volume requirements of our business and the commodity price of natural gas.
Property, Plant and Equipment
Additions to property, plant and equipment are recorded at cost. 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. We also capitalize interest, when applicable, on undeveloped leasehold costs and certain non-regulated construction projects. In addition, asset retirement costs associated with tangible long-lived regulated utility assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived regulated utility assets in the period incurred. The amounts capitalized are included in Property, plant and equipment on the accompanying Consolidated Balance Sheets.
The cost of regulated utility property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage plus cost of removal, is charged to accumulated depreciation. Removal costs associated with non-legal obligations related to our regulated properties are reclassified from accumulated depreciation and reflected as regulatory liabilities. Retirement or disposal of all other assets, except for crude oil and natural gas properties as described below, result in gains or losses recognized as a component of operating income. Ordinary repairs and maintenance of property, except as allowed under rate regulations, are charged to operations as incurred.
Depreciation provisions for property, plant and equipment are generally computed on a straight-line basis based on the applicable estimated service life of the various class of property. Capitalized coal mining costs and coal leases are amortized on a unit-of-production method based on volumes produced and estimated reserves. For certain non-utility power plant components, a unit-of-production methodology based on plant hours run is used.
Oil and Gas Operations
We account for our oil and gas activities under the full cost method. Under the full cost method, costs related to acquisition, exploration and estimated future expenditures to be incurred in developing proved reserves as well as estimated reclamation and abandonment costs, net of estimated salvage values are capitalized. These costs are amortized using a unit-of-production method based on volumes produced and proved reserves. Any conveyances of properties, including gains or losses on abandonment of properties, are typically treated as adjustments to the cost of the properties with no gain or loss recognized. However, we recognized a gain on the sale of a majority of our Williston Basin assets in 2012. See Note 22 for further discussion.
Costs directly associated with unproved properties and major development projects, if any, are excluded from the costs to be amortized. These excluded costs are subsequently included within the costs to be amortized when it is determined whether or not proved reserves can be assigned to the properties. The properties excluded from the costs to be amortized are assessed for impairment at least annually and any amount of impairment is added to the costs to be amortized. These costs are generally expected to be included in costs to be amortized within the term of the underlying lease agreement which varies in length.
Under the full cost method, net capitalized costs are subject to a ceiling test which limits these costs to the present value of future net cash flows discounted at an SEC required rate, net of related tax effects, plus the lower of cost or fair value of unproved properties included in the net capitalized costs. Future net cash flows are estimated based on SEC-defined end-of-period commodity prices adjusted for contracted price changes and held constant for the life of the reserves. An average price is calculated using the price at the first day of each month for each of the preceding 12 months. If the net capitalized costs exceed the full cost “ceiling” at period end, a permanent non-cash write-down would be charged to earnings in that period. As a result of lower natural gas prices, we recorded a non-cash ceiling test impairment of oil and gas long-lived assets included in the Oil and Gas segment in 2012. No ceiling test write-down was recorded in 2011 or 2010. See Note 12 for additional information.
The SEC definition of “reliable technology” permits the use of any reliable technology to establish reserve volumes in addition to those established by production and flow test data. This definition allows, but does not require us, to calculate PUDs to be booked at more than one location away from a producing well. We elected to include PUDs of only one location away from a producing well in our volume reserve estimate. See information on our oil and gas drilling activities in Note 21.
Companies are permitted but not required to disclose probable and possible reserves. We have elected not to report on these additional reserve categories.
Goodwill and Intangible Assets
Goodwill and intangible assets with indefinite lives are not amortized but the carrying values are reviewed upon an indicator of impairment or at least annually. Intangible assets with a finite life continue to be amortized over their estimated useful lives. We perform this annual review of goodwill and indefinite lived intangible assets as of Nov. 30 each year (or more frequently if impairment indicators arise).
We performed our annual goodwill impairment tests as of Nov. 30, 2012. We estimated the fair value of the goodwill using discounted cash flow methodology, EBITDA multiple method, and an analysis of comparable transactions. This analysis required the input of several critical assumptions, including future growth rates, cash flow projections, operating cost escalation rates, rates of return, a risk-adjusted discount rate, timing and level of success in regulatory rate proceedings, the cost of debt and equity capital, and long-term earnings and merger multiples for comparable companies.
Goodwill primarily arose from the acquisition of one regulated electric and four regulated gas utilities in the Aquila Transaction. This goodwill from the Aquila Transaction was allocated approximately 72 percent to Colorado Electric and 28 percent to the Gas Utilities. We believe that the goodwill amount reflects the value of the relatively stable, long-lived cash flows of the regulated gas utility business, considering the regulatory environment and market growth potential and the long-lived cash flow and rate base growth opportunities at our electric utility in Colorado. Goodwill balances were as follows (in thousands):
Our intangible assets represent easements, rights-of-way and trademarks and are amortized using a straight-line method based on estimated useful lives. The finite lived intangible assets are currently being amortized over 20 years. Changes to intangible assets for the years ended Dec. 31, were as follows (in thousands):
_________________
*
Amortization expense for existing intangible assets is expected to be $0.2 million for each year of 2013, 2014, 2015, 2016, and 2017.
Asset Retirement Obligations
Accounting standards for asset retirement obligations associated with long-lived assets require that the present value of retirement costs for which we have a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost and depreciated over an appropriate period. The associated ARO accretion expense for our non-regulated operations is included within Depreciation, depletion and amortization on the accompanying Consolidated Statements of Income. The accounting for the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset.
We initially record liabilities for the present value of retirement costs for which we have a legal obligation, with an equivalent amount added to the asset cost. The asset is then depreciated or depleted over the appropriate useful life and the liability is accreted over time by applying an interest method of allocation. Any difference in the actual cost of the settlement of the liability and the recorded amount is recognized as a gain or loss in the results of operations at the time of settlement for our non-regulated operations, other than Oil and Gas. For the Oil and Gas segment, differences in the settlement of the liability and the recorded amount are generally reflected as adjustments to the capitalized cost of oil and gas properties and depleted pursuant to our use of the full cost method. Additional information is included in Note 10.
Fair Value Measurements
Derivative Financial Instruments
Assets and liabilities are classified and disclosed in one of the following fair value categories:
Level 1 - Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. This level primarily consists of financial instruments such as exchange-traded securities or listed derivatives.
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. These inputs reflect management’s best estimate of fair value using its own assumptions about the assumptions a market participant would use in pricing the asset or liability.
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 the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments.
Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable such as the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs.
Valuation Methodologies for Derivatives
Oil and Gas Segment:
•
The commodity option contracts for the Oil and Gas segment are valued under the market approach and include calls and puts. Fair value was derived using quoted prices from third party brokers for similar instruments as to quantity and timing. The prices are then validated through third party sources and therefore support Level 2 disclosure.
•
The commodity basis swaps for the Oil and Gas segment are valued under the market approach using the instrument’s current forward price strip hedged for the same quantity and date and discounted based on the three-month LIBOR. We utilize observable inputs which support Level 2 disclosure.
Utilities Segment:
•
The commodity contracts for the Utilities, valued using the market approach, include exchange-traded futures, options and basis swaps (Level 2) and OTC basis swaps (Level 3) for natural gas contracts. For Level 2 assets and liabilities, fair value was derived using broker quotes validated by the Chicago Mercantile Exchange pricing for similar instruments. For Level 3 assets and liabilities, fair value was derived using average price quotes from the OTC contract broker and an independent third party market participant since these instruments are not traded on an exchange.
Corporate Segment:
•
The interest rate swaps are valued using the market valuation approach. We establish fair value by obtaining price quotes directly from the counterparty which are based on the floating three-month LIBOR curve for the term of the contract. The fair value obtained from the counterparty is then validated by utilizing a nationally recognized service that obtains observable inputs to compute fair value for the same instrument. In addition, the fair value for the interest rate swap derivatives includes a CVA component. The CVA considers the fair value of the interest rate swap and the probability of default based on the life of the contract. For the probability of a default component, we utilize observable inputs supporting Level 2 disclosure by using our credit default spread, if available, or a generic credit default spread curve that takes into account our credit ratings.
Additional information is included in Note 4.
Derivatives and Hedging Activities
The accounting standards for derivatives and hedging require that derivative instruments be recorded on the balance sheet as either an asset or liability measured at its fair value, and that changes in the derivative instrument’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met and designated accordingly. Each Consolidated Balance Sheet reflects the offsetting of net derivative positions with fair value amounts for cash collateral with the same counterparty when a legal right of offset exists.
Accounting standards for derivatives and hedging require that the unrealized gains or losses on a derivative instrument designated and qualifying as a fair value hedging instrument as well as the offsetting unrealized loss or gain on the hedged item attributable to the hedged risk be recognized currently in earnings in the same accounting period. Conversely, the effective portion of the unrealized gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument must be reported as a component of other comprehensive income and be reclassified into earnings in the same period or periods during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, is recognized currently in earnings.
We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty.
Deferred Financing Costs
Deferred financing costs are amortized using the effective interest method over the useful life of the related debt.
Development Costs
According to accounting standards for business combinations, we expense, when incurred, development and acquisition costs associated with corporate development activities prior to acquiring or beginning construction of a project. Expensed development costs are included in Other operating expenses on the accompanying Consolidated Statements of Income.
Legal Costs
Litigation liabilities, including potential settlements, are recorded when it is both probable that a liability or settlement has been incurred, and the amount can be reasonably estimated. Legal costs related to ongoing litigation are expensed as incurred.
Regulatory Accounting
Our Utilities Group follows accounting standards for regulated operations and reflects the effects of the numerous rate-making principles followed by the various state and federal agencies regulating the utilities. The accounting policies followed are generally subject to the Uniform System of Accounts of the FERC. These accounting policies differ in some respects from those used by our non-regulated businesses. If rate recovery becomes unlikely or uncertain due to competition or regulatory action, these accounting standards may no longer apply which would require these net assets to be charged to current income or OCI. Our regulatory assets represent amounts for which we will recover the cost, but are not allowed a return. In the event we determine that our regulated net assets 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, which could be material.
We had the following regulatory assets and liabilities (in thousands):
__________
(a)
Recovery of costs, but not allowed a rate of return.
(b)
In addition to recovery of costs, we are allowed a rate of return.
(c)
In addition to recovery of costs, we are allowed a return on approximately $24.6 million.
(d)
In addition to recovery of costs, we are allowed a return on approximately $5.4 million.
(e)
Approximately $13.2 million is included in our rate base calculations as a reduction to rate base.
(f)
Approximately $2.6 million is included in our rate base calculations as a reduction to rate base.
Regulatory assets represent items we expect to recover from customers through probable future rates.
Deferred Energy and Fuel Cost Adjustments - Deferred energy and fuel cost adjustments represent the cost of electricity delivered to our electric utility customers that is 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.
Deferred Gas Cost Adjustment and Gas Price Derivatives - Our regulated gas utilities have GCA provisions that allow them to pass the cost of gas on to their customers. In addition, as allowed by state utility commissions, we have entered into certain exchange-traded natural gas futures and options to reduce our customers’ underlying exposure to fluctuations in gas prices. Cheyenne Light files monthly with the WPSC a GCA to be included in tariff rates. The GCA is based on forecasts of the upcoming gas costs and recovery or refund of prior under-recovered or over-recovered costs. To the extent that gas costs are under-recovered or over-recovered, they are recorded as a regulatory asset or liability, respectively. Our Gas Utilities file periodic estimates of future gas costs based on market forecasts with state utility commissions.
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, including costs being amortized from the Aquila Transaction.
Environmental - Environmental is associated with manufactured gas plant sites. The amortization of this asset is first offset by recognition of insurance proceeds and settlements with other third parties. Any remaining recovery will be requested in future rate filings. Recovery has not yet been approved by the applicable commission or board and therefore, the recovery period is unknown.
Asset Retirement Obligations - Asset retirement obligations represent the estimated recoverable costs for legal obligations associated with the retirement of a tangible long-lived asset. See Note 10 for additional details.
Bond Issue Costs - Bond issue costs are recovered over the remaining life of the original issue or, if refinanced, over the life of the new issue.
Renewable Energy Standard Adjustment - The renewable energy standard adjustment is associated with incentives for our Colorado Electric customers to install renewable energy equipment at their location. These incentives are recovered over time with an additional rider charged on customers’ bills.
Flow-Through Accounting - Under flow-through accounting, the income tax effects of certain tax items are reflected in our cost of service for the customer in the year in which the tax benefits are realized and result in lower utility rates. This regulatory treatment was applied to the tax benefit generated by repair costs that were previously capitalized for tax purposes in a rate case settlement that was reached with respect to Black Hills Power in 2010. In this instance, the agreed upon rate increase was less than it would have been absent the flow-through treatment. A regulatory asset was established to reflect that 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.
Deferred Energy and Gas Costs - Deferred energy costs and gas costs related to over-recovery in purchased power, transmission and natural gas costs.
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.
Cost of Removal - Cost of removal represents the estimated cumulative net provisions for future removal costs included in depreciation expense for which there is no legal obligation for removal.
Income Taxes
The Company and its subsidiaries file consolidated federal income tax returns. Each tax paying entity records income taxes as if it were a separate taxpayer and consolidating adjustments are allocated to the subsidiaries based on separate company computations of taxable income or loss.
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 carry forwards. 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. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion of the deferred tax asset will not be realized.
It is our policy to apply the flow-through method of accounting for investment tax credits. Under the flow-through method, investment tax credits are reflected in net income as a reduction to income tax expense in the year they qualify. Another acceptable accounting method and an exception to this general policy currently in our regulated businesses is to apply the deferral method whereby the credit is amortized as a reduction of income tax expense over the useful lives of the related property.
We recognize interest income or interest expense and penalties related to income tax matters in Income tax (expense) benefit on the Consolidated 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 deferred credits and other liabilities on the accompanying Consolidated Balance Sheets. See Note 14 for additional information.
Earnings per Share of Common Stock
Basic earnings per share from continuing and discontinued operations is computed by dividing Income (loss) from continuing or discontinued operations by the weighted average number of common shares outstanding during each year. Diluted earnings (loss) per share is computed by including all dilutive common shares outstanding during each year.
A reconciliation of share amounts used to compute earnings (loss) per share is as follows (in thousands):
_______________
*
In November 2011, we issued shares in conjunction with the settlement of an equity forward agreement. See Note 11 for further information.
The following outstanding securities were not included in the computation of diluted earnings per share as their effect would have been anti-dilutive (in thousands):
Discontinued Operations
Assets of discontinued operations are recorded at the lower of their carrying amount or fair value less cost to sell. Additionally, in accordance with GAAP, indirect corporate costs previously allocated to a disposal group cannot be reclassified to discontinued operations. Assets of discontinued operations and Liabilities of discontinued operations on the accompanying Consolidated Balance Sheets included the assets and liabilities of Enserco Energy Inc. See Note 23 for additional information.
(2) RECENTLY ISSUED AND ADOPTED ACCOUNTING PRONOUNCEMENTS AND LEGISLATION
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 accounting standards for comprehensive income to improve the comparability, consistency and transparency of reporting. 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 2011-05 requires retrospective application, and it is effective for fiscal years, and interim periods within those years, beginning after Dec. 15, 2011, with early adoption permitted. In Dec. 2011, FASB issued ASU 2011-12. ASU 2011-12 indefinitely deferred the provisions of ASU 2011-05 requiring the presentation of reclassification adjustments on the face of the financial statements for items reclassified from other comprehensive income to net income. Ultimately FASB chose not to reinstate the reclassification adjustment requirements in ASU 2011-05 but instead issued ASU 2013-02 in February 2013.
At Dec. 31, 2011, we elected to early adopt the provisions of ASU 2011-05 as amended by ASU 2011-12. The adoption changed our presentation of certain financial statements and provided additional details in notes to the financial statements, but did not have any other impact on our consolidated financial statements. See additional Comprehensive Income Statement and additional disclosures in Note 15.
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 Dec. 31, 2011. The amendment required additional details in notes to financial statements, but did not have any other impact on our consolidated financial statements. The additional disclosures are included in Note 4.
Extractive Activities - Oil and Gas Reserves, ASU 2010-03 (SEC Release #33-8995)
The FASB issued an accounting standards update which aligns the oil and gas reserve estimation and disclosure requirements with the SEC released Final Rule, “Modernization of Oil and Gas Reporting,” which amended the existing Regulation S-K and Regulation S-X reporting requirements to align with current industry practices and technology advances. Key revisions include the ability to include non-traditional resources in reserves, the use of new technology for determining reserves, permitting disclosure of probable and possible reserves, and changes to the oil and gas prices used to determine reserves from the period-end price to a 12-month average price. The average is calculated using the first-day-of-the-month price for each of the 12 months before the end of the reporting period. The amendment was effective for reporting periods ending on or after Dec. 31, 2009. The implementation of this SEC requirement resulted in additional depletion expense of $1.3 million in the fourth quarter of 2010.
Dodd-Frank Wall Street Reform and Consumer Protection Act, SEC Final Rule No. 33-9286, 33-9338, and 34-67717
In July 2010, the President of the United States signed into law comprehensive financial reform legislation under Dodd-Frank. Title VII of Dodd-Frank effectively regulates many derivative transactions in the United States that were previously unregulated. As a result of Dodd-Frank regulations promulgated by the CFTC, we may be required to post collateral to clearing entities for certain swap transactions we enter into. In addition, many of the transactions which were previously classified as swaps have been converted to exchange-traded futures contracts, which are subject to futures margin posting requirements. The adoption of this rule did not have an impact on our financial position, results of operations or cash flows.
In August 2012, the SEC approved a final rule implementing Section 1504 of Dodd-Frank. The rule requires issuers engaged in the commercial development of oil, natural gas or minerals to disclose cash payments made to a foreign government or the Federal government of the United States. We are in the process of evaluating our reporting requirements with the first filing due in 2013. The adoption of this rule will not have an impact on our financial position, results of operations or cash flows.
In December 2011, the SEC issued Final Rule 33-9286 providing requirements for Section 1503 of Dodd-Frank. This release requires issuers that are operators of a coal mine to disclose information concerning mine safety violations or other regulatory matters. The required information for our WRDC coal mine is included in Exhibit 95 of this Form 10-K.
Significant rule-making by numerous governmental agencies, particularly the CFTC with respect to non-security commodities, will be required in order to implement the restrictions, limitations, and requirements contemplated by Dodd-Frank. We will continue to evaluate the impact of additional rules as they become available.
Intangibles - Goodwill and Other: Testing Goodwill for Impairment, ASU 2011-08
In September 2011, the FASB issued an amendment to ASC 350, Intangibles - Goodwill and Other, to provide an option to perform a qualitative assessment to determine whether further impairment testing on goodwill is necessary. Specifically, an entity has the option to first assess qualitative factors to determine whether it is necessary to perform the current two-step test. If an entity believes, as a result of its qualitative assessment, that it is more-likely-than-not that the fair value of a reporting unit is less than its carrying amount, the quantitative impairment test is required. Otherwise, no further testing is required. This standard is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after Dec. 15, 2011. The adoption of this standard did not have a material impact on our consolidated financial statements.
Intangible - Goodwill and Other: Testing Indefinite Lived Intangible Assets for Impairment, ASU 2012-02
In July 2012, the FASB issued an amendment to ASC 350, Intangibles - Goodwill and Other, to provide an option to perform a qualitative assessment to determine whether further impairment testing of indefinite lived intangible assets is necessary. This ASU aligns the impairment testing for intangible assets with that of goodwill as amended by ASU 2011-08. This guidance is effective for interim and annual periods beginning after Sept. 15, 2012, with early adoption permitted. The adoption of this standard will not have an impact on our financial position, results of operations or cash flows.
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.
Balance Sheet: Disclosure about Offsetting Assets and Liabilities, ASU 2011-11
In December 2011, the FASB issued revised accounting guidance to amend ASC 210, Balance Sheet, related to the existing disclosure requirements for offsetting financial assets and liabilities to enhance current disclosures, as well as to improve comparability of balance sheets prepared under GAAP and IFRS. The revised disclosure guidance affects all companies that have financial instruments and derivative instruments that are either offset in the balance sheet (i.e., presented on a net basis) or subject to an enforceable master netting and/or similar arrangement. In addition, the revised guidance requires that certain enhanced quantitative and qualitative disclosures are made with respect to a company’s netting arrangements and/or rights of offset associated with its financial instruments and/or derivative instruments. The revised disclosure guidance is effective on a retrospective basis for interim and annual periods beginning Jan. 1, 2013. The adoption of this standard will not have an impact on our financial position, results of operations or cash flows.
(3) RISK MANAGEMENT ACTIVITIES
Our activities in the regulated and non-regulated energy sectors expose us to a number of risks in the normal operations of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and credit risk. To manage and mitigate these identified risks, we have adopted the Black Hills Corporation Risk Policies and Procedures. Valuation methodologies for our derivatives are detailed within Note 1.
Market Risk
Market risk is the potential loss that may occur as a result of an adverse change in market price or rate. We are exposed to the following market risks, including, but not limited to:
•
Commodity price risk associated with our natural long position with crude oil and natural gas reserves and production, fuel procurement for certain of our gas-fired generation assets and variability in revenue due to changes in gas usage at our regulated Electric Utilities and Gas Utilities segments resulting from commodity price changes; and
•
Interest rate risk associated with our variable rate credit facility, project financing floating rate debt and our other long-term debt instruments.
Credit Risk
Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty.
For production and generation activities, we attempt to mitigate our credit exposure by conducting business primarily with high credit quality entities, setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements, and mitigating credit exposure with less creditworthy counterparties through parental guarantees, prepayments, letters of credit, and other security agreements.
We perform ongoing credit evaluations of our customers and adjust credit limits based upon payment history and the customer’s current creditworthiness, as determined by review of their current credit information. We maintain a provision for estimated credit losses based upon historical experience and any specific customer collection issue that is identified.
As of Dec. 31, 2012, our credit exposure included a $7.6 million exposure to a non-investment grade energy marketing company. The remainder of our credit exposure was concentrated primarily among retail utility customers, investment grade companies, cooperative utilities and federal agencies. Our derivative and hedging activities included in the accompanying Consolidated Balance Sheets, Consolidated Statements of Income and Consolidated Statements of Comprehensive Income (Loss) are detailed below and within Note 4.
Oil and Gas Exploration and Production
We produce natural gas and crude oil through our exploration and production activities. Our natural "long" positions, or unhedged open positions, introduce commodity price risk and variability in our cash flows. We employ risk management methods to mitigate this commodity price risk and preserve cash flows, and we have adopted guidelines covering hedging for our natural gas and crude oil production. These guidelines have been approved by our Executive Risk Committee and the Board of Directors, and are routinely reviewed by the Audit Committee of our Board of Directors.
To mitigate commodity price risk and preserve cash flows, we primarily use over-the-counter swaps, exchange traded futures and related options to hedge portions of our crude oil and natural gas production. We elect hedge accounting on these instruments. These transactions were designated at inception as cash flow hedges, documented under accounting standards for derivatives and hedging, and initially met prospective effectiveness testing. Effectiveness of our hedging position is evaluated at least quarterly.
The derivatives were marked to fair value and were recorded as Derivative assets or Derivative liabilities on the accompanying Consolidated Balance Sheets. The effective portion of the gain or loss on these derivatives for which we have elected cash flow hedge accounting is reported in Accumulated other comprehensive income (loss) on the accompanying Consolidated Balance Sheets and the ineffective portion, if any, is reported in Revenue on the accompanying Consolidated Statements of Income.
We had the following derivatives and related balances for our Oil and Gas segment (dollars in thousands) as of:
________________________
(a)
Crude in Bbls, gas in MMBtu.
(b)
Refers to the term of the derivative instrument. Assets and liabilities are classified as current/non-current based on the timing of the hedged transaction and the corresponding settlement of the derivative instrument.
(c)
Represents the amortization of put premiums.
Based on Dec. 31, 2012 market prices, a $2.1 million gain would be reclassified from AOCI during 2013. Estimated and actual realized gains or losses will change during future periods as market prices fluctuate.
Utilities
Our utility customers are exposed to the effect of volatile natural gas prices; therefore, as allowed or required by state utility commissions, we have entered into commission approved hedging programs utilizing natural gas futures, options and basis swaps to reduce our customers' underlying exposure to these fluctuations. These transactions are considered derivatives and in accordance with accounting standards for derivatives and hedging, mark-to-market adjustments are recorded as Derivative assets or Derivative liabilities on the accompanying Consolidated Balance Sheets. Unrealized and realized gains and losses, as well as option premiums and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in accordance with state commission guidelines. Accordingly, the hedging activity is recognized in the Consolidated Statements of Income or the Consolidated Statements of Comprehensive Income (Loss) when the related costs are recovered through our rates.
The contract or notional amounts and terms of the natural gas derivative commodity instruments held by our Gas Utilities were as follows, as of:
We had the following derivative balances related to the hedges in our Utilities (in thousands) as of:
Financing Activities
We have entered into floating-to-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations associated with our floating rate debt obligations. Our interest rate swaps and related balances were as follows (dollars in thousands) as of:
___________________
(a)
These swaps have been designated to $75.0 million of borrowings on our Revolving Credit Facility and $75.0 million of borrowings on our project financing debt at Black Hills Wyoming, both of which are priced using three-month LIBOR, matching the floating portion of the related swaps.
(b)
The maximum term in years reflect the amended early termination dates. If the early termination dates are not extended, the swaps will require cash settlement based on the swap value at the termination date. If extended, swaps totaling $100.0 million terminate in 6 years and swaps totaling $150.0 million terminate in 16 years.
Collateral requirements based on our corporate credit rating apply to $50.0 million of our de-designated swaps. At our current credit ratings, we are required to post collateral for any amount by which the swap’s negative mark-to-market fair value exceeds $20.0 million. If our senior unsecured credit rating drops to BB+ or below by S&P, or Ba1 or below by Moody’s, we would be required to post collateral for the entire amount of the swap’s negative mark-to-market fair value. We had $6.0 million cash collateral posted at Dec. 31, 2012.
Based on Dec. 31, 2012 market interest rates and balances related to our designated interest rate swaps, a loss of approximately $7.0 million would be reclassified from AOCI during the next 12 months. Estimated and realized gains or losses will change during future periods as market interest rates change.
(4) 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 the placement within the fair value hierarchy levels.
There have been no significant transfers between Level 1 and Level 2 derivative balances during 2012 or 2011. The following tables set forth, by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis (in thousands):
______________
(a)
Level 1 assets and liabilities are described in Note 5.
The following table presents the quantitative information about level 3 fair value measurements (dollars in thousands):
_____________
(a)
The significant unobservable inputs used in the fair value measurement of the long-term OTC contracts are based on the average of price quotes from an independent third party market participant and the OTC contract broker. The unobservable inputs are long-term natural gas prices. Significant changes to these inputs along with the contract term would impact the derivative asset/liability and regulatory asset/liability, but will not impact the results of operations until the contract is settled under the original terms of the contract. The contracts will be classified as Level 2 once settlement is within 60 months of maturity and quoted market prices from a market exchange are available.
_________
(a)
Level 1 assets and liabilities are described in Note 5.
The following tables present the changes in level 3 recurring fair value (in thousands):
__________
(a)
Transfers into Level 3 would occur when significant inputs used to value the derivative instruments become less observable such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs.
(b)
Transfers out of Level 3 would occur when the significant inputs become more observable such as the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs.
(c)
Previously, we utilized pricing methodologies developed by our Energy Marketing segment to value our Oil and Gas derivatives. Oil and Gas now obtains available observable inputs including quoted prices traded on active exchanges from multiple sources to value our options. Therefore, options in the Oil and Gas segment have been reclassified from Level 3 to Level 2.
Fair Value Measures
As required by accounting standards for derivatives and hedging, fair values within the following tables are presented on a gross basis and do not reflect the netting of asset and liability positions permitted in accordance with accounting standards for offsetting and under terms of our master netting agreements. Further, the amounts do not include net cash collateral on deposit in margin accounts at Dec. 31, 2012 and 2011, to collateralize certain financial instruments, which are included in Derivative assets and/or Derivative liabilities. Therefore, the gross balances are not indicative of either our actual credit exposure or net economic exposure. Additionally, the amounts below will not agree with the amounts presented on our Consolidated Balance Sheets, nor will they correspond to the fair value measurements presented in Note 3.
The following tables present the fair value and balance sheet classification of our derivative instruments as of Dec. 31. exclusive of cash collateral (in thousands):
A description of our derivative activities is discussed in Note 3. The following tables present the impact that derivatives had on our Consolidated Statements of Income.
Cash Flow Hedges
The impact of cash flow hedges on our Consolidated Statements of Income and Balance Sheets for the years ended are presented as follows (in thousands):
Derivatives Not Designated as Hedge Instruments
The impact of derivative instruments that have not been designated as hedging instruments on our Consolidated Statements of Income for the years ended Dec. 31 was as follows (in thousands):
(5) FAIR VALUE OF FINANCIAL INSTRUMENTS
The estimated fair values of our financial instruments at Dec. 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.
Cash and Cash Equivalents
Included in cash and cash equivalents is cash, overnight repurchase agreement accounts, money market funds and term deposits. 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.
Restricted Cash and Equivalents
Restricted cash and cash equivalents represent restricted cash and uninsured term deposits.
Notes Payable
Notes Payable represent our short-term corporate term loan and borrowings under our Revolving Credit Facility.
Long-Term Debt
For additional information on our long-term debt, see Note 8.
(6) PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment at Dec. 31 consisted of the following (dollars in thousands):
_____________
(a)
Capital lease - plant in service represents the assets accounted for as a capital lease under the 20-year PPA between Colorado Electric and Black Hills Colorado IPP.
___________
(a) Accumulated depreciation, depletion and amortization at Corporate reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Colorado IPP.
(7) JOINTLY OWNED FACILITIES
Oil and Gas
BHEP owns a 44.7 percent non-operating interest in a natural gas processing facility (the Newcastle Gas Plant). The Newcastle Gas Plant gathers and processes gas, primarily from the Finn-Shurley Field in Wyoming. We receive our proportionate share of the Newcastle Gas Plant’s net revenues and are committed to pay our proportionate share of additions, replacements and operating and maintenance expenses. Each of the respective owners is responsible for providing its own financing. As of Dec. 31, 2012, our investment in the Newcastle Gas Plant included $4.4 million in plant and equipment which is included in Property, plant and equipment on the accompanying Consolidated Balance Sheets. This asset is included in the asset pool being depleted and therefore accumulated depreciation is not separated by asset. Our share of direct expenses is included in the corresponding categories of revenue and expenses in the accompanying Consolidated Statements of Income.
Utility Plant
•
Black Hills Power owns a 20 percent interest in the Wyodak Plant, a coal-fired electric generating station located in Campbell County, Wyoming. PacifiCorp owns the remaining ownership percentage and operates the Wyodak Plant. Black Hills Power receives its proportionate share of the Wyodak Plant’s capacity and is committed to pay its proportionate share of its additions, replacements and operating and maintenance expenses. In addition to supplying Black Hills Power with coal for its share of the Wyodak Plant, our Coal Mining subsidiary, WRDC, supplies PacifiCorp’s share of the coal to the Wyodak Plant under a separate long-term agreement. This coal supply agreement is collateralized by a mortgage on and a security interest in some of WRDC’s coal reserves.
•
Black Hills Power also owns a 35 percent interest in, and is 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 tie is 400 megawatts - 200 megawatts West to East and 200 megawatts from East to West. Black Hills Power is committed to pay its proportionate share of the additions and replacements to and operating and maintenance expenses of the transmission tie.
•
Black Hills Power owns 52 percent of the Wygen III coal-fired generation facility. 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 their proportionate share of the costs of operating the plant for the life of the facility. We retain responsibility for plant operations. Our Coal Mining subsidiary supplies coal to Wygen III for the life of the plant.
•
Colorado Electric owns 50 percent of the Busch Ranch Wind Project while AltaGas owns the remaining undivided ownership interest. We retain responsibility for operations of the wind farm.
Non-Regulated Plants
•
Black Hills Wyoming owns 76.5 percent of the Wygen I plant while MEAN owns the remaining ownership percentage. MEAN is obligated to make payments for their share of the costs associated with administrative services, plant operations and coal supply provided by our Coal Mining subsidiary during the life of the facility. We retain responsibility for plant operations.
Our share of direct expenses for the jointly-owned utility and non-regulated facilities is included in the corresponding categories of operating expenses in the accompanying Consolidated Statements of Income. Each of the respective owners is responsible for providing its own financing.
At Dec. 31, 2012, our interests in jointly-owned generating facilities and transmission systems were (in thousands):
(8) LONG-TERM DEBT
Long-term debt outstanding was as follows (dollars in thousands) as of:
_______________
(a)
On Oct. 31, 2012, we redeemed these senior unsecured notes. See discussion below.
(b)
Variable interest rates; rates presented are as of Dec. 31, 2012.
(c)
If our senior unsecured credit rating should drop below investment grade, then pricing under our credit agreements would be affected, increasing annual interest expense by approximately $1.0 million pre-tax based on our Dec. 31, 2012 debt balances.
(d)
On May 15, 2012, Black Hills Power repaid these Pollution Control Refund Revenue Bonds. See discussion below.
Scheduled maturities of long-term debt, excluding amortization of premiums or discounts, for future years are (in thousands):
Our debt securities contain certain restrictive financial covenants, all of which the Company and its subsidiaries were in compliance with at Dec. 31, 2012.
Substantially all of the tangible utility property of Black Hills Power and Cheyenne Light is subject to the lien of indentures securing their first mortgage bonds. First mortgage bonds of Black Hills Power and Cheyenne Light may be issued in amounts limited by property, earnings and other provisions of the mortgage indentures. The first mortgage bonds issued by Black Hills Power and Cheyenne Light are either currently not callable or are subject to make-whole provisions which would eliminate any economic benefit for us to call the bonds.
Early Redemption of Long-term Debt
On Oct. 31, 2012, we redeemed $225.0 million of senior unsecured 6.5 percent notes, which were originally scheduled to mature on May 15, 2013 for $238.8 million. The payment included accrued interest and a make-whole provision of $7.1 million included in Interest expense on the accompanying Consolidated Statements of Income.
On May 15, 2012, Black Hills Power repaid its 4.8 percent Pollution Control Revenue Bonds in full for $6.5 million principal and interest. These bonds were originally due to mature on Oct. 1, 2014.
Loan Extensions
Our $100.0 million term loan (the “Loan”) with J.P. Morgan and Union Bank was extended through Sept. 30, 2013. The cost of borrowings under the Loan was based on a spread of 1.375 percent over LIBOR (1.63 percent at Dec. 31, 2012). The covenants are substantially the same as the Revolving Credit Facility.
Amortization Expense
Our deferred financing costs and associated amortization expense included in Interest expense on the accompanying Consolidated Statements of Income were as follows (in thousands):
(9) NOTES PAYABLE
Our Revolving Credit Facility and debt securities contain certain restrictive financial covenants. As of Dec. 31, 2012, we were in compliance with all of these covenants.
We had the following short-term debt outstanding at the Consolidated Balance Sheet dates (in thousands):
__________
(a)
In June 2012, this short-term loan was extended for one year. See discussion below.
Revolving Credit Facility
On Feb. 1, 2012, we entered into a new $500 million Revolving Credit Facility expiring Feb. 1, 2017. The facility contains an accordion feature allowing us, with the consent of the administrative agent, to increase the capacity of the facility to $750 million. The Revolving Credit Facility can be used for the issuance of letters of credit, to fund working capital needs and for other corporate purposes. Borrowings are available under a base rate option or a Eurodollar option. The cost of borrowings or letters of credit is determined based upon our credit ratings. At current credit ratings, the margins for base rate borrowings, Eurodollar borrowings and letters of credit were 0.50 percent, 1.50 percent and 1.50 percent, respectively, at Dec. 31, 2012. The facility contains a commitment fee that is charged on the unused amount of the Revolving Credit Facility. Based upon current credit ratings, the fee is 0.25 percent.
Deferred financing costs on the new facility of $2.8 million are being amortized over the estimated useful life of the Revolving Credit Facility and included in Interest expense on the accompanying Consolidated Statements of Income. Upon entering into the Revolving Credit Facility, $1.5 million of deferred financing costs relating to the previous credit facility were written off through Interest expense. The deferred financing costs on the new facility are being amortized as follows (in thousands):
Corporate Term Loans
In June 2012, we extended our one-year $150.0 million unsecured, single draw term loan until June 24, 2013. The cost of borrowing under the extended loan is based on a spread of 1.10 percent over LIBOR (1.35 percent at Dec. 31, 2012). The covenants are substantially the same as those included in the Revolving Credit Facility with an additional requirement to maintain a minimum consolidated net worth. We were in compliance with these covenants as of Dec. 31, 2012.
Debt Covenants
Certain debt obligations require compliance with the following covenants at the end of each quarter (dollars in thousands):
(10) ASSET RETIREMENT OBLIGATIONS
We have identified legal retirement obligations related to plugging and abandonment of natural gas and oil wells in the Oil and Gas segment, reclamation of coal mining sites at the Coal Mining segment and removal of fuel tanks, asbestos, transformers containing polychlorinated biphenyls, an evaporation pond and wind turbines at the regulated Electric Utilities segment and asbestos at our regulated Gas Utilities segment. We periodically review and update estimated costs related to these asset retirement obligations. The actual cost may vary from estimates because of regulatory requirements, changes in technology, and increased costs of labor, materials and equipment.
The following tables present the details of ARO which are included on the accompanying Consolidated Balance Sheets in Other deferred credits and other liabilities (in thousands):
_____________________
(a)
The Revisions to Prior Estimates reflects the change in the estimated liability for final reclamation adjusted for inflation, discount rate and market risk premium.
We also have legally required AROs related to certain assets within our electric and gas utility transmission and distribution systems. These retirement obligations are pursuant to an easement or franchise agreement and are only required if we discontinue our utility service under such easement or franchise agreement. Accordingly, it is not possible to estimate a time period when these obligations could be settled and therefore, a value for the cost of these obligations cannot be measured at this time.
(11) COMMON STOCK
Equity Issuance
On Nov. 10, 2010, we entered into an Equity Forward Agreement with J.P. Morgan in connection with a public offering of 4,000,000 shares of Black Hills Corporation common stock. Subsequently, the underwriters exercised the over-allotment option to purchase 413,519 additional shares under the same terms as the original Forward Equity Agreement. We settled the equity forward instrument on Nov. 1, 2011 by physically delivering 4,413,519 shares of common stock in return for proceeds of $119.6 million.
Equity Compensation Plans
Our 2005 Omnibus Incentive Plan allows for the granting of stock, restricted stock, restricted stock units, stock options and performance shares. We had 863,929 shares available to grant at Dec. 31, 2012.
Compensation expense is determined using the grant date fair value estimated in accordance with the provisions of accounting standards for stock compensation and is recognized over the vesting periods of the individual awards. As of Dec. 31, 2012, total unrecognized compensation expense related to non-vested stock awards was $7.8 million and is expected to be recognized over a weighted-average period of 1.9 years. Stock-based compensation expense included in Operations and maintenance on the accompanying Consolidated Statements of Income was as follow (in thousands):
Stock Options
We have granted options with an option exercise price equal to the fair market value of the stock on the day of the grant. The options granted vest proportionately over 3 years and expire 10 years after the grant date.
A summary of the status of the stock options at Dec. 31, 2012 was as follows:
The table below provides details of our option plans at Dec. 31 (in thousands):
_____________________
(a)
The intrinsic value represents the amount by which the market price of the stock on the date of exercise exceeded the exercise price of the option.
(b)
The tax benefit realized from the exercise of shares granted was recorded as an increase in equity.
As of December 31, 2012, the unrecognized compensation expense related to non-vested stock options is expected to be recognized over a weighted-average period of 1.4 years.
Restricted Stock and Restricted Stock Units
The fair value of restricted stock and restricted stock unit awards equals the market price of our stock on the date of grant.
The shares carry a restriction on the ability to sell the shares until the shares vest. The shares substantially vest over 3 years, contingent on continued employment. Compensation expense related to the awards is recognized over the vesting period.
A summary of the status of the restricted stock and non-vested restricted stock units at Dec. 31, 2012 was as follows:
The weighted-average grant-date fair value of restricted stock and restricted stock units granted and the total fair value of shares vested during the years ended Dec. 31 was as follows:
As of Dec. 31, 2012, there was $5.2 million of unrecognized compensation expense related to non-vested restricted stock that is expected to be recognized over a weighted-average period of 2.0 years.
Performance Share Plan
Certain officers of the Company and its subsidiaries are participants in a performance share award plan, a market-based plan. Performance shares are awarded based on our total shareholder return over designated performance periods as measured against a selected peer group. In addition, certain stock price performance must be achieved for a payout to occur. The final value of the performance shares will vary according to the number of shares of common stock that are ultimately granted based upon the actual level of attainment of the performance criteria.
The performance awards are paid 50 percent in cash and 50 percent in common stock. The cash portion accrued is classified as a liability and the stock portion is classified as equity. In the event of a change-in-control, performance awards are paid 100 percent in cash. If it is determined that a change-in-control is probable, the equity portion of $1.7 million at Dec. 31, 2012 would be reclassified as a liability.
Outstanding performance periods at Dec. 31 were as follows (shares in thousands):
A summary of the status of the Performance Share Plan at Dec. 31 was as follows:
The grant date fair values for the performance shares granted in 2012, 2011 and 2010 were determined by Monte Carlo simulation using a blended volatility of 21 percent, 30 percent and 31 percent, respectively, comprised of 50 percent historical volatility and 50 percent implied volatility and the average risk-free interest rate of the three-year United States Treasury security rate in effect as of the grant date.
The weighted-average grant-date fair value of performance share awards granted in the years ended was as follows:
Performance plan payouts have been as follows (dollars and shares in thousands):
On Jan. 30, 2013, the Compensation Committee of our Board of Directors determined that the company’s total shareholder return for the Jan. 1, 2010 through Dec. 31, 2012 performance period was at the 78th percentile of its peer group and confirmed a payout equal to 170.75 percent of target shares, valued at $4.5 million. The payout was fully accrued at Dec. 31, 2012.
As of Dec. 31, 2012, there was $2.4 million of unrecognized compensation expense related to outstanding performance share plans that is expected to be recognized over a weighted-average period of 1.7 years.
Dividend Reinvestment and Stock Purchase Plan
We have a DRIP under which shareholders may purchase additional shares of common stock through dividend reinvestment and/or optional cash payments at 100 percent of the recent average market price. We have the option of issuing new shares or purchasing the shares on the open market. We are currently issuing new shares.
A summary of the Dividend Reinvestment and Stock Purchase Plan for the years ended and at Dec. 31, is as follows (shares in thousands):
Dividend Restrictions
Our credit facility and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. As of Dec. 31, 2012, we were in compliance with these covenants.
Due to our holding company structure, substantially all of our operating cash flows are provided by dividends paid or distributions made by our subsidiaries. The cash to pay dividends to our shareholders is derived from these cash flows. As a result, certain statutory limitations or regulatory or financing agreements could affect the levels of distributions allowed to be made by our subsidiaries. The following restrictions on distributions from our subsidiaries existed at Dec. 31, 2012:
•
Our utilities are generally limited to the amount of dividends allowed to be paid to our utility holding company under the Federal Power Act and settlement agreements with state regulatory jurisdictions. As of Dec. 31, 2012, the restricted net assets at our Utilities Group were approximately $263.1 million.
•
As required by the covenant in the Black Hills Wyoming project financing, Black Hills Non-regulated Holdings has maintained restricted shareholders’ equity of at least $100.0 million.
(12) IMPAIRMENT OF LONG-LIVED ASSETS
Under the full cost method of accounting used by our Oil and Gas segment to account for exploration, development, and acquisition of crude oil and natural gas reserves, all costs attributable to these activities are capitalized. These capitalized costs, less accumulated amortization and related deferred income taxes, are subject to a ceiling test that limits the pooled costs to the aggregate of the discounted value of future net revenue attributable to proved natural gas and crude oil reserves using a discount rate defined by the SEC plus the lower of cost or market value of unevaluated properties. Any costs in excess of the ceiling are written off as a non-cash charge.
As a result of continued low commodity prices in the second quarter of 2012, we recorded a $26.9 million non-cash impairment of oil and gas assets included in the Oil and Gas segment. In determining the ceiling value of our assets, we utilized the average of the quoted prices from the first day of each month from the previous 12 months. For natural gas, the average NYMEX price was $3.15 per Mcf, adjusted to $2.66 per Mcf at the wellhead; for crude oil, the average NYMEX price was $95.67 per barrel, adjusted to $85.36 per barrel at the wellhead.
(13) OPERATING LEASES
We have entered into lease agreements for vehicles, equipment and office facilities. Rental expense incurred under these operating leases, including month to month leases, for the years ended Dec. 31 was as follows (in thousands):
The following is a schedule of future minimum payments required under the operating lease agreements (in thousands):
(14) INCOME TAXES
Income tax expense (benefit) from continuing operations for the years ended Dec. 31 was (in thousands):
The temporary differences, which gave rise to the net deferred tax liability, for the years ended Dec. 31, were as follows (in thousands):
The effective tax rate differs from the federal statutory rate for the years ended Dec. 31, as follows:
_________________________
(a)
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.
At Dec. 31, 2012, we had federal and state NOL carryforwards of $425.8 million and $475.6 million, respectively, which will expire at various dates as follows (in thousands):
As of Dec. 31, 2012, we had a $2.2 million valuation allowance against the state NOL carryforwards. The re-evaluation of our ability to utilize such NOLs resulted in an increase of the valuation allowance of approximately $1.4 million and an increase to tax expense. The valuation allowance adjustment was primarily attributable to an increase in the NOL generated, as trued up with the filing of the 2011 tax return, in certain states whose carryforward period is much shorter than what is allowed for federal income tax purposes. Ultimate usage of these NOLs depends upon our future tax filings. If the valuation allowance is adjusted due to higher or lower than anticipated utilization of the NOLs, the offsetting amount will affect tax expense.
The following table reconciles the total amounts of unrecognized tax benefits, without interest, at the beginning and end of the period included in Other deferred credits and other liabilities on the accompanying Consolidated Balance Sheets (in thousands):
The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $1.5 million.
We recognized the following interest expense for the years ended Dec. 31 as follows (in thousands):
We had approximately $8.3 million pre-tax and $6.9 million pre-tax of accrued interest associated with income taxes at December 31, 2012 and 2011, respectively.
We file income tax returns with the IRS, various state jurisdictions and Canada. We are currently under examination by the IRS for the 2007, 2008 and 2009 tax years and by the state of Colorado for tax years 2001 through 2009. We remain subject to examination by Canadian income tax authorities for tax years as early as 1999.
We have deferred a substantial amount of tax payments through various tax planning strategies including the deferral of approximately $125.0 million in income taxes attributable to the like-kind exchange effectuated in connection with the IPP Transaction and Aquila Transaction that occurred in 2008. The IRS has challenged our position with respect to the like-kind exchange and it is reasonably possible that the total unrecognized tax benefits attributable to such transaction could change significantly due to a settlement with the IRS prior to Dec. 31, 2013. However, based on the information currently available, it is difficult to determine any reasonable estimate of the financial statement impact including the impact on the effective tax rate.
Excess foreign tax credits have been generated and are available to offset United States federal income taxes. At Dec. 31, 2012, we had remaining foreign tax credit carryforwards of approximately $2.3 million, which break down as follows (in thousands):
As of Dec. 31, 2012, we had a $0.5 million valuation allowance against the foreign tax credit carryforwards. The re-evaluation of our ability to utilize such credits resulted in the establishment of a valuation allowance and an increase to tax expense. Utilization of the foreign tax credit carryforward balance is expected to be included as computational adjustments upon finalization of our current IRS examination covering tax years 2007 to 2009. Due to the expectation that the IRS examination will come to a conclusion within the next twelve months, the balance was reclassified to current tax assets and netted against current tax liability. In addition, approximately $1.8 million of foreign tax credit carryforward is reflected as an offset to liabilities for unrecognized tax benefits in recognition of the estimated impact the resolution of material uncertain tax positions could have with respect to utilization of such carryforward.
State tax credits have been generated and are available to offset future state income taxes. At Dec. 31, 2012, we had the following state tax credit carryforwards (in thousands):
As of Dec. 31, 2012, we had a $3.4 million valuation allowance against the state tax credit carryforwards. Ultimate usage of these credits depends upon our future tax filings. If the valuation allowance is adjusted due to higher or lower than anticipated utilization of the state tax credit carryforwards, the offsetting amount will affect tax expense.
(15) ACCUMULATED OTHER COMPREHENSIVE INCOME
Balances by classification included within Accumulated other comprehensive loss on the accompanying Consolidated Balance Sheets were as follows (in thousands):
____________
* Includes cash flow hedges of equity method investee related to the Idaho Cogeneration Facilities.
(16) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
(17) BUSINESS SEGMENTS INFORMATION
Our reportable segments are based on our method of internal reporting, which generally segregates the strategic business groups due to differences in products, services and regulation. All of our operations and assets are located within the United States.
On Feb. 29, 2012, we sold our Energy Marketing segment, Enserco, which resulted in this segment being reclassified as discontinued operations. For comparative purposes, all prior periods presented have been restated to reflect the reclassification of this segment as discontinued operations. Indirect corporate costs and inter-segment interest expense related to Enserco that have not been classified as discontinued operations have been reclassified to our Corporate segment. For further information see Note 23.
Segment information was as follows (in thousands):
__________________
(a)
The PPA under which the new generation facility was constructed at our Pueblo Airport Generation site by Black Hills Colorado IPP to support Colorado Electric customers is accounted for as a capital lease. Therefore, commencing Dec. 31, 2011, assets previously recorded at Power Generation are now accounted for at Colorado Electric under accounting for a capital lease.
(b)
Deferred taxes that were not classified as discontinued operations are now included in the Corporate segment in 2011.
(c)
See Note 23 for further information relating to discontinued operations.
_________________
(a)
Includes accruals for property, plant and equipment.
_______________
(a)
The PPA under which the new generation facility was constructed at our Pueblo Airport Generation site by Black Hills Colorado IPP to support Colorado Electric customers is accounted for as a capital lease. Therefore, commencing Dec. 31, 2011, assets previously recorded at Power Generation are now accounted for at Colorado Electric under accounting for a capital lease.
________________
(a)
Oil and Gas includes gain on sale of the Williston Basin assets (see Note 22).
(b)
Oil and Gas includes a ceiling test impairment (see Note 12).
(c)
Corporate includes a make-whole provision from early repayment of long-term debt (see Note 8).
_________________
(a)
Electric Utilities includes gain on sale of assets to a related party which was eliminated in consolidation.
______________________
(a)
Electric Utilities includes gain on sale to the City of Gillette of an ownership interest in the Wygen III power generation facility. Gas Utilities includes a gain on the sale of operating assets at Nebraska Gas (see Note 22).
(18) EMPLOYEE BENEFIT PLANS
Defined Contribution Plans
We sponsor a 401(k) retirement savings plan (the 401(k) Plan). Participants in the 401(k) Plan may elect to invest a portion of their eligible compensation to the 401(k) Plan up to the maximum amounts established by the IRS. The 401(k) Plan provides employees the opportunity to invest up to 50 percent of their eligible compensation on a pre-tax or after-tax basis. The 401(k) Plan provides a Company Matching Contribution for all eligible participants and for certain eligible participants a Company Retirement Contribution based on the participant’s age and years of service. Vesting of all Company contributions ranges from immediate vesting to graduated vesting at 20 percent per year with 100 percent vesting when the participant has 5 years of service with the Company.
Funded Status of Benefit Plans
The funded status of postretirement benefit plans is required to be recognized in the statement of financial position. The funded status for pension plans is measured as the difference between the projected benefit obligation and the fair value of plan assets. The funded status for all other benefit plans is measured as the difference between the accumulated benefit obligation and the fair value of plan assets. A liability is recorded for an amount by which the benefit obligation exceeds the fair value of plan assets or an asset is recorded for any amount by which the fair value of plan assets exceeds the benefit obligation. Except for our regulated utilities, the unrecognized net periodic benefit cost is recorded within Accumulated other comprehensive income (loss), net of tax. For our regulated utilities, these costs are recoverable in our rates, and accordingly, the unrecognized net periodic benefit cost was alternatively recorded as a regulatory asset or regulatory liability, net of tax (see Note 1). The measurement date for all plans is Dec. 31. As of Dec. 31, 2012, the funded status of our Defined Benefit Pension Plans was $(94.4) million; the funded status of our Supplemental Non-qualified Defined Benefit Plans was $(34.4) million; and the funded status of our Non-pension Defined Benefit Postretirement Healthcare Plans was $(42.3) million.
Defined Benefit Pension Plans (Pension Plans)
Our BHC Pension Plan covers certain eligible employees of Black Hills Service Company, Black Hills Power, WRDC, BHEP and Cheyenne Light. The Black Hills Utility Holdings, Inc. Pension Plan covers certain eligible employees of Black Hills Energy. The benefits for the Pension Plans are based on year of service and calculations of average earnings during a specific time period prior to retirement. As of Jan. 1, 2012, both Pension Plans have been frozen to new employees and certain employees who did not meet age and service based criteria at the time the Pension Plans were frozen.
In 2011, the Cheyenne Light Pension Plan was amended to freeze the benefits of certain bargaining unit employees. This amendment was effective as of Jan. 1, 2012. Additionally, effective Oct. 1, 2012, the Cheyenne Light Pension Plan was merged into the BHC Pension Plan. The Pension Plan benefits are based on years of service and compensation levels.
On Oct. 29, 2012, our 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 Pension Plans’ beneficiaries. To meet this objective, our pension assets are managed by an outside adviser using a structured portfolio strategy that will provide liquidity to meet the Plans’ benefit payment obligations. The Pension Plans’ 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 percent and 8.75 percent for the 2012 and 2011 plan years, respectively. Our Pension Plan funding policy is in accordance with the federal government’s funding requirements.
Plan Assets
The percentages of total plan asset fair value by investment category for our Pension Plans at Dec. 31 were as follows:
Supplemental Non-qualified Defined Benefit Plans
We have various supplemental retirement plans for key executives of the Company. The plans are non-qualified defined benefit and defined contribution plans (Supplemental Plans). The Supplemental Plans are subject to various vesting schedules and are not funded by the Company.
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 Plans
We sponsor three retiree healthcare plans (Healthcare Plans) for employees who meet certain age and service requirements at retirement. Healthcare Plan benefits are subject to premiums, deductibles, co-payment provisions and other limitations. We may amend or change the Healthcare Plans periodically. A portion of the Healthcare Plans is pre-funded via VEBAs. We have determined that the post-65 retiree prescription drug plans are actuarially equivalent and qualify for the Medicare Part D subsidy.
Plan Assets
We fund the Healthcare Plans on a cash basis as benefits are paid. The Black Hills Energy Plan provides for partial pre-funding via VEBAs. Assets related to this pre-funding are held in trust and are for the benefit of the union and non-union employees of Black Hills Energy located in the states of Kansas and Iowa. We do not pre-fund the Postretirement Healthcare Plans for those employees outside Kansas and Iowa.
Plan Contributions
Contributions 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 Dec. 31 were as follows (in thousands):
While we do not have required contributions, we expect to make approximately $8.8 million in contributions to our Pension Plans in 2013.
Fair Value Measurements
As required by accounting standards for Compensation - Retirement Benefits, assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s 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 (in thousands):
The following table sets forth a summary of changes in the fair value of the Defined Benefit Pension Plans’ level 3 assets for the period ended Dec. 31 (in thousands):
The following table presents the quantitative information about level 3 fair value measurements (dollars in thousands):
_____________
(a)
The underlying net asset value in the Common Collective Trust - Real Estate fund is determined by appraisal of the properties held in the Trust. As part of the Trustee's valuation process, properties are externally appraised generally on an annual basis. The appraisals are conducted by reputable independent appraisal firms and signed by appraisers that are members of the Appraisal Institute, with the professional designation of Member, Appraisal Institute. All external appraisals are performed in accordance with the Uniform Standards of Professional Appraisal Practices. We receive monthly statements from the Trustee along with the annual schedule of investments and rely on these reports for pricing the units of the fund. The fund does contain a participant withdrawal policy.
Additional information about assets of the Pension Plans, including methods and assumptions used to estimate the fair value of these assets, is as follows:
Registered Investment Companies: Investments are valued at the closing price reported on the active market on which the individual securities are traded.
103-12 Investment Entities: The trustee determines the value of the pooled trust fund and the units thereof in U.S. Dollars as of (i) each daily valuation date, and (ii) each other day designated by mutual agreement between the trustee and the investment manager. As of each valuation date, the trustee shall determine the total value of the assets of the pooled trust fund, including the value of any interest accrued or dividends payable with respect thereto, shall be determined and securities valued as of the close of business in the applicable trading market coinciding with or next preceding the close of business on the New York Stock Exchange.
Common Collective Trust: The Pension Plans own 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 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.
Other Plan Information
The following tables provide a reconciliation of the employee benefit plan obligations, fair value of assets and amounts recognized in the statement of financial position, components of the net periodic expense and elements of accumulated other comprehensive income (in thousands):
Benefit Obligations
A reconciliation of the fair value of Plan assets was as follows (in thousands):
____________________
(a)
Asset of VEBA
Amounts recognized in the Consolidated Balance Sheets at Dec. 31 consist of (in thousands):
Accumulated Benefit Obligation
Components of Net Periodic Expense
Accumulated Other Comprehensive Income
In accordance with accounting standards for defined benefit plans, amounts included in Accumulated other comprehensive income (loss), after-tax, that have not yet been recognized as components of net periodic benefit cost at Dec. 31 were as follows (in thousands):
The amounts in Accumulated other comprehensive income (loss), Regulatory assets or Regulatory liabilities, after-tax, expected to be recognized as a component of net periodic benefit cost during calendar year 2013 are as follows (in thousands):
Assumptions
_____________________________
(a)
The expected rate of return on plan assets is 7.25 percent for the calculation of the 2013 net periodic pension cost.
The healthcare benefit obligation was determined at Dec. 31 as follows:
We do not pre-fund our non-qualified pension plans or two of the three postretirement benefit plans. The table below shows the expected impacts of an increase or decrease to our healthcare trend rate for our Retiree Healthcare Plans (in thousands):
The following benefit payments, which reflect future service, are expected to be paid (in thousands):
(19) COMMITMENTS AND CONTINGENCIES
Power Purchase and Transmission Services Agreements
Through our subsidiaries, we have the following significant long-term power purchase contracts with non-affiliated third-parties:
•
Black Hills Power’s PPA with PacifiCorp, expiring Dec. 31, 2023, for the purchase of 50 megawatts of electric capacity and energy from PacifiCorp’s system. The price paid for the capacity and energy is based on the operating costs of one of PacifiCorp’s coal-fired electric generating plants.
•
Black Hills Power has a firm point-to-point transmission service agreement with PacifiCorp that expires December 31, 2023. The agreement provides 50 megawatts of capacity and energy to be transmitted annually by PacifiCorp.
•
Cheyenne Light’s PPA with Duke Energy’s Happy Jack wind site, expiring Sept. 3, 2028, provides up to 30 megawatts of wind energy from Happy Jack to Cheyenne Light. Under a separate inter-company agreement, Cheyenne Light sells 50 percent of the facility output to Black Hills Power.
•
Cheyenne Light’s PPA with Duke Energy’s Silver Sage wind site, expiring Sept. 30, 2029, provides up to 30 megawatts of wind energy. Under a separate inter-company agreement, Cheyenne Light has agreed to sell 20 megawatts of energy from Silver Sage to Black Hills Power.
•
Colorado Electric’s PPA with Cargill expiring Dec. 31, 2013, whereby Colorado Electric purchases 50 megawatts of economy energy.
•
Colorado Electric’s REPA with AltaGas expiring Oct. 16, 2037, provides up to 14.5 megawatts of wind energy from the Busch Ranch Wind Project in which Colorado Electric owns a 50 percent undivided ownership interest.
•
Cheyenne Light has an agreement with Basin Electric whereby Cheyenne Light will receive 40 megawatts of capacity and energy from Basin Electric through March 13, 2013. The agreement became effective March 14, 2011.
Costs under these power purchase contracts for the years ended Dec. 31 were as follows (in thousands):
_______________________
(a)
This PPA with PSCo expired on Dec. 31, 2011 and was replaced with the facilities constructed by Colorado Electric and Black Hills Colorado IPP at our Pueblo Airport Generation site. The facilities constructed by Black Hills Colorado IPP were to support an inter-company PPA with Colorado Electric. This inter-company PPA is being accounted for as a capital lease.
Other Supply Agreements
Our Gas Utilities also purchase natural gas, including transportation capacity to meet customers’ needs, under short-term and long-term purchase contracts. These contracts extend to 2017.
Construction Obligations
We have purchase obligations related to Cheyenne Prairie construction. Our total obligations under these contracts were approximately $31 million, as of Dec. 31, 2012 which are expected to be paid in 2013 and 2014.
Future Minimum Payments
The following is a schedule of future minimum payments required under the power purchase, transmission services, coal and gas supply agreements (in thousands):
Related Party Purchase Option
Cheyenne Light’s PPA for 60 megawatts of capacity and energy from Black Hills Wyoming’s Wygen I generating facility expiring on Dec. 31, 2022, includes an option for Cheyenne Light to purchase Black Hills Wyoming’s ownership in the Wygen I facility. The purchase price related to the option is $2.6 million per megawatt which is the equivalent per megawatt of the estimated price of new construction of the Wygen III plant. This option purchase price is reduced annually by an amount equal to annual depreciation.
Power Sales Agreements
Through our subsidiaries, we have the following significant long-term power sales contracts with non-affiliated third-parties:
•
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 megawatts 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 megawatts 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;
•
Cheyenne Light has an agreement with Basin Electric whereby Cheyenne Light provides 40 megawatts of capacity and energy through March 31, 2013.
•
Black Hills Power has a PPA with MEAN expiring April 1, 2015. Under this contract, MEAN purchases 5 megawatts of unit-contingent capacity from Neil Simpson II and 5 megawatts of unit-contingent capacity from Wygen III.
•
Black Hills Power has a PPA with MEAN expiring May 31, 2023. This contract is unit-contingent on up to 10 megawatts from Neil Simpson II and up to 10 megawatts from Wygen III based on the availability of these plants. The capacity purchase requirements decrease over the term of the agreement.
Related Party Lease
Colorado Electric’s PPA with Black Hills Colorado IPP expiring on Dec. 31, 2031, provides 200 megawatts of power to Colorado Electric from Black Hills Colorado IPP’s combined-cycle turbines. This PPA is accounted for as a capital lease whereby Colorado Electric, as lessee, has included the combined-cycle turbines as property, plant and equipment along with the related lease obligation and Black Hills Colorado IPP, as lessor, has recorded a lease receivable. Segment revenue and expenses associated with the PPA have been impacted by the lease accounting. The effect of the lease accounting is eliminated in corporate consolidations.
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 II, 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 in October 2010 and as a result of this rule, we suspended operations at the Ben French facility on Aug. 31, 2012 with plans to retire Ben French, Osage and Neil Simpson I on or before March 21, 2014. In conjunction with the Colorado Clean Air Clean Jobs Act, the CPUC issued an order approving the closure of the W.N. Clark facility no later than Dec. 31, 2013. This facility suspended operations Dec. 31, 2012. 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.
Our W.N. Clark plant, at which operations have been suspended, sends coal ash to a permitted, privately-owned landfill. While we do not believe that any substances from our solid waste disposal activities will pollute underground water, we can provide no assurance that pollution will not occur over time. In this event, we could incur material costs to mitigate any resulting damages.
Reclamation Liability
For our Pueblo Airport Generation site, we have posted a bond of $3.9 million with the State of Colorado to cover the costs of remediation for a waste water containment pond permitted to provide wastewater storage and processing for this zero discharge facility. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land.
Under its land lease for Busch Ranch, Colorado Electric is required to reclaim all land where it has placed wind turbines. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land.
Under its mining permit, WRDC is required to reclaim all land where it has mined coal reserves. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land.
See Note 10 for additional information.
Manufactured Gas Processing
As a result of the Aquila Transaction, we acquired whole and partial liabilities for several former manufactured gas processing sites in Nebraska and Iowa which were previously used to convert coal to natural gas. The acquisition provided for an insurance recovery, now valued at $1.1 million recorded in Other assets, non-current on our Consolidated Balance Sheets, which will be used to help offset remediation costs. The remediation cost estimate could change materially due to results of further investigations, actions of environmental agencies or the financial viability of other responsible parties.
In March 2011, Nebraska Gas executed an Allocation, Indemnification and Access Agreement with the successor to the former operator of the Nebraska MGPs. Under this agreement, Nebraska Gas agreed to remediate the Blair and Plattsmouth sites in Nebraska. Subsequent to this transaction, Nebraska Gas enrolled Blair and Plattsmouth in Nebraska's Voluntary Cleanup Program. Site remediation was completed in September 2012, however there is a potential for additional minimal remediation work at Plattsmouth. If required, it is expected to be completed by mid-2013. Both Nebraska sites will be required to monitor groundwater quality for a minimum two year period.
As of Dec. 31, 2012, our estimated liabilities for all of the MGP sites currently range from approximately $2.9 million to $6.3 million for which we had $3.1 million accrued for remediation of sites as of Dec. 31, 2012 included in Other deferred credits and other liabilities on our Consolidated Balance Sheets.
Prior to Black Hills Corporation's ownership, Aquila received rate orders that enabled recovery of environmental cleanup costs in certain jurisdictions. We anticipate recovery of these current and future costs would be allowed. Additionally, we may pursue recovery or agreements with other potentially responsible parties when and where permitted.
Legal Proceedings
In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in the consolidated financial statements are adequate in light of the probable and estimable contingencies. However, there can be no assurance that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims and other matters discussed, and to comply with applicable laws and regulations, will not exceed the amounts reflected in the consolidated financial statements.
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.
Oil Creek Fire
On June 29, 2012, a forest and grassland fire occurred in the western Black Hills. It is alleged that the fire occurred when a high voltage electrical transmission line maintained by our electric utility subsidiary 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, and by the United States Bureau of Land Management and the State of Wyoming. Our utility subsidiary 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 a landowner is approximately $8.0 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 this 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.
(20) GUARANTEES
We have entered into various agreements providing financial or performance assurance to third parties on behalf of certain of our subsidiaries. The agreements include guarantees of debt obligations, contractual performance obligations and indemnification for reclamation and surety bonds.
We had the following guarantees in place as of (in thousands):
_______________________
(1)
We have guaranteed some of the obligations of Black Hills Utility Holdings for payment obligations arising from commodity-related physical and financial transactions with BP Energy Company and/or BP Canada Energy Marketing Corp, Northern Natural Gas Company and PSCo. These commodity transactions secure natural gas supply for our regulated gas utilities. The guarantee is a continuing guarantee that may be terminated upon 30 days written notice to the counterparty.
(2)
We have issued a guarantee to Vestas-American Wind Technology, Inc. for the performance and payment obligations of Colorado Electric relating to the purchase of wind turbines for the Colorado Electric wind power generation project. This guarantee will remain in effect until 91 days after satisfaction of Colorado Electric’s contractual obligations.
(3)
We have guarantees in place for reclamation and surety bonds for our subsidiaries. The guarantees were entered into in the normal course of business. To the extent liabilities are incurred as a result of activities covered by the surety bonds, such liabilities are included in our Consolidated Balance Sheets.
(4)
We issued a guarantee to Colorado Interstate Gas Company for payment obligations of Black Hills Utility Holdings related to natural gas transportation, storage and services agreement.
(5)
We issued a guarantee to Cross Timbers Energy Services for the performance and payment obligation of Black Hills Utility Holdings for natural gas supply purchase.
(21) OIL AND GAS RESERVES (Unaudited)
BHEP has operating and non-operating interests in 1,200 gross developed oil and gas wells in 9 states and holds leases on approximately 268,636 net acres.
Costs Incurred
Following is a summary of costs incurred in oil and gas property acquisition, exploration and development during the years ended Dec. 31 (in thousands):
Reserves
The following table summarizes BHEP’s quantities of proved developed and undeveloped oil and natural gas reserves, estimated using SEC-defined product prices, as of December 31, 2012, 2011 and 2010, and a reconciliation of the changes between these dates. These estimates are based on reserve reports by CG&A. Such reserve estimates are inherently imprecise and may be subject to revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.
Minor differences in amounts may result in the following tables relating to oil and gas reserves due to rounding.
________________________
(a)
Production for reserve calculations does not include volumes for natural gas liquids (NGLs).
(b)
Reflects the sale of the majority of the Williston Basin assets during 2012.
(c)
Included in total revisions are (27,051) MMcfe due to lower commodity prices and (2,422) MMcfe for dropped PUD locations due to five year aging of reserves with negative performance revisions of (1,565) MMcfe in various basins.
Reserve additions totaled 5.6 Bcfe, replacing 46 percent of production. Additions resulted from drilling in the Williston Basin, San Juan, Piceance and Powder River Basins. Drilling in Williston Basin (Bakken Shale) accounted for 3.1 Bcfe, Piceance Basin (Mancos Shale) 1.9 Bcfe, Powder River Basin 0.3 Bcfe and recompletions in the San Juan Basin 3.0 Bcfe. Capital spending in 2012 was increased to accommodate the Williston Bakken drilling and to continue evaluating the development potential of the Mancos Shale under our leasehold in the San Juan and Piceance Basins. Additionally, exploratory investments were made to develop future opportunities. Future capital spending rates are anticipated to be dependent on product prices.
SEC regulations require that proved undeveloped locations meet the test of being developed within five years of being categorized as proved. Approximately 2.4 Bcfe was removed from previous estimates due to five year reserve aging of the PUD locations in the Bear Paw Uplift, the Piceance Basin and the Wind River Basin. Negative revisions to previous estimates were mostly due to lower natural gas prices received at the well head. Approximately 27.1 Bcfe of the negative revision was due to low commodity prices. Most of the negative revisions were located in the San Juan Basin 11.5 Bcfe; Piceance Basin 13.9 Bcfe; Wind River Basin 0.8 Bcfe; Oklahoma Basins 0.5 Bcfe; and Bear Paw Uplift and other basins 0.4 Bcfe. Additionally, a 0.5 Bcfe behind pipe reserve in the Piceance Basin was dropped. Overall, approximately 1.6 Bcfe was dropped in various basins for small performance downgrades which were offset by performance upgrades in some basins.
Companies are required to include a narrative disclosure of the total quantity of PUD locations at year end, any material changes in PUD locations during the year, and investment and progress made in converting the PUD locations during the year.
•
In 2012, we sold 29 year-end 2011 PUD locations as part of an asset sale in the Williston Basin that represented $41.7 million in investment and 9.5 Bcfe reserves.
•
The San Juan Basin has three PUD locations (approximately 8.1 Bcfe and $15.1 million investment) and three PUD locations in the Piceance Basin (12.1 Bcfe and $24.7 million investment) were dropped due to low commodity pricing.
•
Approximately 34 PUD locations were dropped for reserve aging. Of those, 32 PUD locations were in the Bear Paw Uplift (1.0 Bcfe) and two PUD locations were in the Piceance Basin (1.4 Bcfe).
•
We invested $5.7 million to develop three Williston Basin PUD locations in our remaining Williston Basin assets. PUD locations, proved reserves and future development costs associated with the Williston Basin during 2012 and at Dec. 31, 2012 were:
•
None of our PUD locations have been reflected in our reserves for five or more years. Consistent with the SEC guidance, these PUD locations will be monitored and reported each year until they are drilled or revised.
Capitalized Costs
Following is information concerning capitalized costs for the years ended Dec. 31 (in thousands):
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(a)
Reflects the sale of the majority of the Williston Basin assets during 2012 recorded under the full-cost method of accounting.
Results of Operations
Following is a summary of results of operations for producing activities for the years ended Dec. 31 (in thousands):
Unproved properties not subject to amortization at Dec. 31, 2012, 2011 and 2010 consisted mainly of exploration cost on various existing work-in-progress projects as well as leasehold acquired through significant natural gas and oil property acquisitions and through direct purchases of leasehold. We capitalized approximately $0.7 million, $0.9 million and $0.8 million of interest during 2012, 2011 and 2010, respectively, on significant investments in unproved properties that were not yet included in the amortization base of the full-cost pool. We will continue to evaluate our unevaluated properties; however, the timing of the ultimate evaluation and disposition of the properties has not been determined. We expect the exploration cost listed below to be added to the cost pool in the next year.
The table below sets forth the cost of unproved properties excluded from the amortization base as of Dec. 31, 2012 and notes the year in which the associated costs were incurred (in thousands):
Standardized Measure of Discounted Future Net Cash Flows
Following is a summary of the standardized measure of discounted future net cash flows and changes relating to proved oil and gas reserves for the years ended Dec. 31 (in thousands):
The following are the principal sources of change in the standardized measure of discounted future net cash flows during the years ended Dec. 31 (in thousands):
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(a)
Reflects sale of Williston Basin assets
Changes in the standardized measure from “revisions of previous quantity estimates” are driven by reserve revisions, modifications of production profiles and timing of future development. For all years presented, we had minimal net reserve revisions to prior estimates due to performance. Production forecast modifications are generally made at the well level each year through the reserve review process. These production profile modifications are based on incorporation of the most recent production information and applicable technical studies. Timing of future development investments are reviewed each year and are often modified in response to current market conditions for items such as permitting, and service availability.
(22) SALE OF ASSETS
Partial Sale of Electric Utilities Assets
On Sept. 18, 2012, Colorado Electric completed the sale of an undivided 50 percent ownership interest in the Busch Ranch Wind Farm to AltaGas for $25.0 million. Colorado Electric retains the remaining undivided interest and will be the operator of this jointly owned facility. Commercial operation of the newly constructed wind farm commenced on Oct. 16, 2012. Colorado Electric will purchase AltaGas’s interest, or approximately 14.5 megawatts, in the energy produced by the wind farm through a REPA expiring on Oct. 16, 2037.
On July 14, 2010, Black Hills Power sold a 23 percent ownership interest in Wygen III to the City of Gillette for $62.0 million. The Participation Agreement provides that the City of Gillette will pay Black Hills Power 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. Black Hills Power recognized a gain on the sale of $6.2 million.
Partial Sale of Oil and Gas Assets
On Sept. 27, 2012, our Oil and Gas segment sold a majority of its Bakken and Three Forks shale assets in the Williston Basin in North Dakota. The sale included approximately 73 gross wells, 28,000 net leasehold acres and had an effective date of July 1, 2012.
Our Oil and Gas segment follows the full-cost method of accounting for oil and gas activities. Typically this methodology does not allow for gain or loss on sale and proceeds from sale are credited against the full cost pool. Gain or loss recognition is allowed when such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. The Sept. 27, 2012 sale of the majority of the Williston Basin assets significantly alters the relationship and accordingly we have recorded a gain of $29.1 million with the remainder of the proceeds recorded as a reduction in the full cost pool. This reduction in the full cost pool significantly decreased the depreciation, depletion and amortization rate for the remainder of 2012.
Net cash proceeds were as follows (in thousands):
_____________
*
Required payment, triggered by the sale of the property, arising from a contractual obligation contained in the original participation agreement with the property operator.
Partial Sale of Gas Utilities Assets
On March 1, 2010, Nebraska Gas sold certain assets to Metropolitan Utilities District as a result of annexation proceedings by the City of Omaha, Nebraska. Nebraska Gas received $6.1 million in cash and recognized a $2.7 million pre-tax gain on the sale.
(23) DISCONTINUED OPERATIONS
Results of operations for discontinued operations have been classified as Income from discontinued operations, net of income taxes in the accompanying Consolidated Statements of Income. Assets and liabilities of the discontinued operations have been classified and reflected on the accompanying Consolidated Balance Sheets as “Assets of discontinued operations” and “Liabilities of discontinued operations.” For comparative purposes, all prior periods presented have been restated to reflect the reclassification on a consistent basis.
Energy Marketing Segment
On Feb. 29, 2012, we sold the outstanding stock of our Energy Marketing segment, Enserco Energy Inc. The transaction was completed through a stock purchase agreement and certain other ancillary agreements. Net cash proceeds on Dec. 31, 2012 were approximately $165.0 million, subject to final post-closing adjustments. The proceeds represent $107.5 million received from the buyer and $57.5 million cash retained from Enserco before closing.
Pursuant to the provisions of the Stock Purchase Agreement, disputes regarding post-closing purchase price adjustments are subject to arbitration before a nationally-recognized accounting firm and all other disputes are subject to the indemnification procedures in the agreement. The buyer originally demanded an amount totaling $7.2 million, characterizing all claims in such demand as purchase price adjustments. We contested certain claims in the buyer's demand, including whether certain claims were properly characterized as purchase price adjustments, but reached a partial settlement and paid the buyer the sum of $1.4 million. The parties were unable to reach a negotiated agreement regarding the balance of the claims.
In December 2012, we agreed to arbitrate the claims that we believe are properly characterized as purchase price adjustments, but objected to the arbitration of the claims that we believe are not properly characterized as purchase price adjustments. After joint discussions of the parties with the arbitrator, in January 2013 the arbitrator advised the parties that it would not arbitrate the claims to which we objected. On Feb. 7, 2013, the buyer filed a petition in the United States District Court for the District of Colorado applying for an order compelling arbitration on all of the disputed claims. We will respond to this litigation, requesting the court to deny the buyer's application. The filing of this petition does not alter our characterization or evaluation of the original claim.
Operating results of the Energy Marketing segment included in Income (loss) from discontinued operations, net of tax on the accompanying Consolidated Statements of Income were as follows (in thousands):
________
(a)
2012 includes transaction related costs, net of tax, of $2.5 million for the year ended Dec. 31, 2012.
Total indirect corporate costs and inter-segment interest expenses previously allocated to Enserco were not reclassified to discontinued operations in accordance with GAAP and instead have been reclassified to our Corporate segment.
Net assets of the Energy Marketing segment included in Assets/Liabilities of discontinued operations in the Consolidated Balance Sheets were as follows (in thousands) as of:
(24) QUARTERLY HISTORICAL DATA (Unaudited)
The Company operates on a calendar year basis. The following tables set forth select unaudited historical operating results and market data for each quarter of 2012 and 2011.
__________________________
(a)
Second quarter includes a pre-tax ceiling test impairment loss of $26.9 million and the third and fourth quarters include a pre-tax gain on sale of the Williston Basin assets of $27.3 million and $1.8 million, respectively.
(b)
Includes unrealized mark-to-market gain (loss) for interest rate swaps of $7.8 million, $(10.1) million, $0.4 million, and $3.1 million after-tax in the first, second, third and fourth quarters, respectively.
(c)
Second quarter includes an after-tax ceiling test impairment loss of $17.3 million and the third and fourth quarters include an after-tax gain on sale of the Williston Basin assets of $17.7 million and $1.2 million, respectively.
__________________________
(a)
Includes unrealized mark-to-market gain (loss) for interest rate swaps of $3.6 million, $(5.1) million, $(24.9) million and $(0.9) million after-tax in the first, second, third and fourth quarters, respectively.
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 Dec. 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 Corporation 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 Dec. 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 Dec. 31, 2012.
Deloitte & Touche LLP, our independent registered public accounting firm, has issued an attestation report on the effectiveness of Black Hills Corporation's internal control over financial reporting as of Dec. 31, 2012. Deloitte & Touche LLP's report on Black Hills Corporation's internal control over financial reporting is included herein.
Black Hills Corporation
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Black Hills Corporation
Rapid City, South Dakota
We have audited the internal controls over financial reporting of Black Hills Corporation’s and subsidiaries’ (the “Company’s”) as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel 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. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2012 of the Company and our report dated February 25, 2013 expressed an unqualified opinion on those consolidated financial statements and financial statement schedules.
/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 25, 2013
ITEM 9B.
ITEM 9B.
OTHER INFORMATION
None
PART III
ITEM 10.
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information required under this item with respect to directors and information required by Items 401, 405, 406, 407(c)(3), 407(d)(4) and 407(d)(5) of Regulation S-K, is set forth in the Proxy Statement for our 2013 Annual Meeting of Shareholders, which is incorporated herein by reference.
Executive Officers
David R. Emery, age 50, was elected Chairman in April 2005 and has been President and Chief Executive Officer and a member of the Board of Directors since January 2004. Prior to that, he was our President and Chief Operating Officer - Retail Business Segment from April 2003 to January 2004 and Vice President - Fuel Resources from January 1997 to April 2003. Mr. Emery has 23 years of experience with the Company.
Scott A. Buchholz, age 51, has been our Senior Vice President - Chief Information Officer since the closing of the Aquila Transaction in July 2008. Prior to joining the Company, he was Aquila’s Vice President of Information Technology from June 2005 until July 2008, Six Sigma Deployment Leader/Black Belt from January 2004 until June 2005, and General Manager, Corporate Information Technology from February 2002 until January 2004. He was employed with Aquila for 28 years.
Anthony S. Cleberg, age 60, has been Executive Vice President and Chief Financial Officer since July 2008. He was an independent investor, developer and consultant with companies in Colorado and Wyoming from 2002 until joining the Company in 2008. Prior to his consulting role, he was the Executive Vice President and Chief Financial Officer of two publicly-traded companies: Washington Group, International, Inc., a large engineering and construction company involved in power plant construction and mining operations, and Champion Enterprises, a builder of factory-built housing. Before his CFO roles, he spent 15 years in various senior financial positions with Honeywell International, Inc., and eight years in public accounting at Deloitte & Touche, LLP.
Linden R. Evans, age 50, has been President and Chief Operating Officer - Utilities since October 2004. Mr. Evans served as the Vice President and General Manager of our former communication subsidiary from December 2003 to October 2004, and served as our Associate Counsel from May 2001 to December 2003. Mr. Evans has 11 years of experience with the Company.
Steven J. Helmers, age 56, has been our Senior Vice President, General Counsel and Chief Compliance Officer since January 2008. He served as our Senior Vice President, General Counsel since January 2004 and our Senior Vice President, General Counsel and Corporate Secretary from 2001 to 2004. Mr. Helmers has 12 years of experience with the Company.
Robert A. Myers, age 55, has been our Senior Vice President - Chief Human Resource Officer since January 2009 and served as our Interim Human Resources Executive since June 2008. He was a partner with Strategic Talent Solutions, a human resources consulting firm, from October 2006 until December 2008, Senior Vice President - Chief Human Resource Officer for Devon Energy from March 2006 until September 2006, and Senior Vice President and Chief Human Resource Officer at Reebok International, Ltd from November 2003 until January 2006. He has over 32 years of service in key human resources leadership roles.
ITEM 11.
ITEM 11.
EXECUTIVE COMPENSATION
Information required under this item is set forth in the Proxy Statement for our 2013 Annual Meeting of Shareholders, which is incorporated herein by reference.
ITEM 12.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information regarding the security ownership of certain beneficial owners and management is set forth in the Proxy Statement for our 2013 Annual Meeting of Shareholders, which is incorporated herein by reference.
EQUITY COMPENSATION PLAN INFORMATION
The following table includes information as of December 31, 2012 with respect to our equity compensation plans. These plans include the 1999 Stock Option Plan, 2001 Omnibus Incentive Plan and 2005 Omnibus Incentive Plan.
_________________________
(1)
Includes 220,013 full value awards outstanding as of December 31, 2012, comprised of restricted stock units, performance shares and Director common stock units. The weighted average exercise price does not include the restricted stock units, performance shares or common stock units. In addition, 287,422 shares of unvested restricted stock were outstanding as of December 31, 2012, which are not included in the above table because they have already been issued.
(2)
Shares available for issuance are from the 2005 Omnibus Incentive Plan. The 2005 Omnibus Incentive Plan permits the grant of stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, cash-based awards and other stock based awards.
ITEM 13.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information regarding certain relationships and related transactions and director independence is set forth in the Proxy Statement for our 2013 Annual Meeting of Shareholders, which is incorporated herein by reference.
ITEM 14.
ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
Information regarding principal accounting fees and services is set forth in the Proxy Statement for our 2013 Annual Meeting to Shareholders, which is incorporated herein by reference.
PART IV
ITEM 15.
ITEM 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a)
1.
Consolidated Financial Statements
Financial statements required under this item are included in Item 8 of Part II
2.
Schedules
Schedule I - Condensed Financial Information of the Registrant
Schedule II - Consolidated Valuation and Qualifying Accounts for the years ended Dec. 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 in our consolidated financial statements and notes thereto.
3.
Exhibits
SCHEDULE I
BLACK HILLS CORPORATION (PARENT COMPANY)
CONDENSED STATEMENTS OF INCOME
The accompanying notes to condensed financial statements are an integral part of these condensed financial statements.
BLACK HILLS CORPORATION (PARENT COMPANY)
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
The accompanying notes to condensed financial statements are an integral part of these condensed financial statements.
BLACK HILLS CORPORATION (PARENT COMPANY)
CONDENSED BALANCE SHEETS
The accompanying notes to condensed financial statements are an integral part of these condensed financial statements.
BLACK HILLS CORPORATION (PARENT COMPANY)
CONDENSED STATEMENTS OF CASH FLOWS
The accompanying notes to condensed financial statements are an integral part of these condensed financial statements.
NOTES TO BLACK HILLS CORPORATION (PARENT COMPANY) CONDENSED FINANCIAL STATEMENTS
(1) BASIS OF PRESENTATION
Pursuant to rules and regulations of the SEC, the unconsolidated condensed financial statements of Black Hills Corporation do not reflect all of the information and notes normally included with financial statements prepared in accordance with GAAP. Therefore, these condensed financial statements should be read in conjunction with the consolidated financial statements and related notes included in this Annual Report on Form 10-K.
Dividends paid and distributed to Black Hills Corporation (the Parent) from its subsidiaries were as follows (in thousands):
(2) NOTES RECEIVABLE AND NOTES PAYABLE
Black Hills Corporation has notes receivable and notes payable with affiliates under Utility Money Pool Agreements and Non-Utility Money Pool Agreements. Borrowings under these agreements bear interest at the weighted average daily cost of external funds as defined under the agreements.
Additionally, Black Hills Corporation has a Revolving Credit Facility and corporate term loans with various banks. Our credit facility and debt securities contain certain restrictive financial covenants. At December 31, 2012, we were in compliance with all of these covenants. See Note 9 to Notes to Consolidated Financial Statements on this Annual Report on Form 10-K.
(3) LONG-TERM DEBT
Long-term debt outstanding at Dec. 31 was as follows (in thousands):
_______________
(a)
This note was repaid on Oct. 31, 2012. This senior unsecured note had been recorded by Black Hills Utility Holdings and is recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets for 2011.
(b)
This senior unsecured note has been recorded by Black Hills Utility Holdings and is recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets for 2012.
(c)
This senior unsecured note has been recorded by Colorado Electric and is recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets for 2012. In 2011 $100 million of this senior unsecured note had been recorded by Black Hills Colorado IPP and was recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets.
(d)
This term loan has been recorded by Black Hills Utility Holdings and is recorded as Notes receivable - affiliate, current on the Parent’s Condensed Balance Sheets for 2012.
(e)
If our senior unsecured credit rating should drop below investment grade, then pricing under our credit agreements would be affected, increasing annual interest expense by approximately $1.0 million pre-tax based on our Dec. 31, 2012 debt balances.
Certain debt instruments of the Company contain restrictions and covenants, all of which we were in compliance with at December 31, 2012.
Scheduled maturities of long-term debt, excluding amortization of premiums or discounts, for future years are (in thousands):
(4) GUARANTEES
We have entered into various agreements providing financial or performance assurance to third parties on behalf of certain of our subsidiaries. The agreements include guarantees of debt obligations, contractual performance obligations and indemnification for reclamation and surety bonds. See Note 20 of Notes to Consolidated Financial Statements on this Annual Report on Form 10-K for further information.
(5) RISK MANAGEMENT ACTIVITIES
We engage in activities to manage risks associated with changes in interest rates. We have entered into floating-to-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations associated with our floating rate debt obligations. See Note 3 of Notes to Consolidated Financial Statements on this Annual Report on Form 10-K for further information.
On Dec. 31 our interest rate swaps and related balances were as follows (dollars in thousands):
________________________
(a)
Under the terms of the Black Hills Wyoming project financing, Black Hills Wyoming was required to become a party to hedging agreements fixing the interest rate on a portion of the principal amount of the debt. To accomplish this, two existing swap agreements totaling $75.0 million were amended and transferred to Black Hills Wyoming so that the Parent and Black Hills Wyoming are now both jointly and severally liable for the full amount of the obligations under the swap agreements. The balance in AOCI of the Parent was frozen at that point in time and is being amortized over the remaining life of the swaps through the quarterly settlement process.
Based on December 31, 2012 market interest rates and balances, a loss of approximately $3.5 million would be realized and reported in pre-tax earnings during the next 12 months. Estimated and realized losses will change during the future periods as market interest rates fluctuate.
(6) FAIR VALUE OF FINANCIAL INSTRUMENTS
The estimated fair values of our financial instruments at Dec. 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.
Cash and Cash Equivalents
Included in cash and cash equivalents is cash, overnight repurchase agreement accounts, money market funds and term deposits. 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.
Notes Payable
Notes Payable represent our short-term corporate term loan and borrowings under our Revolving Credit Facility.
Long-Term Debt
For additional information see Note 3 of these Black Hills Corporation (the Parent) Condensed Financial Statements.
(7) COMMON STOCK
Forward Equity Issuance
In November 2011, we settled the equity forward agreement. For additional information see Note 11 of Notes to the Consolidated Financial Statements included in this Annual Report on Form 10-K.
(8) COMMITMENTS AND CONTINGENCIES
In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in the condensed financial statements are adequate in light of the probable and estimable contingencies. However, there can be no assurance that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims and other matters discussed, and to comply with applicable laws and regulations, will not exceed the amounts reflected in the condensed financial statements.
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.
SCHEDULE II
3.
Exhibits
________________________
*
Previously filed as part of the filing indicated and incorporated by reference herein.
†
Indicates a board of director or management compensatory plan.
(a)
See (a) 3. Exhibits above.
(b)
See (a) 2. Schedules above.
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.
†
Indicates a board of director or management compensatory plan.