We are substantially leveraged, the terms of our senior and subordinated debt do not restrict the incurrence of additional debt by us or our subsidiaries, and our senior and subordinated debt isare structurally subordinated to the debt of our subsidiaries, each of which could adversely affect our consolidated financial results.
Given our substantial leverage, we may not have sufficient cash to service our debt, which could limit our ability to finance future acquisitions, develop and construct additional projects, or operate successfully under adverse conditions, including those brought on by declining national and global economies, and unfavorable financial markets.markets or growth conditions where our capital needs may exceed our ability to fund them. Our leverage could a lsoalso impair our credit quality or the credit quality of our subsidiaries, making it more difficult to finance operations or issue future debt on favorable terms, and could result in a downgrade in debt ratings by credit rating agencies.
The terms of our senior and subordinated debt do not limit our ability or the ability of our subsidiaries to incur additional debt or issue preferred stock. Accordingly, we or our subsidiaries could enter into acquisitions, new financings, refinancings, recapitalizations, capital leases or other highly leveraged transactions that could significantly increase our or our subsidiaries' total amount of outstanding debt. The interest payments needed to service this increased level of debt could adversely affect our consolidated financial re sults.results. Many of our subsidiaries' debt agreements contain covenants, or may in the future contain covenants, that restrict or limit, among other things, such subsidiaries' ability to create liens, sell assets, make certain distributions, incur additional debt or miss contractual deadlines or requirements, and our ability to comply with these covenants may be affected by events beyond our control. Further, if an event of default accelerates a repayment obligation and such acceleration results in an event of default under some or all of our other debt, we may not have sufficient funds to repay all of the accelerated debt, and the other risks described under "Our Corporate and Financial Structure Risks" may be magnified as well.
Because we are a holding company, the claims of our senior and subordinated debt holders are structurally subordinated with respect to the assets and earnings of our subsidiaries. Therefore, the rights of our creditors to participate in the assets of any subsidiary in the event of a liquidation or reorganization are subject to the prior claims of the subsidiary's creditors and preferred shareholders. In addition, a significant amo untamount of the stock or assets of our operating subsidiaries is directly or indirectly pledged to secure their financings and, therefore, may be unavailable as potential sources of repayment of our senior and subordinated debt.
A downgrade in our credit ratings or the credit ratings of our subsidiaries could negatively affect our or our subsidiaries' access to capital, increase the cost of borrowing or raise energy transaction credit support requirements.
Similarly, any downgrade or other event negatively affecting the credit ratings of our subsidiaries could make their costs of borrowing higher or access to funding sources more limited, which in turn could cause us to provide liquidity in the form of capital contributions or loans to such subsidiaries, thus reducing our and our subsidiaries' liquidity and borrowing capacity.
Our majority shareholder, Berkshire Hathaway, could exercise control over us in a manner that would benefit Berkshire Hathaway to the detriment of our creditors.
Berkshire Hathaway is our majority owner and has control over all decisions requiring shareholder approval, including the election of our directors. In circumstances involving a conflict of interest between Berkshire Hathaway and our creditors, Berkshire Hathaway could exercise its control in a manner that would benefit Berkshire Hathaway to the detriment of our creditors.
Much of our growth has been achieved through acquisitions, and additional acquisitions may not be successful.
Much of our growth has been achieved through acquisitions. Future acquisitions may range from buying individual assets to the purchase of entire businesses. We will continue to investigate and pursue opportunities for future acquisitions that we believe may increase shareholder value and expand or complement existing businesses. We may participate in bidding or other negotiations at any time for such acquisition opport unitiesopportunities which may or may not be successful. Any transaction that does take place may involve consideration in the form of cash or debt or equity securities.
Completion of any acquisition entails numerous risks, including, among others, the:
An acquisition could cause an interruption of, or loss of momentum in, the activities of one or more of our businesses. The diversion of management's attention and any delays or difficulties encountered in connection with the approval and integration of the acquired operations could adversely affect our combined businesses and financial results and could impair our ability to realize the anticipated benefits of the acquisition.
We cannot assure you that future acquisitions, if any, or any related integration efforts will be successful, or that our ability to repay our obligations will not be adversely affected by any future acquisitions.
We and our businesses are subject to extensive federal, state, local and foreign legislation and regulation, including numerous environmental, health, safety and other laws and regulations that affect us and our businesses' operations and costs. These laws and r egulationsregulations are complex, dynamic and subject to new interpretations or change. In addition, new laws and regulations are continually being proposed and enacted that create new or revised requirements or standards on us and our businesses.
We and our businesses are required to comply with numerous federal, state, local and foreign laws and regulations that have broad application to us and our electric and natural gas utilities and interstate pipelinessubsidiaries and limit our ability to independently make and implement management decisions regarding, among other items, business combinations;acquiring businesses; constructing, acquiring or disposing of operating assets; operation ofoperating generating facilities and transmission and distribution assets; complying with pipeline safety and integrity and environmental requirements; setting rates charged to customers; establishing capital structures and issuing debt or equity securities; transactionstransacting between subsidiaries and affiliates; and paying dividends. These laws and regulations are implemented and enforced by federal, state and local regulatory agencies, such as, among others, the FERC, the EPA, the NRC, the MSHA, the DOT, the IUBNRC and the OPUCvarious state regulatory commissions in the United States, and GEMA, which discharges certain of its powers through its staff within Ofgem, in the United Kingdom.
Compliance with applicable laws and regulations generally requires our subsidiaries to obtain and comply with a wide variety of licenses, permits, inspections and other approvals. Further, compliance with laws and regulations can require significant capital and operating expenditures, including expenditures for new equipment, inspection, cleanup costs, removal and remediation costs, damages aris ingarising out of contaminated properties and fines, penalties and injunctive measures affecting operating assets for failure to comply with environmental regulations. Compliance activities pursuant to laws and regulations could be prohibitively expensive. As a result, some facilities may be required to shut down or alter their operations. Further, our subsidiaries may not be able to obtain or maintain all required environmental or other regulatory approvals and permits for their operating assets or development projects. Delays in or active opposition by third parties to obtaining any required environmental or regulatory permits,authorizations, failure to comply with the terms and conditions of the permitsauthorizations or increasedenhanced regulatory or environmental requirements may increase costs or prevent or delay our subsidiaries from operating their facilities, developing new facilities, expanding existing facilities or favorably locating new facilities. If our subsidiaries fail to comply with any environmental or other regulatory requirements, they may be subject to penalties and fin esfines or other sanctions.sanctions, including changes to the way our electric generating facilities are operated or how the Pipeline Companies are permitted to operate their systems that may impact generation or throughput. The costs of complying with laws and regulations could adversely affect our consolidated financial results. Not being able to operate existing facilities or develop new generating facilities to meet customer electricity needs could require our subsidiaries to increase their purchases of electricity on the wholesale market, which could increase market and price risks and adversely affect our consolidated financial results.
Existing laws and regulations, while comprehensive, are subject to changes and revisions from ongoing policy initiatives by legislators and regulators and to interpretations that may ultimately be resolved by the courts. For example, changes in lawlaws and regulationregulations could result in, but are not limited to, increased retail compet itioncompetition within our subsidiaries' service territories; new environmental requirements, including the implementation of renewable portfolio standardsRPS and greenhouse gasGHG emissions ("GHG") reduction goals; the issuance of stricter air quality standards and the implementation of energy efficiency mandates; the issuance of regulations over the management and disposal of coal combustion byproducts; changes to our subsidiaries' service territories as a result of condemnation or takeover by municipalities or other governmental entities, particularly where they lack the acquisition by a municipalityexclusive right to serve their customers; the inability of our subsidiaries' distribution facilities;to recover their costs; new pipeline safety requirements; or a negative impact on our subsidiaries' current transportation and cost recovery arrangements.
In addition to changes in existing legislation and regulation, new laws and regulations are likely to be enacted that impose additional or new requirements or standards on our businesses. For example, while significant measures to regulate emissions at the federal level were considered by the United States Congress in 2010, comprehensive legislation has not been adopted; however, the EPA issued the CSAPR and federal policy makers recently considered, but did not adopt, comprehensive climate change legislation. Adoption ofMATS rules in 2011. Implementing actions required under, and otherwise complying with, new federal and state laws and regulations and changes in existing ones is emerging as one ofare among the moremost challenging aspects of managing utility operations. We cannot predict the future course of new laws and regulations, changes in existing ones or new interpretations by agency orders or court decisions nor can their impact on us be determined at this time; however, any one of these could adversely affect our consolidated financial results through higher capital expenditures and operating costs and cause an overall change in how we o perateoperate our businesses. To the extent that our regulated subsidiaries are not allowed by their regulators to recover or cannot otherwise recover the costs to comply with new laws and regulations or changes in existing ones, the additional requirements could have a material adverse effect on our consolidated financial results. Additionally, even if such costs are recoverable in rates, if they are substantial and result in rates increasing to levels that substantially reduce customer demand or reduce our Pipeline Companies throughput, this could have a material adverse effect on our consolidated financial results.
Recovery of costs by our regulated subsidiaries is subject to regulatory review and approval, and the inability to recover costs may adversely affect our consolidated financial results.
The Utilities establish rates for their regulated retail service through state regulatory proceedings. These proceedings typically involve multiple parties, including government bodies and officials, consumer advocacy groups and various consumers of energy, who have differing concerns, but who generally have the common objective of limiting rate increases. Decisions are subject to appeal, potentially leading to further uncertainty as sociatedassociated with the approval proceedings.
Each state sets retail rates based in part upon the state regulatory commission's acceptance of an allocated share of total utility costs. When states adopt different methods to calculate interjurisdictional cost allocations, some costs may not be incorporated into rates of any state. Ratemaking is also generally done on the basis of estimates of normalized costs, so if a given year's realized costs are higher than normalized costs, rates may not be sufficient to cover those costs. In some cases, actual costs are lower than the normalized or estimated costs recovered through rates and from time-to-time may result in a state regulator requiring refunds to customers. Each state regulatory commission generally sets rates based on a test year established in accordance with that commission's policies. The test year data adopted by each state regulatory commission may create a lag between the incurrence of a cost and its recovery in rates. Each state regulatory commission also decides the allowed levels of expense and investment that they deem are just and reasonable in providing the service and may disallow recovery in rates for any costs that do not meet such standard. StateAdditionally, each state regulatory commissions also decidecommission establishes the allowed rate of return the Utilities will be given an opportunity to earn on their sources of capital.
FERC Jurisdiction
The FERC establishes cost-based rates under which PacifiCorp providesassociated with transmission services to wholesale marketsprovided by PacifiCorp and retail markets in states that allow retail competition and establishes cost-based rates associated with MidAmerican Energy's transmission facilities, including those used to provide wholesale distribution service.facilities. Under the Federal Power Act, the Utilities may voluntarily file, or be obligated to file for changes, including general rate changes, to their system-wide transmissi ontransmission service rates. General rate changes implemented may be subject to refund. The FERC also has responsibility for approving both cost- and market-based rates under which the Utilities sell electricity at wholesale, has licensing authority over most of PacifiCorp's hydroelectric generating facilities and has broad jurisdiction over energy markets. The FERC may impose price limitations, bidding rules and other mechanisms to address some of the volatility of these markets or could revoke or restrict the ability of the Utilities to sell electricity at market-based rates, which could adversely affect our consolidated financial results. As a transmission owning member of the MISO, MidAmerican Energy is also subject to MISO-directed modifications of market rules, which are subject to FERC approval and operational procedures. The FERC may also impose substantial civil penalties for any non-compliance with the Federal Power Act and the FERC's rules and orders.
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The FERC has jurisdiction over the construction and operation of natural gas pipelines and related facilities used in the transportation, storage and sale of natural gas in interstate commerce, including the modification or abandonment of such facilities and rates, charges and terms and conditions of service for the transportation, storage and sale of natural gas in interstate commerce.commerce and the modification or abandonment of such facilities and rates. The FERC was granted expandedalso has market transparency authority under §23 of the NGA, a section added to the NGA by the Energy Policy Act of 2005. The FERCand has adopted additional reporting and internet posting requirements for natural gas pipelines and buyers and sellers of natural gas.
Rates established for our interstate natural gas transmission and storage operations at Northern Natural Gas and Kern Riverthe Pipeline Companies are also subject toestablished by the FERC. In accordance with the FERC's rate-making principles, the Pipeline Companies current maximum tariff rates are designed to recover prudently incurred costs included in their pipeline system's regulatory authority. Thecost of service that are associated with the construction, operation and maintenance of their pipeline system and to afford our Pipeline Companies an opportunity to earn a reasonable rate of return. Nevertheless, the rates the FERC authorizes these companiesour Pipeline Companies to charge their customers may not be sufficient to cover the costs incurred to provide services in any given period. These pipelines,Moreover, from time to time, have in effect rate settlements approved by the FERC which prevent themmay change, alter or third parties from modifyingrefine its policies or methodologies for establishing pipeline rates except for allowed adjustments, for certain periods. These settlements do not precludeand terms and conditions of service. In addition, the FERC from initiating a separate proceedinghas expressed its intent to continue reviewing data submitted in interstate natural gas pipelines' annual FERC Form 2 filings to determine whether pipelines may be earning more than their allowed rate of return and, when appropriate, to institute proceedings against such pipelines under Section 5 of the NGA to modify thereduce rates. It is not possible to determine at this time whether any such actions would be instituted with respect to our Pipeline Companies' rates or what the outcome would be, but such proceedings could result in rate adjustments.
Under FERC policy, interstate pipelines and their customers may execute contracts at negotiated rates, which may be above or below the FERC regulated maximum tariff rate for that service. In a rate proceeding, these negotiated or discounted rate contracts are generally not subject to adjustment for increased costs which could occur due to inflation, increases in the cost of capital or taxes or other factors. It is possible that the cost to perform services under negotiated or discounted rate contracts will exceed the expected cost used when the negotiated or discounted rates were agreed to, which could result either in losses or lower rates of return in providing such services. FERC policy allows interstate natural gas pipelines to recover such costs under certain circumstances in rate cases. However, with respect to discounts granted to affiliates and negotiated rates, the interstate natural gas pipeline has a strong burden of proof to support such recovery on the basis that the discounted or negotiated rate was necessary in order to meet competition.
United Kingdom Electricity Distribution
Northern Electric and Yorkshire Electricity,The Distribution Companies, as DNOs and holders of electricity distribution licenses, are subject to regulation by GEMA. Most of the revenue of a DNO is controlled by a distribution price control formula set out in the electricity distribution license. The price control formula does not directly constrain profits from year to year, but is a control on revenue that operates independently of most of the DNO's costs. It has been the practice of Ofgem to review and reset the formula at five-year intervals, although th e formula has been, and may be, reviewed at other times at the discretion of Ofgem. The current five-year cost control period became effective on April 1, 2010 and extends through March 31, 2015. A resetting of the formula requires the consent of the DNO; however, license modifications may be unilaterally imposed by Ofgem without such consent following review by the British competition commission. GEMA is able to impose financial penalties on DNOs that contravene any of their electricity distribution license duties or certain of their duties under British law, or fail to achieve satisfactory performance of individual standards prescribed by GEMA. Any penalty imposed must be reasonable and may not exceed 10% of the DNO's revenue. During the term of the price control, additional costs have a direct impact on the financial results of Northern Electric and Yorkshire Electricity.the Distribution Companies.
Through our subsidiaries, we are actively pursuing, developing and constructing new or expanded facilities, the completion and expected cost of which are subject to significant risk, and our subsidiaries have significant funding needs related to their planned capital expenditures.
Through our subsidiaries, we are actively pursuing, developingpursue, develop and constructingconstruct new or expanded facilities. We expect that these subsidiaries will incur substantial annual capital expenditures over the next several years. ExpendituresSuch expenditures could include, among others, amounts for new electric generating facilities, electric transmission or distribution p rojects,projects, environmental control and compliance systems, natural gas storage facilities, new or expanded pipeline systems, as well as the continued maintenance and upgrades of existing assets.
Development and construction of major facilities are subject to substantial risks, including fluctuations in the price and availability of commodities, manufactured goods, equipment, labor, siting and permitting and other items over a multi-year construction period, as well as counterparty risk and the economic viability of our suppliers.suppliers, customers and contractors. Certain of our construction projects are substantially dependent upon a single contractor and replacement of such contractor may be difficult and cannot be assured. These risks may result in the inability to timely complete a project or higher than expected costs to complete an asset and place it in service. Such costs may not be recoverable in the regulated rates or market or contract prices our subsidiaries are able to charge their customers. It is also possible that additional generation needs may be obtained through power purchase agreements, which could increase long-term purchase obligations and force reliance on the operating performance of a third party. The inability to successfully and timely complete a project, avoid unexpected costs or to recover any such costs could adversely affect our consolidated financial results.
Furthermore, our subsidiaries depend upon both internal and external sources of liquidity to provide working capital and to fund capital requirements. In some cases, we will commit to provide significant amounts of equity to our subsidiaries that are engaged in construction projects. If we do not provide needed funding to our subsidiaries and the subsidiaries are unable to obtain funding from external sources, they may need to postpone or cancel planned capital expenditures.
Failure to construct these planned projects could limit opportunities for revenue growth, increase operating costs and adversely affect the reliability of electricity service to our customers. For example, if PacifiCorp is not able to expand its existing portfolio of generating facilities, it may be required to enter into long-term wholesale electricity purchase contracts or purchase wholesale electricity at more volatile and potentially higher prices in the spot markets to support retail loads.
A sustained decrease in demand for electricity or natural gas in the markets served by our subsidiaries would significantly decrease our operating revenue and adversely affect our consolidated financial results.
A sustained decrease in demand for electricity or natural gas in the markets served by our subsidiaries would significantly reduce our operating revenue and adversely affect our consolidated financial results. Factors that could lead to a decrease in market demand include, among others:
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• | a depression, recession or other adverse economic condition that results in a lower level of economic activity or reduced spending by consumers on electricity or natural gas, such as the significant adverse changes in the economy and credit markets experienced in 2008 and 2009; |
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• | an increase in the market price of electricity or natural gas or a decrease in the price of other competing forms of energy; |
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• | efforts by customers, legislators and regulators to reduce the consumption of energy through various conservation and energy efficiency measures and programs; |
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• | higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of natural gas or other fuel sources for electricity generation or that limit the use of natural gas or the generation of electricity from fossil fuels; and |
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• | a shift to more energy-efficient or alternative fuel machinery or an improvement in fuel economy, whether as a result of technological advances by manufacturers, legislation mandating higher fuel economy or lower emissions, price differentials, incentives or otherwise. |
a depression, recession or other adverse economic condition that results in a lower level of economic activity or reduced spending by consumers on electricity or natural gas, such as the significant adverse changes in the economy and credit markets experienced in 2008 and 2009;
an increase in the market price of electricity or natural gas or a decrease in the price of other competing forms of energy;
shifts in competitively priced natural gas supply sources away from the sources connected to our Pipeline Companies' systems;
efforts by customers, legislators and regulators to reduce the consumption of energy through various conservation and energy efficiency measures and programs;
laws mandating or encouraging renewable energy resources which may reduce the demand for natural gas;
higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of natural gas or other fuel sources for electricity generation or that limit the use of natural gas or the generation of electricity from fossil fuels; and
a shift to more energy-efficient or alternative fuel machinery or an improvement in fuel economy, whether as a result of technological advances by manufacturers, legislation mandating higher fuel economy or lower emissions, price differentials, incentives or otherwise.
Our subsidiaries are subject to market risk associated with the wholesale energy markets, which could adversely affect our consolidated financial results.
In general, our primary market risk is the risk of adverse fluctuations in the market price of wholesale electricity and fuel, including natural gas, coal and fuel oil, which is compounded by volumetric changes affecting the availability of or demand for electricity and fuel. WholesaleThe market price of wholesale electricity may be influenced by several factors, such as the adequacy or type of generating capacity; scheduled and unscheduled outages of generating facilities; prices and availability of fuel sources for generation; disruptions or constraints to transmission and distribution facilities; weather conditions; economic growth; and changes in technology. Volumetric changes are caused by unanticipated changes in generation availability or changes in customer needs that can be due to the weather, electricity and fuel prices, the economy, regulations or customer behavior. For example, the Utilities purchase electricity and fuel in the open ma rketmarket as part of their normal operating businesses. If market prices rise, especially in a time when larger than expected volumes must be purchased at market or short-term prices, PacifiCorp or MidAmerican Energy may incur significantly greater expense than anticipated. Likewise, if electricity market prices decline in a period when PacifiCorp or MidAmerican Energy is a net seller of electricity in the wholesale market, PacifiCorp or MidAmerican Energy will earn less revenue.
Our subsidiaries are subject to counterparty credit risk, which could adversely affect our consolidated financial results.
Our subsidiaries are subject to counterparty credit risk related to contractual obligations with wholesale suppliers, customers and, as is the case for MidAmerican Energy, other participants in organized RTO markets. Adverse economic conditions or other events affecting counterparties with whom our subsidiaries conduct business could impair the ability of these counterparties to timely pay for services. Our subsidiaries depend on these counterparties to remit payments on a timely basis. For example, certain wholesale suppliers, customers and other RTO market partici pantsparticipants experienced deteriorating credit quality in 2008 and 2009, and this trend continued, though on a limited basis, in 2010.2009. If our wholesale customers are unable to pay us for energy, there may be a significant adverse impact on our consolidated financial results.
Transactional activities of MidAmerican Energy and other participants in organized RTO markets are governed by credit policies specified in each respective RTO's governing tariff and related business practices. Credit policies of RTO's, which have been developed through extensive stakeholder participation, generally seek to minimize potential loss in the event of a market participant default without unnecessarily inhibiting access to the marketplace. In the event of a default by a RTO market participant on its market-related obligations, losses are allocated among all other market participants in proportion to each participant's share of overall market activity during the period of time the loss was incurred. Because of this, MidAmerican Energy has potential indirect exposure to every other market participant in the RTO markets where it actively participates, including the MISO, the PJM, and the ERCOT.
We continue to monitor the creditworthiness of wholesale suppliers and customers in an attempt to reduce the impact of any potential counterparty default. If strategies used to minimize these risk exposures are ineffective or if our subsidiariessubsidiaries' wholesale customers' financial condition deteriorates as a result of economic conditions causing them to be unable to pay, significant losses could result. Although our subsidiaries monitor the creditworthiness of their customers in an attempt to reduce the impact of any potential counterparty default, defaults in payment could adversely affect our consolidated financial results.
Our subsidiaries are subject to counterparty performance risk, which could adversely affect our consolidated financial results.
Our subsidiaries are subject to counterparty performance risk related to performance of contractual obligations by wholesale suppliers, customers and, as is the case for MidAmerican Energy, other participants in organized RTO markets. Each subsidiary relies on wholesale suppliers to deliver commodities, primarily natural gas, coal a ndand electricity, in accordance with short- and long-term contracts. Failure or delay by suppliers to provide these commodities pursuant to existing contracts could disrupt the delivery of electricity and require the utilities to incur additional expenses to meet customer needs. In addition, when these contracts terminate, the utilities may be unable to purchase the commodities on terms equivalent to the terms of current contracts.
Our subsidiaries rely on wholesale customers to take delivery of the energy they have committed to purchase. Failure of customers to take delivery may require these subsidiaries to find other customers to take the energy at lower prices than the original customers committed to pay. If our subsidiaries' wholesale customers are unable to fulfi llfulfill their obligations, there may be a significant adverse impact on our consolidated financial results.
Our subsidiaries are subject to the risk that customers will not renew their contracts or that our subsidiaries will be unable to obtain new customers for expanded capacity, each of which could adversely affect our consolidated financial results.
Certain of our subsidiaries are dependent upon a relatively small number of customers for a significant portion of their revenu e.revenue. For example:
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• | a significant portion of our pipeline subsidiaries' capacity is contracted under long-term arrangements, and our pipeline subsidiaries are dependent upon relatively few customers for a substantial portion of their revenue; and |
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• | generally, a single power purchaser takes electricity from each of our Philippine and United States qualifying generating facilities. |
a significant portion of the Pipeline Companies' capacity is contracted under long-term arrangements, and the Pipeline Companies are dependent upon relatively few customers for a substantial portion of their revenue; and
generally, a single power purchaser takes electricity from our Philippine hydroelectric generating facility and each of our United States qualifying generating facilities and, when commercially operational, from our unregulated solar-powered projects.
If our subsidiaries are unable to renew, remarket, or find replacements for their long-term arrangements,customer agreements on favorable terms, our sales volumes and operating revenue would be exposed to reduction and increased volatility. For example, without the benefit of long-term transportation agreements, we cannot assure that our pipeline subsidiariesthe Pipeline Companies will be able to transport natural gas at efficient capacity levels. Similarly, without long-term power purchase agreements, we cann otcannot assure that our unregulated power generators will be able to operate profitably. Failure to maintain existing long-term agreements or secure new long-term agreements, or being required to discount rates significantly upon renewal or replacement, could adversely affect our consolidated financial results. The replacement of any existing long-term agreements depends on market conditions and other factors that may be beyond our subsidiaries' control.
Disruptions in the financial markets could affect our and our subsidiaries' ability to obtain debt financing, draw upon or renew existing credit facilities, and have other adverse effects on us and our subsidiaries.
During 2008 and early 2009, the United States, the United Kingdom and global credit markets experienced historic dislocations and liquidity disruptions that caused financing to be unavailable in manycertain cases. These circumstances materially impacted liquidity in the bank and debt capital markets during this period, making financing terms less attractive for borrowers that were able to find financing, and in other cases resulted in the unavailability of certain types of debt financing. It is difficult to predict how the financial markets will react toWhile there has been a gradual recovery in the United States federal government's continued involvement or gradual withdrawal or removal of certaineconomy and an improvement in its financial markets, there remains much financial and economic stimulus programs.uncertainty on a global basis, especially in the European community, which may adversely affect the United States' credit markets. Uncertainty in the credit markets may negatively impact our and our subsidiaries' ability to access funds on favorable terms or at all. If we or our subsidiaries are unable to access the bank and debt markets to meet liquidity and capital expenditure needs, it may adversely affect the timing and amount of our capital expenditures, acquisition financing and our consolidated financial results.
Inflation and changes in commodity prices and fuel transportation costs may adversely affect our consolidated financial results.
Inflation may affect our businesses by increasing both operating and capital costs. As a result of existing rate agreements, andcontractual arrangements or competitive price pressures, our subsidiaries may not be able to pass the costs of inflation on to their customers. If our subsidiaries are unable to manage cost increases or successfully pass them on to their customers, our consolidated financial results could be adversely affected.
Some of our subsidiaries' financial results may be adversely affected if they are unable to obtain adequate, reliable and affordable access to electricity transmission service and natural gas transportation.
Some of our subsidiaries depend on electricity transmission and natural gas transportation facilities owned and operated by other companies to transport electricity and natural gas to both wholesale and retail markets, as well as natural gas purchased to supply somecertain of our subsidiaries' generating facilities. If adequateA lack of available transmission and transportation is unavailable, our subsidiaries may be unable to purchase and sell and deliver products. A lack of availability could also hinder our subsidiaries from providing adequate or cost-effective electricity or natural gas to their wholesale markets and retail electric and natural gas customers and could adversely affect our consolidated financial results.
The different regional power markets have varying and dynamic regulatory structures, which could affect our businesses' growth and performance. In addition, the independent system operators who oversee the transmission systems in certain portions of the regional power markets in which we transact have imposed in the past, and may impose in the future, price limitations and other mechanisms to counter volatility in the power markets. These types of price limitations and other mechanisms may adversely affect our consolidated financial results.
Our operating results may fluctuate on a seasonal and quarterly basis and may be adversely affected by weather.
In most parts of the United States and other markets in which our subsidiaries operate, demand for electricity peaks during the hot summer months when irrigation and cooling needs are higher. Market prices for electricity also generally peak at that time. In other areas, demand for electricity peaks during the winter. In addition, demand for natural gas and other fuels generally peaks during the winter when heating needs are higher. This is especially true in Northern Natural Gas' market area and MidAmerican Energy's retail natural gas business. Further, extreme weather conditions, such as heat waves, winter storms or floods could cause these seasonal fluctuations to be more pronounced. Periods of low rainfall or snowpack may impact electricity gene rationgeneration at PacifiCorp's hydroelectric generating facilities, which may result in greater purchases of electricity from the wholesale market or from other sources at market prices. Additionally, the Utilities have added substantial wind-powered generationgenerating capacity, and our unregulated businesses are adding solar-powered generating capacity, each of which is also a climate-dependent resource.
As a result, the overall financial results of our subsidiaries may fluctuate substantially on a seasonal and quarterly basis. We have historically sold less energy, and consequently earned less income, when weather conditions are mild. Unusually mild weather in the future may adversely affect our consolidated financial results through lower revenue or margins. Conversely, unusually extreme weather conditions could increase our costs to provide energy and could adve rselyadversely affect our consolidated financial results. The extent of fluctuation in our consolidated financial results may change depending on a number of factors related to our subsidiaries' regulatory environment and contractual agreements, including their ability to recover energy costs, the existence of revenue sharing provisions and terms of the wholesale sale contracts.
Our subsidiaries are subj ectsubject to operating uncertainties that could adversely affect our consolidated financial results.
The operation of complex, integrated electric and natural gas utility (including generation, transmission and distribution) systems or interstate natural gas pipeline systems that are spread over large geographic areas involves many operating uncertainties and events beyond our control. These potential events include the breakdown or failure of electricity generating equipment, compressors, pipelines, transmission and distribution lines or other equipment or processes; unscheduled generating facility outages; strikes, lockouts or other labor-related actions; shortage of qualified labor; transmission and distribution system constraints or outages; cyber attacks; fuel shortages or interruptions; unavailab ilityunavailability of critical equipment, materials and supplies; low water flows and other weather-related impacts; performance below expected levels of output, capacity or efficiency; operator error and catastrophic events such as severe storms, floods, fires, earthquakes, explosions, orand mining accidents. A casualty occurrencecatastrophic event might result in injury or loss of life, extensive property damage or environmental damage. Any of these risks or other operational risks could significantly reduce or eliminate our subsidiaries' revenue or significantly increase their expenses, thereby reducing the availability of distributions to us. For example, if our subsidiaries cannot operate their electricity or natural gas facilities at full capacity due to damage caused by a catastrophic event, their revenue could decrease and their expenses could increase due to the need to obtain energy from more expensive sources. Further, we and our subsidiaries self-insure many risks, and current and future insurance coverage may not be sufficient to replace lost revenue or cover repair and replacement costs. The scope, cost and availability of our and our subsidiaries' insurance coverage may change, including the portion that is self-insured. Any reduction of our subsidiaries' revenue or increase in their expenses resulting from the risks described above, could adversely affect our consolidated financial results.
Potential terrorist activities or military or other actions, including cyber attacks, could adversely affect our consolidated financial results.
The ongoing thre atthreat of terrorism and the impact of military and other actions by the United States and its allies createscreate increased political, economic and financial market instability, which subjects our subsidiaries' operations to increased risks. The United States government has issued warnings that energy assets, specifically pipeline, nuclear generation and other electric utility infrastructure are potential targets for terrorist organizations. Cyber attacks could adversely affect our subsidiaries' ability to operate their facilities, information technology and business systems, or compromise confidential customer and employee information. Political, economic or financial market instability or damage to the operating assets of our subsidiaries, customers or suppliers may result in business interruptions, lost revenue, higher commodity prices, disruption in fuel supplies, lower energy consumption and unstable markets, particularly with respect to electricity and natural gas, increased security, repair or other costs that may materially adversely affect us and our subsidiaries in ways that cannot be predicted at this time. Any of these risks could materially affect our consolidated financial results. Furthermore, ins tabilityinstability in the financial markets as a result of terrorism, sustained or significant cyber attacks, or war could also materially adversely affect our ability and the ability of our subsidiaries to raise capital.
MidAmerican Energy is subject to the unique risks associated with nuclear generation.
The ownership and operation of nuclear power plants, such as MidAmerican Energy's 25% ownership interest in Quad Cities Station, involves certain risks. These risks include, among other items, mechanical or structural probl ems,problems, inadequacy or lapses in maintenance protocols, the impairment of reactor operation and safety systems due to human error, the costs of storage, handling and disposal of nuclear materials, limitations on the amounts and types of insurance coverage commercially available, and uncertainties with respect to the technological and financial aspects of decommissioning nuclear facilities at the end of their useful lives. The prolonged unavailability of Quad Cities Station could materially adversely affect MidAmerican Energy's financial results, particularly when the cost to produce power at the plant is significantly less than market wholesale prices. The following are among the more significant of these risks:
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• | Operational Risk - Operations at any nuclear power plant could degrade to the point where the plant would have to be shut down. If such degradations were to occur, the process of identifying and correcting the causes of the operational downgrade to return the plant to operation could require significant time and expense, resulting in both lost revenue and increased fuel and purchased electricity costs to meet supply commitments. Rather than incurring substantial costs to restart the plant, the plant could be shut down. Furthermore, a shut-down or failure at any other nuclear plant could cause regulators to require a shut-down or reduced availability at Quad Cities Station.
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• | Regulatory Risk - The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with the Atomic Energy Act applicable regulations or the terms of the licenses of nuclear facilities. Unless extended, the NRC operating licenses for Quad Cities Station will expire in 2032. Changes in regulations by the NRC could require a substantial increase in capital expenditures or result in increased operating or decommissioning costs.
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• | Nuclear Accident Risk - Accidents and other unforeseen problems have occurred at nuclear facilities other than Quad Cities Station, both in the United States and elsewhere. The consequences of an accident can be severe and include loss of life and property damage. Any resulting liability from a nuclear accident could exceed MidAmerican Energy's resources, including insurance coverage.
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41Operational Risk - Operations at any nuclear power plant could degrade to the point where the plant would have to be shut down. If such degradations were to occur, the process of identifying and correcting the causes of the operational downgrade to return the plant to operation could require significant time and expense, resulting in both lost revenue and increased fuel and purchased electricity costs to meet supply commitments. Rather than incurring substantial costs to restart the plant, the plant could be shut down. Furthermore, a shut-down or failure at any other nuclear plant could cause regulators to require a shut-down or reduced availability at Quad Cities Station.
Regulatory Risk - The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with the Atomic Energy Act applicable regulations or the terms of the licenses of nuclear facilities. Unless extended, the NRC operating licenses for Quad Cities Station will expire in 2032. Changes in regulations by the NRC could require a substantial increase in capital expenditures or result in increased operating or decommissioning costs.
Nuclear Accident and Catastrophic Risks - Accidents and other unforeseen catastrophic events have occurred at nuclear facilities other than Quad Cities Station, both in the United States and elsewhere, such as at the Fukushima Daiichi nuclear plant in Japan as a result of the earthquake and tsunami in March 2011. The consequences of an accident or catastrophic event can be severe and include loss of life and property damage. Any resulting liability from a nuclear accident or catastrophic event could exceed MidAmerican Energy's resources, including insurance coverage.
We own investments and projects located in foreign countries that are exposed to increased economic, regulatory and political risks.
We own and may acquire significant energy-related investments and projects outside of the United States. In addition to any disruption in the global financial markets, the economic, regulatory and political conditions in some of the countries where we have operations or are pursuing investment opportunities may present increased risks related to, among others, inflation, foreign currency exchange rate fluctuations, currency repatriation restrictions, nationalization, renegotiation, privatization, availability of financing on suitable terms, customer creditworthiness, construction delays, business interruption, political instability, civil unrest, guerilla activity, terrorism, expropriation, trade sanctions, contract nullification and changes in law, regulations or tax policy. We may not be capable of either fully insuring against or effectively hedging these risks.
We are exposed to risks related to fluctuations in foreign currency exchange rates.
Our business operations and investments outside the United States increase our risk related to fluctuations in foreign currency exchange rates, primarily the British pound. Our principal reporting currency is the United States dollar, and the value of the assets and liabilities, earnings, cash flows and potential distributions from our foreign operations changes with the fluctuations of the currency in which they transact. We may selectively reduce some foreign currency exchange rate risk by, among other things, requiring contracted amounts be settled in, or indexed to, United States dollars indexing contracts to theor a currency freely convertible into United States dollardollars, or hedging through foreign currency derivatives. These efforts, however, may not be effective and could negatively affect our consolidated financial results. We attempt, in many circumstances, to structure foreign transactions to provide for payments to be made in, or indexed to, United States dollars or a currency freely convertible into United States dollars. We may not be able to obtain sufficient dollars or other hard currency or available dollars may not be allocated to pay such obligations, which could adversely affect our consolidated financial results.
Cyclical fluctuations in the residential real estate brokerage and mortgage businesses could adversely affect HomeServices.
The residential real estate brokerage and mortgage industries tend to experience cycles of greater and lesser activity and profitability and are typically affected by changes in economic conditions, including the current downturn in the United States housing market, which are beyond HomeServices' control. Any of the following, among others, are examples of items that could have a material adverse effect on HomeServices' businesses by causing a general decline in the number of home sales, sale prices or the number of home financings which, in turn, would adversely affect its financial results:
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• | rising interest rates or unemployment rates, including the significant rise in unemployment in the United States which may continue into future periods; |
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• | periods of economic slowdown or recession in the markets served, such as the significant adverse changes in the economy experienced in 2008 and 2009; |
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• | decreasing home affordability; |
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• | lack of avail able mortgage credit for potential homebuyers, such as the reduced availability of credit generally experienced in 2008 and 2009 and that may continue into future periods; |
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• | declining demand for residential real estate as an investment; |
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• rising interest rates or unemployment rates, including the significant rise in unemployment in the United States which may continue into future periods; periods of economic slowdown or recession in the markets served, such as the significant adverse changes in the economy experienced in recent years; decreasing home affordability; lack of available mortgage credit for potential homebuyers, such as the reduced availability of credit generally experienced in recent years and that may continue into future periods; declining demand for residential real estate as an investment; nontraditional sources of new competition; and changes in applicable tax law.
| nontraditional sources of new competition; and |
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• | changes in applicable tax law. |
Poor performance of plan and fund investments and other factors impacting the pension and other postretirement benefit plans and nuclear decommissioning and mine reclamation trust funds could unfavorably impact our cash flows and liquidity.
Costs of providing our defined benefit pension and other postretirement benefit plans depend upon a number of factors, including the rates of return on plan assets, , the level and nature of benefits provided, discount rates, the interest rates used to measure required minimum funding levels, changes in benefit design, changes in laws and government regulation and our required or voluntary contributions made to the plans. OurAll of our pension plans and PacifiCorp's other postretirement benefit plansplan are in underfunded positions. Even with sustained growth in the investments over future periods to increase the value of these plans' assets, we will likely be required to make significant cash contributions to fund these plans in the future. Additionally, our plans have investments in sovereign debt and foreign currency denominated securities. Credit rating downgrades and default by the entities in which our plans have invested could add to the volatility and timing of future contributions. Furthermore, the Pension Protection Act of 2006, as amended, may result in more volatility in the amount and timing of future contributions. Similarly, for example, funds dedicated to nuclear decommissioning and mine reclamation are invested in equitydebt and fixed incomeequity securities and poor performance of these investments will reduce the amount of funds available for their intended purpose, which would require us to make additional cash contributions. Such cash funding obligations, which are also impacted by the other factors described above, could have a material impact on our liquidity by reducing our cash flows.
We and our subsidiaries are involved in numerous legal proceedings, the outcomes of which are uncertain and could adversely affect our consolidated financial results.
We and our subsidiaries are party to numerous legal proceedings. Litigation is subject to many uncertainties, and we cannot predict the outcome of individual matters. It is possible that the final reso lutionresolution of some of the matters in which we and our subsidiaries are involved could result in additional payments in excess of established reserves over an extended period of time and in amounts that could have a material adverse effect on our consolidated financial results. Similarly, it is also possible that the terms of resolution could require that we or our subsidiaries change business practices and procedures, which could also have a material adverse effect on our consolidated financial results. Further, litigation could result in the imposition of financial penalties or injunctions which could limit our ability to take certain desired actions or the denial of needed permits, licenses or regulatory authority to conduct our business, including the siting or permitting of facilities. Any of these outcomes could adversely affect our consolidated financial results.
Potential changes in accounting standards may impact our consolidated financial results and disclosures in the future, which may change the way analysts measure our business or financial performance.
The Financial Accounting Standards Board ("FASB") and the SEC continuously make changes to accounting standards and disclosure and other financial reporting requirements. New or revised accounting standards and requirements issued by the FASB or the SEC or new accounting orders issued by the FERC could significantly impact our consolidated financial results and disclosures.
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| Item 1B. | Unresolved Staff Comments |
Item 1B.Unresolved Staff Comments
Not applicable.
Item 2. Properties
The Company's energy properties consist of the physical assets necessary to support its electricity and natural gas businesses. Properties of the Company's electricity businesses include electric generation, transmission and distribution facilities, as well as coal mining assets that support certain of the Company's electric generating facilities. Properties of the Company's natural gas businesses include natural gas distribution facilities, interstate pipelines, storage facilities, compressor stations and meter stations. In addition to these physical assets, the Company has rights-of-way, mineral rights and wat erwater rights that enable the Company to utilize its facilities. It is the opinion of the Company's management that the principal depreciable properties owned by the Company are in good operating condition and are well maintained. Pursuant to separate financing agreements, substantially all or mostof PacifiCorp's electric utility properties and substantially all of the propertiesassets of each of MEHC's subsidiaries (except MidAmericanCordova Energy Northern Natural Gas, CE Electric UK and CE Casecnan)Company LLC are pledged or encumbered to support or otherwise provide the security for thetheir related subsidiary debt. For additional information regarding the Company's energy properties, refer to Item 1 of this Form 10-K and Notes 3, 4 and 22 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
The following table summarizes the electric generating facilities of MEHC's subsidiaries as of December 31, 2010:2011:
| | | | | | | | |
| | | | | | | Facility Net | | Net Owned |
| Energy | | | | | | Capacity | | Capacity |
| Source | | Entity | | Location by Significance | | (MW) | | (MW) |
| | | | | | | | | |
| Coal | | PacifiCorp and MidAmerica n Energy | | Iowa, Wyoming, Utah, Arizona, Colorado and Montana | | 14,369 | | 9,568 |
| | | | | | | | | |
| Natural gas and other | | PacifiCorp, MidAmerican Energy and CalEnergy U.S. | | Utah, Iowa, Illinois, Washington, Oregon, Texas, New York and Arizona | | 4,876 | | 4,358 |
| | | | | | | | | |
| Wind | | PacifiCorp and MidAmerican Energy | | Iowa, Wyoming, Washington and Oregon | | 2,324 | | 2,316 |
| | | | | | | | | |
| Hydroelectric | | PacifiCorp, MidAmerican Energy, CalEnergy Philippines and CalEnergy U.S. | | Washington, Oregon, The Philippines, Idaho, California, Utah, Hawaii, Montana, Illinois and Wyoming | | 1,320 | | 1,293 |
| | | | | | | | | |
| Nuclear | | MidAmerican Energy | | Illinois | | 1,783 | | 446 |
| | | | | | | | | |
| Geothermal | | PacifiCorp and CalEnergy U.S. | | California and Utah | | 361 | | 198 |
| | | | | Total | |
25,033 | | 18,179 | |
| | | | | | | | |
| | | | | | | Facility Net | | Net Owned |
| Energy | | | | | | Capacity | | Capacity |
| Source | | Entity | | Location by Significance | | (MW) | | (MW) |
| | | | | | | | | |
| Coal | | PacifiCorp and MidAmerican Energy | | Iowa, Wyoming, Utah, Arizona, Colorado and Montana | | 14,326 | | 9,538 |
| | | | | | | | | |
Natural gas and other | | PacifiCorp, MidAmerican Energy and MidAmerican Renewables | | Utah, Iowa, Illinois, Washington, Oregon, Texas, New York and Arizona | | 4,829 | | 4,311 |
| | | | | | | | | |
| Wind | | PacifiCorp and MidAmerican Energy | | Iowa, Wyoming, Washington and Oregon | | 2,918 | | 2,909 |
| | | | | | | | | |
| Hydroelectric | | PacifiCorp, MidAmerican Energy and MidAmerican Renewables | | Washington, Oregon, The Philippines, Idaho, California, Utah, Hawaii, Montana, Illinois and Wyoming | | 1,308 | | 1,281 |
| | | | | | | | | |
| Nuclear | | MidAmerican Energy | | Illinois | | 1,760 | | 440 |
| | | | | | | | | |
| Geothermal | | PacifiCorp and MidAmerican Renewables | | California and Utah | | 361 | | 198 |
| | | | | Total | | 25,502 | | 18,677 |
The right to construct and operate the Company's electric transmission and distribution facilities and interstate natural gas pipelines across certain property was obtained in most circumstances through negotiations and, where necessary, through the exercise of the power of eminent domain. PacifiCorp, MidAmerican Energy, Northern Natural Gas and Kern River in the United States and Northern ElectricPowergrid (Northeast) Limited and Yorkshire ElectricityNorthern Powergrid (Yorkshire) plc in the United KingdomGreat Britain continue to have the power of eminent domain in each of the jurisdictions in which they operate their respective facilities, but the United States utilities do not have the power of eminent domain with respect to governmental or Native American tribal lands. Although the main Kern River pipeline crosses the Moapa Indian Reservation, all facilities in the Moapa Indian Reservation are located within a utility corridor that is reserved to the United States Department of Interior, Bureau of Land Management.
With respect to real property, each of the electric transmission and distribution facilities and interstate natural gas pipelines fall into two basic categories: (1) parcels that are owned in fee, such as certain of the electric generation stations, electric substations, natural gas compressor stations, natural gas meter stations and office sites; and (2) parcels where the interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for the construction, operation and maintenance of the electric transmission and distribution facilities and interstate natural gas pipelines. The Company believes that each of its energy subsidiaries has satisfactory title to all of the real property making up their respective facilities in all material respects.
Item 3. Legal Proceedings
The Company is party to a variety ofNone
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| Item 4. | Mine Safety Disclosures |
Information regarding the Company's mine safety violations and other legal actions arising outmatters disclosed in accordance with Section 1503(a) of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. The Company does not believe that such normal and routine litigation will have a material impact on its consolidated financial results. The CompanyDodd-Frank Reform Act is also involvedincluded in other kinds of legal actions, some of which assert or may assert claims or seekExhibit 95 to impose fines, penalties and other costs in substantial amounts and are described below.this Form 10-K.
CalEnergy Philippines
In February 2002, pursuant to the share ownership adjustment mechanism in the CE Casecnan shareholder agreement, MEHC's indirect wholly owned subsidiary, CE Casecnan Ltd., advised the minority shareholder of CE Casecnan, LaPrairie Group Contractors (International) Ltd. ("LPG"), that MEHC's indirect ownership interest in CE Casecnan had increased to 100% effective from commencement of commercial operations. In 2002, LPG filed a complaint in the Superior Court of the State of California, City and County of San Francisco (the "Superior Court"), against CE Casecnan Ltd. and MEHC. In November 2010, following a series of Superior Court decisions, CE Casecnan Ltd., MEHC and LPG agreed to a settlement of all issues arising out of the litigation. The settlement resulted in LPG having a 15% ownership interest in CE Casecnan and had no material impact on the Consolidated Financial Statements.
In July 2005, MEHC and CE Casecnan Ltd. commenced an action against San Lorenzo Ruiz Builders and Developers Group, Inc. ("San Lorenzo") in the District Court of Douglas County, Nebraska (the "District Court"), seeking a declaratory judgment as to San Lorenzo's right to repurchase up to 15% of the shares in CE Casecnan. In January 2006, San Lorenzo filed a counterclaim against MEHC and CE Casecnan Ltd. seeking declaratory relief that it had effectively exercised its option to purchase up to 15% of the shares of CE Casecnan, that it was the rightful owner of such shares and that it was due all dividends previously paid on such shares. In March 2010, a di rected verdict was issued in favor of San Lorenzo. In November 2010, CE Casecnan Ltd., MEHC and San Lorenzo agreed to a settlement of all issues arising out of the litigation and executed a Purchase Agreement and Release whereby, among other items, MEHC purchased San Lorenzo's ownership rights.
Item 4.(Removed and Reserved)
PART II
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| Item 5. | Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
Item 5.Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Se curities
MEHC's common stock is owned by Berkshire Hathaway, Mr. Walter Scott, Jr. and certain of his family members and family controlled trusts and corporations, and Mr. Gregory E. Abel, its Chairman, President and Chief Executive Officer, and has not been registered with the SEC pursuant to the Securities Act of 1933, as amended, listed on a stock exchange or otherwise publicly held or traded. MEHC has not declared or paid any cash dividends on its common stock during the last ten fiscal years and does not presently anticipate that it will declare any dividends on its common stock in the foreseeable future.
For a discussion of unregistered sales of equity securities and regulatory restrictions that limit PacifiCorp's and MidAmerican Energy's ability to pay dividends on their common stock to MEHC, refer to Note 17 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Item 6. Selected Financial Data
The following table sets forth the Company's selected consolidated historical financial data, which should be read in conjunction with the information in Item 7 of this Form 10-K and with the Company's historical Consolidated Financial Statements and notes thereto in Item 8 of this Form 10-K. The selected consolidated historical financial data has been derived from the Company's audited historical Consolidated Financial Statements and notes thereto (in millions).
| | | | Years Ended December 31, | Years Ended December 31, |
| | 2010 | | 2009 | | 2008 | | 2007 | | 2006(1) | 2011 | | 2010 | | 2009 | | 2008 | | 2007 |
| Consolidated Statement of Operations Data: | | | | | | | | | | | | | | | | | | |
| Operating revenue | $ | 11,127 | | | $ | 11,204 | | | $ | 12,668 | | | $ | 12,376 | | | $ | 10,301 | | $ | 11,173 |
| | $ | 11,127 |
| | $ | 11,204 |
| | $ | 12,668 |
| | $ | 12,376 |
|
Net income(2) | 1,310 | | | 1,188 | | | 1,871 | | | 1,219 | | | 943 | | |
Net income(1) | | 1,352 |
| | 1,310 |
| | 1,188 |
| | 1,871 |
| | 1,219 |
|
| Net income attributable to noncontrolling interests | 72 | | | 31 | | | 21 | | | 30 | | | 27 | | 21 |
| | 72 |
| | 31 |
| | 21 |
| | 30 |
|
Net income attributable to MEHC(2) | 1,238 | | | 1,157 | | | 1,850 | | | 1,189 | | | 916 | | |
Net income attributable to MEHC(1) | | 1,331 |
| | 1,238 |
| | 1,157 |
| | 1,850 |
| | 1,189 |
|
| | | | | | | | | | | | | | | | | | | |
| | As of December 31, | As of December 31, |
| | 2010 | | 2009 | | 2008 | | 2007 | | 2006(1) | 2011 | | 2010 | | 2009 | | 2008 | | 2007 |
| Consolidated Balance Sheet Data: | | | | | | | | | | | | | | | | | | |
| Total assets | $ | 45,668 | | | $ | 44,684 | &n bsp; | | $ | 41,441 | | | $ | 39,216 | | | $ | 36,447 | | $ | 47,718 |
| | $ | 45,668 |
| | $ | 44,684 |
| | $ | 41,441 |
| | $ | 39,216 |
|
| Short-term debt | 320 | | | 179 | | | 836 | | | 130 | | | 552 | | 865 |
| | 320 |
| | 179 |
| | 836 |
| | 130 |
|
| Long-term debt, including current maturities: | | | | | | | | | | | | | | | | | | |
| MEHC senior debt | 5,371 | | | 5,371 | | | 5,121 | | | 5,471 | | | 4,479 | | 5,363 |
| | 5,371 |
| | 5,371 |
| | 5,121 |
| | 5,471 |
|
| MEHC subordinated debt | 315 | | | 590 | | | 1,321 | | | 1,125 | | | 1,357 | | 22 |
| | 315 |
| | 590 |
| | 1,321 |
| | 1,125 |
|
| Subsidiary debt | 13,805 | | | 13, 791 | | | 12,954 | | | 13,097 | | | 11,614 | | 13,687 |
| | 13,805 |
| | 13,791 |
| | 12,954 |
| | 13,097 |
|
| Total MEHC shareholders' equity | 13,232 | | | 12, 576 | | | 10,207 | | | 9,326 | | | 8,011 | | 14,092 |
| | 13,232 |
| | 12,576 |
| | 10,207 |
| | 9,326 |
|
| Noncontrolling interests | 176 | | | 267 | | | 270 | | | 256 | | | 242 | | 173 |
| | 176 |
| | 267 |
| | 270 |
| | 256 |
|
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| (1) | Reflects the acquisition of PacifiCorp on March 21, 2006. |
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(2) | Reflects the $646 million after-tax gain recognized on the termination of the Constellation Energy Group, Inc. ("Constellation Energy") merger agreement on December 17, 2008. |
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| Item 7. | Management's Discussion and Analysis of Financial Condition and Results of Operations |
Item 7.Management's Discussion and Analysis of Financial Condition and Results of Operations
The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of the Company during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth and other factors. This discussion should be read in conjunction with Item 6 of this Form 10-K and with the Company's historical Consolid atedConsolidated Financial Statements and Notes to Consolidated Financial Statements in Item 8 of this Form 10-K. The Company's actual results in the future could differ significantly from the historical results.
The reportable segment financial information includes all necessary adjustments and eliminations needed to conform to the Company's significant accounting policies. The differences between the segment amounts and the consolidated amounts, described as "MEHC and Other," relate principally to corporate functions, including administrative costs and intersegment eliminations. Effective December 31, 2011, the Company changed its reportable segments. Northern Natural Gas and Kern River have been aggregated in the reportable segment called MidAmerican Energy Pipeline Group, and CalEnergy Philippines and MidAmerican Renewables, LLC, formerly CalEnergy U.S., have been aggregated in the reportable segment called MidAmerican Renewables. Prior year amounts have been changed to conform to the current presentation.
Results of Operations
Overview
Net income attributable to MEHC for 2011 was $1.331 billion, an increase of $93 million, or 8%, compared to 2010. PacifiCorp's net income was $554 million for 2011, a decrease of $15 million, or 3%, compared to 2010 as higher retail prices approved by regulators, higher customer load and the net impact of the Utah general rate case settlement were more than offset by lower wholesale revenue, higher purchased power costs, lower AFUDC, higher depreciation and amortization, higher operating expense and lower sales of RECs. Net income at MidAmerican Funding was $304 million for 2011, a decrease of $36 million, or 11%, compared to 2010 due to lower wholesale electric margins, resulting from lower average prices and volumes, and the effects of ratemaking on income taxes, partially offset by higher AFUDC, lower interest expense, lower operating expense and lower depreciation and amortization. MidAmerican Energy Pipeline Group's net income was $236 million for 2011, an increase of $11 million, or 5%, compared to 2010 due to lower interest expense and higher AFUDC. Northern Powergrid Holdings' net income was $389 million for 2011, an increase of $113 million, or 41%, compared to 2010 due to higher distribution revenue resulting from lower regulatory provisions and higher tariffs, higher deferred income tax benefits in 2011 related to enacted changes in the United Kingdom's corporate income tax rate and $12 million due to a weaker United States dollar, partially offset by a tax free gain of $45 million recognized on the sale of CE Gas (Australia) Limited in 2010. Additionally, net income attributable to MEHC was favorably impacted by an after-tax charge of $38 million related to the CE Casecnan noncontrolling interest settlement in 2010, lower MEHC subordinated interest expense in 2011 of $16 million, higher variable energy and water delivery fees earned in 2011 on higher rainfall at the Casecnan project totaling $14 million and higher equity income from ETT in 2011 of $10 million, partially offset by charges associated with the early redemption of MEHC subordinated debt in 2011 totaling $24 million and a dividend received in 2010 from BYD Company Limited totaling $6 million.
Net income attributable to MEHC for 2010 was $1.238 billion, an increase of $81 million, or 7%, compared to 2009. Higher net income at PacifiCorp, MidAmerican Energy and CE Electric UK was partially offset by lower net income at Northern Natural Gas, Kern River, CalEnergy Philippines and CalEnergy U.S.2009. PacifiCorp's net income increased primarilywas $569 million for 2010, an increase of $27 million, or 5%, compared to 2009 due to higher retail prices approved by regulators, higher sales of renewable energy credits,RECs, higher benefits associated with deferred net power costs, higher allowances for funds used during construction ("AF UDC")AFUDC and a lower effective income tax rate due to the effects of ratemaking and higher production tax credits, partially offset by lower net wholesale electricity activities, higher depreciation on higher plant placed in-service and higher operating expense. Net income at MidAmerican Energy increasedwas $340 million for 2010, an increase of $13 million, or 4%, compared to 2009 due to higher margins on warmer weather and $21 million of income tax benefits for changes related to the tax capitalization policy for overhead costs and repairs deductions. These improvements were partially offset by higher maintenance costs from plant outages and storm damage. MidAmerican Energy Pipeline Group's net income was $225 million for 2010, a decrease of $49 million, or 18%, compared to 2009 as a result of lower revenue from less favorable market conditions. Net income at Northern Powergrid Holdings was higher at CE Electric UK$276 million for 2010, an increase of $98 million, or 55%, compared to 2009 due to a $45 million tax free gain on the sale of CE Gas (Australia) Limited, the recognition of deferred income tax benefits totaling $25 million upon enactment of the reduction in the United Kingdom corporate income tax rate from 28% to 27%, a $15 million after-tax impairment of certain Australian hydrocarbon exploration and development assets in 2009 and higher distribution reve nue. Net income at Northern Natural Gas and Kern River was lower as a result of lower revenue from less favorable market conditions. CalEnergy Philippines'revenue. Additionally, net income decreased dueattributable to MEHC was unfavorably impacted by the settlement of a noncontrolling interest disputesettlement totaling $38 million, and lower rainfall and related lower revenue earned in 2010. Net income2010 at CalEnergy U.S. decreased due to the expirationCasecnan project totaling $23 million and an after-tax gain in 2009 on the Constellation Energy common stock investment of a favorable power purchase contract in the second quarter of 2009. The results for 2009 included$22 million, partially offset by an after-tax stock-based compensation charge of $75 million in 2009 as a result of the purchase of shares of common stock that were issued upon the exercise of stock options and an after-tax gain on the Constellation Energy common stock investment of $22 million.options.
Net income attributable to MEHC for 2009 was $1.157 billion, a decrease of $693 million, or 37%, compared to 2008. The results for 2009 included an after-tax stock-based compensation charge of $75 million and an after-tax gain on the Constellation Energy common stock investment of $22 million. The results for 2008 included a $646 million after-tax gain recognized on the termination of the Constellation Energy merger agreement in 2008. Excluding the impact of these items, net income attributable to MEHC increased $6 million for 2009 compared to 2008. Higher net income at PacifiCorp, MidAmerican Funding, CalEnergy Philippines and HomeServices and lower United States income taxes on foreign earnings was partially offset by lower net income at Northern Natural Gas, Kern River and CE Electric UK. Net income was higher at PacifiCorp as a result of higher operating income and a lower effective income tax rate, partially offset by higher interest expense. MidAmerican Funding's net income increased due to lower income taxes, which included income tax benefits of $55 million for repairs deductions, partially offset by lower operating income. MidAmerican Funding's operating income was lower due to lower regulated electric margins and higher depreciation and amortization, partially offset by lower maintenance costs as a result of the storm and flood damage in 2008. Net income was higher at CalEnergy Philippines due to higher rainfall and related revenue earned at the Casecnan project and at HomeServices due to lower office closure costs and other operating expenses. Net income at Northern Natural Gas and Kern River was lower as a result of less favorable market conditions, $30 million of after-tax gains on the sale of certain non-strategic operating assets at Northern Natural Gas in 2008 and a lower customer refund liability in 2008 related to Kern River's 2004 rate case of $26 million. Net income was lower at CE Electric UK due primarily to a stronger United States dollar that reduced net income $33 million, lower distribution revenue and a $15 million after-tax impairment of certain Australian hydrocarbon exploration and development assets recognized in 2009.
Segment Results
The reportable segment financial information includes all necessary adjustments and eliminations needed to conform to the Company's significant accounting policies. The differences between the segment amounts and the consolidated amounts, described as "Corporate/other," relate principally to corporate functions, including administrative costs and intersegment eliminations.
Operating revenue and operating income for the Company's reportable segments for the years ended December 31 are summarized as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2010 | | 2009 | | Change | | 2009 | | 2008 | | Change |
| Operating revenue: | | | | | | | | | | | | | | | |
| PacifiCorp | $ | 4,432 | | | $ | 4,457 | | | $ | (25 | ) | | (1 | )% | | $ | 4,457 | | | $ | 4,498 | | | $ | (41 | ) | | (1 | )% |
| MidAmerican Funding | 3,815 | | | 3,699 | | | 116 | | | 3 | | | 3,699 | | | 4,715 | | | (1,016 | ) | | (22 | ) |
| Northern Natural Gas | 624 | | | 689 | | | (65 | ) | | (9 | ) | | 689 | | | 769 | | | (80 | ) | | (10 | ) |
| Kern River | 357 | | | 372 | | | (15 | ) | | (4 | ) | | 372 | | | 443 | | | (71 | ) | | (16 | ) |
| CE Electric UK | 802 | | | 825 | | | (23 | ) | | (3 | ) | | 825 | | | 993 | | | (168 | ) | | (17 | ) |
| CalEnergy Philippines | 105 | | | 147 | | | (42 | ) | | (29 | ) | | 147 | | | 138 | | | 9 | | | 7 | |
| CalEnergy U.S. | 32 | | | 31 | | | 1 | | | 3 | | | 31 | | | 30 | | | 1 | | | 3 | |
| HomeServices | 1,020 | | | 1,037 | | | (17 | ) | | (2 | ) | | 1,037 | | | 1,133 | | | (96 | ) | | (8 | ) |
| Corporate/other | (60 | ) | | (53 | ) | | (7 | ) | | (13 | ) | | (53 | ) | | (51 | ) | | (2 | ) | | (4 | ) |
| Total operating revenue | $ | 11,127 | | | $ | 11,204 | | | $ | (77 | ) | | (1 | )
| $ | 11,204 | | | $ | 12,668 | | | $ | (1,464 | ) | | (12 | ) |
| | | | | | | | | | | | | | | | |
| Operating income: | | | | | | | | | | | | | |
|
| PacifiCorp | $ | 1,055 | | | $ | 1,079 | | | $ | (24 | ) | | (2 | )% | | $ | 1,079 | | | $ | 952 | | | $ | 127 | | | 13 | % |
| MidAmerican Funding | 460 | | | 469 | | | (9 | ) | | (2 | ) | | 469 | | | 590 | | | (121 | ) | | (21 | ) |
| Northern Natural Gas | 274 | | | 337 | | | (63 | ) | | (19 | ) | | 337 | | | 457 | | | (120 | ) | | (26 | ) |
| Kern River | 198 | | | 221 | | | (23 | ) | | (10 | ) | | 221 | | | 305 | | | (84 | ) | | (28 | ) |
| CE Electric UK | 474 | | | 394 | | | 80 | | | 20 | | | 394 | | | 514 | | | (120 | ) | | (23 | ) |
| CalEnergy Philippines | 71 | | | 113 | | | (42 | ) | | (37 | ) | | 113 | | | 103 | | | 10 | | | 10 | |
| CalEnergy U.S. | 17 | | | 15 | & nbsp; | | 2 | | | 13 | | | 15 | | | 15 | | | — | | | — | |
| HomeServices | 17 | | | 11 | | | 6 | | | 55 | | | 11 | | | (58 | ) | | 69 | | | (119 | ) |
| Corporate/other | (64 | ) | | (174 | ) | | 110 | | | 63 | | | (174 | ) | | (50 | ) | | (124 | ) | | * |
| Total operating income | $ | 2,502 | | | $ | 2,465 | | | $ | 37 | | | 2 | | | $ | 2,465 |
| $ | 2,828 | | | $ | (363 | ) | | (13 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2011 | | 2010 | | Change | | 2010 | | 2009 | | Change |
| Operating revenue: | | | | | | | | | | | | | | | |
| PacifiCorp | $ | 4,586 |
| | $ | 4,432 |
| | $ | 154 |
| | 3 | % | | $ | 4,432 |
| | $ | 4,457 |
| | $ | (25 | ) | | (1 | )% |
| MidAmerican Funding | 3,503 |
| | 3,815 |
| | (312 | ) | | (8 | ) | | 3,815 |
| | 3,699 |
| | 116 |
| | 3 |
|
| MidAmerican Energy Pipeline Group | 977 |
| | 981 |
| | (4 | ) | | — |
| | 981 |
| | 1,061 |
| | (80 | ) | | (8 | ) |
| Northern Powergrid Holdings | 1,014 |
| | 802 |
| | 212 |
| | 26 |
| | 802 |
| | 825 |
| | (23 | ) | | (3 | ) |
| MidAmerican Renewables | 161 |
| | 137 |
| | 24 |
| | 18 |
| | 137 |
| | 178 |
| | (41 | ) | | (23 | ) |
| HomeServices | 992 |
| | 1,020 |
| | (28 | ) | | (3 | ) | | 1,020 |
| | 1,037 |
| | (17 | ) | | (2 | ) |
| MEHC and Other | (60 | ) | | (60 | ) | | — |
| | — |
| | (60 | ) | | (53 | ) | | (7 | ) | | (13 | ) |
| Total operating revenue | $ | 11,173 |
| | $ | 11,127 |
| | $ | 46 |
| | — |
| | $ | 11,127 |
| | $ | 11,204 |
| | $ | (77 | ) | | (1 | ) |
| | | | | | | | | | | | | | | | |
| Operating income: | | | | | | | | | | | | | | | |
| PacifiCorp | $ | 1,099 |
| | $ | 1,055 |
| | $ | 44 |
| | 4 | % | | $ | 1,055 |
| | $ | 1,079 |
| | $ | (24 | ) | | (2 | )% |
| MidAmerican Funding | 428 |
| | 460 |
| | (32 | ) | | (7 | ) | | 460 |
| | 469 |
| | (9 | ) | | (2 | ) |
| MidAmerican Energy Pipeline Group | 468 |
| | 472 |
| | (4 | ) | | (1 | ) | | 472 |
| | 558 |
| | (86 | ) | | (15 | ) |
| Northern Powergrid Holdings | 615 |
| | 474 |
| | 141 |
| | 30 |
| | 474 |
| | 394 |
| | 80 |
| | 20 |
|
| MidAmerican Renewables | 106 |
| | 88 |
| | 18 |
| | 20 |
| | 88 |
| | 128 |
| | (40 | ) | | (31 | ) |
| HomeServices | 24 |
| | 17 |
| | 7 |
| | 41 |
| | 17 |
| | 11 |
| | 6 |
| | 55 |
|
| MEHC and Other | (56 | ) | | (64 | ) | | 8 |
| | 13 |
| | (64 | ) | | (174 | ) | | 110 |
| | 63 |
|
| Total operating income | $ | 2,684 |
| | $ | 2,502 |
| | $ | 182 |
| | 7 |
| | $ | 2,502 |
| | $ | 2,465 |
| | $ | 37 |
| | 2 |
|
PacifiCorp
Operating revenue increased $154 million for 2011 compared to 2010 due to higher retail revenue of $350 million, partially offset by lower wholesale and other revenue of $196 million. The increase in retail revenue was due to higher prices approved by regulators of $280 million and higher customer load. Customer load increased 2% due to higher commercial load in Utah and Oregon, higher industrial load in Utah and the impacts of colder weather on residential load in Oregon. The decrease in wholesale and other revenue was due to a 24% decrease in average wholesale prices and a 6% decrease in wholesale volumes. Additionally, wholesale and other revenue decreased $57 million due to lower sales and higher deferrals of RECs, net of amortization, including the general rate case settlement in Utah totaling $30 million.
Operating income increased $44 million for 2011 compared to 2010 due to the higher operating revenue, partially offset by higher depreciation and amortization of $51 million due to higher plant placed in service, higher operating expense of $41 million and higher energy costs of $18 million. Operating expense increased due to the higher plant placed in service, higher salaries and benefit expenses and material and supplies expense in 2011. Energy costs increased as a result of the higher per unit costs of coal and natural gas totaling $94 million, partially offset by energy cost adjustment mechanisms totaling $76 million, which included the impact of the Utah rate case settlement totaling $60 million. Energy supplied increased 1% for 2011 compared to 2010 as a 23% increase in purchased power volumes, higher than average hydroelectric generation and higher wind-powered generation were partially offset by lower generation from natural gas and coal-fueled generating facilities.
Operating revenue decreased $25$25 million for 2010 compared to 2009 due to a decrease in wholesale and other revenue of $212 million, partially offset by higher retail revenue of $144 million and an increase in the sale of renewable energy creditsRECs totaling $43 million. Wholesale and other revenue decreased primarily due to a 17% decrease in average wholesale prices, an 8% decrease in wholesale volumes and the impact of deconsolidating PacifiCorp's coal mining joint venture, Bridger Coal Company ("Bridger Coal"), as a result of adopting authoritative guidance requiring equity method accounting treatment effective January 1, 2010. The lower revenue due to deconsolidating Bridger Coal is largely offse toffset by lower operating expense and depreciation and amortization. Retail revenue increased due to higher prices approved by regulators and higher demand-side management revenue, which is offset by related higher operating expenses, partially offset by lower revenue related to Oregon Senate Bill 408 ("SB 408408") and lower customer usage.
Operating income decreased $24$24 million for 2010 compared to 2009 due to the lower operating revenue, higher depreciation and property taxes associated with recent plant placed in-service and higher maintenance costs primarily due to increased plant overhauls, partially offset by lower energy costs. Energy costs de creaseddecreased due to a decrease in the average cost of purchased electricity and natural gas, lower natural gas volumes and the effects of regulatory cost recovery adjustment mechanisms for net power costs, partially offset by higher transmission costs of $18 million from higher contract rates, higher volumes of purchased electricity and higher coal prices.
Operating revenue decreased $41 million for 2009 compared to 2008 due to a decrease in wholesale and other revenue of $154 million, partially offset by higher retail revenue of $69 million and the sale of renewable energy credits totaling $44 million. The decrease in wholesale and other revenue was due primarily to a 24% decrease in average wholesale prices, partially offset by higher revenue attributable to PacifiCorp's majority owned coal mining operation. The increase in retail revenue was due to higher prices approved by regulators totaling $134 million, partially offset by a 3% decrease in retail volumes. The decrease in retail volumes was principally related to lower average customer usage due to the effect of current economic conditions mainly on industrial customers throughout PacifiCorp's service territory and residential customers in Oregon, partially offset by growth in the average number of commercial a nd residential customers primarily in Utah.
Operating income increased $127 million for 2009 compared to 2008 due to lower energy costs of $305 million, partially offset by the lower operating revenue, higher depreciation and amortization of $68 million due to the addition of new generating facilities and higher operating expenses of $69 million. Energy costs were lower due largely to a 35% decrease in the average cost of purchased electricity on a 4% decrease in the volume of purchased electricity, partially offset by the effects of regulatory cost recovery adjustment mechanisms of $26 million. The addition of the Chehalis natural gas-fired generating facility and new wind-powered generating facilities in the second half of 2008 and during 2009, along with the 2% decrease in overall sales volumes, allowed PacifiCorp to reduce its need for purchased electricity. Operating expenses increased due to higher costs attributable to PacifiCorp's majority owned coal mining operation, higher DSM costs, which are recovered in rates, and increased property taxes driven by increased levels of assessable property.
MidAmerican Funding
MidAmerican Funding's operating revenue and operating income for the years ended December 31 are summarized as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2010 | | 2009 | | Change | | 2009 | | 2008 | | Change |
Operating revenue: | | | | | | | | | | | | | | | |
Regulated electric | $ | 1,779 | | | $ | 1,715 | | | $ | 64 | | | 4 | % | | $ | 1,715 | | | $ | 2,030 | | | $ | (315 | ) | | (16 | )% |
Regulated natural gas | 852 | | | 857 | | | (5 | ) | | (1 | ) | | 857 | | | 1,377 | | | (520 | ) | | (38 | ) |
Nonregulated and other | 1,184 | | | 1,127 | | | 57 | | | 5 | | | 1,127 | | | 1,308 | | | (181 | ) | | (14 | ) |
Total operating revenue | $ | 3,815 | | | $ | 3,699 | | | $ | 116 | | | 3 | | | $ | 3,699 | | | $ | 4,715 | | | $ | (1,016 | ) | | (22 | ) |
| | | | | | | | | | | | | | | |
Operating income: | | | | | | | | | | | | | | | |
Regulated electric | $ | 319 | | | $ | 331 | | | $ | (12 | ) | | (4 | )% | | $ | 331 | | | $ | 470 | | | $ | (139 | ) | | (30 | )% |
Regulated natural gas | 64 | | | 70 | | | (6 | )
| | (9 | ) | | 70 | | | 66 | |
| 4 | | | 6 | |
Nonregulated and other | 77 | | | 68 | | | 9 | | | 13 | | | 68 | | | 54 | | | 14 | | | 26 | |
Total operating income | $ | 460 | | | $ | 469 | | | $ | (9 | ) | | (2 | ) | | $ | 469 | | | $ | 590 | | | $ | (121 | ) | | (21 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2011 | | 2010 | | Change | | 2010 | | 2009 | | Change |
| Operating revenue: | | | | | | | | | | | | | | | |
| Regulated electric | $ | 1,662 |
| | $ | 1,779 |
| | $ | (117 | ) | | (7 | )% | | $ | 1,779 |
| | $ | 1,715 |
| | $ | 64 |
| | 4 | % |
| Regulated natural gas | 769 |
| | 852 |
| | (83 | ) | | (10 | ) | | 852 |
| | 857 |
| | (5 | ) | | (1 | ) |
| Nonregulated and other | 1,072 |
| | 1,184 |
| | (112 | ) | | (9 | ) | | 1,184 |
| | 1,127 |
| | 57 |
| | 5 |
|
| Total operating revenue | $ | 3,503 |
| | $ | 3,815 |
| | $ | (312 | ) | | (8 | ) | | $ | 3,815 |
| | $ | 3,699 |
| | $ | 116 |
| | 3 |
|
| | | | | | | | | | | | | | | | |
| Operating income: | | | | | | | | | | | | | | | |
| Regulated electric | $ | 294 |
| | $ | 319 |
| | $ | (25 | ) | | (8 | )% | | $ | 319 |
| | $ | 331 |
| | $ | (12 | ) | | (4 | )% |
| Regulated natural gas | 66 |
| | 64 |
| | 2 |
| | 3 |
| | 64 |
| | 70 |
| | (6 | ) | | (9 | ) |
| Nonregulated and other | 68 |
| | 77 |
| | (9 | ) | | (12 | ) | | 77 |
| | 68 |
| | 9 |
| | 13 |
|
| Total operating income | $ | 428 |
| | $ | 460 |
| | $ | (32 | ) | | (7 | ) | | $ | 460 |
| | $ | 469 |
| | $ | (9 | ) | | (2 | ) |
Regulated electric operating revenue decreased $117 million for 2011 compared to 2010. Wholesale and other revenue decreased $123 million due to lower volumes of 19% and lower average prices of 8%. Retail revenue increased $6 million due to a 1% increase in customer load.
Regulated electric operating income decreased $25 million for 2011 compared to 2010. The lower operating revenue was partially offset by lower energy costs, operating expense and depreciation and amortization. Energy costs decreased $75 million due to lower purchased energy and lower coal and natural gas generation volumes, as lower wholesale sales prices and higher wind-powered generation made it less economical to dispatch these units, partially offset by the higher average cost of natural gas and coal. Operating expense decreased $9 million due to higher maintenance costs in 2010 from plant outages and storm restoration costs. Depreciation and amortization decreased $8 million due to lower depreciation rates effective June 1, 2011 following the results of a depreciation study. The new rates generally reflect longer estimated useful lives and lower net salvage. The effect of this change is estimated to be $28 million annually based on depreciable plant balances at the time of the change.
Regulated natural gas operating revenue decreased $83 million for 2011 compared to 2010 due to lower wholesale volumes of 30% due to the narrowing of natural gas price spreads and a decrease in the average per-unit cost of gas sold, resulting in lower costs of sales. Regulated natural gas operating income increased $2 million for 2011 compared to 2010 due to lower operating expense.
Nonregulated and other operating revenue decreased $112 million for 2011 compared to 2010 due to lower electricity and natural gas volumes and prices. Nonregulated and other operating income decreased $9 million for 2011 compared to 2010 due to lower margins.
Regulated electric operating revenue increased $64$64 million for 2010 compared to 2009. Retail revenue increased $100 million on higher volumes of 8% due to higher customer usage, primarily as a result of the impacts of favorable weather, and customer growth. Wholesale and other revenue decreased $36 million due to lower average wholesale sales prices and volumes.
Regul atedRegulated electric operating income decreased $12$12 million for 2010 compared to 2009. The higher operating revenue was offset by higher energy costs of $44 million, higher operating expenses of $24 million and higher depreciation and amortization of $8 million. Energy costs increased due to higher coal prices and greater thermal generation as a result of higher retail volumes. Operating expenses increased primarily due to higher maintenance costs from plant outages and storm damage totaling $12 million.
Regulated natural gas operating revenue decreased $5$5 million for 2010 compared to 2009 due to lower wholesale and retail volumes, partially offset by an increase in the average per-unit cost of gas sold, which was passed on to customers. Regulated natural gas operating income decreased $6$6 million for 2010 compared to 2009 due to higher operating expenses.
Nonregulated and other operating revenue increased $57$57 million for 2010 compa redcompared to 2009 due to a 10% increase in electric retail volumes, partially offset by a 3% decrease in electric retail prices. Nonregulated and other operating income increased $9$9 million for 2010 compared to 2009 primarily due to higher electric retail margins.
Regulated electric operat ing revenue decreased $315 million for 2009 compared to 2008. Wholesale and other revenue decreased $288 million due to lower average wholesale sales prices and lower volumes resulting from reduced demand for electricity due to economic conditions and mild temperatures. Retail revenue decreased $27 million on 4% lower volumes due primarily to reduced industrial demand and mild temperatures experienced throughout the service territory in 2009.
Regulated electric operating income decreased $139 million for 2009 compared to 2008. The lower revenue was partially offset by a decrease in the cost of energy of $222 million as a result of lower purchased electricity of $176 million and a lower cost of natural gas of $54 million, which were both due to lower average costs and volumes. The addition of new wind-powered generating facilities in 2008 allowed MidAmerican Energy to replace more expensive sources of electricity. Depreciation and amortization increased $53 million due primarily to the addition of new wind-powered generating facilities. Operating expenses decreased $7 million due largely to lower maintenance costs as a result of the storm and flood damage in 2008, partially offset by higher DSM costs, which are recovered in rates.Pipeline Group
Regulated natural gas operating revenue decreased $520 million for 2009 compared to 2008 due primarily to a reduction in the average per-unit cost of gas sold, which was passed on to customers and resulted in lower cost of sales, and lower sales volumes of 5% as a result of fewer wholesale market opportunities due to lower price spreads and mild weather experienced throughout the service territory in 2009. Regulated natural gas operating income increased $4 million for 2009 compared to 2008, due primarily to lower operating expenses.
Nonregulated and other operating revenue decreased $181 million for 2009 compared to 2008 due to lower gas revenue of $244 million on a 47% decrease in average prices and a 13% decrease in volumes, partially offset by higher electric retail revenue on a 10% increase in volumes. Nonregulated and other operating income increased $14 million for 2009 compared to 2008 due primarily to higher margins on electric retail sales.
Northern Natural Gas
Operating revenue decreased $65$4 million for 20102011 compared to 2009 primarily2010 due to lower transportation and storage revenue from the narrowing of $70 million,natural gas price spreads, partially offset by higher revenue from long-term contracts related to the Apex and 2010 Expansion projects at Kern River totaling $27 million and higher sales of gas and condensate liquids of $7$10 million. Transportation and storage revenue decreased primarily due to lower field area transportation volumes caused by less favorable economic conditions and lower natural gas price spreads and lower rates. Operating income decreased $63$4 million primarily for 2011 compared to 2010 due to the lower operating revenue.revenue and higher depreciation and amortization of $11 million on assets placed in service, partially offset by lower operating expense due to reduced maintenance costs and lower natural gas storage losses.
Operating revenue decreased $80$80 million for 2009 compared to 2008 due to lower transportation revenue of $70 million and lower sales of gas for operational purposes due primarily to lower prices. Transportation revenue decreased due to lower volumes caused by less favorable economic conditions, lower natural gas price spreads and the sale of the Beaver system in 2008. Operating income decreased $120 millionfor 2009 compared to 2008 due to the lower transportation revenue and pre-tax gains on the sale of certain non-strategic operating assets of $50 million in 2008.
Kern River
Operating revenue decreased $15 million for 2010 compared to 2009 due to lower rates at Kern River as a result of the FERC order received in December 200 92009 and lower natural gas price spreads, partially offset by the 2010 Expansion project at Kern River being placed in-servicein service in April 2010.2010 and higher sales of gas and condensate liquids of $7 million. Operating income decreased $23$86 million for 2010 compared to 2009 due to the lower operating revenue and higher depreciation and amortization expense of $9 million.
Northern Powergrid Holdings
Operating revenue increased $212 million for 2011 compared to 2010 due to higher distribution revenue of $197 million and a weaker United States dollar totaling $32 million, partially offset by lower contracting revenue of $11 million and lower revenue of $6 million at CE Gas. Distribution revenue increased due to lower regulatory provisions totaling $126 million and higher tariff rates, partially offset by lower distributed units. Operating income increased $141 million for 2011 compared to 2010 due to the higher distribution revenue and a weaker United States dollar totaling $19 million, partially offset by a tax free gain of $45 million recognized on the sale of CE Gas (Australia) Limited in 2010 and higher distribution costs and depreciation and amortization.
Operating revenue decreased $71$23 million for 2009 compared to 2008 due to lower price spreads and changes in Kern River's customer refund liability related to the 2004 rate case, wh ich resulted in lower revenue of $33 million. Operating income decreased $84 million for 2009 compared to 2008 due to the lower operating revenue and higher depreciation and amortization expense of $15 million.
CE Electric UK
Operating revenue decreased $23 million for 2010 compared to 2009 due to lower contracting revenue of $30 million, lower gas production of $17 million due to the sale of CE Gas (Australia) Limited in September 2010, and the stronger United States dollar totaling $6 million, partially offset by higher distribution revenue of $31 million. Distribution revenue increased due to higher rates implemented April 1, 2010 related to the Distribution Price Control Review and higher volumes, partially offset by unfavorable movements in certain regulatory provisions totaling $77 million. Operating income increased $80$80 million for 2010 compared to 2009 due to a tax free gain of $45 million recognized on the sale of CE Gas (Australia) Limited in 2010, a $20 million impairment of certain Australian hydrocarbon exploration and development assets in 2009 and the higher distribution revenue, partially offset by the lower gas production.
MidAmerican Renewables
Operating revenue increased $24 million for 2011 compared to 2010 due to higher variable energy and variable water delivery fees earned in 2011 from higher rainfall at the Casecnan project. Operating income increased $18 million for 2011 compared to 2010 due to the higher revenue at the Casecnan project, partially offset by higher maintenance costs at an independent power project in the United States.
Operating revenue decreased $41 million and operating income decreased $40 million for 2010 compared to 2009 due to lower than normal rainfall in 2010 and above normal rainfall in 2009 at the Casecnan project, which resulted in lower variable energy and water delivery fees earned in 2010.
HomeServices
Operating revenue decreased $28 million for 2011 compared to 2010 due to a 4% decrease in average home sale prices. Operating income increased $7 million for 2011 compared to 2010 as the lower operating revenue, net of commissions, was more than offset by lower operating expense.
Operating revenue decreased $17 million for 2010 compared to 2009 due to a 7% decrease in closed brokerage units, partially offset by higher average home sale prices. Operating income increased $6 million for 2010 compared to 2009 as the lower operating revenue, net of commissions, was more than offset by lower operating expenses.
MEHC and Other
Operating loss decreased $110 million for 2010 compared to 2009 due to $125 million of stock-based compensation expense in 2009 as a result of the purchase of common stock issued by MEHC upon the exercise of the last remaining stock options that had been granted to certain members of management at the time of Berkshire Hathaway's acquisition of MEHC in 2000.
Consolidated Other Income and Expense Items
Interest Expense
Interest expense for the years ended December 31 is summarized as follows (in millions):
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2011 | | 2010 | | Change | | 2010 | | 2009 | | Change |
| | | | | | | | | | | | |
| Subsidiary debt | $ | 841 |
| | $ | 844 |
| | $ | (3 | ) | | — | % | | $ | 844 |
| | $ | 864 |
| | $ | (20 | ) | | (2 | )% |
| MEHC senior debt and other | 329 |
| | 329 |
| | — |
| | — |
| | 329 |
| | 331 |
| | (2 | ) | | (1 | ) |
| MEHC subordinated debt-Berkshire Hathaway | 13 |
| | 30 |
| | (17 | ) | | (57 | ) | | 30 |
| | 58 |
| | (28 | ) | | (48 | ) |
| MEHC subordinated debt-other | 13 |
| | 22 |
| | (9 | ) | | (41 | ) | | 22 |
| | 22 |
| | — |
| | — |
|
| Total interest expense | $ | 1,196 |
| | $ | 1,225 |
| | $ | (29 | ) | | (2 | ) | | $ | 1,225 |
| | $ | 1,275 |
| | $ | (50 | ) | | (4 | ) |
Interest expense decreased $29 million for 2011 compared to 2010 due to scheduled maturities and principal repayments, partially offset by a weaker United States dollar and the debt issuances at PacifiCorp ($400 million in May 2011), Northern Natural Gas ($200 million in April 2011) and Northern Powergrid Holdings (£151 million in the third quarter of 2010 and £119 million in the first quarter of 2011).
Interest expense decreased $50 million for 2010 compared to 2009 due to scheduled maturities, principal repayments and lower interest rates on variable rate debt.
Capitalized Interest
Capitalized interest decreased $14 million for 2011 compared to 2010 due to lower construction work-in-progress balances at PacifiCorp, partially offset by higher construction work-in-progress balances at MidAmerican Energy and Kern River.
Capitalized interest increased $13 million for 2010 compared to 2009 due to higher construction work-in-progress balances at PacifiCorp.
Interest and Dividend Income
Interest and dividend income decreased $10 million for 2011 compared to 2010 due to an $11 million dividend received in 2010 from BYD Company Limited.
Interest and dividend income decreased $14 million for 2010 compared to 2009 due to interest associated with SB 408 refunds received in 2009 at PacifiCorp, income earned in 2009 related to the Constellation Energy investments and lower average cash balances, partially offset by the dividend received in 2010 from BYD Company Limited.
Other, net
Other, net decreased $59 million for 2011 compared to 2010 due to costs associated with the early redemption of MEHC subordinated debt totaling $40 million, lower equity AFUDC of $17 million and lower Rabbi Trust earnings, partially by the impairment of an asset in 2010 totaling $8 million at MidAmerican Funding. Equity AFUDC decreased due to lower construction work-in-progress balances at PacifiCorp, partially offset by higher construction work-in-progress balances at MidAmerican Energy and Kern River.
Other, net decreased $36 million for 2010 compared to 2009 due primarily to a $37 million pre-tax gain on the Constellation Energy common stock investment in 2009 and the impairment of an asset in 2010 at MidAmerican Funding, partially offset by higher equity AFUDC in 2010, primarily at PacifiCorp and MidAmerican Energy.
Income Tax Expense
Income tax expense increased $96 million for 2011 compared to 2010. The effective tax rates were 18% and 14% for 2011 and 2010, respectively. The increase in the effective tax rate was due to the effects of ratemaking, lower tax benefits received at MidAmerican Energy for changes related to the tax capitalization and repairs deductions policies totaling $26 million and higher United States income taxes on foreign earnings, partially offset by additional production tax credits in 2011 totaling $29 million, higher deferred income tax benefits in 2011 related to enacted changes in the United Kingdom's corporate income tax rate discussed below and lower state income taxes.
In July 2011, the Company recognized $40 million of deferred income tax benefits upon the enactment of a reduction in the United Kingdom corporate income tax rate from 27% to 26% effective April 1, 2011, and a further reduction to 25% effective April 1, 2012. In July 2010, the Company recognized $25 million of deferred income tax benefits upon the enactment of the reduction in the United Kingdom corporate income tax rate from 28% to 27% effective April 1, 2011.
Federal renewable electricity production tax credits are earned on qualifying wind-powered generation placed in service. In 2004, the Utilities began placing qualified wind-powered generation in service and that has continued through 2011. Federal renewable electricity production tax credits are recognized as energy from wind-powered generating facilities is sold based on a per kilowatt rate as prescribed pursuant to the applicable federal income tax law and are eligible for the credit for 10 years from the date the qualifying generating facilities were placed in service. A credit of $0.022 per kilowatt hour was applied to 2011 production.
Income tax expense decreased $84 million for 2010 compared to 2009. The effective tax rates were 14% and 20% for 2010 and 2009, respectively. The decrease in the effective tax rate was primarily due to deferred income tax benefits totaling $25 million upon the enactment of the reduction in the United Kingdom corporate income tax rate from 28% to 27%, additional production tax credits totaling $20 million, a non-taxable gain on the sale of CE Gas (Australia) Limited and higher tax benefits received at MidAmerican Energy for changes related to the tax capitalization policy and repairs deductions totaling $6 million, partially offset by the impact of ratemaking. The benefits for changes to the tax capitalization policy and the repairs deductions were realized as MidAmerican Energy changed the method by which it determines current income tax deductions for overhead costs and repairs on certain of its regulated utility assets, which results in current deductibility for costs that are capitalized for book purposes. Iowa, MidAmerican Energy's largest jurisdiction for rate-regulated operations, requires immediate income recognition of such temporary differences.
Equity Income
Equity income increased $10 million for 2011 compared to 2010 due to continued investment at ETT and higher earnings at CE Generation due to improved results at the gas plants, partially offset by lower earnings at HomeServices' mortgage joint venture due to lower refinancing activity and higher compliance costs.
Equity income decreased $12 million for 2010 compared to 2009 due to lower earnings at CE Generation, primarily due to the expiration of a favorable power purchase contract in the second quarter of 2009 at the Saranac project.
Net Income Attributable to Noncontrolling Interests
Net income attributable to noncontrolling interests decreased $51 million for 2011 compared to 2010 and increased $41 million for 2010 compared to 2009 due to a $54 million pre-tax charge in 2010 related to the CE Casecnan noncontrolling interest settlement.
Liquidity and Capital Resources
Each of MEHC's direct and indirect subsidiaries is organized as a legal entity separate and apart from MEHC and its other subsidiaries. It should not be assumed that the assets of any subsidiary will be available to satisfy MEHC's obligations or the obligations of its other subsidiaries. However, unrestricted cash or other assets that are available for distribution may, subject to applicable law, regulatory commitments and the terms of financing and ring-fencing arrangements for such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to MEHC or affiliates thereof. The long-term debt of subsidiaries may include provisions that allow MEHC's subsidiaries to redeem it in whole or in part at any time. These provisions generally include make-whole premiums. Refer to Note 17 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding the limitation of distributions from MEHC's subsidiaries.
As of December 31, 2011, the Company's total net liquidity was $3.741 billion. The components of total net liquidity are as follows (in millions):
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | Northern | | | | |
| | | | | | MidAmerican | | Powergrid | | | | |
| | MEHC | | PacifiCorp | | Funding | | Holdings | | Other | | Total |
| | | | | | | | | | | | |
| Cash and cash equivalents | $ | 13 |
| | $ | 47 |
| | $ | 1 |
| | $ | 21 |
| | $ | 204 |
| | $ | 286 |
|
| | |
| | | | | | | | | | |
|
| Credit facilities | 552 |
| | 1,355 |
| | 654 |
| | 233 |
| | 50 |
| | 2,844 |
|
| Less: | | | | | | | | | | | |
|
| Short-term debt | (108 | ) | | (688 | ) | | — |
| | (69 | ) | | — |
| | (865 | ) |
Tax-exempt bond support and letters of credit | (25 | ) | | (304 | ) | | (195 | ) | | — |
| | — |
| | (524 | ) |
| Net credit facilities | 419 |
| | 363 |
| | 459 |
| | 164 |
| | 50 |
| | 1,455 |
|
| | | | | | | | | | | | |
Net liquidity before Berkshire Equity Commitment | $ | 432 |
| | $ | 410 |
| | $ | 460 |
| | $ | 185 |
| | $ | 254 |
| | $ | 1,741 |
|
Berkshire Equity Commitment(1) | 2,000 |
| | |
| | |
| | |
| | |
| | 2,000 |
|
| Total net liquidity | $ | 2,432 |
| | |
| | |
| | |
| | |
| | $ | 3,741 |
|
| Unsecured revolving credit facilities: | |
| | |
| | |
| | |
| | |
| | |
|
| Maturity date | 2013 |
| | 2012, 2013 |
| | 2012, 2013 |
| | 2013 |
| | 2013 |
| | |
|
Largest single bank commitment as a % of total revolving credit facilities(2) | 18 | % | | 16 | % | | 23 | % | | 33 | % | | 100 | % | | |
|
| |
| (1) | MEHC has an Equity Commitment Agreement with Berkshire Hathaway (the "Berkshire Equity Commitment") pursuant to which Berkshire Hathaway has agreed to purchase up to $2.0 billion of MEHC's common equity upon any requests authorized from time to time by MEHC's Board of Directors. The proceeds of any such equity contribution shall only be used for the purpose of (a) paying when due MEHC's debt obligations and (b) funding the general corporate purposes and capital requirements of MEHC's regulated subsidiaries. The Berkshire Equity Commitment expires on February 28, 2014. |
| |
| (2) | An inability of financial institutions to honor their commitments could adversely affect the Company's short-term liquidity and ability to meet long-term commitments. |
The above table does not include unused revolving credit facilities and letters of credit for investments that are accounted for under the equity method.
In January 2012, MEHC entered into a $500 million revolving loan agreement with a subsidiary of Berkshire Hathaway that expires June 30, 2012. Refer to Note 9 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding the Company's credit facilities.
In January 2012, subsidiaries of MEHC acquired ownership interests in two solar projects. Refer to Note 23 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding the Company's equity commitments, letters of credit and other related items.
Operating Activities
Operating revenue decreasedNet cash flows from operating activities for the years ended December 31, $168 million2011 and 2010 were $3.220 billion and $2.759 billion, respectively. The increase was primarily due to higher income tax receipts of $270 million mainly attributable to bonus depreciation, improved operating results, changes in collateral posted for derivative contracts and a Kern River customer rate refund in 2010, partially offset by changes in working capital.
Net cash flows from operating activities for the years ended December 31, 2010 and 2009 compared were $2.759 billion and $3.572 billion, respectively. The decrease was mainly due to 2008lower income tax receipts of $391 million due to the impacttiming of repairs deductions and bonus depreciation, changes in collateral posted for derivative contracts, $128 million of net cash flows in 2009 related to the Constellation Energy transaction, which is comprised of $536 million of proceeds received from the foreign currency exchangesale of Constellation Energy common stock and $408 million of income taxes paid on gains recognized on the termination of the Constellation Energy merger agreement in December 2008 and the sale of stock in 2009, higher contributions to pension and other postretirement benefit plans and rate totaling $150 million, lower distribution revenuecase refunds paid in 2010 at Kern River.
In September 2010, the President signed the Small Business Jobs Act into law, extending retroactively to January 1, 2010 the 50% bonus depreciation for qualifying property purchased and placed in service in 2010. In December 2010, the President signed the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of $10 million2010 into law, which provided for 100% bonus depreciation for qualifying property purchased and lower contracting revenueplaced in service after September 8, 2010 and prior to January 1, 2012, and extended 50% bonus depreciation for qualifying property purchased and placed in service after December 31, 2010 and prior to January 1, 2013. As a result of $8 million. Distribution revenue decreasedthe new laws, the Company's cash flows from operations benefited in 2011 and are expected to benefit in 2012 due to certain regulatory provisionsbonus depreciation on qualifying assets placed in service.
Investing Activities
Net cash flows from investing activities for the current regulatory period totaling $16 millionyears ended December 31, 2011 and lower units distributed, partially offset by higher tariff rates. Operating income decreased2010 were $120 million(2.816) billion for 2009 compared to 2008and $(2.484) billion, respectively. The change was primarily due to the impacthigher capital expenditures of $91 million, proceeds received from the foreign currency exchange rate on operating income totaling $73 million, a $20 million impairmentsale of certain Australian hydrocarbon exploration and development assets during the second quarter of 2010 totaling $78 million and net proceeds received from the sale of CE Gas (Australia) Limited during the third quarter of 2010 totaling $59 million and higher depreciationinvestments in companies accounted for under the equity method totaling $58 million.
Net cash flows from investing activities for the years ended December 31, 2010 and amortization2009 were $(2.484) billion and $(2.669) billion, respectively. Capital expenditures decreased $820 million. In January 2009, the Company received $1 billion, plus accrued interest, in full satisfaction of the 14% Senior Notes from Constellation Energy. In July 2009, the Company purchased 225 million shares, representing approximately a 10% interest, of BYD Company Limited common stock for $232 million. Additionally, the Company received proceeds from the sales of certain CE Gas assets in 2010 totaling $137 million, partially offset by higher investments in companies accounted for under the equity method totaling $32 million.
Capital Expenditures
Capital expenditures, which exclude amounts for non-cash equity AFUDC and other non-cash items, by reportable segment for the years ended December 31 are summarized as follows (in millions):
|
| | | | | | | | | | | |
| | 2011 | | 2010 | | 2009 |
| Capital expenditures: | | | | | |
| PacifiCorp | $ | 1,506 |
| | $ | 1,607 |
| | $ | 2,328 |
|
| MidAmerican Funding | 566 |
| | 338 |
| | 439 |
|
| MidAmerican Energy Pipeline Group | 289 |
| | 293 |
| | 250 |
|
| Northern Powergrid Holdings | 309 |
| | 349 |
| | 387 |
|
| Other | 14 |
| | 6 |
| | 9 |
|
| Total capital expenditures | $ | 2,684 |
| | $ | 2,593 |
| | $ | 3,413 |
|
The Company's capital expenditures relate primarily to the Utilities and consisted mainly of the following for the years ended December 31:
2011:
The construction of wind-powered generating facilities at MidAmerican Energy totaling $295 million, which excludes $647 million of costs for which payments are due in December 2013. MidAmerican Energy placed in service 594 MW during 2011 and is constructing an additional 407 MW to be placed in service in 2012.
Transmission system investments totaling $240 million, including permitting and right-of-way costs for the 100-mile high-voltage transmission line being built between the Mona substation in central Utah and the Oquirrh substation in the Salt Lake Valley. A 65-mile segment of the Mona to Oquirrh transmission project will be a single-circuit 500-kV transmission line, while the remaining 35-mile segment will be a double-circuit 345-kV transmission line. The transmission line is expected to be placed in service in 2013.
Emissions control equipment on existing generating facilities totaling $217 million for installation or upgrade of sulfur dioxide scrubbers, low nitrogen oxide burners and particulate matter control systems.
The development and construction of the Lake Side 2 637-MW combined-cycle combustion turbine natural gas-fueled generating facility ("Lake Side 2") totaling $180 million, which is expected to be placed in service in 2014.
Distribution, generation, mining and other infrastructure needed to serve existing and expected demand totaling $1.140 billion.
2010:
Emissions control equipment totaling $348 million.
Transmission system investments totaling $303 million, including construction costs for the first major segment of the Energy Gateway Transmission Expansion Program, a 135-mile, double circuit, 345-kilovolt transmission line between the Populus substation in southern Idaho and the Terminal substation near Salt Lake City, Utah, which was fully placed in-service in 2010.
The development and construction of wind-powered generating facilities totaling $228 million. During 2010, PacifiCorp placed in service a 111 MW wind-powered generating facility, and MidAmerican Energy began contracting for the construction of 594 MW of wind-powered generating projects.
Distribution, generation, mining and other infrastructure needed to serve existing and expected demand totaling $1.066 billion.
2009:
Transmission system investments totaling $715 million, including a major segment of the Energy Gateway Transmission Expansion Program at PacifiCorp.
Emissions control equipment totaling $372 million.
The development and construction of wind-powered generating facilities totaling $250 million, including 127 MW PacifiCorp placed in service in September 2009 and construction costs for PacifiCorp's 111-MW Dunlap Ranch wind-powered generating facility.
Distribution, generation, mining and other infrastructure needed to serve existing and expected demand totaling $1.430 billion.
Additionally, capital expenditures for the years ended December 31, 2011, 2010 and 2009 include costs related to Kern River's expansion projects totaling $174 million, $129 million and $65 million, respectively. The 2010 Expansion project was placed in service in April 2010 and added 145,000 Dth per day of capacity. The Apex Expansion project was placed in service in October 2011 and added 266,000 Dth per day of capacity. The remaining amounts are for ongoing investments in distribution and other infrastructure needed at the other platforms to serve existing and expected demand.
Financing Activities
Net cash flows from financing activities for the year ended December 31, 2011 were $(589) million. Uses of cash totaled $1.924 billion and consisted mainly of $1.548 billion for repayments of subsidiary debt, repayments of MEHC subordinated debt totaling $334 million, including $191 million called and repaid at par value, and net payments to noncontrolling interest totaling $24 million. Sources of cash totaled $1.335 billion and consisted of proceeds from subsidiary debt totaling $790 million and net proceeds from short-term debt totaling $545 million. Debt issuances during the year ended December 31, 2011 included the following:
In May 2011, PacifiCorp issued $400 million of 3.85% First Mortgage Bonds due June 15, 2021. The net proceeds were used to fund capital expenditures, repay short-term debt and for general corporate purposes.
In April 2011, Northern Natural Gas issued $200 million of 4.25% Senior Notes due June 1, 2021. The net proceeds were used to partially repay its $250 million, 7.0% Senior Notes due June 1, 2011.
In January and February 2011, Northern Powergrid (Northeast) Limited issued £119 million of notes with maturity dates ranging from 2018 to 2020 at interest rates ranging from 3.901% to 4.586% under its finance contract with the European Investment Bank.
Net cash flows from financing activities for the year ended December 31, 2010 were $(234) million. Uses of cash totaled $614 million and consisted mainly of repayments of MEHC subordinated debt totaling $281 million, including $92 million called and repaid at par value, repayments of subsidiary debt totaling $192 million, net payments to noncontrolling interests totaling $80 million and net purchases of common stock totaling $56 million. Sources of cash totaled $380 million and consisted of proceeds from subsidiary debt totaling $231 million and net proceeds from short-term debt totaling $149 million.
Net cash flows from financing activities for the year ended December 31, 2009 were $(758) million. Uses of cash totaled $2.0 billion and consisted mainly of repayments of MEHC subordinated debt totaling $734 million, net repayments of short-term debt totaling $664 million, repayments of subsidiary debt totaling $444 million, net purchases of common stock of $123 million and net payments to noncontrolling interests totaling $19 million. Sources of cash totaled $1.242 billion and consisted of proceeds from the issuance of subsidiary debt totaling $992 million and proceeds from the issuance of MEHC senior debt totaling $250 million.
2012 Long-term Debt Transactions
In February 2012, Topaz issued $850 million of the 5.75% Series A Senior Secured Notes. The principal of the notes amortize beginning September 2015 with a final maturity in September 2039. The net proceeds will be used to fund or reimburse the costs and expenses related to the development, construction and financing of the Topaz Project, including amounts that have been advanced by, or will be advanced by, MEHC for the Topaz Project. Any unused amounts will be invested or, in certain circumstances, loaned to MEHC. Topaz expects to issue approximately $430 million of additional senior secured notes contingent upon certain contractual conditions and market conditions to fund construction costs.
In January 2012, PacifiCorp issued $350 million of its 2.95% First Mortgage Bonds due February 1, 2022 and $300 million of its 4.10% First Mortgage Bonds due February 1, 2042. The net proceeds were used to repay short-term debt, fund capital expenditures and for general corporate purposes.
The Company may from time to time seek to acquire its outstanding debt securities through cash purchases in the open market, privately negotiated transactions or otherwise. Any debt securities repurchased by the Company may be reissued or resold by the Company from time to time and will depend on prevailing market conditions, the Company's liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
Future Uses of Cash
The Company has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the issuance of commercial paper, the use of unsecured revolving credit facilities, the issuance of equity and other sources. These sources are expected to provide funds required for current operations, capital expenditures, acquisitions, investments, debt retirements and other capital requirements. The availability and terms under which each subsidiary has access to external financing depends on a variety of factors, including its credit ratings, investors' judgment of risk and conditions in the overall capital market, including the condition of the utility industry in general. Additionally, MEHC has the Berkshire Equity Commitment pursuant to which Berkshire Hathaway has agreed to purchase up to $2.0 billion of MEHC's common equity upon any requests authorized from time to time by MEHC's Board of Directors. The Berkshire Equity Commitment expires on February 28, 2014 and may only be used for the purpose of (a) paying when due MEHC's debt obligations and (b) funding the general corporate purposes and capital requirements of MEHC's regulated subsidiaries. Berkshire Hathaway will have up to 180 days to fund any such request in increments of at least $250 million pursuant to one or more drawings authorized by MEHC's Board of Directors. The funding of any such drawing will be made by means of a cash equity contribution to MEHC in exchange for additional shares of MEHC's common stock.
Capital Expenditures
The Company has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in rules and regulations, including environmental and nuclear; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; and the cost and availability of capital. Prudently incurred expenditures for compliance-related items, such as pollution-control technologies, replacement generation, nuclear decommissioning, hydroelectric relicensing, hydroelectric decommissioning and associated operating costs are generally incorporated into MEHC's energy subsidiaries' regulated retail rates.
Forecasted capital expenditures, which exclude amounts for non-cash equity AFUDC and other non-cash items, for the years ended December 31 are as follows (in millions):
|
| | | | | | | | | | | |
| | 2012 | | 2013 | | 2014 |
Forecasted capital expenditures: | | | | | |
| Construction and other development projects | $ | 2,094 |
| | $ | 2,051 |
| | $ | 1,959 |
|
| Operating projects | 1,753 |
| | 1,426 |
| | 1,638 |
|
| Total | $ | 3,847 |
| | $ | 3,477 |
| | $ | 3,597 |
|
Construction and other development projects consist mainly of large scale projects at MidAmerican Renewables and the Utilities.
In January 2012, MEHC acquired Topaz and its 550-MW Topaz Project in California from a subsidiary of First Solar, Inc. ("First Solar"). The Topaz Project is expected to cost approximately $2.44 billion, including all interest during construction, and will be completed in 22 blocks with an aggregate tested capacity of 586 MW. The Topaz Project expects to place 45 MW in service in 2012, 236 MW in service in 2013, 252 MW in service in 2014 and 53 MW in service in 2015. The Topaz Project is being constructed pursuant to a fixed price, date certain, turn-key engineering, procurement and construction contract with a subsidiary of First Solar.
MEHC has committed to provide Topaz with equity to fund the costs of the Topaz Project in an amount up to $2.44 billion less, among other things, the gross proceeds of long-term debt issuances (including the gross proceeds of $850 million of the 5.75% Series A Senior Secured Notes issued by Topaz in February 2012), project revenue prior to completion and the total equity contributions made by MEHC or its subsidiaries. If MEHC does not maintain a minimum credit rating from two of the following three rating agencies of at least BBB- from Standard & Poor's Ratings Services or Fitch Ratings or Baa3 from Moody's Investors Service, MEHC's obligations under the equity commitment agreement would be supported by cash collateral or a letter of credit issued by a financial institution that meets certain minimum criteria specified in the financing documents. Upon reaching the final commercial operation date of the Topaz Project, MEHC will have no further obligation to make any equity contribution and any unused equity contribution obligations will be canceled.
The Utilities anticipate costs for emissions control equipment will total $1.361 billion between 2012 and 2014, which includes equipment to meet anticipated air quality and visibility targets, including the reduction of sulfur dioxide, nitrogen oxides and particulate matter emissions. This estimate includes the installation of new or the replacement of existing emissions control equipment at a number of units at several of the Utilities coal-fueled generating facilities.
PacifiCorp anticipates costs for transmission projects will total $1.205 billion between 2012 and 2014. The costs include PacifiCorp's Energy Gateway Transmission Expansion Program totaling $905 million, including the following estimated costs:
$245 million for the 100-mile high-voltage transmission line being built between the Mona substation in central Utah and the Oquirrh substation in the Salt Lake Valley. A 65-mile segment of the Mona to Oquirrh transmission project will be a single-circuit 500-kV transmission line, while the remaining 35-mile segment will be a double-circuit 345-kV transmission line. The project is estimated to cost $374 million and is expected to be placed in service in 2013.
$288 million for the 160-mile single-circuit 345-kV transmission line being built between the Sigurd Substation in central Utah and the Red Butte Substation in southwest Utah. The Sigurd to Red Butte project is estimated to cost $380 million and is expected to be placed in service in 2015.
$372 million for other segments associated with the Energy Gateway Transmission Expansion Program that are expected to be placed in service through 2021, depending on siting, permitting and construction schedules.
PacifiCorp anticipates costs for additional natural gas-fueled generating facilities will total $893 million between 2012 and 2014, which includes the construction of the Lake Side 2 natural gas-fueled generating facility that is expected to be placed in service in 2014, and the initial development and construction of another combined-cycle combustion turbine natural gas-fueled generating facility planned to be placed in service in 2016.
MidAmerican Energy is constructing 407 MW (nominal ratings) of wind-powered generation that it expects to place in service in 2012. Total costs are estimated to be $680 million, with the payment of over half of those costs deferred until the fourth quarter of 2015.
MidAmerican Renewables anticipates costs for the Bishop Hill II Project, an 81 MW wind-powered generating facility, will total $164 million in 2012. The Bishop Hill II Project is expected to be placed in service in 2012. Definitive agreements have been executed, subject to customary closing conditions, and the acquisition is expected to close in March 2012.
In December 2011, MidAmerican Energy received approval from the MISO for several MVPs located in Iowa and Illinois totaling approximately $550 million in capital expenditures, the bulk of which will be incurred in 2014-2017. As of December 31, 2011, MidAmerican Energy had not contractually committed to material amounts for these projects.
Separately, in July 2011, the FERC issued Order No. 1000, which addresses transmission planning and cost allocation issues. Among other things, Order No. 1000 removes the federal right of first refusal for certain new transmission investments approved by the MISO following its compliance filing with the FERC. MidAmerican Energy believes its approved MVPs are not subject to the loss of right of first refusal unless the projects are re-evaluated and changed under a three-year review process required by the FERC. MidAmerican Energy continues to actively review other impacts of Order No. 1000.
Capital expenditures related to operating projects consist of routine expenditures for distribution, generation, mining and other infrastructure needed to serve existing and expected demand.
Equity Investments
ETT, a company owned equally by subsidiaries of American Electric Power Company, Inc. and MEHC, owns and operates electric transmission assets in the ERCOT. In order to fund ETT's ongoing transmission investment, MEHC expects to make equity contributions to ETT during 2012, 2013 and 2014 of $107 million, $58 million and $4 million, respectively.
In January 2012, MEHC, through a wholly-owned subsidiary, acquired from NRG Energy, Inc. a 49 percent interest in Agua Caliente, the owner of the 290-MW Agua Caliente Project in Arizona. The Agua Caliente Project is expected to costs approximately $1.8 billion and will be completed in 12 blocks with an aggregate tested capacity of 310 MW. The first 30-MW block of the Agua Caliente Project was placed in service in January 2012 and the Agua Caliente Project expects to place 112 additional MW in service in 2012, 136 MW in service in 2013 and 32 MW in service in 2014. The project is being constructed pursuant to a fixed price, date certain, turn-key engineering, procurement and construction contract with a subsidiary of First Solar. Construction costs are expected to be funded with equity contributions from MEHC and NRG Energy, Inc. and proceeds from a $967 million secured loan maturing in 2037 from an agency of the United States government as part of the United States Department of Energy loan guarantee program. Funding requests are submitted on a monthly basis and the approved loans accrue interest at a fixed rate based on the current average yield of comparable maturity United States Treasury rates plus a spread of 0.375%.
Pursuant to an equity funding and contribution agreement, MEHC has committed to provide Agua Caliente with funding for (a) base equity contributions of up to an aggregate amount of $303 million for the construction of the project, and (b) transmission upgrade costs. In January 2012, MEHC entered into a $303 million letter of credit facility related to its funding commitments. The equity funding and contribution agreement and the letter of credit commitment decreases as equity is contributed to the Agua Caliente Project.
Contractual Obligations
The Company has contractual cash obligations that may affect its consolidated financial condition. The following table summarizes the Company's material contractual cash obligations as of December 31, 2011 (in millions):
|
| | | | | | | | | | | | | | | | | | | | |
| | | Payments Due By Periods |
| | | | | 2013- | | 2015- | | 2017 and | | |
| | | 2012 | | 2014 | | 2016 | | After | | Total |
| | | | | | | | | | | |
| MEHC senior debt | | $ | 742 |
| | $ | 250 |
| | $ | — |
| | $ | 4,375 |
| | $ | 5,367 |
|
| MEHC subordinated debt | | 22 |
| | — |
| | — |
| | — |
| | 22 |
|
| Subsidiary debt | | 434 |
| | 2,043 |
| | 663 |
| | 10,526 |
| | 13,666 |
|
Interest payments on long-term debt(1) | | 1,073 |
| | 1,951 |
| | 1,809 |
| | 12,060 |
| | 16,893 |
|
| Short-term debt | | 865 |
| | — |
| | — |
| | — |
| | 865 |
|
Coal, electricity and natural gas contract commitments(1) | | 1,389 |
| | 1,958 |
| | 1,261 |
| | 3,621 |
| | 8,229 |
|
Construction commitments(1) | | 757 |
| | 466 |
| | 442 |
| | 52 |
| | 1,717 |
|
Operating leases and easements(1) | | 89 |
| | 127 |
| | 71 |
| | 366 |
| | 653 |
|
Maintenance, service and other contracts(1) | | 192 |
| | 172 |
| | 51 |
| | 142 |
| | 557 |
|
| Total contractual cash obligations | | $ | 5,563 |
| | $ | 6,967 |
| | $ | 4,297 |
| | $ | 31,142 |
| | $ | 47,969 |
|
| |
| (1) | Not reflected on the Consolidated Balance Sheets. |
The Company has other types of commitments that arise primarily from unused lines of credit, letters of credit or relate to construction and other development costs (Liquidity and Capital Resources included within this Item 7), asset retirement obligations (Note 13) and uncertain tax positions (Note 15) which have not been included in the above table because the amount and timing of the cash payments are not certain. Additionally, refer to Note 23 for commitments that arose subsequent to December 31, 2011 and that are not included in the above table. Refer, where applicable, to the respective referenced note in Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
Regulatory Matters
MEHC's regulated subsidiaries and certain affiliates are subject to comprehensive regulation. In addition to the discussion contained herein regarding regulatory matters, refer to Item 1 of this Form 10-K for further discussion regarding the general regulatory framework at MEHC's regulated subsidiaries.
PacifiCorp
Utah
In March 2009, PacifiCorp filed for an ECAM with the UPSC. The filing recommended that the UPSC adopt the mechanism to recover the difference between base net power costs set in the next Utah general rate case and actual net power costs. In July 2010, the UPSC issued an order approving a stipulation that would establish deferred accounts for both net power costs and REC revenues in excess of the levels currently included in rates, subject to the UPSC's final determination of the ratemaking treatment of the deferrals. In December 2010, the UPSC approved a separate stipulation that provided a $3 million monthly credit to customers effective January 1, 2011 to be applied toward the UPSC's final decision. In March 2011, the UPSC issued its final order approving the use of an EBA in Utah to begin at the conclusion of the general rate case described below. Under the EBA, which has been established as a four year pilot program, 70% of any difference between actual net power costs incurred and the amount of net power costs recovered through base rates are deferred during the calendar year. PacifiCorp must then file by March 15 of the following year to initiate collection or refund of the deferred balance. In April 2011, PacifiCorp filed a petition with the UPSC for clarification and reconsideration of certain aspects of the EBA order, including reconsideration of the UPSC's decision to exclude financial swaps from the EBA, which was granted in May 2011.
In January 2011, PacifiCorp filed a general rate case with the UPSC requesting a rate increase of $232 million, or an average price increase of 14%. In June 2011, PacifiCorp filed its rebuttal testimony with the UPSC reducing the requested rate increase to $188 million, or an average price increase of 11%. In July 2011, PacifiCorp filed a settlement with the UPSC, which was approved by the UPSC in August 2011 and resulted in a $117 million rate increase, or an average price increase of 7% effective September 21, 2011. The settlement resolved all major dockets outstanding before the UPSC. Under the terms of the settlement, financial swaps are included in the EBA and a collaborative process with Utah stakeholders may result in future modifications to PacifiCorp's risk management and hedging policies. The settlement also concluded the ratemaking treatment of deferred accounts for net power costs and estimated sales of RECs in excess of the levels included in rates since the 2009 general rate case. The settlement provides for $60 million of net power costs in excess of amounts included in base rates to be recovered from Utah customers over a three-year period beginning June 1, 2012, without carrying charges. The settlement also provides for a $33 million credit to customers related to sales of RECs that substantially occurred in prior years and that will be credited to Utah customers over a period of approximately nine months beginning September 21, 2011, plus carrying charges. The settlement also establishes a balancing account for prospective REC sales. The settlement stipulation defers decisions regarding the ratemaking treatment associated with the Klamath hydroelectric system's four mainstem dams and relicensing and settlement costs as described in Note 16 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
In November 2011, PacifiCorp filed with the UPSC to decrease its DSM cost recovery tariff in Utah by 1% of a customer's eligible monthly charges. In January 2012, the UPSC approved an all-party stipulation to reduce the DSM surcharge by 0.4% effective February 1, 2012. In addition, approximately $5 million will be credited to customers over a one-year period beginning June 1, 2012.
In February 2012, PacifiCorp filed a general rate case with the UPSC requesting a rate increase of $172 million, or an average price increase of 10%.
Oregon
In March 2011, PacifiCorp made its initial filing for the annual TAM with the OPUC for an annual increase of $62 million to recover the anticipated net power costs forecasted for calendar year 2012. In July 2011, PacifiCorp filed updated net power costs, reflecting an increase in the overall request to $63 million. In August 2011, PacifiCorp filed its surrebuttal testimony in the TAM proceeding decreasing the overall request to $59 million due to a reduction in forecasted net power costs. In September 2011, PacifiCorp reached a settlement with several parties, including the OPUC staff, to reduce the requested increase to $51 million, or an average price increase of 4%, subject to final net power cost updates in November 2011. In November 2011, the OPUC approved the overall rate increase of $51 million, or an average price increase of 4%. The new rates were effective January 1, 2012.
In October 2010, PacifiCorp filed its 2009 tax report under SB 408. In January 2011, PacifiCorp entered into a stipulation with the OPUC staff and the Citizens' Utility Board of Oregon, whereby PacifiCorp, the OPUC staff and the Citizens' Utility Board of Oregon agreed to a surcharge of $13 million, plus interest. In April 2011, the OPUC issued an order adopting the stipulation without significant modification. The $13 million, plus interest, was recorded in earnings in the second quarter of 2011 and is being collected over a one-year period that began in June 2011.
In May 2011, Oregon Senate Bill 967 ("SB 967") was enacted into law. SB 967 repealed and replaced SB 408, and as a result, PacifiCorp will no longer be required to file tax reports under SB 408. Among other matters, SB 967 directs the OPUC to consider the income tax component of rates when conducting ratemaking proceedings. The enactment of SB 967 did not impact PacifiCorp's consolidated financial results.
Wyoming
In April 2010, PacifiCorp filed an application with the WPSC requesting approval of a new ECAM to replace the existing PCAM. The PCAM concluded with the final deferral of net power costs in November 2010 and collection through March 2012. In February 2011, the WPSC issued an order approving an ECAM effective December 1, 2010, under which 70% of any difference between actual net power costs incurred and the amount of net power costs recovered through base rates, subject to certain other adjustments, are deferred as incurred during the calendar year. PacifiCorp must then file by March 15 of the following year to initiate collection or refund of the deferred balance beginning June 1.
In November 2010, PacifiCorp filed a general rate case with the WPSC requesting a rate increase of $98 million, or an average price increase of 17%. In May 2011, PacifiCorp filed its rebuttal testimony with the WPSC reducing the requested rate increase to $80 million. In June 2011, the WPSC approved a multi-party stipulation resulting in an annual rate increase of $62 million, or an average price increase of 11%. The stipulation also established a surcredit and a balancing account to pass on to or collect from customers any difference between the amount of the REC sales established in the surcredit and actual REC sales. The surcredit will be established annually based on PacifiCorp's forecasted REC sales, and the difference between the surcredit and actual REC sales will be tracked in the balancing account. For 2011, the surcredit was set at $17 million, or a 3% reduction. The rates were effective September 22, 2011.
In February 2011, PacifiCorp filed its final PCAM application with the WPSC requesting recovery of $16 million in deferred net power costs over the 12-month period ending March 31, 2012. PacifiCorp requested and received approval from the WPSC to implement an $11 million interim rate increase over the $5 million reflected in the tariff to be effective from April 1, 2011 until the WPSC issues a final order. In September 2011, PacifiCorp reached an agreement with intervening parties and filed a stipulation with the WPSC to recover $14 million in deferred net power costs. In October 2011, the WPSC approved the stipulation with an effective date of November 1, 2011.
In December 2011, PacifiCorp filed a general rate case with the WPSC requesting an annual increase of $63 million, or an average price increase of 10%. If approved by the WPSC, the new rates are expected to be effective October 9, 2012.
Washington
In May 2010, PacifiCorp filed a general rate case with the WUTC requesting an annual increase of $57 million, or an average price increase of 21%. In November 2010, the requested annual increase was reduced to $49 million, or an average price increase of 18%. In March 2011, the WUTC issued a final order and clarification letter approving an annual increase of $33 million, or an average price increase of 12%, reduced in the first year by a customer bill credit of $5 million, or 2%, related to the sale of RECs expected during the twelve-month period ended March 31, 2012, as well as requiring PacifiCorp to submit additional information to the WUTC regarding the sales of RECs. The new rates were effective in April 2011. Although both PacifiCorp and the WUTC staff filed petitions for reconsideration of various items on the final order, the WUTC denied the petitions for reconsideration. In May 2011 PacifiCorp submitted to the WUTC the additional information required by the March 2011 order regarding PacifiCorp's proceeds from sales of RECs for the period January 1, 2009 forward and a detailed proposal for a tracking mechanism for proceeds of RECs. Intervening parties and WUTC staff are proposing that PacifiCorp refund to customers the amount of REC sales in excess of the amount included in base rates since January 1, 2009. Initial and reply briefs from all parties were filed in November 2011. Oral arguments were held before the WUTC in January 2012, and an order is expected during the first quarter of 2012.
In July 2011, PacifiCorp filed a general rate case with the WUTC requesting an annual increase of $13 million, or an average price increase of 4%, with an effective date no later than June 1, 2012. In February 2012, the parties to the proceeding filed a settlement agreement with the WUTC reflecting an annual increase of $5 million, or an average price increase of 2%. A hearing on the settlement agreement is scheduled for March 2012.
Idaho
In May 2010, PacifiCorp filed a general rate case with the IPUC requesting an annual increase of $28 million, or an average price increase of 14%. In November 2010, the requested annual increase was reduced to $25 million, or an average price increase of 12%. In December 2010, the IPUC issued an interim order approving an annual increase of $14 million, or an average price increase of 7% with an effective date of December 28, 2010. In February 2011, the IPUC issued its final order with no revisions to the December 2010 increase. In March 2011, PacifiCorp petitioned the IPUC seeking reconsideration or rehearing on certain aspects of the order, including the IPUC's conclusion that 27% of PacifiCorp's Populus to Terminal transmission line investment is not currently used and useful and should be carried as plant held for future use. The Idaho-allocated share of 27% of the investment is approximately $13 million. In April 2011, the IPUC issued an order, accepting in part and rejecting in part, PacifiCorp's motion for reconsideration, resulting in no significant changes to the IPUC's initial order. In May 2011, PacifiCorp filed an appeal of the Populus to Terminal decision to the Idaho Supreme Court requesting a determination on the legality of the IPUC's decision to exclude 27% of the Populus to Terminal line as a result of its conclusion that the line is not fully used and useful. As a result of the general rate case settlement process discussed below, PacifiCorp joined in a motion filed with the Idaho Supreme Court in October 2011, to stay the procedural schedule associated with the appeal until January 30, 2012, and the lower distribution revenue.Idaho Supreme Court granted the motion. The matter was settled in the general rate case described below and the appeal was dismissed.
In May 2011, PacifiCorp filed a general rate case with the IPUC requesting an annual increase of $33 million, or an average price increase of 15%. In October 2011, a settlement was reached with the majority of parties in the case providing for a two-year agreement to increase rates by $17 million each year effective January 1, 2012 and January 1, 2013, representing average price increases of 8% and 7%, respectively. The settlement also resolved the dispute over the 27% of PacifiCorp's Populus to Terminal investment, providing for recovery of PacifiCorp's investment beginning on or after January 1, 2014. In January 2012, PacifiCorp received an order from the IPUC approving the settlement.
In February 2011, PacifiCorp filed an ECAM application with the IPUC requesting recovery of $13 million in deferred net power costs. In March 2011, the IPUC issued an order approving recovery of $10 million beginning April 1, 2011 and the remaining $3 million beginning in 2012.
In February 2012, PacifiCorp filed an ECAM application with the IPUC requesting recovery of $18 million in deferred net power costs through an increase to the current ECAM surcharge rate established in 2011. If approved, the new rates will be effective April 1, 2012.
MidAmerican Energy
On February 21, 2012, MidAmerican Energy filed an application with the IUB for an interim and final increase in Iowa retail electric rates in the form of two adjustment clauses to be added to customers' bills. The requested adjustment clauses and a modification to current revenue sharing provisions are consistent with a November 2011 settlement agreement between MidAmerican Energy and the OCA, in which the parties agree to support the proposed changes. The adjustment clauses would recover anticipated increases in retail coal and coal transportation costs and environmental control expenditures subject to an aggregate maximum of $39 million, or 3.4%, for 2012 and an additional $37 million for an aggregate maximum of $76 million for 2013, or a 3.2% increase from 2012. The requested modification to the existing revenue sharing provisions provides for MidAmerican Energy to share with its customers 20% of revenue associated with Iowa electric returns on equity between 10% and 10.5%, 50% of revenue associated with Iowa electric returns on equity between 10.5% and 11.75%, 75% of revenue associated with Iowa electric returns on equity between 11.75% and 13.0% and 83.3% of revenue associated with Iowa electric returns on equity above 13.0%. Such shared amounts would reduce MidAmerican Energy's investment in the Walter Scott, Jr. Energy Center Unit 4. There would be no revenue sharing for Iowa electric returns on equity below 10%. Pursuant to the settlement agreement, MidAmerican Energy is not precluded from seeking interim rate relief in 2013.
Kern River
In December 2009, the FERC issued an order establishing revised rates for the period of Kern River's current long-term contracts ("Period One rates") and required that rates be established based on a levelized rate design for eligible customers to elect to take service following the expiration of their current contracts ("Period Two rates"). The FERC set all other issues related to Period Two rates for hearing. In November 2010, the FERC issued an order that denied all requests for rehearing related to Period One rates from the FERC's December 2009 order and established that Kern River is entitled to base its Period Two rates on a 100% equity capital structure. In January 2011, Kern River filed a motion for clarification on certain depreciation issues with the FERC.
In July 2011, the FERC issued its order substantially adopting the presiding administrative law judge's initial decision issued in April 2011 regarding Kern River's Period Two rates. According to the decisions, Period Two rates should be based on a return on equity of 11.55%, a capital structure of 100% and a levelization period that coincides with a contract length of 10 or 15 years. Kern River has a regulatory asset approved by the FERC associated with compressor engines and general plant replacements that can be recovered in a future rate case and was not incorporated into Period Two rates at this time. Kern River, as well as others, requested rehearing and clarification of the FERC's July 2011 order on a majority of the issues. Kern River filed tariffs in compliance with the FERC's order in August 2011 and, following an order on compliance, again in September 2011. In late September 2011, the FERC issued a second order on compliance, accepting Kern River's tariff filing. The FERC has not yet responded to the requests for rehearing and clarification of the July 2011 order.
ETT
In December 2011, ETT filed its second Interim Transmission Cost of Service ("TCOS") of 2011 at the PUCT. The application was based on a test year ending October 31, 2011. The filing requested an increase in total transmission invested capital of $82 million and a total revenue requirement increase of $11 million. In January 2012, the PUCT staff recommended approval of ETT's second interim TCOS filing of 2011. ETT, along with PUCT staff, filed a joint proposed notice of approval. On January 31, 2012, the administrative law judge signed the final order making the new rates effective.
Environmental Laws and Regulations
The Company is subject to federal, state, local and foreign laws and regulations regarding air and water quality, RPS, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact the Company's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by the EPA and various other state, local and international agencies. All such laws and regulations are subject to a range of interpretation, which may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and the Company is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. The Company believes it is in material compliance with all applicable laws and regulations. Refer to "Liquidity and Capital Resources" for discussion of the Company's forecasted environmental-related capital expenditures.
Clean Air Standards
The Clean Air Act is a federal law administered by the EPA that provides a framework for protecting and improving the nation's air quality and controlling sources of air emissions. The implementation of new standards is generally outlined in SIPs, which are a collection of regulations, programs and policies to be followed. SIPs vary by state and are subject to public hearings and EPA approval. Some states may adopt additional or more stringent requirements than those implemented by the EPA. The major Clean Air Act programs most directly affecting the Company's operations, are described below.
National Ambient Air Quality Standards
Under the authority of the Clean Air Act, the EPA sets minimum national ambient air quality standards for six principal pollutants, consisting of carbon monoxide, lead, nitrogen oxides, particulate matter, ozone and sulfur dioxide, considered harmful to public health and the environment. Areas that achieve the standards, as determined by ambient air quality monitoring, are characterized as being in attainment, while those that fail to meet the standards are designated as being nonattainment areas. Generally, sources of emissions in a nonattainment area that are determined to contribute to the nonattainment are required to reduce emissions. Most air quality standards require measurement over a defined period of time to determine the average concentration of the pollutant present. Currently, air quality monitoring data indicates that all counties where MidAmerican Energy's major emission sources are located are in attainment of the current national ambient air quality standards.
In December 2009, the EPA designated the Utah counties of Davis and Salt Lake, as well as portions of Box Elder, Cache, Tooele, Utah and Weber counties, to be in nonattainment of the fine particulate matter standard. This designation has the potential to impact PacifiCorp's Lake Side and Gadsby generating facilities, depending on the requirements to be established in the Utah SIP. The impact, if any, on PacifiCorp's generating facilities is not anticipated to be significant.
In January 2010, the EPA proposed a rule to strengthen the national ambient air quality standard for ground level ozone. The proposed rule arose out of legal challenges claiming that a March 2008 rule that reduced the standard from 80 parts per billion to 75 parts per billion was not strict enough. The new rule proposed a standard between 60 and 70 parts per billion. In September 2011, the President requested that the EPA withdraw the proposed ozone standard and allow the review of the standards to proceed through the regularly scheduled review in 2013. The EPA is, therefore, proceeding with implementation of the March 2008 ozone standards and, in December 2011, issued its response to states' recommendations on area attainment designations. Part of the EPA's response recommended that the Upper Green River Basin Area in Wyoming, including all of Sublette and portions of Lincoln and Sweetwater Counties, be designated as nonattainment for the March 2008 ozone standard. While PacifiCorp's Jim Bridger plant is located in Sweetwater County, it is not in the portion proposed for designation as nonattainment and is not expected to be impacted by the proposed designation. The EPA also published a proposed consent decree in the Federal Register in December 2011, requiring it to sign final designations for the March 2008 ozone standard by May 31, 2012.
In January 2010, the EPA finalized a one-hour air quality standard for nitrogen dioxide at 0.10 part per million. The EPA published final designations that are effective February 29, 2012, indicating that based on air quality monitoring data, all areas of the country are designated as "unclassifiable/attainment" for the 2010 nitrogen dioxide national ambient air quality standard.
In June 2010, the EPA finalized a new national ambient air quality standard for sulfur dioxide. Under the new rule, the existing 24-hour and annual standards for sulfur dioxide, which were 140 parts per billion measured over 24 hours and 30 parts per billion measured over an entire year, were replaced with a new one-hour standard of 75 parts per billion. The new rule will utilize a three-year average to determine attainment. The rule will utilize source modeling, in addition to the installation of ambient monitors where sulfur dioxide emissions impact populated areas, with new monitors required to be placed in service no later than January 2013. Attainment designations are due by June 2012, with SIPs due by 2014 and final attainment demonstrations by August 2017.
As new, more stringent standards are adopted, the number of counties designated as nonattainment areas is likely to increase. Businesses operating in newly designated nonattainment counties could face increased regulation and costs to monitor or reduce emissions. For instance, existing major emissions sources may have to install reasonably available control technologies to achieve certain reductions in emissions and undertake additional monitoring, recordkeeping and reporting. The construction or modification of facilities that are sources of emissions could become more difficult in nonattainment areas. Until additional monitoring and modeling is conducted, the impacts on the Company cannot be determined.
Mercury and Air Toxics Standards
The Clean Air Mercury Rule ("CAMR"), issued by the EPA in March 2005, was the United States' first attempt to regulate mercury emissions from coal-fueled generating facilities through the use of a market-based cap-and-trade system. The CAMR, which mandated emissions reductions of approximately 70% by 2018, was overturned by the United States Court of Appeals for the District of Columbia Circuit ("D.C. Circuit") in February 2008. In March 2011, the EPA proposed a new rule that would require coal-fueled generating facilities to reduce mercury emissions and other hazardous air pollutants through the establishment of "Maximum Achievable Control Technology" standards rather than a cap-and-trade system. The final rule, MATS, was released by the EPA in December 2011 and published in the Federal Register on February 16, 2012, and requires that new and existing coal-fueled facilities achieve emission standards for mercury, acid gases and other non-mercury hazardous air pollutants. Existing sources are required to comply with the new standards within three years after the rule is final, with individual sources granted an additional year to complete installation of controls if approved by the permitting authority. While the final MATS continues to be reviewed by the Company, the Company believes that its emissions reduction projects completed to date or currently permitted or planned for installation, including scrubbers, baghouses and electrostatic precipitators are consistent with the EPA's MATS and will support the Company's ability to comply with the final rule's standards for acid gases and non-mercury metallic hazardous air pollutants. The Company will be required to take additional actions to reduce mercury emissions through the installation of controls or use of sorbent injection at certain of its coal-fueled generating facilities and otherwise comply with the final rule's standards. The Company is evaluating whether or not to close certain units. Incremental costs to install and maintain mercury emissions control equipment at the Company's coal-fueled generating facilities and any requirements to shut down generating facilities will increase the cost of providing service to customers.
Clean Air Interstate Rule, Clean Air Transport Rule and Cross-State Air Pollution Rule
The EPA promulgated the CAIR in March 2005 to reduce emissions of nitrogen oxides and sulfur dioxide, precursors of ozone and particulate matter, from down-wind sources. The CAIR required states in the eastern United States, including Iowa, to reduce emissions by implementing a plan based on a market-based cap-and-trade system, emissions reductions, or both. The CAIR created separate trading programs for nitrogen oxides and sulfur dioxide emissions credits. The nitrogen oxides and sulfur dioxide emissions reductions were planned to be accomplished in two phases, in 2009-2010 and 2015.
In July 2008, a three-judge panel of the D.C. Circuit issued a unanimous decision vacating the CAIR. In December 2008, the D.C. Circuit issued an opinion remanding, without vacating, the CAIR back to the EPA to conduct proceedings to fix the flaws in CAIR consistent with the D.C. Circuit's July 2008 ruling.
In July 2010, the EPA proposed the Clean Air Transport Rule ("Transport Rule"), a replacement of the CAIR, which required electric generating units in 31 states and the District of Columbia to reduce emissions of nitrogen oxides and sulfur dioxide on a state-by-state basis in accordance with each state's modeled contribution to nonattainment of the ozone and fine particulate standards in downwind states. The emissions reductions required under the Transport Rule were intended only to resolve transported emissions and not to resolve air quality issues in the states where the generation is located. The Transport Rule's emissions reduction requirements were proposed to take place in two phases, with the first phase beginning in 2012 and the second phase beginning in 2014. By 2014, the Transport Rule and other state and EPA actions would reduce power plant nitrogen oxides emissions by 52% and sulfur dioxide emissions by 71% from 2005 levels in covered states. The EPA proposed to administer separate trading programs for nitrogen oxides and sulfur dioxide credits under the Transport Rule. Facilities were required to comply with the CAIR until the Transport Rule became effective.
In July 2011, the EPA issued the final Transport Rule, renamed the Cross-State Air Pollution Rule ("CSAPR"), to address interstate transport of sulfur dioxide and nitrogen oxides emissions in 27 eastern and Midwestern states. Upon full implementation in 2014, the CSAPR will reduce total sulfur dioxide emissions by 73% and nitrogen oxides emissions by 54% at electric generating facilities in the 27-state region as compared to 2005 levels. MidAmerican Energy's coal-fueled generating facilities in Iowa are impacted by and required to make emissions reductions and otherwise comply with the CSAPR. In addition to issuing the final rule, the EPA issued a supplemental notice of proposed rulemaking to include Iowa and five other states in the ozone season nitrogen oxides emissions reduction requirements. The ozone season supplemental proposal was finalized in December 2011, and includes Iowa and four other states in the CSAPR ozone season nitrogen oxide emission reduction requirements. While MidAmerican Energy operates natural gas-fueled generating facilities in Iowa and MidAmerican Renewables operates natural gas-fueled generating facilities within the states of Illinois, Texas and New York, which are in the CSAPR region, no significant impact is expected on those generating facilities.
In December 2011, the D.C. Circuit issued a stay on the implementation of the CSAPR pending consideration of several petitions for review before the court. The court held that the CAIR should be administered pending the resolution of the pending petitions for review.
MidAmerican Energy is currently complying with the CAIR and has installed or is in the process of installing emissions controls at some of its generating facilities to comply with the CAIR and may purchase nitrogen oxides and sulfur dioxide emissions credits for emissions in excess of allocated allowances. The cost of these credits is subject to market conditions at the time of purchase and historically has not been material. The full impact of the CSAPR, or the CAIR, cannot be determined until the outcome of the litigation pending in the D.C. Circuit or the stay of the CSAPR is lifted. It is possible that the existing CAIR or the CSAPR may be replaced with more stringent requirements to reduce nitrogen oxides and sulfur dioxide emissions and that these requirements could be extended to the western United States through regulation or legislation such as a multi-pollutant emissions reduction bill.
MidAmerican Renewables' natural gas generating facilities in Texas, Illinois and New York are also subject to the CAIR until the CSAPR is adopted. However, the provisions are not anticipated to have a material impact on the Company. PacifiCorp's generating facilities are not subject to the CAIR or the CSAPR.
Regional Haze
The EPA has initiated a regional haze program intended to improve visibility in designated federally protected areas ("Class I areas"). Some of PacifiCorp's coal-fueled generating facilities in Utah and Wyoming and MidAmerican Energy's coal-fueled generating facilities meet the threshold applicability criteria to be eligible units under the Clean Air Visibility Rules. In accordance with the federal requirements, states were required to submit SIPs by December 2007 to demonstrate reasonable progress towards achieving natural visibility conditions in Class I areas by requiring emissions controls, known as best available retrofit technology, on sources constructed between 1962 and 1977 with emissions that are anticipated to cause or contribute to impairment of visibility. Utah submitted its most recent regional haze SIP amendments in 2011 and suggested that the emissions reduction projects planned by PacifiCorp are sufficient to meet its initial emissions reduction requirements. In September 2011, the Company received a Section 114 request for information from the EPA Region VIII requiring the Company to submit a five-factor best available retrofit technology analysis for PacifiCorp's Hunter Units 1 and 2 and the Huntington generating facility in Utah within 30 days based on the EPA's assertion that Utah failed to submit such an analysis. The Company responded to the request in November 2011 and indicated it would work with the Utah Division of Air Quality to complete the requested analysis which, based on a schedule proposed by Utah to the EPA, will be part of a process to conclude with a submittal to the EPA in February 2013. Wyoming submitted its regional haze SIP to the EPA in January 2011. The EPA is currently under a consent decree to issue a proposed decision on the Wyoming SIP by May 15, 2012, and a final decision by October 15, 2012. PacifiCorp believes that its planned emissions reduction projects will satisfy the regional haze requirements in Utah and Wyoming. It is possible that additional controls may be required after the respective SIPs have been considered by the EPA or that the timing of installation of planned controls could change.
The EPA's rejection of regional haze SIPs based on the state's selection of less stringent controls than the EPA believes are warranted has resulted in lawsuits being filed by states and affected entities. Cases are pending before the Tenth Circuit Court of Appeals by New Mexico and Oklahoma and additional cases are likely to be filed.
In December 2011, the EPA proposed to accept the emission reductions made by states impacted by the CSAPR, including Iowa, as meeting the requirements of the regional haze program. If the EPA finalizes the proposal, no further emission reductions are expected from MidAmerican Energy's coal-fueled generating facilities for purposes of meeting the regional haze requirements.
New Source Review
Under existing New Source Review ("NSR") provisions of the Clean Air Act, any facility that emits regulated pollutants is required to obtain a permit from the EPA or a state regulatory agency prior to (a) beginning construction of a new major stationary source of a regulated pollutant or (b) making a physical or operational change to an existing stationary source of such pollutants that increases certain levels of emissions, unless the changes are exempt under the regulations (including routine maintenance, repair and replacement of equipment). In general, projects subject to NSR regulations require pre-construction review and permitting under the Prevention of Significant Deterioration ("PSD") provisions of the Clean Air Act. Under the PSD program, a project that emits threshold levels of regulated pollutants must undergo an analysis to determine the best available control technology and evaluate the most effective emissions controls after consideration of a number of factors. Violations of NSR regulations, which may be alleged by the EPA, states, environmental groups and others, potentially subject a company to material fines and other sanctions and remedies, including installation of enhanced pollution controls and funding of supplemental environmental projects.
Numerous changes have been proposed to the NSR rules and regulations over the last several years. In addition to the proposed changes, differing interpretations by the EPA and the courts create risk and uncertainty for entities when seeking permits for new projects and installing emissions controls at existing facilities under NSR requirements. The Company monitors these changes and interpretations to ensure permitting activities are conducted in accordance with the applicable requirements.
As part of an industry-wide investigation to assess compliance with the NSR and PSD provisions, the EPA has requested information and supporting documentation from numerous utilities regarding their capital projects for various coal-fueled generating facilities. A NSR enforcement case against an unrelated utility has been decided by the United States Supreme Court, holding that an increase in the annual emissions of a generating facility, when combined with a modification (i.e., a physical or operational change), may trigger NSR permitting. Between 2001 and 2003, PacifiCorp and MidAmerican Energy responded to requests for information relating to their capital projects at their coal-fueled generating facilities. PacifiCorp engaged in periodic discussions with the EPA over several years regarding PacifiCorp's historical projects and their compliance with NSR and PSD provisions. In September 2011, PacifiCorp received a letter from the EPA concluding these discussions. PacifiCorp cannot predict the next steps in this process and could be required to install additional emissions controls and incur additional costs and penalties in the event it is determined that PacifiCorp's historical projects did not meet all regulatory requirements.
In October 2011, MidAmerican Energy received a request from the EPA Region VII pursuant to Section 114 of the Clean Air Act for information on its coal-fueled generating facilities to supplement the requests made in 2002 and 2003. MidAmerican Energy submitted its response to the October 2011 request in December 2011. MidAmerican Energy cannot predict the outcome of this matter at this time.
Climate Change
In April 2011, the United States House of Representatives voted 255-177 on a bill (H.R. 910) that would prevent the EPA from regulating GHG emissions. No action has been taken by the Senate on the bill. While significant measures to regulate GHG emissions at the federal level were considered by the United States Congress in 2010, comprehensive climate change legislation has not been adopted. International discussions regarding climate change continue to be held periodically, but agreement has not been reached on how nations will address future climate change commitments upon the expiration of the Kyoto Protocol in December 2012.
In December 2009, the EPA published its findings that GHG threaten the public health and welfare and is pursuing regulation of GHG emissions under the Clean Air Act. Additionally, in May 2010, the EPA issued the GHG "Tailoring Rule" to address permitting requirements for GHG after determining that GHG are subject to regulation and would trigger Clean Air Act permitting requirements for stationary sources beginning in January 2011. Numerous lawsuits have been filed on both the EPA's endangerment finding and the tailoring rule and are pending in the D.C. Circuit with arguments scheduled to take place in February 2012.
While the debate continues at the federal and international level over the direction of climate change policy, several states have developed or are developing state-specific laws or regional initiatives to report or mitigate GHG emissions. In addition, governmental, non-governmental and environmental organizations have become more active in pursuing climate change related litigation under existing laws.
California mandatory GHG reporting requirements began with 2008 emissions and PacifiCorp has reported its GHG emissions annually since their inception. In September 2009, the EPA issued its final rule regarding mandatory reporting of GHG ("GHG Reporting") beginning January 1, 2010. Under GHG Reporting, suppliers of fossil fuels, manufacturers of vehicles and engines, and facilities that emit 25,000 metric tons or more per year of GHG are required to submit annual reports to the EPA. PacifiCorp, MidAmerican Energy and MidAmerican Renewables are subject to this requirement and submitted their first reports prior to September 30, 2011. Northern Natural Gas and Kern River reported their combustion-related GHG emissions prior to September 30, 2011, and are required to report their GHG emissions from equipment leaks and venting by September 28, 2012. The EPA released the 2010 GHG emissions reports in January 2012.
In the absence of comprehensive climate legislation or regulation, the Company has continued to invest in lower- and non-carbon generating resources and to operate in an environmentally responsible manner. Examples of the Company's significant investments in programs and facilities that will mitigate its GHG emissions include:
MidAmerican Energy owns the largest and PacifiCorp owns the second largest portfolio of wind-powered generating capacity in the United States among rate-regulated utilities. As of December 31, 2011, the Company owned 2,909 MW of operating wind-powered generating capacity at a total cost of $5.4 billion. MidAmerican Energy is constructing an additional 407 MW of wind-powered generation that it expects to place in service in 2012. Additionally, the Company has power purchase agreements with 858 MW of wind-powered generating capacity.
PacifiCorp owns 1,145 MW of hydroelectric generating capacity.
In January 2012, MEHC, through wholly-owned subsidiaries, acquired the 550-MW Topaz Project and a 49 percent interest in the 290-MW Agua Caliente Project. The electricity delivered by the Topaz Project and Agua Caliente Project is being and will be sold to PG&E and will help PG&E meet its obligations under a California state mandate to procure capacity and electricity from renewable resources.
PacifiCorp's Energy Gateway Transmission Expansion Program represents a planto build approximately 2,000 miles of new high-voltage transmission lines with an estimated cost exceeding $6 billion. The plan includes several transmission line segments that will: (a) address customer load growth; (b) improve system reliability; (c) reduce transmission system constraints; (d) provide access to diverse generation resources, including renewable resources; and (e) improve the flow of electricity throughout PacifiCorp's six-state service area.
ETT plans to construct $1.5 billion of transmission investment in support of CREZ. CREZ is a transmission plan that advances the development of over 18,000 MW of new wind-powered generation in Texas. Additionally, AEP subsidiaries have transferred to ETT the obligation to build approximately $1.7 billion of transmission projects within ERCOT. Through December 31, 2011, $1.1 billion has been spent, of which $617 million has been placed in service. ETT's transmission system included 445 miles of transmission lines and 19 substations as of December 31, 2011.
PacifiCorp and MidAmerican Energy have offered customers a comprehensive set of DSM programs for more than 20 years. The programs assist customers to manage the timing of their usage, as well as to reduce overall energy consumption, resulting in lower utility bills.
The Utilities have installed and upgraded emissions control equipment at certain of its coal-fueled generating facilities to reduce emissions of sulfur dioxide and nitrogen oxides.
MEHC holds a 10% interest in BYD Company Limited, which continues to make advances in applying its proprietary battery technology to electric vehicles and has also developed an energy storage system, solar power system, hybrid energy system and other green energy solutions.
The impact of potential federal, regional, state and international accords, legislation, regulation, or judicial proceedings related to climate change cannot be quantified in any meaningful range at this time. New requirements limiting GHG emissions could have a material adverse impact on the Company, the United States and the global economy. Companies and industries with higher GHG emissions, such as utilities with significant coal-fueled generating facilities, will be subject to more direct impacts and greater financial and regulatory risks. The impact is dependent on numerous factors, none of which can be meaningfully quantified at this time. These factors include, but are not limited to, the magnitude and timing of GHG emissions reduction requirements; the design of the requirements; the cost, availability and effectiveness of emissions control technology; the price, distribution method and availability of offsets and allowances used for compliance; government-imposed compliance costs; and the existence and nature of incremental cost recovery mechanisms. Examples of how new requirements may impact the Company include:
Additional costs may be incurred to purchase required emissions allowances under any market-based cap-and-trade system in excess of allocations that are received at no cost. These purchases would be necessary until new technologies could be developed and deployed to reduce emissions or lower carbon generation is available;
Acquiring and renewing construction and operating permits for new and existing generating facilities may be costly and difficult;
Additional costs may be incurred to purchase and deploy new generating technologies;
Costs may be incurred to retire existing coal-fueled generating facilities before the end of their otherwise useful lives or to convert them to burn fuels, such as natural gas or biomass, that result in lower emissions;
Operating costs may be higher and generating unit outputs may be lower;
Higher interest and financing costs and reduced access to capital markets may result to the extent that financial markets view climate change and GHG emissions as a business risk; and
The Company's natural gas pipeline operations, electric transmission and retail sales may be impacted in response to changes in customer demand and requirements to reduce GHG emissions.
The impact of events or conditions caused by climate change, whether from natural processes or human activities, could vary widely, from highly localized to worldwide, and the extent to which a utility's operations may be affected is uncertain. Climate change may cause physical and financial risk through, among other things, sea level rise, changes in precipitation and extreme weather events. Consumer demand for energy may increase or decrease, based on overall changes in weather and as customers promote lower energy consumption through the continued use of energy efficiency programs or other means. Availability of resources to generate electricity, such as water for hydroelectric production and cooling purposes, may also be impacted by climate change and could influence the Company's existing and future electricity generating portfolio. These issues may have a direct impact on the costs of electricity production and increase the price customers pay or their demand for electricity.
International Accords
Under the United Nations Framework Convention on Climate Change, adopted in 1992, members of the convention meet periodically to discuss international responses to climate change. To date, the United States has not made a binding reduction commitment as a result of these international discussions.
Federal Legislation
Legislation introduced in the 112th Congress has been focused on repeal or delay of the EPA's ability to regulate GHG emissions. There is currently no federal legislation pending to regulate GHG emissions.
GHG Tailoring Rule
The EPA finalized the GHG "Tailoring Rule" in May 2010 requiring new or modified sources of GHG emissions with increases of 75,000 or more tons per year of total GHG to determine the best available control technology for their GHG emissions beginning in January 2011. New or existing major sources will also be subject to Title V operating permit requirements for GHG. Beginning July 1, 2011 through June 30, 2013, new construction projects that emit GHG emissions of at least 100,000 tons per year and modifications of existing facilities that increase GHG emissions by at least 75,000 tons per year will be subject to permitting requirements and facilities that were previously not subject to Title V permitting requirements will be required to obtain Title V permits if they emit at least 100,000 tons per year of carbon dioxide equivalents. Several legal challenges to the GHG Tailoring Rule have been filed in the D.C. Circuit. The EPA issued a GHG best available control technology guidance document in November 2010 in an effort to provide permitting authorities guidance on how to conduct a best available control technology review for GHG.
MidAmerican Energy has obtained and is in the process of obtaining permits to install emissions reduction equipment at existing generating facilities to comply with CSAPR and was required to assess the impacts of the projects on GHG emissions. A GHG emissions limit was imposed on the permits for those projects and management believes compliance with the GHG limits under these permits will not result in a material adverse impact on its operations. PacifiCorp's permitting of certain existing generating facilities to install emissions reduction equipment to comply with the Regional Haze Rules assessed the impacts of the projects on GHG emissions under the GHG Tailoring Rule. No GHG emissions limit was included in the permits. However, PacifiCorp's Lake Side 2 was subject to a best available control technology review and the permit includes a limit for carbon dioxide equivalent emissions. To date, permitting authorities implementing the GHG Tailoring Rule have included efficiency improvements to demonstrate compliance with best available control technology for GHG, as well as requiring emissions limits for GHGs in permits; as such, the impacts of the Tailoring Rule on the Company have not been material.
GHG New Source Performance Standards
Under the Clean Air Act, the EPA may establish emissions standards that reflect the degree of emissions reductions achievable through the best technology that has been demonstrated, taking into consideration the cost of achieving those reductions and any non-air quality health and environmental impact and energy requirements. The EPA entered into a settlement agreement with a number of parties, including certain state governments and environmental groups, in December 2010 to promulgate emissions standards covering GHG by September 30, 2011, as amended, and issue final regulations by May 26, 2012. However, in mid-September, the EPA indicated it would not meet the September 30, 2011 deadline to promulgate the standards and it has not yet established a new schedule for issuing the proposed rules. It is unclear what standards the EPA will establish for new and modified sources or what the guidelines will be for existing sources. Until the standards are proposed and finalized, the impact on the Company cannot be determined.
Regional and State Activities
Several states have promulgated or otherwise participate in state-specific or regional laws or initiatives to report or mitigate GHG emissions. These are expected to impact PacifiCorp, MidAmerican Energy and other MEHC energy subsidiaries, and include:
The Western Climate Initiative was established as a comprehensive regional effort to reduce GHG emissions by 15% below 2005 levels by 2020 through a cap-and-trade program that includes the electricity sector. The Western Climate Initiative initially included the states of California, Montana, New Mexico, Oregon, Utah and Washington and the Canadian provinces of British Columbia, Manitoba, Ontario and Quebec. However, only California, British Columbia and Quebec are moving forward under the initiative, with the other states focused on efforts to design, promote and implement cost-effective policies to reduce GHG emissions and create economic opportunities.
In October 2011, the California Air Resources Board adopted a GHG cap-and-trade program with an effective date of January 1, 2012; compliance obligations will be imposed on entities beginning in 2013. In addition, California law imposes a GHG emissions performance standard to all electricity generated within the state or delivered from outside the state that is no higher than the GHG emissions levels of a state-of-the-art combined-cycle natural gas-fueled generating facility, as well as legislation that adopts an economy-wide cap on GHG emissions to 1990 levels by 2020.
Over the past several years, the states of California, Washington and Oregon have adopted GHG emissions performance standards for base load electrical generating resources. Under the laws in all three states, the emissions performance standards provide that emissions must not exceed 1,100 pounds of carbon dioxide per MWh. These GHG emissions performance standards generally prohibit electric utilities from entering into long-term financial commitments (e.g., new ownership investments, upgrades, or new or renewed contracts with a term of five or more years) unless any base load generation supplied under long-term financial commitments comply with the GHG emissions performance standards.
The Washington and Oregon governors enacted legislation in May 2007 and August 2007, respectively, establishing goals for the reduction of GHG emissions in their respective states. Washington's goals seek to (a) reduce emissions to 1990 levels by 2020; (b) reduce emissions to 25% below 1990 levels by 2035; and (c) reduce emissions to 50% below 1990 levels by 2050, or 70% below Washington's forecasted emissions in 2050. Oregon's goals seek to (a) cease the growth of Oregon GHG emissions by 2010; (b) reduce GHG levels to 10% below 1990 levels by 2020; and (c) reduce GHG levels to at least 75% below 1990 levels by 2050. Each state's legislation also calls for state government to develop policy recommendations in the future to assist in the monitoring and achievement of these goals.
In Iowa, legislation enacted in 2007 required the Iowa Climate Change Advisory Council ("ICCAC"), a 23-member group appointed by the Iowa governor, to develop scenarios designed to reduce statewide GHG emissions, including one scenario that would reduce emissions by 50% by 2050, and submit its recommendations to the legislature. The ICCAC also developed a second scenario to reduce GHG emissions by 90% with reductions in both scenarios from 2005 emissions levels. In January 2009, the ICCAC presented to the Iowa governor and legislature several policy options to consider to achieve GHG emissions reductions, including enhanced energy efficiency programs and increased renewable generation. No legislation has yet been enacted that would require GHG emissions reductions.
In November 2007, the Iowa governor signed the Midwest Greenhouse Gas Accord and the Energy Security and Climate Stewardship Platform for the Midwest. The signatories to the platform were other Midwestern states that agreed to implement a regional cap-and-trade system for GHG emissions. Advisory group recommendations included the assessment of 2020 emissions reduction targets of 15%, 20% and 25% below 2005 levels and a 2050 target of 60% to 80% below 2005 levels. In addition, the accord calls for the participating states to collectively meet at least 2% of regional annual retail sales of electricity and natural gas through energy efficiency improvements by 2015 and continue to achieve an additional 2% in efficiency improvements every year thereafter. There has been no further progress in implementing a Midwest regional cap-and-trade program.
The Regional Greenhouse Gas Initiative, a mandatory, market-based effort to reduce GHG emissions in ten Northeastern and Mid-Atlantic states, requires, beginning in 2009, the reduction of carbon dioxide emissions from the power sector of 10% by 2018. In May 2011, New Jersey withdrew from participation in the Regional Greenhouse Gas Initiative and in June 2011, a lawsuit filed in New York alleged that the state of New York unlawfully joined the Regional Greenhouse Gas Initiative without legislative approval.
GHG Litigation
The Company closely monitors ongoing environmental litigation. Many of the pending cases described below relate to lawsuits against industry that attempt to link GHG emissions to public or private harm. The Company believes the cases are without merit, despite decisions where United States Courts of Appeals reversed district court rulings dismissing the cases in 2009. The lower courts initially refrained from adjudicating the cases under the "political question" doctrine, because of their inherently political nature. Nevertheless, an adverse ruling in any of these cases would likely result in increased regulation of GHG emitters, including the Company's generating facilities, and financial uncertainty.
In September 2009, the United States Court of Appeals for the Second Circuit ("Second Circuit") issued its opinion in the case of Connecticut v. American Electric Power, et al, which remanded to the lower court a nuisance action by eight states and the City of New York against five large utility emitters of carbon dioxide. The United States District Court for the Southern District of New York ("Southern District of New York") dismissed the case in 2005, holding that the claims that GHG emissions from the defendants' coal-fueled generating facilities were causing harmful climate change and should be enjoined as a public nuisance under federal common law presented a "political question" that the court lacked jurisdiction to decide. The Second Circuit rejected this conclusion and stated the Southern District of New York was not precluded from determining the case on its merits. In December 2010, the United States Supreme Court agreed to hear the case on appeal from the Second Circuit and issued its decision in June 2011 dismissing the federal common law claim of nuisance and holding that the Clean Air Act provides a means to seek limits on emissions of carbon dioxide on power plants.
In October 2009, a three-judge panel in the United States Court of Appeals for the Fifth Circuit ("Fifth Circuit") issued its opinion in the case of Ned Comer, et al. v. Murphy Oil USA, et al., ("Comer I") a putative class action lawsuit against insurance, oil, coal and chemical companies, based on claims that the defendants' GHG emissions contributed to global warming that in turn caused a rise in sea levels and added to the ferocity of Hurricane Katrina, which combined to damage the plaintiff's private property, as well as public property. In 2007, the United States District Court for the Southern District of Mississippi ("Southern District of Mississippi") dismissed the case based on the lack of standing and further held that the claims were barred by the political question doctrine. In March 2010, the full court of the Fifth Circuit agreed to rehear the case; however, in May 2010, the Fifth Circuit dismissed the appeal for failure to have a quorum, resulting in the Southern District of Mississippi's decision, holding that property owners did not have standing to sue for climate change and that climate change was a political question for the United States Congress, standing as good law. The plaintiffs filed a petition asking the United States Supreme Court to direct the Fifth Circuit to reinstate the appeal and return it to the original panel. In January 2011, the United States Supreme Court denied the request, resulting in the original dismissal of the case to stand. However, on May 27, 2011, the Comer case was refiled ("Comer II") in the Southern District of Mississippi. The defendants in Comer II have filed a motion to dismiss, which is pending before the court. The Company was not a party in Comer I and is not a party in Comer II.
In October 2009, the United States District Court for the Northern District of California ("Northern District of California") granted the defendants' motions to dismiss in the case of Native Village of Kivalina v. ExxonMobil Corporation, et al. The plaintiffs filed their complaint in February 2008, asserting claims against 24 defendants, including electric generating companies, oil companies and a coal company, for public nuisance under state and federal common law based on the defendants' GHG emissions. MEHC was a named defendant in the Kivalina case. The Northern District of California dismissed all of the plaintiffs' federal claims, holding that the court lacked subject matter jurisdiction to hear the claims under the political question doctrine, and that the plaintiffs lacked standing to bring their claims. The Northern District of California declined to hear the state law claims and the case was dismissed without prejudice to their future presentation in an appropriate state court. In November 2009, the plaintiff's appealed the case to the United States Court of Appeals for the Ninth Circuit ("Ninth Circuit") where briefing has been completed, but the case has not yet been scheduled for oral argument. In February 2011, the Ninth Circuit stayed the case, pending the issuance of the United States Supreme Court's decision in Connecticut v. American Electric Power, et al. The oral arguments in Kivalina were held before the Ninth Circuit in November 2011 and the parties await the court's decision.
Renewable Portfolio Standards
The RPS described below could significantly impact the Company's consolidated financial results. Resources that meet the qualifying electricity requirements under the RPS vary from state to state. Each state's RPS requires some form of compliance reporting, and the Company can be subject to penalties in the event of noncompliance.
In November 2006, Washington voters approved a ballot initiative establishing a RPS requirement for qualifying electric utilities, including PacifiCorp. The requirements are 3% of retail sales by January 1, 2012 through 2015, 9% of retail sales by January 1, 2016 through 2019 and 15% of retail sales by January 1, 2020. The WUTC has adopted final rules to implement the initiative.
In June 2007, the Oregon Renewable Energy Act ("OREA") was adopted, providing a comprehensive renewable energy policy and RPS for Oregon. Subject to certain exemptions and cost limitations established in the OREA, PacifiCorp and other qualifying electric utilities must meet minimum qualifying electricity requirements for electricity sold to retail customers of at least 5% in 2011 through 2014, 15% in 2015 through 2019, 20% in 2020 through 2024, and 25% in 2025 and subsequent years. As required by the OREA, the OPUC has approved an automatic adjustment clause to allow an electric utility, including PacifiCorp, to recover prudently incurred costs of its investments in renewable energy generating facilities and associated transmission costs.
In April 2011, the California governor signed into law Senate Bill 2 of the First Extraordinary Session that expanded the RPS to require all California retail sellers to procure an average of 20% of retail load from renewable resources by December 31, 2013, 25% by December 31, 2016 and 33% by December 31, 2020 and each year thereafter. In December 2011, the CPUC adopted a decision confirming that multi-jurisdictional utilities, such as PacifiCorp, are not subject to the percentage limits within the three categories of RPS-eligible resources established by the legislation that have been imposed on other California retail sellers. The CPUC is in the process of an extensive rulemaking to implement the new requirements under the legislation.
In March 2008, Utah's governor signed Utah Senate Bill 202. Among other things, this law provides that, beginning in the year 2025, 20% of adjusted retail electric sales of all Utah utilities be supplied by renewable energy, if it is cost effective. Retail electric sales will be adjusted by deducting the amount of generation from sources that produce zero or reduced carbon emissions, and for sales avoided as a result of energy efficiency and DSM programs. Qualifying renewable energy sources can be located anywhere in the WECC areas, and renewable energy credits can be used.
Water Quality Standards
The federal Water Pollution Control Act ("Clean Water Act") establishes the framework for maintaining and improving water quality in the United States through a program that regulates, among other things, discharges to and withdrawals from waterways. The Clean Water Act requires that cooling water intake structures reflect the "best technology available for minimizing adverse environmental impact" to aquatic organisms. In July 2004, the EPA established significant new technology-based performance standards for existing electric generating facilities that take in more than 50 million gallons of water per day. These rules were aimed at minimizing the adverse environmental impacts of cooling water intake structures by reducing the number of aquatic organisms lost as a result of water withdrawals. In response to a legal challenge to the rule, in January 2007, the Second Circuit remanded almost all aspects of the rule to the EPA, without addressing whether companies with cooling water intake structures were required to comply with these requirements. On appeal from the Second Circuit, in April 2009, the United States Supreme Court ruled that the EPA permissibly relied on a cost-benefit analysis in setting the national performance standards regarding "best technology available for minimizing adverse environmental impact" at cooling water intake structures and in providing for cost-benefit variances from those standards as part of the §316(b) Clean Water Act Phase II regulations. The United States Supreme Court remanded the case back to the Second Circuit to conduct further proceedings consistent with its opinion.
In March 2011, the EPA released a proposed rule under §316(b) of the Clean Water Act to regulate cooling water intakes at existing facilities. The proposed rule establishes requirements for all power generating facilities that withdraw more than two million gallons per day, based on total design intake capacity, of water from waters of the United States and use at least 25% of the withdrawn water exclusively for cooling purposes. PacifiCorp's Dave Johnston generating facility and all of MidAmerican Energy's coal-fueled generating facilities, except Louisa, Ottumwa and Walter Scott, Jr. Unit 4, which have water cooling towers, withdraw more than two million gallons per day of water from waters of the United States. PacifiCorp's Jim Bridger, Naughton, Gadsby, Hunter, Carbon and Huntington generating facilities currently utilize closed cycle cooling towers but withdraw more than two million gallons of water per day. The proposed rule includes impingement (i.e., when fish and other organisms are trapped against screens when water is drawn into a facility's cooling system) mortality standards to be met through average impingement mortality or intake velocity design criteria and entrainment (i.e., when organisms are drawn into the facility) standards to be determined on a case-by-case basis. The standards are required to be met as soon as possible after the effective date of the final rule, but no later than eight years thereafter. The rule is required to be finalized by the EPA by July 2012. Assuming the final rule is issued by July 2012, PacifiCorp's and MidAmerican Energy's generating facilities impacted by the final rule will be required to complete impingement and entrainment studies in 2013. The costs of compliance with the cooling water intake structure rule cannot be determined until the rule is final and the prescribed studies are conducted. In the event that PacifiCorp's or MidAmerican Energy's existing intake structures require modification, the costs are not anticipated to be significant.
Coal Combustion Byproduct Disposal
In December 2008, an ash impoundment dike at the Tennessee Valley Authority's Kingstonpower plant collapsed after heavy rain, releasing a significant amount of fly ash and bottom ash, coal combustion byproducts, and water to the surrounding area. In light of this incident, federal and state officials have called for greater regulation of the storage and disposal of coal combustion byproducts. In May 2010, the EPA released a proposed rule to regulate the management and disposal of coal combustion byproducts, presenting two alternatives to regulation under the RCRA. Under the first option, coal combustion byproducts would be regulated as special waste under RCRA Subtitle C and the EPA would establish requirements for coal combustion byproducts from the point of generation to disposition, including the closure of disposal units. Alternatively, the EPA is considering regulation under RCRA Subtitle D under which it would establish minimum nationwide standards for the disposal of coal combustion byproducts. Under both options, surface impoundments utilized for coal combustion byproducts would have to be cleaned and closed unless they could meet more stringent regulatory requirements; in addition, more stringent requirements would be implemented for new ash landfills and expansions of existing ash landfills. PacifiCorp operates 16 surface impoundments and six landfills that contain coal combustion byproducts. MidAmerican Energy operates eight surface impoundments and four landfills that contain coal combustion byproducts. These ash impoundments and landfills may be impacted by the newly proposed regulation, particularly if the materials are regulated as hazardous or special waste under RCRA Subtitle C, and could pose significant additional costs associated with ash management and disposal activities at the Company's coal-fueled generating facilities. The public comment period closed in November 2010. The EPA has not indicated when the rule will be finalized, and the substance of the final rule is not known. The United States House of Representatives passed H.R. 2273 in October 2011, which would regulate coal combustion byproducts under RCRA Subtitle D. A Senate bill similar to the House bill has been introduced, but action has not been taken on the bill. The impact of the proposed regulations on coal combustion byproducts cannot be determined at this time; however, both PacifiCorp and MidAmerican Energy have begun developing surface impoundment and landfill compliance plan options to ensure that physical infrastructure decisions are aligned with the potential outcomes of the rulemaking.
Other
Other laws, regulations and agencies to which the Company is subject to include, but are not limited to:
The federal Comprehensive Environmental Response, Compensation and Liability Act and similar state laws may require any current or former owners or operators of a disposal site, as well as transporters or generators of hazardous substances sent to such disposal site, to share in environmental remediation costs.
The Nuclear Waste Policy Act of 1982, under which the United States Department of Energy is responsible for the selection and development of repositories for, and the permanent disposal of, spent nuclear fuel and high-level radioactive wastes. Refer to Note 13 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding nuclear decommissioning obligations.
The federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes establish operational, reclamation and closure standards that must be met during and upon completion of mining activities.
The FERC oversees the relicensing of existing hydroelectric systems and is also responsible for the oversight and issuance of licenses for new construction of hydroelectric systems, dam safety inspections and environmental monitoring. Refer to Note 16 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the relicensing of certain of PacifiCorp's existing hydroelectric facilities.
MEHC expects its Domestic Regulated Businesses will be allowed to recover the prudently incurred costs to comply with the environmental laws and regulations discussed above. The Company's planning efforts take into consideration the complexity of balancing factors such as: (a) pending environmental regulations and requirements to reduce emissions, address waste disposal, ensure water quality, and protect wildlife; (b) avoidance of excessive reliance on any one generation technology; (c) costs and trade-offs of various resource options including energy efficiency, demand response programs, and renewable generation; (d) state-specific energy policies, resource preferences, and economic development efforts; (e) additional transmission investment to reduce power costs and increase efficiency and reliability of the integrated transmission system; and (f) keeping rates as affordable as possible. Due to the number of generating units impacted by environmental regulations, deferring installation of compliance-related projects is often not feasible or cost effective and places the Company at risk of not having access to necessary capital, material, and labor while attempting to perform major equipment installations in a compressed timeframe concurrent with other utilities across the country. Therefore, the Company has established installation schedules with permitting agencies that coordinate compliance timeframes with construction and tie-in of major environmental compliance projects as units are scheduled off-line for planned maintenance outages; these coordinated efforts help reduce costs associated with replacement power and maintain system reliability.
Collateral and Contingent Features
Debt and preferred securities of MEHC and certain of its subsidiaries are rated by credit rating agencies. Assigned credit ratings are based on each rating agency's assessment of the rated company's ability to, in general, meet the obligations of its issued debt or preferred securities. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time.
MEHC and its subsidiaries have no credit rating downgrade triggers that would accelerate the maturity dates of outstanding debt, and a change in ratings is not an event of default under the applicable debt instruments, except for those discussed in Note 23 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K related to the Topaz financing. The Company's unsecured revolving credit facilities do not require the maintenance of a minimum credit rating level in order to draw upon their availability, but, under certain instances, must maintain sufficient covenant tests if ratings drop below a certain level. However, commitment fees and interest rates under the credit facilities are tied to credit ratings and increase or decrease when the ratings change. A ratings downgrade could also increase the future cost of commercial paper, short- and long-term debt issuances or new credit facilities.
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain provisions that require certain of MEHC's subsidiaries, principally the Utilities, to maintain specific credit ratings on their unsecured debt from one or more of the three recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance" in the event of a material adverse change in the subsidiary's creditworthiness. These rights can vary by contract and by counterparty. As of December 31, 2011, these subsidiary's credit ratings from the three recognized credit rating agencies were investment grade. If all credit-risk-related contingent features or adequate assurance provisions for these agreements had been triggered as of December 31, 2011, the Company would have been required to post $569 million of additional collateral. The Company's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors. Refer to Note 7 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for a discussion of the Company's collateral requirements specific to the Company's derivative contracts.
In July 2010, the President signed into law the Dodd-Frank Reform Act. The Dodd-Frank Reform Act reshapes financial regulation in the United States by creating new regulators, regulating new markets and firms, and providing new enforcement powers to regulators. Virtually all major areas of the Dodd-Frank Reform Act, including collateral requirements on derivative contracts, are the subject of regulatory interpretation and implementation rules requiring rulemaking proceedings, some of which have been completed and others that are expected to be finalized in 2012.
The Company is a party to derivative contracts, including over-the-counter derivative contracts. The Dodd-Frank Reform Act provides for extensive new regulation of over-the-counter derivative contracts and certain market participants, including imposition of mandatory clearing, exchange trading, capital and margin requirements for "swap dealers" and "major swap participants." The Dodd-Frank Reform Act provides certain exemptions from these regulations for commercial end-users that use derivatives to hedge and manage the commercial risk of their businesses. Although the Company generally does not enter into over-the-counter derivative contracts for purposes unrelated to hedging of commercial risk and does not believe it will be considered a swap dealer or major swap participant, the outcome of the rulemaking proceedings cannot be predicted and, therefore, the impact of the Dodd-Frank Reform Act on the Company's consolidated financial results cannot be determined at this time.
Inflation
Historically, overall inflation and changing prices in the economies where MEHC's subsidiaries operate have not had a significant impact on the Company's consolidated financial results. In the United States, MEHC's regulated subsidiaries operate under cost-of-service based rate structures administered by various state commissions and the FERC. Under these rate structures, MEHC's regulated subsidiaries are allowed to include prudent costs in their rates, including the impact of inflation. The price control formula used by the United Kingdom Distribution Companies incorporates the rate of inflation in determining rates charged to customers. MEHC's subsidiaries attempt to minimize the potential impact of inflation on their operations by employing prudent risk management and hedging strategies and by considering, among other areas, its impact on purchases of energy, operating expenses, materials and equipment costs, contract negotiations, future capital spending programs and long-term debt issuances. There can be no assurance that such actions will be successful.
Off-Balance Sheet Arrangements
The Company has certain investments that are accounted for under the equity method in accordance with accounting principles generally accepted in the United States of America ("GAAP"). Accordingly, an amount is recorded on the Company's Consolidated Balance Sheets as an equity investment and is increased or decreased for the Company's pro-rata share of earnings or losses, respectively, less any dividends from such investments.
As of December 31, 2011, the Company's investments that are accounted for under the equity method had short- and long-term debt of $1.045 billion, unused revolving credit facilities of $147 million and letters of credit outstanding of $57 million. As of December 31, 2011, the Company's pro-rata share of such short- and long-term debt was $508 million, unused revolving credit facilities was $73 million and outstanding letters of credit was $29 million. The entire amount of the Company's pro-rata share of the outstanding short- and long-term debt and unused revolving credit facilities is non-recourse to the Company. $25 million of the Company's pro-rata share of the outstanding letters of credit is recourse to the Company. Although the Company is generally not required to support debt service obligations of its equity investees, default with respect to this non-recourse short- and long-term debt could result in a loss of invested equity.
New Accounting Pronouncements
For a discussion of new accounting pronouncements affecting the Company, refer to Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Critical Accounting Estimates
Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. The following critical accounting estimates are impacted significantly by the Company's methods, judgments and assumptions used in the preparation of the Consolidated Financial Statements and should be read in conjunction with the Company's Summary of Significant Accounting Policies included in Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Accounting for the Effects of Certain Types of Regulation
The Domestic Regulated Businesses prepare their financial statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, the Domestic Regulated Businesses are required to defer the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates.
The Company continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition which could limit the Domestic Regulated Businesses' ability to recover their costs. Based upon this continuous evaluation, the Company believes the application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at both the federal and state levels and is subject to change in the future. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be written off to net income, returned to customers or re-established as accumulated other comprehensive income (loss) ("AOCI"). Total regulatory assets were $2.918 billion and total regulatory liabilities were $1.731 billion as of December 31, 2011. Refer to Note 5 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the Domestic Regulated Businesses' regulatory assets and liabilities.
Derivatives
The Company is exposed to the impact of market fluctuations in commodity prices, interest rates and foreign currency exchange rates. The Company is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk primarily through MEHC's ownership of the Utilities as they have an obligation to serve retail customer load in their regulated service territories. MidAmerican Energy also provides nonregulated retail electricity and natural gas services in competitive markets. The Utilities' load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity, wholesale electricity that is purchased and sold, and natural gas supply for regulated and nonregulated retail customers. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints.Interest rate risk exists on variable-rate debt and future debt issuances. Additionally, the Company is exposed to foreign currency exchange rate risk from its business operations and investments in Great Britain. Each of the Company's business platforms has established a risk management process that is designed to identify, assess, monitor, report, manage and mitigate each of the various types of risk involved in its business. The Company employs a number of different derivative contracts, which may include forwards, futures, options, swaps and other agreements, to manage price risk for electricity, natural gas and other commodities; interest rate risk; and foreign currency exchange rate risk. The Company does not hedge all of its commodity price, interest rate and foreign currency exchange rate risks, thereby exposing the unhedged portion to changes in market prices. Refer to Notes 6 and 7 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the Company's derivative contracts.
Measurement Principles
Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which the Company transacts. When quoted prices for identical contracts are not available, the Company uses forward price curves. Forward price curves represent the Company's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. The Company bases its forward price curves upon market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent energy brokers, exchanges, direct communication with market participants and actual transactions executed by the Company. Market price quotations for certain major electricity and natural gas trading hubs are generally readily obtainable for the applicable term of the Company's outstanding derivative contracts; therefore, the Company's forward price curves for those locations and periods reflect observable market quotes. As of December 31, 2011, the Company had a net derivative liability of $468 million related to contracts valued using either quoted prices or forward price curves based upon observable market quotes. Market price quotations for other electricity and natural gas trading hubs are not as readily obtainable due to the length of the contract. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, the Company uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these derivative contracts is a function of underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of contracts. The assumptions used in these models are critical, since any changes in assumptions could have a significant impact on the estimated fair value of the contracts. As of December 31, 2011, the Company had a net derivative asset of $23 million related to contracts where the Company uses internal models with unobservable inputs.
Classification and Recognition Methodology
Almost all of the Company's derivative contracts are probable of inclusion in the rates of its rate-regulated subsidiaries and changes in the estimated fair value of derivative contracts are generally recorded as net regulatory assets or liabilities. Accordingly, amounts are generally not recognized in earnings until the contracts are settled and the forecasted transaction has occurred. As of December 31, 2011, the Company had $400 million recorded as net regulatory assets related to derivative contracts on the Consolidated Balance Sheets. If it becomes no longer probable that a derivative contract will be included in regulated rates, the regulatory asset or liability will be written off and recognized in earnings.
Impairment of Long-Lived Assets and Goodwill
The Company evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value. The impacts of regulation are considered when evaluating the carrying value of regulated assets. Substantially all property, plant and equipment was used in regulated businesses as of December 31, 2011. For all other assets, any resulting impairment loss is reflected on the Consolidated Statements of Operations.
The estimate of cash flows arising from the future use of the asset that are used in the impairment analysis requires judgment regarding what the Company would expect to recover from the future use of the asset. Changes in judgment that could significantly alter the calculation of the fair value or the recoverable amount of the asset may result from significant changes in the regulatory environment, the business climate, management's plans, legal factors, market price of the asset, the use of the asset or the physical condition of the asset, future market prices, load growth, competition and many other factors over the life of the asset. Any resulting impairment loss is highly dependent on the underlying assumptions and could significantly affect the Company's results of operations.
The Company's Consolidated Balance Sheet as of December 31, 2011 includes goodwill of acquired businesses of $4.996 billion. The Company evaluates goodwill for impairment at least annually and completed its annual review as of October 31. Additionally, no indicators of impairment were identified as of December 31, 2011. A significant amount of judgment is required in estimating the fair value of the reporting unit and performing goodwill impairment tests. The Company uses a variety of methods to estimate a reporting unit's fair value, principally discounted projected future net cash flows. Key assumptions used include, but are not limited to, the use of estimated future cash flows; multiples of earnings; and an appropriate discount rate. Estimated future cash flows are impacted by, among other factors, growth rates, changes in regulations and rates, ability to renew contracts and estimates of future commodity prices. In estimating future cash flows, the Company incorporates current market information, as well as historical factors. Refer to Note 22 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the Company's goodwill.
Pension and Other Postretirement Benefits
The Company sponsors defined benefit pension and other postretirement benefit plans that cover the majority of its employees. The Company recognizes the funded status of its defined benefit pension and other postretirement benefit plans on the Consolidated Balance Sheets. Funded status is the fair value of plan assets minus the benefit obligation as of the measurement date. As of December 31, 2011, the Company recognized a net liability totaling $794 million for the funded status of the Company's defined benefit pension and other postretirement benefit plans. As of December 31, 2011, amounts not yet recognized as a component of net periodic benefit cost that were included in net regulatory assets and AOCI totaled $822 million and $673 million, respectively.
The expense and benefit obligations relating to these defined benefit pension and other postretirement benefit plans are based on actuarial valuations. Inherent in these valuations are key assumptions, including discount rates, expected long-term rate of return on plan assets and healthcare cost trend rates. These key assumptions are reviewed annually and modified as appropriate. The Company believes that the assumptions utilized in recording obligations under the plans are reasonable based on prior plan experience and current market and economic conditions. Refer to Note 14 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for disclosures about the Company's defined benefit pension and other postretirement benefit plans, including the key assumptions used to calculate the funded status and net periodic benefit cost for these plans as of and for the year ended December 31, 2011.
The Company chooses a discount rate based upon high quality debt security investment yields in effect as of the measurement date that corresponds to the expected benefit period. The pension and other postretirement benefit liabilities increase as the discount rate is reduced.
In establishing its assumption as to the expected long-term rate of return on plan assets, the Company utilizes the expected asset allocation and return assumptions for each asset class based on historical performance and forward-looking views of the financial markets. Pension and other postretirement benefits expense increases as the expected long-term rate of return on plan assets decreases. The Company regularly reviews its actual asset allocations and rebalances its investments to its targeted allocations when considered appropriate.
The Company chooses a healthcare cost trend rate that reflects the near and long-term expectations of increases in medical costs and corresponds to the expected benefit payment periods. The healthcare cost trend rate gradually declines to 5% in 2016 at which point the rate is assumed to remain constant. Refer to Note 14 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for healthcare cost trend rate sensitivity disclosures.
The key assumptions used may differ materially from period to period due to changing market and economic conditions. These differences may result in a significant impact to pension and other postretirement benefits expense and the funded status. If changes were to occur for the following key assumptions, the approximate effect on the Consolidated Financial Statements would be as follows (in millions):
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Domestic Plans | | |
| | | | | | Other Postretirement | | United Kingdom |
| | Pension Plans | | Benefit Plans | | Pension Plan |
| | +0.5% | | -0.5% | | +0.5% | | -0.5% | | +0.5% | | -0.5% |
| | | | | | | | | | | | |
| Effect on December 31, 2011 | | | | | | | | | | | |
| Benefit Obligations: | | | | | | | | | | | |
| Discount rate | $ | (103 | ) | | $ | 114 |
| | $ | (41 | ) | | $ | 45 |
| | $ | (137 | ) | | $ | 157 |
|
| | | | | | | | | | | | |
| Effect on 2011 Periodic Cost: | | | | | | | | | | | |
| Discount rate | $ | (4 | ) | | $ | 4 |
| | $ | (2 | ) | | $ | 3 |
| | $ | (13 | ) | | $ | 13 |
|
| Expected rate of return on plan assets | (8 | ) | | 8 |
| | (3 | ) | | 3 |
| | (8 | ) | | 8 |
|
A variety of factors affect the funded status of the plans, including asset returns, discount rates, plan changes and the Company's funding policy for each plan. Additionally, federal laws may require the Company to increase future contributions to its domestic pension plans, which may create more volatility in annual contributions than historically experienced and could have a material impact on the Company's consolidated financial results.
Income Taxes
In determining the Company's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by the Company's various regulatory jurisdictions. The Company's income tax returns are subject to continuous examinations by federal, state, local and foreign income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. The Company recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. Although the ultimate resolution of the Company's federal, state, local and foreign income tax examinations is uncertain, the Company believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations, if any, is not expected to have a material adverse impact on the Company's consolidated financial results. Refer to Note 15 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the Company's income taxes.
The Utilities are required to pass income tax benefits related to certain property-related basis differences and other various differences on to their customers in certain state jurisdictions. These amounts were recognized as a net regulatory asset totaling $1.003 billion as of December 31, 2011 and will be included in regulated rates when the temporary differences reverse. Management believes the existing net regulatory assets are probable of inclusion in regulated rates. If it becomes no longer probable that these costs will be included in regulated rates, the related regulatory asset will be charged to net income.
The Company has not established deferred income taxes on the undistributed foreign earnings of Northern Powergrid Holdings or the related currency translation adjustment that have been determined by management to be reinvested indefinitely. The cumulative earnings were approximately$2.0 billion as of December 31, 2011. The Company periodically evaluates its capital requirements. If circumstances change in the future and a portion of Northern Powergrid Holdings' undistributed earnings were repatriated, the dividends would be subject to taxation in the United States. However, any United States income tax liability would be offset, in part, by available United States income tax credits with respect to corporate income taxes previously paid principally in the United Kingdom. Because of the availability of foreign income tax credits, it is not practicable to determine the United States income tax liability that would be recognized if such cumulative earnings were not reinvested indefinitely. The Company has established deferred income taxes on all other undistributed foreign earnings.
Revenue Recognition - Unbilled Revenue
Unbilled revenue was $474 million as of December 31, 2011. Revenue from energy business customers is recognized as electricity or natural gas is delivered or services are provided. The determination of customer billings is based on a systematic reading of meters, fixed reservation charges based on contractual quantities and rates or, in the case of the United Kingdom distribution businesses, when information is received from the national settlement system. At the end of each month, amounts of energy provided to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recorded. Factors that can impact the estimate of unbilled energy include, but are not limited to, seasonal weather patterns, total volumes supplied to the system, line losses, economic impacts and composition of sales among customer classes. Estimates are reversed in the following month and actual revenue is recorded based on subsequent meter readings.
| |
| Item 7A. | Quantitative and Qualitative Disclosures About Market Risk |
The Company's Consolidated Balance Sheets include assets and liabilities with fair values that are subject to market risks. The Company's significant market risks are primarily associated with commodity prices, interest rates, equity prices, foreign currency exchange rates and the extension of credit to counterparties with which the Company transacts. The following discussion addresses the significant market risks associated with the Company's business activities. Each of the Company's business platforms has established guidelines for credit risk management. Refer to Notes 2 and 7 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the Company's contracts accounted for as derivatives.
Commodity Price Risk
The Company is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk primarily through MEHC's ownership of the Utilities as they have an obligation to serve retail customer load in their regulated service territories. MidAmerican Energy also provides nonregulated retail electricity and natural gas services in competitive markets. The Utilities' load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity, wholesale electricity that is purchased and sold, and natural gas supply for regulated and nonregulated retail customers. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints.The Company does not engage in a material amount of proprietary trading activities.To mitigate a portion of its commodity price risk, the Company uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. The Company does not hedge all of its commodity price risk, thereby exposing the unhedged portion to changes in market prices. The Company's exposure to commodity price risk is generally limited by its ability to include the costs in regulated rates, which is subject to regulatory lag that occurs between the time the costs are incurred and when the costs are included in regulated rates.
The table that follows summarizes the Company's price risk on commodity contracts accounted for as derivatives, excluding collateral netting of $156 million and $141 million as of December 31, 2011 and 2010, respectively, and shows the effects of a hypothetical 10% increase and 10% decrease in forward market prices with the contracted or expected volumes. The selected hypothetical change does not reflect what could be considered the best or worst case scenarios (dollars in millions).
|
| | | | | | | | | | | |
| | Fair Value - | | Estimated Fair Value after |
| | Net Asset | | Hypothetical Change in Price |
| | (Liability) | | 10% increase | | 10% decrease |
| As of December 31, 2011: | | | | | |
| Not designated as hedging contracts | $ | (399 | ) | | $ | (341 | ) | | $ | (457 | ) |
| Designated as hedging contracts | (46 | ) | | (7 | ) | | (85 | ) |
| Total commodity derivative contracts | $ | (445 | ) | | $ | (348 | ) | | $ | (542 | ) |
| | | | | | |
| As of December 31, 2010: | | | | | |
| Not designated as hedging contracts | $ | (565 | ) | | $ | (537 | ) | | $ | (593 | ) |
| Designated as hedging contracts | (48 | ) | | (9 | ) | | (87 | ) |
| Total commodity derivative contracts | $ | (613 | ) | | $ | (546 | ) | | $ | (680 | ) |
The majority of the Company's commodity derivative contracts not designated as hedging contracts are recoverable from customers in regulated rates and, therefore, net unrealized gains and losses associated with interim price movements on commodity derivative contracts do not expose the Company to earnings volatility. As of December 31, 2011 and 2010, a net regulatory asset of $400 million and $564 million, respectively, was recorded related to the net derivative liability of $399 million and $565 million, respectively. For the Company's commodity derivative contracts designated as hedging contracts, net unrealized gains and losses associated with interim price movements on commodity derivative contracts, to the extent the hedge is considered effective, generally do not expose the Company to earnings volatility. The settled cost of these commodity derivative contracts is generally included in regulated rates. Consolidated financial results would be negatively impacted if the costs of wholesale electricity, natural gas or fuel are higher than what is included in regulated rates, including the impacts of adjustment mechanisms.
Interest Rate Risk
The Company is exposed to interest rate risk on its outstanding variable-rate short- and long-term debt and future debt issuances. The Company manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. As a result of the fixed interest rates, the Company's fixed-rate long-term debt does not expose the Company to the risk of loss due to changes in market interest rates. Additionally, because fixed-rate long-term debt is not carried at fair value on the Consolidated Balance Sheets, changes in fair value would impact earnings and cash flows only if the Company were to reacquire all or a portion of these instruments prior to their maturity. The Company may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate the Company's exposure to interest rate risk. The nature and amount of the Company's short- and long-term debt can be expected to vary from period to period as a result of future business requirements, market conditions and other factors. Refer to Notes 6, 9, 10, 11 and 12 of Notes to Consolidated Financial Statements in Item 1 of this Form 10-K for additional discussion of the Company's short- and long-term debt.
As of December 31, 2011 and 2010, the Company had short- and long-term variable-rate obligations totaling $1.715 billion and $1.170 billion, respectively, that expose the Company to the risk of increased interest expense in the event of increases in short-term interest rates. The market risk related to the Company's variable-rate debt as of December 31, 2011 is not hedged. If variable interest rates were to increase by 10% from December 31 levels, it would not have a material effect on the Company's consolidated annual interest expense. The carrying value of the variable-rate obligations approximates fair value as of December 31, 2011 and 2010.
Equity Price Risk
Market prices for equity securities are subject to fluctuation and consequently the amount realized in the subsequent sale of an investment may significantly differ from the reported market value. Fluctuation in the market price of a security may result from perceived changes in the underlying economic characteristics of the investee, the relative price of alternative investments and general market conditions.
As of December 31, 2011 and 2010, the Company's investment in BYD Company Limited common stock represented approximately 68% and 84%, respectively, of the total fair value of the Company's equity securities. The Company's remaining equity securities are primarily related to certain trust funds in which realized and unrealized gains and losses are recorded as net regulatory assets or liabilities since the Company expects to recover costs for these activities through regulated rates. The following table summarizes our investment in BYD Company Limited as of December 31, 2011 and 2010 and the effects of a hypothetical 30% increase and a 30% decrease in market price as of those dates. The selected hypothetical change does not reflect what could be considered the best or worst case scenarios (dollars in millions).
|
| | | | | | | | | | | | |
| | | | | | Estimated | | Hypothetical |
| | | | Hypothetical | | Fair Value after | | Percentage Increase |
| | Fair | | Price | | Hypothetical | | (Decrease) in MEHC |
| | Value | | Change | | Change in Prices | | Shareholders' Equity |
| | | | | | | | |
| As of December 31, 2011 | $ | 488 |
| | 30% increase | | $ | 634 |
| | 1 | % |
| | | | 30% decrease | | 342 |
| | (1 | ) |
| | | | | | | | |
| As of December 31, 2010 | $ | 1,182 |
| | 30% increase | | $ | 1,537 |
| | 2 | % |
| | | | 30% decrease | | 827 |
| | (2 | ) |
Foreign Currency Exchange Rate Risk
MEHC's business operations and investments outside of the United States increase its risk related to fluctuations in foreign currency exchange rates primarily in relation to the British pound. MEHC's reporting currency is the United States dollar, and the value of the assets and liabilities, earnings, cash flows and potential distributions from MEHC's foreign operations changes with the fluctuations of the currency in which they transact.
Northern Powergrid Holdings' functional currency is the British pound. At December 31, 2011, a 10% devaluation in the British pound to the United States dollar would result in the Company's Consolidated Balance Sheet being negatively impacted by a $270 million cumulative translation adjustment in AOCI. A 10% devaluation in the average currency exchange rate would have resulted in lower reported earnings for Northern Powergrid Holdings of $39 million in 2011.
Credit Risk
Domestic Regulated Operations
The Utilities extend unsecured credit to other utilities, energy marketing companies, financial institutions and other market participants in conjunction with their wholesale energy supply and marketing activities. Credit risk relates to the risk of loss that might occur as a result of nonperformance by counterparties on their contractual obligations to make or take delivery of electricity, natural gas or other commodities and to make financial settlements of these obligations. Credit risk may be concentrated to the extent that one or more groups of counterparties have similar economic, industry or other characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in market or other conditions. In addition, credit risk includes not only the risk that a counterparty may default due to circumstances relating directly to it, but also the risk that a counterparty may default due to circumstances involving other market participants that have a direct or indirect relationship with the counterparty.
The Utilities analyze the financial condition of each significant wholesale counterparty before entering into any transactions, establish limits on the amount of unsecured credit to be extended to each counterparty and evaluate the appropriateness of unsecured credit limits on an ongoing basis. To mitigate exposure to the financial risks of wholesale counterparties, the Utilities enter into netting and collateral arrangements that may include margining and cross-product netting agreements and obtain third-party guarantees, letters of credit and cash deposits. Counterparties may be assessed fees for delayed payments. If required, the Utilities exercise rights under these arrangements, including calling on the counterparty's credit support arrangement.
As of December 31, 2011, PacifiCorp's aggregate credit exposure from wholesale activities totaled $338 million, based on settlement and mark-to-market exposures, net of collateral. As of December 31, 2011, $333 million, or 99%, of PacifiCorp's credit exposure was with counterparties having investment grade credit ratings by either Moody's Investor Service or Standard & Poor's Rating Services. As of December 31, 2011, $5 million, or 1%, of such credit exposure was with counterparties having externally rated "non-investment grade" credit ratings. As of December 31, 2011, four counterparties comprised $274 million, or 81%, of the aggregate credit exposure. All four counterparties are rated investment grade by Moody's Investor Service and Standard & Poor's Rating Services, and PacifiCorp is not aware of any factors that would likely result in a downgrade of the counterparties' credit ratings to below investment grade over the remaining term of transactions outstanding as of December 31, 2011.
During 2011, approximately 89% of MidAmerican Energy's electric wholesale sales revenues resulted from participation in RTOs, including the MISO and the PJM. MidAmerican Energy has potential indirect credit exposure to other market participants in these RTO markets. In the event of a default by a RTO market participant on its market-related obligations, losses are allocated among all other market participants in proportion to each participant's share of overall market activity during the period of time the loss was incurred, diversifying MidAmerican Energy's exposure to credit losses from individual participants. Transactional activities of MidAmerican Energy and other participants in organized RTO markets are governed by credit policies specified in each respective RTO's governing tariff or related business practices. Credit policies of RTO's, which have been developed through extensive stakeholder participation, generally seek to minimize potential loss in the event of a market participant default without unnecessarily inhibiting access to the marketplace. MidAmerican Energy's share of historical losses from defaults by other RTO market participants has not been material. As of December 31, 2011, MidAmerican Energy's aggregate direct credit exposure from electric wholesale marketing counterparties was not material.
Northern Natural Gas' primary customers include utilities in the upper Midwest. Kern River's primary customers are major oil and natural gas companies or affiliates of such companies, electric generating companies, energy marketing and trading companies, financial institutions and natural gas distribution utilities which provide services in Utah, Nevada and California. As a general policy, collateral is not required for receivables from creditworthy customers. Customers' financial condition and creditworthiness, as defined by the tariff, are regularly evaluated and historical losses have been minimal. In order to provide protection against credit risk, and as permitted by the separate terms of each of Northern Natural Gas' and Kern River's tariffs, the companies have required customers that lack creditworthiness to provide cash deposits, letters of credit or other security until their creditworthiness improves.
Northern Powergrid Holdings
The Distribution Companies charge fees for the use of their electrical infrastructure to supply companies and generators connected to their networks. The supply companies, which purchase electricity from generators and traders and sell the electricity to end-use customers, use the Distribution Companies' distribution networks pursuant to the multilateral "Distribution Connection and Use of System Agreement." The Distribution Companies' customers are concentrated in a small number of electricity supply businesses with RWE Npower PLC accounting for approximately 29% of distribution revenue in 2011. Ofgem has determined a framework which sets credit limits for each supply business based on its credit rating or payment history and requires them to provide credit cover if their value at risk (measured as being equivalent to 45 days usage) exceeds the credit limit. Acceptable credit typically is provided in the form of a parent company guarantee, letter of credit or an escrow account. Ofgem has indicated that, provided the Distribution Companies have implemented credit control, billing and collection in line with best practice guidelines and can demonstrate compliance with the guidelines or are able to satisfactorily explain departure from the guidelines, any bad debt losses arising from supplier default will be recovered through an increase in future allowed income. Losses incurred to date have not been material.
CalEnergy PhilippinesCapitalized Interest
Operating revenueCapitalized interest decreased $42$14 million for 2011 compared to 2010 due to lower construction work-in-progress balances at PacifiCorp, partially offset by higher construction work-in-progress balances at MidAmerican Energy and operatingKern River.
Capitalized interest increased $13 million for 2010 compared to 2009 due to higher construction work-in-progress balances at PacifiCorp.
Interest and Dividend Income
Interest and dividend income decreased $42$10 million for 2011 compared to 2010 due to an $11 million dividend received in 2010 from BYD Company Limited.
Interest and dividend income decreased $14 million for 2010 compared to 2009 due to interest associated with SB 408 refunds received in 2009 at PacifiCorp, income earned in 2009 related to the Constellation Energy investments and lower average cash balances, partially offset by the dividend received in 2010 from BYD Company Limited.
Other, net
Other, net decreased $59 million for 2011 compared to 2010 due to costs associated with the early redemption of MEHC subordinated debt totaling $40 million, lower equity AFUDC of $17 million and lower Rabbi Trust earnings, partially by the impairment of an asset in 2010 totaling $8 million at MidAmerican Funding. Equity AFUDC decreased due to lower construction work-in-progress balances at PacifiCorp, partially offset by higher construction work-in-progress balances at MidAmerican Energy and Kern River.
Other, net decreased $36 million for 2010 compared to 2009 due primarily to a $37 million pre-tax gain on the Constellation Energy common stock investment in 2009 and the impairment of an asset in 2010 at MidAmerican Funding, partially offset by higher equity AFUDC in 2010, primarily at PacifiCorp and MidAmerican Energy.
Income Tax Expense
Income tax expense increased $96 million for 2011 compared to 2010. The effective tax rates were 18% and 14% for 2011 and 2010, respectively. The increase in the effective tax rate was due to the effects of ratemaking, lower tax benefits received at MidAmerican Energy for changes related to the tax capitalization and repairs deductions policies totaling $26 million and higher United States income taxes on foreign earnings, partially offset by additional production tax credits in 2011 totaling $29 million, higher deferred income tax benefits in 2011 related to enacted changes in the United Kingdom's corporate income tax rate discussed below and lower state income taxes.
In July 2011, the Company recognized $40 million of deferred income tax benefits upon the enactment of a reduction in the United Kingdom corporate income tax rate from 27% to 26% effective April 1, 2011, and a further reduction to 25% effective April 1, 2012. In July 2010, the Company recognized $25 million of deferred income tax benefits upon the enactment of the reduction in the United Kingdom corporate income tax rate from 28% to 27% effective April 1, 2011.
Federal renewable electricity production tax credits are earned on qualifying wind-powered generation placed in service. In 2004, the Utilities began placing qualified wind-powered generation in service and that has continued through 2011. Federal renewable electricity production tax credits are recognized as energy from wind-powered generating facilities is sold based on a per kilowatt rate as prescribed pursuant to the applicable federal income tax law and are eligible for the credit for 10 years from the date the qualifying generating facilities were placed in service. A credit of $0.022 per kilowatt hour was applied to 2011 production.
Income tax expense decreased $84 million for 2010 compared to 2009. The effective tax rates were 14% and 20% for 2010 and 2009, respectively. The decrease in the effective tax rate was primarily due to deferred income tax benefits totaling $25 million upon the enactment of the reduction in the United Kingdom corporate income tax rate from 28% to 27%, additional production tax credits totaling $20 million, a non-taxable gain on the sale of CE Gas (Australia) Limited and higher tax benefits received at MidAmerican Energy for changes related to the tax capitalization policy and repairs deductions totaling $6 million, partially offset by the impact of ratemaking. The benefits for changes to the tax capitalization policy and the repairs deductions were realized as MidAmerican Energy changed the method by which it determines current income tax deductions for overhead costs and repairs on certain of its regulated utility assets, which results in current deductibility for costs that are capitalized for book purposes. Iowa, MidAmerican Energy's largest jurisdiction for rate-regulated operations, requires immediate income recognition of such temporary differences.
Equity Income
Equity income increased $10 million for 2011 compared to 2010 due to continued investment at ETT and higher earnings at CE Generation due to improved results at the gas plants, partially offset by lower earnings at HomeServices' mortgage joint venture due to lower refinancing activity and higher compliance costs.
Equity income decreased $12 million for 2010 compared to 2009 due to lower than normal rainfallearnings at CE Generation, primarily due to the expiration of a favorable power purchase contract in 2010 and above normal rainfall inthe second quarter of 2009 at the Casecnan project, which resulted in lower variable ene rgy and water delivery fees earned in 2010.Saranac project.
Operating revenue increased $9Net Income Attributable to Noncontrolling Interests
Net income attributable to noncontrolling interests decreased $51 million and operating income increased $10 million for 20092011 compared to 2008 due to above normal rainfall in 2009 at the Casecnan project, which resulted in higher variable water delivery fees earned in 2009, partially offset by lower prices received on variable energy.
HomeServices
Operating revenue decreased $172010 and increased $41 million for 2010 compared to 2009 primarily due to a 7% decrease in closed brokerage units, partially offset by higher average home sales prices. Operating income increased $6 million for 2010 compared to 2009 primarily due to lower operating expenses and lower comm issions, partially offset by the lower operating revenue.
Operating revenue decreased $96 million for 2009 compared to 2008 due to declines in average home sale prices of 10% and transaction volumes of 1%. Lower mortgage and brokerage activity during the first nine months of 2009 was mostly offset by higher activity in the fourth quarter in part due to the new homebuyer credit. Operating income increased $69 million for 2009 compared to 2008 due to lower commissions, $30&nbs p;million of higher office closure charges taken in 2008 and lower other operating expenses, partially offset by the lower operating revenue.
Corporate/other
Operating income increased $110 million for 2010 compared to 2009 due to $125a $54 million pre-tax charge in 2010 related to the CE Casecnan noncontrolling interest settlement.
Liquidity and Capital Resources
Each of stock-based compensation expense in 2009MEHC's direct and indirect subsidiaries is organized as a resultlegal entity separate and apart from MEHC and its other subsidiaries. It should not be assumed that the assets of any subsidiary will be available to satisfy MEHC's obligations or the purchaseobligations of common stock issued byits other subsidiaries. However, unrestricted cash or other assets that are available for distribution may, subject to applicable law, regulatory commitments and the terms of financing and ring-fencing arrangements for such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to MEHC uponor affiliates thereof. The long-term debt of subsidiaries may include provisions that allow MEHC's subsidiaries to redeem it in whole or in part at any time. These provisions generally include make-whole premiums. Refer to Note 17 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding the exerciselimitation of distributions from MEHC's subsidiaries.
As of December 31, 2011, the last remaining stock optionsCompany's total net liquidity was $3.741 billion. The components of total net liquidity are as follows (in millions):
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | Northern | | | | |
| | | | | | MidAmerican | | Powergrid | | | | |
| | MEHC | | PacifiCorp | | Funding | | Holdings | | Other | | Total |
| | | | | | | | | | | | |
| Cash and cash equivalents | $ | 13 |
| | $ | 47 |
| | $ | 1 |
| | $ | 21 |
| | $ | 204 |
| | $ | 286 |
|
| | |
| | | | | | | | | | |
|
| Credit facilities | 552 |
| | 1,355 |
| | 654 |
| | 233 |
| | 50 |
| | 2,844 |
|
| Less: | | | | | | | | | | | |
|
| Short-term debt | (108 | ) | | (688 | ) | | — |
| | (69 | ) | | — |
| | (865 | ) |
Tax-exempt bond support and letters of credit | (25 | ) | | (304 | ) | | (195 | ) | | — |
| | — |
| | (524 | ) |
| Net credit facilities | 419 |
| | 363 |
| | 459 |
| | 164 |
| | 50 |
| | 1,455 |
|
| | | | | | | | | | | | |
Net liquidity before Berkshire Equity Commitment | $ | 432 |
| | $ | 410 |
| | $ | 460 |
| | $ | 185 |
| | $ | 254 |
| | $ | 1,741 |
|
Berkshire Equity Commitment(1) | 2,000 |
| | |
| | |
| | |
| | |
| | 2,000 |
|
| Total net liquidity | $ | 2,432 |
| | |
| | |
| | |
| | |
| | $ | 3,741 |
|
| Unsecured revolving credit facilities: | |
| | |
| | |
| | |
| | |
| | |
|
| Maturity date | 2013 |
| | 2012, 2013 |
| | 2012, 2013 |
| | 2013 |
| | 2013 |
| | |
|
Largest single bank commitment as a % of total revolving credit facilities(2) | 18 | % | | 16 | % | | 23 | % | | 33 | % | | 100 | % | | |
|
| |
| (1) | MEHC has an Equity Commitment Agreement with Berkshire Hathaway (the "Berkshire Equity Commitment") pursuant to which Berkshire Hathaway has agreed to purchase up to $2.0 billion of MEHC's common equity upon any requests authorized from time to time by MEHC's Board of Directors. The proceeds of any such equity contribution shall only be used for the purpose of (a) paying when due MEHC's debt obligations and (b) funding the general corporate purposes and capital requirements of MEHC's regulated subsidiaries. The Berkshire Equity Commitment expires on February 28, 2014. |
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| (2) | An inability of financial institutions to honor their commitments could adversely affect the Company's short-term liquidity and ability to meet long-term commitments. |
The above table does not include unused revolving credit facilities and letters of credit for investments that had been granted to certain members of management atare accounted for under the timeequity method.
In January 2012, MEHC entered into a $500 million revolving loan agreement with a subsidiary of Berkshire Hathaway's acquisitionHathaway that expires June 30, 2012. Refer to Note 9 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding the Company's credit facilities.
In January 2012, subsidiaries of MEHC acquired ownership interests in 2000.two solar projects. Refer to Note 23 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding the Company's equity commitments, letters of credit and other related items.
Operating Activities
Operating income decreased $124 million for 2009 compared to 2008 due to the $125 million of stock-based compensation expense in 2009.
Consolidated Other Income and Expense Items
Interest Expense
Interest expenseNet cash flows from operating activities for the years ended December 31, 2011 and 2010 were $3.220 billion and $2.759 billion, respectively. The increase was primarily due to higher income tax receipts of $270 million mainly attributable to bonus depreciation, improved operating results, changes in collateral posted for derivative contracts and a Kern River customer rate refund in 2010, partially offset by changes in working capital.
Net cash flows from operating activities for the years ended December 31, 2010 and 2009 were $2.759 billion and $3.572 billion, respectively. The decrease was mainly due to lower income tax receipts of $391 million due to the timing of repairs deductions and bonus depreciation, changes in collateral posted for derivative contracts, $128 million of net cash flows in 2009 related to the Constellation Energy transaction, which is comprised of $536 million of proceeds received from the sale of Constellation Energy common stock and $408 million of income taxes paid on gains recognized on the termination of the Constellation Energy merger agreement in December 2008 and the sale of stock in 2009, higher contributions to pension and other postretirement benefit plans and rate case refunds paid in 2010 at Kern River.
In September 2010, the President signed the Small Business Jobs Act into law, extending retroactively to January 1, 2010 the 50% bonus depreciation for qualifying property purchased and placed in service in 2010. In December 2010, the President signed the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 into law, which provided for 100% bonus depreciation for qualifying property purchased and placed in service after September 8, 2010 and prior to January 1, 2012, and extended 50% bonus depreciation for qualifying property purchased and placed in service after December 31, 2010 and prior to January 1, 2013. As a result of the new laws, the Company's cash flows from operations benefited in 2011 and are expected to benefit in 2012 due to bonus depreciation on qualifying assets placed in service.
Investing Activities
Net cash flows from investing activities for the years ended December 31, 2011 and 2010 were $(2.816) billion and $(2.484) billion, respectively. The change was primarily due to higher capital expenditures of $91 million, proceeds received from the sale of certain Australian hydrocarbon exploration and development assets during the second quarter of 2010 totaling $78 million and net proceeds received from the sale of CE Gas (Australia) Limited during the third quarter of 2010 totaling $59 million and higher investments in companies accounted for under the equity method totaling $58 million.
Net cash flows from investing activities for the years ended December 31, 2010 and 2009 were $(2.484) billion and $(2.669) billion, respectively. Capital expenditures decreased $820 million. In January 2009, the Company received $1 billion, plus accrued interest, in full satisfaction of the 14% Senior Notes from Constellation Energy. In July 2009, the Company purchased 225 million shares, representing approximately a 10% interest, of BYD Company Limited common stock for $232 million. Additionally, the Company received proceeds from the sales of certain CE Gas assets in 2010 totaling $137 million, partially offset by higher investments in companies accounted for under the equity method totaling $32 million.
Capital Expenditures
Capital expenditures, which exclude amounts for non-cash equity AFUDC and other non-cash items, by reportable segment for the years ended December 31 are summarized as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2010 | | 2009 | | Change | | 2009 | | 2008 | | Change |
| | | | | | | | | | | | |
| Subsidiary debt | $ | 844 | | | $ | 864 | | | $ | (20 | ) | | (2 | )% | | $ | 864 | | | $ | 850 | | | $ | 14 | | | 2 | % |
| MEHC senior debt and other | 329 | | | 331 | | | (2 | ) | | (1 | ) | | 331 | | | 348 | | | (17 | ) | | (5 | ) |
| MEHC subordinated debt- | | | | | | | | | | | | | | | |
| Berkshire Hathaway | 30 | | | 58 | | | (28 | ) | | (48 | ) | | 58 | | | 111 | | | (53 | ) | | (48 | ) |
| MEHC subordinated debt-other | 22 | | | 22 | | | — | | | — | | | 22 | | | 24 | | | (2 | ) | | (8 | ) |
| Total interest expense | $ | 1,225 | | | $ | 1,275 | | | $ | (50 | ) | | (4 | ) | | $ | 1,275 | | | $ | 1,333 | | | $ | (58 | ) | | (4 | ) |
|
| | | | | | | | | | | |
| | 2011 | | 2010 | | 2009 |
| Capital expenditures: | | | | | |
| PacifiCorp | $ | 1,506 |
| | $ | 1,607 |
| | $ | 2,328 |
|
| MidAmerican Funding | 566 |
| | 338 |
| | 439 |
|
| MidAmerican Energy Pipeline Group | 289 |
| | 293 |
| | 250 |
|
| Northern Powergrid Holdings | 309 |
| | 349 |
| | 387 |
|
| Other | 14 |
| | 6 |
| | 9 |
|
| Total capital expenditures | $ | 2,684 |
| | $ | 2,593 |
| | $ | 3,413 |
|
Interest expense decreased $50 million for 2010 compared to 2009 due to scheduled maturities, principal repayments and lower interest rates on variable rate debt.
The Company's capital expenditures relate primarily to the Utilities and consisted mainly of the following for the years ended December 31:
2011:
The construction of wind-powered generating facilities at MidAmerican Energy totaling $295 million, which excludes $647 million of costs for which payments are due in December 2013. MidAmerican Energy placed in service 594 MW during 2011 and is constructing an additional 407 MW to be placed in service in 2012.
Transmission system investments totaling $240 million, including permitting and right-of-way costs for the 100-mile high-voltage transmission line being built between the Mona substation in central Utah and the Oquirrh substation in the Salt Lake Valley. A 65-mile segment of the Mona to Oquirrh transmission project will be a single-circuit 500-kV transmission line, while the remaining 35-mile segment will be a double-circuit 345-kV transmission line. The transmission line is expected to be placed in service in 2013.
Emissions control equipment on existing generating facilities totaling $217 million for installation or upgrade of sulfur dioxide scrubbers, low nitrogen oxide burners and particulate matter control systems.
The development and construction of the Lake Side 2 637-MW combined-cycle combustion turbine natural gas-fueled generating facility ("Lake Side 2") totaling $180 million, which is expected to be placed in service in 2014.
Distribution, generation, mining and other infrastructure needed to serve existing and expected demand totaling $1.140 billion.
2010:
Emissions control equipment totaling $348 million.
Transmission system investments totaling $303 million, including construction costs for the first major segment of the Energy Gateway Transmission Expansion Program, a 135-mile, double circuit, 345-kilovolt transmission line between the Populus substation in southern Idaho and the Terminal substation near Salt Lake City, Utah, which was fully placed in-service in 2010.
The development and construction of wind-powered generating facilities totaling $228 million. During 2010, PacifiCorp placed in service a 111 MW wind-powered generating facility, and MidAmerican Energy began contracting for the construction of 594 MW of wind-powered generating projects.
Distribution, generation, mining and other infrastructure needed to serve existing and expected demand totaling $1.066 billion.
2009:
Transmission system investments totaling $715 million, including a major segment of the Energy Gateway Transmission Expansion Program at PacifiCorp.
Emissions control equipment totaling $372 million.
The development and construction of wind-powered generating facilities totaling $250 million, including 127 MW PacifiCorp placed in service in September 2009 and construction costs for PacifiCorp's 111-MW Dunlap Ranch wind-powered generating facility.
Distribution, generation, mining and other infrastructure needed to serve existing and expected demand totaling $1.430 billion.
Interest expense decreasedAdditionally, capital expenditures for the years ended December 31, 2011, 2010 and 2009 include costs related to Kern River's expansion projects totaling $174 million, $129 million and $65 million, respectively. The 2010 Expansion project was placed in service in April 2010 and added 145,000 Dth per day of capacity. The Apex Expansion project was placed in service in October 2011 and added 266,000 Dth per day of capacity. The remaining amounts are for ongoing investments in distribution and other infrastructure needed at the other platforms to serve existing and expected demand.
Financing Activities
Net cash flows from financing activities for the year ended December 31, 2011 were $58(589) million. Uses of cash totaled $1.924 billion and consisted mainly of $1.548 billion for repayments of subsidiary debt, repayments of MEHC subordinated debt totaling $334 million, including $191 million called and repaid at par value, and net payments to noncontrolling interest totaling $24 million. Sources of cash totaled $1.335 billion and consisted of proceeds from subsidiary debt totaling $790 million and net proceeds from short-term debt totaling $545 million. Debt issuances during the year ended December 31, 2011 included the following:
In May 2011, PacifiCorp issued $400 million of 3.85% First Mortgage Bonds due June 15, 2021. The net proceeds were used to fund capital expenditures, repay short-term debt and for general corporate purposes.
In April 2011, Northern Natural Gas issued $200 million of 4.25% Senior Notes due June 1, 2021. The net proceeds were used to partially repay its $250 million, 7.0% Senior Notes due June 1, 2011.
In January and February 2011, Northern Powergrid (Northeast) Limited issued £119 million of notes with maturity dates ranging from 2018 to 2020 at interest rates ranging from 3.901% to 4.586% under its finance contract with the European Investment Bank.
Net cash flows from financing activities for the year ended December 31, 2010 were $(234) million. Uses of cash totaled $614 million and consisted mainly of repayments of MEHC subordinated debt totaling $281 million, including $92 million called and repaid at par value, repayments of subsidiary debt totaling $192 million, net payments to noncontrolling interests totaling $80 million and net purchases of common stock totaling $56 million. Sources of cash totaled $380 million and consisted of proceeds from subsidiary debt totaling $231 million and net proceeds from short-term debt totaling $149 million.
Net cash flows from financing activities for the year ended December 31, 2009 were $(758) million. Uses of cash totaled $2.0 billion and consisted mainly of repayments of MEHC subordinated debt totaling $734 million, net repayments of short-term debt totaling $664 million, repayments of subsidiary debt totaling $444 million, net purchases of common stock of $123 million and net payments to noncontrolling interests totaling $19 million. Sources of cash totaled $1.242 billion and consisted of proceeds from the issuance of subsidiary debt totaling $992 million and proceeds from the issuance of MEHC senior debt totaling $250 million.
2012 Long-term Debt Transactions
In February 2012, Topaz issued $850 million of the 5.75% Series A Senior Secured Notes. The principal of the notes amortize beginning September 2015 with a final maturity in September 2039. The net proceeds will be used to fund or reimburse the costs and expenses related to the development, construction and financing of the Topaz Project, including amounts that have been advanced by, or will be advanced by, MEHC for the Topaz Project. Any unused amounts will be invested or, in certain circumstances, loaned to MEHC. Topaz expects to issue approximately $430 million of additional senior secured notes contingent upon certain contractual conditions and market conditions to fund construction costs.
In January 2012, PacifiCorp issued $350 million of its 2.95% First Mortgage Bonds due February 1, 2022 and $300 million of its 4.10% First Mortgage Bonds due February 1, 2042. The net proceeds were used to repay short-term debt, fund capital expenditures and for general corporate purposes.
The Company may from time to time seek to acquire its outstanding debt securities through cash purchases in the open market, privately negotiated transactions or otherwise. Any debt securities repurchased by the Company may be reissued or resold by the Company from time to time and will depend on prevailing market conditions, the Company's liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
Future Uses of Cash
The Company has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the issuance of commercial paper, the use of unsecured revolving credit facilities, the issuance of equity and other sources. These sources are expected to provide funds required for current operations, capital expenditures, acquisitions, investments, debt retirements and other capital requirements. The availability and terms under which each subsidiary has access to external financing depends on a variety of factors, including its credit ratings, investors' judgment of risk and conditions in the overall capital market, including the condition of the utility industry in general. Additionally, MEHC has the Berkshire Equity Commitment pursuant to which Berkshire Hathaway has agreed to purchase up to $2.0 billion of MEHC's common equity upon any requests authorized from time to time by MEHC's Board of Directors. The Berkshire Equity Commitment expires on February 28, 2014 and may only be used for the purpose of (a) paying when due MEHC's debt obligations and (b) funding the general corporate purposes and capital requirements of MEHC's regulated subsidiaries. Berkshire Hathaway will have up to 180 days to fund any such request in increments of at least $250 million pursuant to one or more drawings authorized by MEHC's Board of Directors. The funding of any such drawing will be made by means of a cash equity contribution to MEHC in exchange for additional shares of MEHC's common stock.
Capital Expenditures
The Company has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in rules and regulations, including environmental and nuclear; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; and the cost and availability of capital. Prudently incurred expenditures for compliance-related items, such as pollution-control technologies, replacement generation, nuclear decommissioning, hydroelectric relicensing, hydroelectric decommissioning and associated operating costs are generally incorporated into MEHC's energy subsidiaries' regulated retail rates.
Forecasted capital expenditures, which exclude amounts for non-cash equity AFUDC and other non-cash items, for the years ended December 31 are as follows (in millions):
|
| | | | | | | | | | | |
| | 2012 | | 2013 | | 2014 |
Forecasted capital expenditures: | | | | | |
| Construction and other development projects | $ | 2,094 |
| | $ | 2,051 |
| | $ | 1,959 |
|
| Operating projects | 1,753 |
| | 1,426 |
| | 1,638 |
|
| Total | $ | 3,847 |
| | $ | 3,477 |
| | $ | 3,597 |
|
Construction and other development projects consist mainly of large scale projects at MidAmerican Renewables and the Utilities.
In January 2012, MEHC acquired Topaz and its 550-MW Topaz Project in California from a subsidiary of First Solar, Inc. ("First Solar"). The Topaz Project is expected to cost approximately $2.44 billion, including all interest during construction, and will be completed in 22 blocks with an aggregate tested capacity of 586 MW. The Topaz Project expects to place 45 MW in service in 2012, 236 MW in service in 2013, 252 MW in service in 2014 and 53 MW in service in 2015. The Topaz Project is being constructed pursuant to a fixed price, date certain, turn-key engineering, procurement and construction contract with a subsidiary of First Solar.
MEHC has committed to provide Topaz with equity to fund the costs of the Topaz Project in an amount up to $2.44 billion less, among other things, the gross proceeds of long-term debt issuances (including the gross proceeds of $850 million of the 5.75% Series A Senior Secured Notes issued by Topaz in February 2012), project revenue prior to completion and the total equity contributions made by MEHC or its subsidiaries. If MEHC does not maintain a minimum credit rating from two of the following three rating agencies of at least BBB- from Standard & Poor's Ratings Services or Fitch Ratings or Baa3 from Moody's Investors Service, MEHC's obligations under the equity commitment agreement would be supported by cash collateral or a letter of credit issued by a financial institution that meets certain minimum criteria specified in the financing documents. Upon reaching the final commercial operation date of the Topaz Project, MEHC will have no further obligation to make any equity contribution and any unused equity contribution obligations will be canceled.
The Utilities anticipate costs for emissions control equipment will total $1.361 billion between 2012 and 2014, which includes equipment to meet anticipated air quality and visibility targets, including the reduction of sulfur dioxide, nitrogen oxides and particulate matter emissions. This estimate includes the installation of new or the replacement of existing emissions control equipment at a number of units at several of the Utilities coal-fueled generating facilities.
PacifiCorp anticipates costs for transmission projects will total $1.205 billion between 2012 and 2014. The costs include PacifiCorp's Energy Gateway Transmission Expansion Program totaling $905 million, including the following estimated costs:
$245 million for the 100-mile high-voltage transmission line being built between the Mona substation in central Utah and the Oquirrh substation in the Salt Lake Valley. A 65-mile segment of the Mona to Oquirrh transmission project will be a single-circuit 500-kV transmission line, while the remaining 35-mile segment will be a double-circuit 345-kV transmission line. The project is estimated to cost $374 million and is expected to be placed in service in 2013.
$288 million for the 160-mile single-circuit 345-kV transmission line being built between the Sigurd Substation in central Utah and the Red Butte Substation in southwest Utah. The Sigurd to Red Butte project is estimated to cost $380 million and is expected to be placed in service in 2015.
$372 million for other segments associated with the Energy Gateway Transmission Expansion Program that are expected to be placed in service through 2021, depending on siting, permitting and construction schedules.
PacifiCorp anticipates costs for additional natural gas-fueled generating facilities will total $893 million between 2012 and 2014, which includes the construction of the Lake Side 2 natural gas-fueled generating facility that is expected to be placed in service in 2014, and the initial development and construction of another combined-cycle combustion turbine natural gas-fueled generating facility planned to be placed in service in 2016.
MidAmerican Energy is constructing 407 MW (nominal ratings) of wind-powered generation that it expects to place in service in 2012. Total costs are estimated to be $680 million, with the payment of over half of those costs deferred until the fourth quarter of 2015.
MidAmerican Renewables anticipates costs for the Bishop Hill II Project, an 81 MW wind-powered generating facility, will total $164 million in 2012. The Bishop Hill II Project is expected to be placed in service in 2012. Definitive agreements have been executed, subject to customary closing conditions, and the acquisition is expected to close in March 2012.
In December 2011, MidAmerican Energy received approval from the MISO for several MVPs located in Iowa and Illinois totaling approximately $550 million in capital expenditures, the bulk of which will be incurred in 2014-2017. As of December 31, 2011, MidAmerican Energy had not contractually committed to material amounts for these projects.
Separately, in July 2011, the FERC issued Order No. 1000, which addresses transmission planning and cost allocation issues. Among other things, Order No. 1000 removes the federal right of first refusal for certain new transmission investments approved by the MISO following its compliance filing with the FERC. MidAmerican Energy believes its approved MVPs are not subject to the loss of right of first refusal unless the projects are re-evaluated and changed under a three-year review process required by the FERC. MidAmerican Energy continues to actively review other impacts of Order No. 1000.
Capital expenditures related to operating projects consist of routine expenditures for distribution, generation, mining and other infrastructure needed to serve existing and expected demand.
Equity Investments
ETT, a company owned equally by subsidiaries of American Electric Power Company, Inc. and MEHC, owns and operates electric transmission assets in the ERCOT. In order to fund ETT's ongoing transmission investment, MEHC expects to make equity contributions to ETT during 2012, 2013 and 2014 of $107 million, $58 million and $4 million, respectively.
In January 2012, MEHC, through a wholly-owned subsidiary, acquired from NRG Energy, Inc. a 49 percent interest in Agua Caliente, the owner of the 290-MW Agua Caliente Project in Arizona. The Agua Caliente Project is expected to costs approximately $1.8 billion and will be completed in 12 blocks with an aggregate tested capacity of 310 MW. The first 30-MW block of the Agua Caliente Project was placed in service in January 2012 and the Agua Caliente Project expects to place 112 additional MW in service in 2012, 136 MW in service in 2013 and 32 MW in service in 2014. The project is being constructed pursuant to a fixed price, date certain, turn-key engineering, procurement and construction contract with a subsidiary of First Solar. Construction costs are expected to be funded with equity contributions from MEHC and NRG Energy, Inc. and proceeds from a $967 million secured loan maturing in 2037 from an agency of the United States government as part of the United States Department of Energy loan guarantee program. Funding requests are submitted on a monthly basis and the approved loans accrue interest at a fixed rate based on the current average yield of comparable maturity United States Treasury rates plus a spread of 0.375%.
Pursuant to an equity funding and contribution agreement, MEHC has committed to provide Agua Caliente with funding for (a) base equity contributions of up to an aggregate amount of $303 million for the construction of the project, and (b) transmission upgrade costs. In January 2012, MEHC entered into a $303 million letter of credit facility related to its funding commitments. The equity funding and contribution agreement and the letter of credit commitment decreases as equity is contributed to the Agua Caliente Project.
Contractual Obligations
The Company has contractual cash obligations that may affect its consolidated financial condition. The following table summarizes the Company's material contractual cash obligations as of December 31, 2011 (in millions):
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| | | | | | | | | | | | | | | | | | | | |
| | | Payments Due By Periods |
| | | | | 2013- | | 2015- | | 2017 and | | |
| | | 2012 | | 2014 | | 2016 | | After | | Total |
| | | | | | | | | | | |
| MEHC senior debt | | $ | 742 |
| | $ | 250 |
| | $ | — |
| | $ | 4,375 |
| | $ | 5,367 |
|
| MEHC subordinated debt | | 22 |
| | — |
| | — |
| | — |
| | 22 |
|
| Subsidiary debt | | 434 |
| | 2,043 |
| | 663 |
| | 10,526 |
| | 13,666 |
|
Interest payments on long-term debt(1) | | 1,073 |
| | 1,951 |
| | 1,809 |
| | 12,060 |
| | 16,893 |
|
| Short-term debt | | 865 |
| | — |
| | — |
| | — |
| | 865 |
|
Coal, electricity and natural gas contract commitments(1) | | 1,389 |
| | 1,958 |
| | 1,261 |
| | 3,621 |
| | 8,229 |
|
Construction commitments(1) | | 757 |
| | 466 |
| | 442 |
| | 52 |
| | 1,717 |
|
Operating leases and easements(1) | | 89 |
| | 127 |
| | 71 |
| | 366 |
| | 653 |
|
Maintenance, service and other contracts(1) | | 192 |
| | 172 |
| | 51 |
| | 142 |
| | 557 |
|
| Total contractual cash obligations | | $ | 5,563 |
| | $ | 6,967 |
| | $ | 4,297 |
| | $ | 31,142 |
| | $ | 47,969 |
|
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| (1) | Not reflected on the Consolidated Balance Sheets. |
The Company has other types of commitments that arise primarily from unused lines of credit, letters of credit or relate to construction and other development costs (Liquidity and Capital Resources included within this Item 7), asset retirement obligations (Note 13) and uncertain tax positions (Note 15) which have not been included in the above table because the amount and timing of the cash payments are not certain. Additionally, refer to Note 23 for commitments that arose subsequent to December 31, 2011 and that are not included in the above table. Refer, where applicable, to the respective referenced note in Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
Regulatory Matters
MEHC's regulated subsidiaries and certain affiliates are subject to comprehensive regulation. In addition to the discussion contained herein regarding regulatory matters, refer to Item 1 of this Form 10-K for further discussion regarding the general regulatory framework at MEHC's regulated subsidiaries.
PacifiCorp
Utah
In March 2009, comparedPacifiCorp filed for an ECAM with the UPSC. The filing recommended that the UPSC adopt the mechanism to 2008recover the difference between base net power costs set in the next Utah general rate case and actual net power costs. In July 2010, the UPSC issued an order approving a stipulation that would establish deferred accounts for both net power costs and REC revenues in excess of the levels currently included in rates, subject to the UPSC's final determination of the ratemaking treatment of the deferrals. In December 2010, the UPSC approved a separate stipulation that provided a $3 million monthly credit to customers effective January 1, 2011 to be applied toward the UPSC's final decision. In March 2011, the UPSC issued its final order approving the use of an EBA in Utah to begin at the conclusion of the general rate case described below. Under the EBA, which has been established as a four year pilot program, 70% of any difference between actual net power costs incurred and the amount of net power costs recovered through base rates are deferred during the calendar year. PacifiCorp must then file by March 15 of the following year to initiate collection or refund of the deferred balance. In April 2011, PacifiCorp filed a petition with the UPSC for clarification and reconsideration of certain aspects of the EBA order, including reconsideration of the UPSC's decision to exclude financial swaps from the EBA, which was granted in May 2011.
In January 2011, PacifiCorp filed a general rate case with the UPSC requesting a rate increase of $232 million, or an average price increase of 14%. In June 2011, PacifiCorp filed its rebuttal testimony with the UPSC reducing the requested rate increase to $188 million, or an average price increase of 11%. In July 2011, PacifiCorp filed a settlement with the UPSC, which was approved by the UPSC in August 2011 and resulted in a $117 million rate increase, or an average price increase of 7% effective September 21, 2011. The settlement resolved all major dockets outstanding before the UPSC. Under the terms of the settlement, financial swaps are included in the EBA and a collaborative process with Utah stakeholders may result in future modifications to PacifiCorp's risk management and hedging policies. The settlement also concluded the ratemaking treatment of deferred accounts for net power costs and estimated sales of RECs in excess of the levels included in rates since the 2009 general rate case. The settlement provides for $60 million of net power costs in excess of amounts included in base rates to be recovered from Utah customers over a three-year period beginning June 1, 2012, without carrying charges. The settlement also provides for a $33 million credit to customers related to sales of RECs that substantially occurred in prior years and that will be credited to Utah customers over a period of approximately nine months beginning September 21, 2011, plus carrying charges. The settlement also establishes a balancing account for prospective REC sales. The settlement stipulation defers decisions regarding the ratemaking treatment associated with the Klamath hydroelectric system's four mainstem dams and relicensing and settlement costs as described in Note 16 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
In November 2011, PacifiCorp filed with the UPSC to decrease its DSM cost recovery tariff in Utah by 1% of a customer's eligible monthly charges. In January 2012, the UPSC approved an all-party stipulation to reduce the DSM surcharge by 0.4% effective February 1, 2012. In addition, approximately $5 million will be credited to customers over a one-year period beginning June 1, 2012.
In February 2012, PacifiCorp filed a general rate case with the UPSC requesting a rate increase of $172 million, or an average price increase of 10%.
Oregon
In March 2011, PacifiCorp made its initial filing for the annual TAM with the OPUC for an annual increase of $62 million to recover the anticipated net power costs forecasted for calendar year 2012. In July 2011, PacifiCorp filed updated net power costs, reflecting an increase in the overall request to $63 million. In August 2011, PacifiCorp filed its surrebuttal testimony in the TAM proceeding decreasing the overall request to $59 million due to a reduction in forecasted net power costs. In September 2011, PacifiCorp reached a settlement with several parties, including the repaymentOPUC staff, to reduce the requested increase to $51 million, or an average price increase of $1 billion4%, subject to final net power cost updates in November 2011. In November 2011, the OPUC approved the overall rate increase of $51 million, or an average price increase of 4%. The new rates were effective January 1, 2012.
In October 2010, PacifiCorp filed its 2009 tax report under SB 408. In January 2011, PacifiCorp entered into a stipulation with the OPUC staff and the Citizens' Utility Board of Oregon, whereby PacifiCorp, the OPUC staff and the Citizens' Utility Board of Oregon agreed to a surcharge of $13 million, plus interest. In April 2011, the OPUC issued an order adopting the stipulation without significant modification. The $13 million, plus interest, was recorded in earnings in the second quarter of 2011 and is being collected over a one-year period that began in June 2011.
In May 2011, Oregon Senate Bill 967 ("SB 967") was enacted into law. SB 967 repealed and replaced SB 408, and as a result, PacifiCorp will no longer be required to file tax reports under SB 408. Among other matters, SB 967 directs the OPUC to consider the income tax component of rates when conducting ratemaking proceedings. The enactment of SB 967 did not impact PacifiCorp's consolidated financial results.
Wyoming
In April 2010, PacifiCorp filed an application with the WPSC requesting approval of a new ECAM to replace the existing PCAM. The PCAM concluded with the final deferral of net power costs in November 2010 and collection through March 2012. In February 2011, the WPSC issued an order approving an ECAM effective December 1, 2010, under which 70% of any difference between actual net power costs incurred and the amount of net power costs recovered through base rates, subject to certain other adjustments, are deferred as incurred during the calendar year. PacifiCorp must then file by March 15 of the following year to initiate collection or refund of the deferred balance beginning June 1.
In November 2010, PacifiCorp filed a general rate case with the WPSC requesting a rate increase of $98 million, or an average price increase of 17%. In May 2011, PacifiCorp filed its rebuttal testimony with the WPSC reducing the requested rate increase to $80 million. In June 2011, the WPSC approved a multi-party stipulation resulting in an annual rate increase of $62 million, or an average price increase of 11% mandatory redeemable preferred securities. The stipulation also established a surcredit and a balancing account to affiliatespass on to or collect from customers any difference between the amount of Berkshire Hathawaythe REC sales established in the surcredit and actual REC sales. The surcredit will be established annually based on PacifiCorp's forecasted REC sales, and the difference between the surcredit and actual REC sales will be tracked in the balancing account. For 2011, the surcredit was set at $17 million, or a 3% reduction. The rates were effective September 22, 2011.
In February 2011, PacifiCorp filed its final PCAM application with the WPSC requesting recovery of $16 million in deferred net power costs over the 12-month period ending March 31, 2012. PacifiCorp requested and received approval from the WPSC to implement an $11 million interim rate increase over the $5 million reflected in the tariff to be effective from April 1, 2011 until the WPSC issues a final order. In September 2011, PacifiCorp reached an agreement with intervening parties and filed a stipulation with the WPSC to recover $14 million in deferred net power costs. In October 2011, the WPSC approved the stipulation with an effective date of November 1, 2011.
In December 2011, PacifiCorp filed a general rate case with the WPSC requesting an annual increase of $63 million, or an average price increase of 10%. If approved by the WPSC, the new rates are expected to be effective October 9, 2012.
Washington
In May 2010, PacifiCorp filed a general rate case with the WUTC requesting an annual increase of $57 million, or an average price increase of 21%. In November 2010, the requested annual increase was reduced to $49 million, or an average price increase of 18%. In March 2011, the WUTC issued a final order and clarification letter approving an annual increase of $33 million, or an average price increase of 12%, reduced in the first year by a customer bill credit of $5 million, or 2%, related to the sale of RECs expected during the twelve-month period ended March 31, 2012, as well as requiring PacifiCorp to submit additional information to the WUTC regarding the sales of RECs. The new rates were effective in April 2011. Although both PacifiCorp and the WUTC staff filed petitions for reconsideration of various items on the final order, the WUTC denied the petitions for reconsideration. In May 2011 PacifiCorp submitted to the WUTC the additional information required by the March 2011 order regarding PacifiCorp's proceeds from sales of RECs for the period January 1, 2009 forward and a detailed proposal for a tracking mechanism for proceeds of RECs. Intervening parties and WUTC staff are proposing that PacifiCorp refund to customers the amount of REC sales in excess of the amount included in base rates since January 1, 2009. Initial and reply briefs from all parties were filed in November 2011. Oral arguments were held before the WUTC in January 2012, and an order is expected during the first quarter of 2012.
In July 2011, PacifiCorp filed a general rate case with the WUTC requesting an annual increase of $13 million, or an average price increase of 4%, with an effective date no later than June 1, 2012. In February 2012, the parties to the proceeding filed a settlement agreement with the WUTC reflecting an annual increase of $5 million, or an average price increase of 2%. A hearing on the settlement agreement is scheduled for March 2012.
Idaho
In May 2010, PacifiCorp filed a general rate case with the IPUC requesting an annual increase of $28 million, or an average price increase of 14%. In November 2010, the requested annual increase was reduced to $25 million, or an average price increase of 12%. In December 2010, the IPUC issued an interim order approving an annual increase of $14 million, or an average price increase of 7% with an effective date of December 28, 2010. In February 2011, the IPUC issued its final order with no revisions to the December 2010 increase. In March 2011, PacifiCorp petitioned the IPUC seeking reconsideration or rehearing on certain aspects of the order, including the IPUC's conclusion that 27% of PacifiCorp's Populus to Terminal transmission line investment is not currently used and useful and should be carried as plant held for future use. The Idaho-allocated share of 27% of the investment is approximately $13 million. In April 2011, the IPUC issued an order, accepting in part and rejecting in part, PacifiCorp's motion for reconsideration, resulting in no significant changes to the IPUC's initial order. In May 2011, PacifiCorp filed an appeal of the Populus to Terminal decision to the Idaho Supreme Court requesting a determination on the legality of the IPUC's decision to exclude 27% of the Populus to Terminal line as a result of its conclusion that the line is not fully used and useful. As a result of the general rate case settlement process discussed below, PacifiCorp joined in a motion filed with the Idaho Supreme Court in October 2011, to stay the procedural schedule associated with the appeal until January 30, 2012, and the Idaho Supreme Court granted the motion. The matter was settled in the general rate case described below and the appeal was dismissed.
In May 2011, PacifiCorp filed a general rate case with the IPUC requesting an annual increase of $33 million, or an average price increase of 15%. In October 2011, a settlement was reached with the majority of parties in the case providing for a two-year agreement to increase rates by $17 million each year effective January 1, 2012 and January 1, 2013, representing average price increases of 8% and 7%, respectively. The settlement also resolved the dispute over the 27% of PacifiCorp's Populus to Terminal investment, providing for recovery of PacifiCorp's investment beginning on or after January 1, 2014. In January 2012, PacifiCorp received an order from the IPUC approving the settlement.
In February 2011, PacifiCorp filed an ECAM application with the IPUC requesting recovery of $13 million in deferred net power costs. In March 2011, the IPUC issued an order approving recovery of $10 million beginning April 1, 2011 and the remaining $3 million beginning in 2012.
In February 2012, PacifiCorp filed an ECAM application with the IPUC requesting recovery of $18 million in deferred net power costs through an increase to the current ECAM surcharge rate established in 2011. If approved, the new rates will be effective April 1, 2012.
MidAmerican Energy
On February 21, 2012, MidAmerican Energy filed an application with the IUB for an interim and final increase in Iowa retail electric rates in the form of two adjustment clauses to be added to customers' bills. The requested adjustment clauses and a modification to current revenue sharing provisions are consistent with a November 2011 settlement agreement between MidAmerican Energy and the OCA, in which the parties agree to support the proposed changes. The adjustment clauses would recover anticipated increases in retail coal and coal transportation costs and environmental control expenditures subject to an aggregate maximum of $39 million, or 3.4%, for 2012 and an additional $37 million for an aggregate maximum of $76 million for 2013, or a 3.2% increase from 2012. The requested modification to the existing revenue sharing provisions provides for MidAmerican Energy to share with its customers 20% of revenue associated with Iowa electric returns on equity between 10% and 10.5%, 50% of revenue associated with Iowa electric returns on equity between 10.5% and 11.75%, 75% of revenue associated with Iowa electric returns on equity between 11.75% and 13.0% and 83.3% of revenue associated with Iowa electric returns on equity above 13.0%. Such shared amounts would reduce MidAmerican Energy's investment in the Walter Scott, Jr. Energy Center Unit 4. There would be no revenue sharing for Iowa electric returns on equity below 10%. Pursuant to the settlement agreement, MidAmerican Energy is not precluded from seeking interim rate relief in 2013.
Kern River
In December 2009, the FERC issued an order establishing revised rates for the period of Kern River's current long-term contracts ("Period One rates") and required that rates be established based on a levelized rate design for eligible customers to elect to take service following the expiration of their current contracts ("Period Two rates"). The FERC set all other issues related to Period Two rates for hearing. In November 2010, the FERC issued an order that denied all requests for rehearing related to Period One rates from the FERC's December 2009 order and established that Kern River is entitled to base its Period Two rates on a 100% equity capital structure. In January 2011, Kern River filed a motion for clarification on certain depreciation issues with the FERC.
In July 2011, the FERC issued its order substantially adopting the presiding administrative law judge's initial decision issued in connectionApril 2011 regarding Kern River's Period Two rates. According to the decisions, Period Two rates should be based on a return on equity of 11.55%, a capital structure of 100% and a levelization period that coincides with a contract length of 10 or 15 years. Kern River has a regulatory asset approved by the FERC associated with compressor engines and general plant replacements that can be recovered in a future rate case and was not incorporated into Period Two rates at this time. Kern River, as well as others, requested rehearing and clarification of the FERC's July 2011 order on a majority of the issues. Kern River filed tariffs in compliance with the purchaseFERC's order in August 2011 and, following an order on compliance, again in September 2011. In late September 2011, the FERC issued a second order on compliance, accepting Kern River's tariff filing. The FERC has not yet responded to the requests for rehearing and clarification of the Constellation Energy 8% preferred stock, debt retirements, scheduled principal repaymentsJuly 2011 order.
ETT
In December 2011, ETT filed its second Interim Transmission Cost of Service ("TCOS") of 2011 at the PUCT. The application was based on a test year ending October 31, 2011. The filing requested an increase in total transmission invested capital of $82 million and a total revenue requirement increase of $11 million. In January 2012, the PUCT staff recommended approval of ETT's second interim TCOS filing of 2011. ETT, along with PUCT staff, filed a joint proposed notice of approval. On January 31, 2012, the administrative law judge signed the final order making the new rates effective.
Environmental Laws and Regulations
The Company is subject to federal, state, local and foreign laws and regulations regarding air and water quality, RPS, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact the Company's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by the EPA and various other state, local and international agencies. All such laws and regulations are subject to a range of interpretation, which may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and the Company is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. The Company believes it is in material compliance with all applicable laws and regulations. Refer to "Liquidity and Capital Resources" for discussion of the Company's forecasted environmental-related capital expenditures.
Clean Air Standards
The Clean Air Act is a federal law administered by the EPA that provides a framework for protecting and improving the nation's air quality and controlling sources of air emissions. The implementation of new standards is generally outlined in SIPs, which are a collection of regulations, programs and policies to be followed. SIPs vary by state and are subject to public hearings and EPA approval. Some states may adopt additional or more stringent requirements than those implemented by the EPA. The major Clean Air Act programs most directly affecting the Company's operations, are described below.
National Ambient Air Quality Standards
Under the authority of the Clean Air Act, the EPA sets minimum national ambient air quality standards for six principal pollutants, consisting of carbon monoxide, lead, nitrogen oxides, particulate matter, ozone and sulfur dioxide, considered harmful to public health and the environment. Areas that achieve the standards, as determined by ambient air quality monitoring, are characterized as being in attainment, while those that fail to meet the standards are designated as being nonattainment areas. Generally, sources of emissions in a nonattainment area that are determined to contribute to the nonattainment are required to reduce emissions. Most air quality standards require measurement over a defined period of time to determine the average concentration of the pollutant present. Currently, air quality monitoring data indicates that all counties where MidAmerican Energy's major emission sources are located are in attainment of the current national ambient air quality standards.
In December 2009, the EPA designated the Utah counties of Davis and Salt Lake, as well as portions of Box Elder, Cache, Tooele, Utah and Weber counties, to be in nonattainment of the fine particulate matter standard. This designation has the potential to impact PacifiCorp's Lake Side and Gadsby generating facilities, depending on the requirements to be established in the Utah SIP. The impact, if any, on PacifiCorp's generating facilities is not anticipated to be significant.
In January 2010, the EPA proposed a rule to strengthen the national ambient air quality standard for ground level ozone. The proposed rule arose out of legal challenges claiming that a March 2008 rule that reduced the standard from 80 parts per billion to 75 parts per billion was not strict enough. The new rule proposed a standard between 60 and 70 parts per billion. In September 2011, the President requested that the EPA withdraw the proposed ozone standard and allow the review of the standards to proceed through the regularly scheduled review in 2013. The EPA is, therefore, proceeding with implementation of the March 2008 ozone standards and, in December 2011, issued its response to states' recommendations on area attainment designations. Part of the EPA's response recommended that the Upper Green River Basin Area in Wyoming, including all of Sublette and portions of Lincoln and Sweetwater Counties, be designated as nonattainment for the March 2008 ozone standard. While PacifiCorp's Jim Bridger plant is located in Sweetwater County, it is not in the portion proposed for designation as nonattainment and is not expected to be impacted by the proposed designation. The EPA also published a proposed consent decree in the Federal Register in December 2011, requiring it to sign final designations for the March 2008 ozone standard by May 31, 2012.
In January 2010, the EPA finalized a one-hour air quality standard for nitrogen dioxide at 0.10 part per million. The EPA published final designations that are effective February 29, 2012, indicating that based on air quality monitoring data, all areas of the country are designated as "unclassifiable/attainment" for the 2010 nitrogen dioxide national ambient air quality standard.
In June 2010, the EPA finalized a new national ambient air quality standard for sulfur dioxide. Under the new rule, the existing 24-hour and annual standards for sulfur dioxide, which were 140 parts per billion measured over 24 hours and 30 parts per billion measured over an entire year, were replaced with a new one-hour standard of 75 parts per billion. The new rule will utilize a three-year average to determine attainment. The rule will utilize source modeling, in addition to the installation of ambient monitors where sulfur dioxide emissions impact populated areas, with new monitors required to be placed in service no later than January 2013. Attainment designations are due by June 2012, with SIPs due by 2014 and final attainment demonstrations by August 2017.
As new, more stringent standards are adopted, the number of counties designated as nonattainment areas is likely to increase. Businesses operating in newly designated nonattainment counties could face increased regulation and costs to monitor or reduce emissions. For instance, existing major emissions sources may have to install reasonably available control technologies to achieve certain reductions in emissions and undertake additional monitoring, recordkeeping and reporting. The construction or modification of facilities that are sources of emissions could become more difficult in nonattainment areas. Until additional monitoring and modeling is conducted, the impacts on the Company cannot be determined.
Mercury and Air Toxics Standards
The Clean Air Mercury Rule ("CAMR"), issued by the EPA in March 2005, was the United States' first attempt to regulate mercury emissions from coal-fueled generating facilities through the use of a market-based cap-and-trade system. The CAMR, which mandated emissions reductions of approximately 70% by 2018, was overturned by the United States Court of Appeals for the District of Columbia Circuit ("D.C. Circuit") in February 2008. In March 2011, the EPA proposed a new rule that would require coal-fueled generating facilities to reduce mercury emissions and other hazardous air pollutants through the establishment of "Maximum Achievable Control Technology" standards rather than a cap-and-trade system. The final rule, MATS, was released by the EPA in December 2011 and published in the Federal Register on February 16, 2012, and requires that new and existing coal-fueled facilities achieve emission standards for mercury, acid gases and other non-mercury hazardous air pollutants. Existing sources are required to comply with the new standards within three years after the rule is final, with individual sources granted an additional year to complete installation of controls if approved by the permitting authority. While the final MATS continues to be reviewed by the Company, the Company believes that its emissions reduction projects completed to date or currently permitted or planned for installation, including scrubbers, baghouses and electrostatic precipitators are consistent with the EPA's MATS and will support the Company's ability to comply with the final rule's standards for acid gases and non-mercury metallic hazardous air pollutants. The Company will be required to take additional actions to reduce mercury emissions through the installation of controls or use of sorbent injection at certain of its coal-fueled generating facilities and otherwise comply with the final rule's standards. The Company is evaluating whether or not to close certain units. Incremental costs to install and maintain mercury emissions control equipment at the Company's coal-fueled generating facilities and any requirements to shut down generating facilities will increase the cost of providing service to customers.
Clean Air Interstate Rule, Clean Air Transport Rule and Cross-State Air Pollution Rule
The EPA promulgated the CAIR in March 2005 to reduce emissions of nitrogen oxides and sulfur dioxide, precursors of ozone and particulate matter, from down-wind sources. The CAIR required states in the eastern United States, including Iowa, to reduce emissions by implementing a plan based on a market-based cap-and-trade system, emissions reductions, or both. The CAIR created separate trading programs for nitrogen oxides and sulfur dioxide emissions credits. The nitrogen oxides and sulfur dioxide emissions reductions were planned to be accomplished in two phases, in 2009-2010 and 2015.
In July 2008, a three-judge panel of the D.C. Circuit issued a unanimous decision vacating the CAIR. In December 2008, the D.C. Circuit issued an opinion remanding, without vacating, the CAIR back to the EPA to conduct proceedings to fix the flaws in CAIR consistent with the D.C. Circuit's July 2008 ruling.
In July 2010, the EPA proposed the Clean Air Transport Rule ("Transport Rule"), a replacement of the CAIR, which required electric generating units in 31 states and the District of Columbia to reduce emissions of nitrogen oxides and sulfur dioxide on a state-by-state basis in accordance with each state's modeled contribution to nonattainment of the ozone and fine particulate standards in downwind states. The emissions reductions required under the Transport Rule were intended only to resolve transported emissions and not to resolve air quality issues in the states where the generation is located. The Transport Rule's emissions reduction requirements were proposed to take place in two phases, with the first phase beginning in 2012 and the second phase beginning in 2014. By 2014, the Transport Rule and other state and EPA actions would reduce power plant nitrogen oxides emissions by 52% and sulfur dioxide emissions by 71% from 2005 levels in covered states. The EPA proposed to administer separate trading programs for nitrogen oxides and sulfur dioxide credits under the Transport Rule. Facilities were required to comply with the CAIR until the Transport Rule became effective.
In July 2011, the EPA issued the final Transport Rule, renamed the Cross-State Air Pollution Rule ("CSAPR"), to address interstate transport of sulfur dioxide and nitrogen oxides emissions in 27 eastern and Midwestern states. Upon full implementation in 2014, the CSAPR will reduce total sulfur dioxide emissions by 73% and nitrogen oxides emissions by 54% at electric generating facilities in the 27-state region as compared to 2005 levels. MidAmerican Energy's coal-fueled generating facilities in Iowa are impacted by and required to make emissions reductions and otherwise comply with the CSAPR. In addition to issuing the final rule, the EPA issued a supplemental notice of proposed rulemaking to include Iowa and five other states in the ozone season nitrogen oxides emissions reduction requirements. The ozone season supplemental proposal was finalized in December 2011, and includes Iowa and four other states in the CSAPR ozone season nitrogen oxide emission reduction requirements. While MidAmerican Energy operates natural gas-fueled generating facilities in Iowa and MidAmerican Renewables operates natural gas-fueled generating facilities within the states of Illinois, Texas and New York, which are in the CSAPR region, no significant impact is expected on those generating facilities.
In December 2011, the D.C. Circuit issued a stay on the implementation of the CSAPR pending consideration of several petitions for review before the court. The court held that the CAIR should be administered pending the resolution of the pending petitions for review.
MidAmerican Energy is currently complying with the CAIR and has installed or is in the process of installing emissions controls at some of its generating facilities to comply with the CAIR and may purchase nitrogen oxides and sulfur dioxide emissions credits for emissions in excess of allocated allowances. The cost of these credits is subject to market conditions at the time of purchase and historically has not been material. The full impact of the CSAPR, or the CAIR, cannot be determined until the outcome of the litigation pending in the D.C. Circuit or the stay of the CSAPR is lifted. It is possible that the existing CAIR or the CSAPR may be replaced with more stringent requirements to reduce nitrogen oxides and sulfur dioxide emissions and that these requirements could be extended to the western United States through regulation or legislation such as a multi-pollutant emissions reduction bill.
MidAmerican Renewables' natural gas generating facilities in Texas, Illinois and New York are also subject to the CAIR until the CSAPR is adopted. However, the provisions are not anticipated to have a material impact on the Company. PacifiCorp's generating facilities are not subject to the CAIR or the CSAPR.
Regional Haze
The EPA has initiated a regional haze program intended to improve visibility in designated federally protected areas ("Class I areas"). Some of PacifiCorp's coal-fueled generating facilities in Utah and Wyoming and MidAmerican Energy's coal-fueled generating facilities meet the threshold applicability criteria to be eligible units under the Clean Air Visibility Rules. In accordance with the federal requirements, states were required to submit SIPs by December 2007 to demonstrate reasonable progress towards achieving natural visibility conditions in Class I areas by requiring emissions controls, known as best available retrofit technology, on sources constructed between 1962 and 1977 with emissions that are anticipated to cause or contribute to impairment of visibility. Utah submitted its most recent regional haze SIP amendments in 2011 and suggested that the emissions reduction projects planned by PacifiCorp are sufficient to meet its initial emissions reduction requirements. In September 2011, the Company received a Section 114 request for information from the EPA Region VIII requiring the Company to submit a five-factor best available retrofit technology analysis for PacifiCorp's Hunter Units 1 and 2 and the Huntington generating facility in Utah within 30 days based on the EPA's assertion that Utah failed to submit such an analysis. The Company responded to the request in November 2011 and indicated it would work with the Utah Division of Air Quality to complete the requested analysis which, based on a schedule proposed by Utah to the EPA, will be part of a process to conclude with a submittal to the EPA in February 2013. Wyoming submitted its regional haze SIP to the EPA in January 2011. The EPA is currently under a consent decree to issue a proposed decision on the Wyoming SIP by May 15, 2012, and a final decision by October 15, 2012. PacifiCorp believes that its planned emissions reduction projects will satisfy the regional haze requirements in Utah and Wyoming. It is possible that additional controls may be required after the respective SIPs have been considered by the EPA or that the timing of installation of planned controls could change.
The EPA's rejection of regional haze SIPs based on the state's selection of less stringent controls than the EPA believes are warranted has resulted in lawsuits being filed by states and affected entities. Cases are pending before the Tenth Circuit Court of Appeals by New Mexico and Oklahoma and additional cases are likely to be filed.
In December 2011, the EPA proposed to accept the emission reductions made by states impacted by the CSAPR, including Iowa, as meeting the requirements of the regional haze program. If the EPA finalizes the proposal, no further emission reductions are expected from MidAmerican Energy's coal-fueled generating facilities for purposes of meeting the regional haze requirements.
New Source Review
Under existing New Source Review ("NSR") provisions of the Clean Air Act, any facility that emits regulated pollutants is required to obtain a permit from the EPA or a state regulatory agency prior to (a) beginning construction of a new major stationary source of a regulated pollutant or (b) making a physical or operational change to an existing stationary source of such pollutants that increases certain levels of emissions, unless the changes are exempt under the regulations (including routine maintenance, repair and replacement of equipment). In general, projects subject to NSR regulations require pre-construction review and permitting under the Prevention of Significant Deterioration ("PSD") provisions of the Clean Air Act. Under the PSD program, a project that emits threshold levels of regulated pollutants must undergo an analysis to determine the best available control technology and evaluate the most effective emissions controls after consideration of a number of factors. Violations of NSR regulations, which may be alleged by the EPA, states, environmental groups and others, potentially subject a company to material fines and other sanctions and remedies, including installation of enhanced pollution controls and funding of supplemental environmental projects.
Numerous changes have been proposed to the NSR rules and regulations over the last several years. In addition to the proposed changes, differing interpretations by the EPA and the courts create risk and uncertainty for entities when seeking permits for new projects and installing emissions controls at existing facilities under NSR requirements. The Company monitors these changes and interpretations to ensure permitting activities are conducted in accordance with the applicable requirements.
As part of an industry-wide investigation to assess compliance with the NSR and PSD provisions, the EPA has requested information and supporting documentation from numerous utilities regarding their capital projects for various coal-fueled generating facilities. A NSR enforcement case against an unrelated utility has been decided by the United States Supreme Court, holding that an increase in the annual emissions of a generating facility, when combined with a modification (i.e., a physical or operational change), may trigger NSR permitting. Between 2001 and 2003, PacifiCorp and MidAmerican Energy responded to requests for information relating to their capital projects at their coal-fueled generating facilities. PacifiCorp engaged in periodic discussions with the EPA over several years regarding PacifiCorp's historical projects and their compliance with NSR and PSD provisions. In September 2011, PacifiCorp received a letter from the EPA concluding these discussions. PacifiCorp cannot predict the next steps in this process and could be required to install additional emissions controls and incur additional costs and penalties in the event it is determined that PacifiCorp's historical projects did not meet all regulatory requirements.
In October 2011, MidAmerican Energy received a request from the EPA Region VII pursuant to Section 114 of the Clean Air Act for information on its coal-fueled generating facilities to supplement the requests made in 2002 and 2003. MidAmerican Energy submitted its response to the October 2011 request in December 2011. MidAmerican Energy cannot predict the outcome of this matter at this time.
Climate Change
In April 2011, the United States House of Representatives voted 255-177 on a bill (H.R. 910) that would prevent the EPA from regulating GHG emissions. No action has been taken by the Senate on the bill. While significant measures to regulate GHG emissions at the federal level were considered by the United States Congress in 2010, comprehensive climate change legislation has not been adopted. International discussions regarding climate change continue to be held periodically, but agreement has not been reached on how nations will address future climate change commitments upon the expiration of the Kyoto Protocol in December 2012.
In December 2009, the EPA published its findings that GHG threaten the public health and welfare and is pursuing regulation of GHG emissions under the Clean Air Act. Additionally, in May 2010, the EPA issued the GHG "Tailoring Rule" to address permitting requirements for GHG after determining that GHG are subject to regulation and would trigger Clean Air Act permitting requirements for stationary sources beginning in January 2011. Numerous lawsuits have been filed on both the EPA's endangerment finding and the tailoring rule and are pending in the D.C. Circuit with arguments scheduled to take place in February 2012.
While the debate continues at the federal and international level over the direction of climate change policy, several states have developed or are developing state-specific laws or regional initiatives to report or mitigate GHG emissions. In addition, governmental, non-governmental and environmental organizations have become more active in pursuing climate change related litigation under existing laws.
California mandatory GHG reporting requirements began with 2008 emissions and PacifiCorp has reported its GHG emissions annually since their inception. In September 2009, the EPA issued its final rule regarding mandatory reporting of GHG ("GHG Reporting") beginning January 1, 2010. Under GHG Reporting, suppliers of fossil fuels, manufacturers of vehicles and engines, and facilities that emit 25,000 metric tons or more per year of GHG are required to submit annual reports to the EPA. PacifiCorp, MidAmerican Energy and MidAmerican Renewables are subject to this requirement and submitted their first reports prior to September 30, 2011. Northern Natural Gas and Kern River reported their combustion-related GHG emissions prior to September 30, 2011, and are required to report their GHG emissions from equipment leaks and venting by September 28, 2012. The EPA released the 2010 GHG emissions reports in January 2012.
In the absence of comprehensive climate legislation or regulation, the Company has continued to invest in lower- and non-carbon generating resources and to operate in an environmentally responsible manner. Examples of the Company's significant investments in programs and facilities that will mitigate its GHG emissions include:
MidAmerican Energy owns the largest and PacifiCorp owns the second largest portfolio of wind-powered generating capacity in the United States among rate-regulated utilities. As of December 31, 2011, the Company owned 2,909 MW of operating wind-powered generating capacity at a total cost of $5.4 billion. MidAmerican Energy is constructing an additional 407 MW of wind-powered generation that it expects to place in service in 2012. Additionally, the Company has power purchase agreements with 858 MW of wind-powered generating capacity.
PacifiCorp owns 1,145 MW of hydroelectric generating capacity.
In January 2012, MEHC, through wholly-owned subsidiaries, acquired the 550-MW Topaz Project and a 49 percent interest in the 290-MW Agua Caliente Project. The electricity delivered by the Topaz Project and Agua Caliente Project is being and will be sold to PG&E and will help PG&E meet its obligations under a California state mandate to procure capacity and electricity from renewable resources.
PacifiCorp's Energy Gateway Transmission Expansion Program represents a planto build approximately 2,000 miles of new high-voltage transmission lines with an estimated cost exceeding $6 billion. The plan includes several transmission line segments that will: (a) address customer load growth; (b) improve system reliability; (c) reduce transmission system constraints; (d) provide access to diverse generation resources, including renewable resources; and (e) improve the flow of electricity throughout PacifiCorp's six-state service area.
ETT plans to construct $1.5 billion of transmission investment in support of CREZ. CREZ is a transmission plan that advances the development of over 18,000 MW of new wind-powered generation in Texas. Additionally, AEP subsidiaries have transferred to ETT the obligation to build approximately $1.7 billion of transmission projects within ERCOT. Through December 31, 2011, $1.1 billion has been spent, of which $617 million has been placed in service. ETT's transmission system included 445 miles of transmission lines and 19 substations as of December 31, 2011.
PacifiCorp and MidAmerican Energy have offered customers a comprehensive set of DSM programs for more than 20 years. The programs assist customers to manage the timing of their usage, as well as to reduce overall energy consumption, resulting in lower utility bills.
The Utilities have installed and upgraded emissions control equipment at certain of its coal-fueled generating facilities to reduce emissions of sulfur dioxide and nitrogen oxides.
MEHC holds a 10% interest in BYD Company Limited, which continues to make advances in applying its proprietary battery technology to electric vehicles and has also developed an energy storage system, solar power system, hybrid energy system and other green energy solutions.
The impact of potential federal, regional, state and international accords, legislation, regulation, or judicial proceedings related to climate change cannot be quantified in any meaningful range at this time. New requirements limiting GHG emissions could have a material adverse impact on the Company, the United States and the global economy. Companies and industries with higher GHG emissions, such as utilities with significant coal-fueled generating facilities, will be subject to more direct impacts and greater financial and regulatory risks. The impact is dependent on numerous factors, none of which can be meaningfully quantified at this time. These factors include, but are not limited to, the magnitude and timing of GHG emissions reduction requirements; the design of the requirements; the cost, availability and effectiveness of emissions control technology; the price, distribution method and availability of offsets and allowances used for compliance; government-imposed compliance costs; and the existence and nature of incremental cost recovery mechanisms. Examples of how new requirements may impact the Company include:
Additional costs may be incurred to purchase required emissions allowances under any market-based cap-and-trade system in excess of allocations that are received at no cost. These purchases would be necessary until new technologies could be developed and deployed to reduce emissions or lower carbon generation is available;
Acquiring and renewing construction and operating permits for new and existing generating facilities may be costly and difficult;
Additional costs may be incurred to purchase and deploy new generating technologies;
Costs may be incurred to retire existing coal-fueled generating facilities before the end of their otherwise useful lives or to convert them to burn fuels, such as natural gas or biomass, that result in lower emissions;
Operating costs may be higher and generating unit outputs may be lower;
Higher interest and financing costs and reduced access to capital markets may result to the extent that financial markets view climate change and GHG emissions as a business risk; and
The Company's natural gas pipeline operations, electric transmission and retail sales may be impacted in response to changes in customer demand and requirements to reduce GHG emissions.
The impact of events or conditions caused by climate change, whether from natural processes or human activities, could vary widely, from highly localized to worldwide, and the extent to which a utility's operations may be affected is uncertain. Climate change may cause physical and financial risk through, among other things, sea level rise, changes in precipitation and extreme weather events. Consumer demand for energy may increase or decrease, based on overall changes in weather and as customers promote lower energy consumption through the continued use of energy efficiency programs or other means. Availability of resources to generate electricity, such as water for hydroelectric production and cooling purposes, may also be impacted by climate change and could influence the Company's existing and future electricity generating portfolio. These issues may have a direct impact on the costs of electricity production and increase the price customers pay or their demand for electricity.
International Accords
Under the United Nations Framework Convention on Climate Change, adopted in 1992, members of the convention meet periodically to discuss international responses to climate change. To date, the United States has not made a binding reduction commitment as a result of these international discussions.
Federal Legislation
Legislation introduced in the 112th Congress has been focused on repeal or delay of the EPA's ability to regulate GHG emissions. There is currently no federal legislation pending to regulate GHG emissions.
GHG Tailoring Rule
The EPA finalized the GHG "Tailoring Rule" in May 2010 requiring new or modified sources of GHG emissions with increases of 75,000 or more tons per year of total GHG to determine the best available control technology for their GHG emissions beginning in January 2011. New or existing major sources will also be subject to Title V operating permit requirements for GHG. Beginning July 1, 2011 through June 30, 2013, new construction projects that emit GHG emissions of at least 100,000 tons per year and modifications of existing facilities that increase GHG emissions by at least 75,000 tons per year will be subject to permitting requirements and facilities that were previously not subject to Title V permitting requirements will be required to obtain Title V permits if they emit at least 100,000 tons per year of carbon dioxide equivalents. Several legal challenges to the GHG Tailoring Rule have been filed in the D.C. Circuit. The EPA issued a GHG best available control technology guidance document in November 2010 in an effort to provide permitting authorities guidance on how to conduct a best available control technology review for GHG.
MidAmerican Energy has obtained and is in the process of obtaining permits to install emissions reduction equipment at existing generating facilities to comply with CSAPR and was required to assess the impacts of the projects on GHG emissions. A GHG emissions limit was imposed on the permits for those projects and management believes compliance with the GHG limits under these permits will not result in a material adverse impact on its operations. PacifiCorp's permitting of certain existing generating facilities to install emissions reduction equipment to comply with the Regional Haze Rules assessed the impacts of the projects on GHG emissions under the GHG Tailoring Rule. No GHG emissions limit was included in the permits. However, PacifiCorp's Lake Side 2 was subject to a best available control technology review and the permit includes a limit for carbon dioxide equivalent emissions. To date, permitting authorities implementing the GHG Tailoring Rule have included efficiency improvements to demonstrate compliance with best available control technology for GHG, as well as requiring emissions limits for GHGs in permits; as such, the impacts of the Tailoring Rule on the Company have not been material.
GHG New Source Performance Standards
Under the Clean Air Act, the EPA may establish emissions standards that reflect the degree of emissions reductions achievable through the best technology that has been demonstrated, taking into consideration the cost of achieving those reductions and any non-air quality health and environmental impact and energy requirements. The EPA entered into a settlement agreement with a number of parties, including certain state governments and environmental groups, in December 2010 to promulgate emissions standards covering GHG by September 30, 2011, as amended, and issue final regulations by May 26, 2012. However, in mid-September, the EPA indicated it would not meet the September 30, 2011 deadline to promulgate the standards and it has not yet established a new schedule for issuing the proposed rules. It is unclear what standards the EPA will establish for new and modified sources or what the guidelines will be for existing sources. Until the standards are proposed and finalized, the impact on the Company cannot be determined.
Regional and State Activities
Several states have promulgated or otherwise participate in state-specific or regional laws or initiatives to report or mitigate GHG emissions. These are expected to impact PacifiCorp, MidAmerican Energy and other MEHC energy subsidiaries, and include:
The Western Climate Initiative was established as a comprehensive regional effort to reduce GHG emissions by 15% below 2005 levels by 2020 through a cap-and-trade program that includes the electricity sector. The Western Climate Initiative initially included the states of California, Montana, New Mexico, Oregon, Utah and Washington and the Canadian provinces of British Columbia, Manitoba, Ontario and Quebec. However, only California, British Columbia and Quebec are moving forward under the initiative, with the other states focused on efforts to design, promote and implement cost-effective policies to reduce GHG emissions and create economic opportunities.
In October 2011, the California Air Resources Board adopted a GHG cap-and-trade program with an effective date of January 1, 2012; compliance obligations will be imposed on entities beginning in 2013. In addition, California law imposes a GHG emissions performance standard to all electricity generated within the state or delivered from outside the state that is no higher than the GHG emissions levels of a state-of-the-art combined-cycle natural gas-fueled generating facility, as well as legislation that adopts an economy-wide cap on GHG emissions to 1990 levels by 2020.
Over the past several years, the states of California, Washington and Oregon have adopted GHG emissions performance standards for base load electrical generating resources. Under the laws in all three states, the emissions performance standards provide that emissions must not exceed 1,100 pounds of carbon dioxide per MWh. These GHG emissions performance standards generally prohibit electric utilities from entering into long-term financial commitments (e.g., new ownership investments, upgrades, or new or renewed contracts with a term of five or more years) unless any base load generation supplied under long-term financial commitments comply with the GHG emissions performance standards.
The Washington and Oregon governors enacted legislation in May 2007 and August 2007, respectively, establishing goals for the reduction of GHG emissions in their respective states. Washington's goals seek to (a) reduce emissions to 1990 levels by 2020; (b) reduce emissions to 25% below 1990 levels by 2035; and (c) reduce emissions to 50% below 1990 levels by 2050, or 70% below Washington's forecasted emissions in 2050. Oregon's goals seek to (a) cease the growth of Oregon GHG emissions by 2010; (b) reduce GHG levels to 10% below 1990 levels by 2020; and (c) reduce GHG levels to at least 75% below 1990 levels by 2050. Each state's legislation also calls for state government to develop policy recommendations in the future to assist in the monitoring and achievement of these goals.
In Iowa, legislation enacted in 2007 required the Iowa Climate Change Advisory Council ("ICCAC"), a 23-member group appointed by the Iowa governor, to develop scenarios designed to reduce statewide GHG emissions, including one scenario that would reduce emissions by 50% by 2050, and submit its recommendations to the legislature. The ICCAC also developed a second scenario to reduce GHG emissions by 90% with reductions in both scenarios from 2005 emissions levels. In January 2009, the ICCAC presented to the Iowa governor and legislature several policy options to consider to achieve GHG emissions reductions, including enhanced energy efficiency programs and increased renewable generation. No legislation has yet been enacted that would require GHG emissions reductions.
In November 2007, the Iowa governor signed the Midwest Greenhouse Gas Accord and the Energy Security and Climate Stewardship Platform for the Midwest. The signatories to the platform were other Midwestern states that agreed to implement a regional cap-and-trade system for GHG emissions. Advisory group recommendations included the assessment of 2020 emissions reduction targets of 15%, 20% and 25% below 2005 levels and a 2050 target of 60% to 80% below 2005 levels. In addition, the accord calls for the participating states to collectively meet at least 2% of regional annual retail sales of electricity and natural gas through energy efficiency improvements by 2015 and continue to achieve an additional 2% in efficiency improvements every year thereafter. There has been no further progress in implementing a Midwest regional cap-and-trade program.
The Regional Greenhouse Gas Initiative, a mandatory, market-based effort to reduce GHG emissions in ten Northeastern and Mid-Atlantic states, requires, beginning in 2009, the reduction of carbon dioxide emissions from the power sector of 10% by 2018. In May 2011, New Jersey withdrew from participation in the Regional Greenhouse Gas Initiative and in June 2011, a lawsuit filed in New York alleged that the state of New York unlawfully joined the Regional Greenhouse Gas Initiative without legislative approval.
GHG Litigation
The Company closely monitors ongoing environmental litigation. Many of the pending cases described below relate to lawsuits against industry that attempt to link GHG emissions to public or private harm. The Company believes the cases are without merit, despite decisions where United States Courts of Appeals reversed district court rulings dismissing the cases in 2009. The lower courts initially refrained from adjudicating the cases under the "political question" doctrine, because of their inherently political nature. Nevertheless, an adverse ruling in any of these cases would likely result in increased regulation of GHG emitters, including the Company's generating facilities, and financial uncertainty.
In September 2009, the United States Court of Appeals for the Second Circuit ("Second Circuit") issued its opinion in the case of Connecticut v. American Electric Power, et al, which remanded to the lower court a nuisance action by eight states and the City of New York against five large utility emitters of carbon dioxide. The United States District Court for the Southern District of New York ("Southern District of New York") dismissed the case in 2005, holding that the claims that GHG emissions from the defendants' coal-fueled generating facilities were causing harmful climate change and should be enjoined as a public nuisance under federal common law presented a "political question" that the court lacked jurisdiction to decide. The Second Circuit rejected this conclusion and stated the Southern District of New York was not precluded from determining the case on its merits. In December 2010, the United States Supreme Court agreed to hear the case on appeal from the Second Circuit and issued its decision in June 2011 dismissing the federal common law claim of nuisance and holding that the Clean Air Act provides a means to seek limits on emissions of carbon dioxide on power plants.
In October 2009, a three-judge panel in the United States Court of Appeals for the Fifth Circuit ("Fifth Circuit") issued its opinion in the case of Ned Comer, et al. v. Murphy Oil USA, et al., ("Comer I") a putative class action lawsuit against insurance, oil, coal and chemical companies, based on claims that the defendants' GHG emissions contributed to global warming that in turn caused a rise in sea levels and added to the ferocity of Hurricane Katrina, which combined to damage the plaintiff's private property, as well as public property. In 2007, the United States District Court for the Southern District of Mississippi ("Southern District of Mississippi") dismissed the case based on the lack of standing and further held that the claims were barred by the political question doctrine. In March 2010, the full court of the Fifth Circuit agreed to rehear the case; however, in May 2010, the Fifth Circuit dismissed the appeal for failure to have a quorum, resulting in the Southern District of Mississippi's decision, holding that property owners did not have standing to sue for climate change and that climate change was a political question for the United States Congress, standing as good law. The plaintiffs filed a petition asking the United States Supreme Court to direct the Fifth Circuit to reinstate the appeal and return it to the original panel. In January 2011, the United States Supreme Court denied the request, resulting in the original dismissal of the case to stand. However, on May 27, 2011, the Comer case was refiled ("Comer II") in the Southern District of Mississippi. The defendants in Comer II have filed a motion to dismiss, which is pending before the court. The Company was not a party in Comer I and is not a party in Comer II.
In October 2009, the United States District Court for the Northern District of California ("Northern District of California") granted the defendants' motions to dismiss in the case of Native Village of Kivalina v. ExxonMobil Corporation, et al. The plaintiffs filed their complaint in February 2008, asserting claims against 24 defendants, including electric generating companies, oil companies and a coal company, for public nuisance under state and federal common law based on the defendants' GHG emissions. MEHC was a named defendant in the Kivalina case. The Northern District of California dismissed all of the plaintiffs' federal claims, holding that the court lacked subject matter jurisdiction to hear the claims under the political question doctrine, and that the plaintiffs lacked standing to bring their claims. The Northern District of California declined to hear the state law claims and the case was dismissed without prejudice to their future presentation in an appropriate state court. In November 2009, the plaintiff's appealed the case to the United States Court of Appeals for the Ninth Circuit ("Ninth Circuit") where briefing has been completed, but the case has not yet been scheduled for oral argument. In February 2011, the Ninth Circuit stayed the case, pending the issuance of the United States Supreme Court's decision in Connecticut v. American Electric Power, et al. The oral arguments in Kivalina were held before the Ninth Circuit in November 2011 and the parties await the court's decision.
Renewable Portfolio Standards
The RPS described below could significantly impact the Company's consolidated financial results. Resources that meet the qualifying electricity requirements under the RPS vary from state to state. Each state's RPS requires some form of compliance reporting, and the Company can be subject to penalties in the event of noncompliance.
In November 2006, Washington voters approved a ballot initiative establishing a RPS requirement for qualifying electric utilities, including PacifiCorp. The requirements are 3% of retail sales by January 1, 2012 through 2015, 9% of retail sales by January 1, 2016 through 2019 and 15% of retail sales by January 1, 2020. The WUTC has adopted final rules to implement the initiative.
In June 2007, the Oregon Renewable Energy Act ("OREA") was adopted, providing a comprehensive renewable energy policy and RPS for Oregon. Subject to certain exemptions and cost limitations established in the OREA, PacifiCorp and other qualifying electric utilities must meet minimum qualifying electricity requirements for electricity sold to retail customers of at least 5% in 2011 through 2014, 15% in 2015 through 2019, 20% in 2020 through 2024, and 25% in 2025 and subsequent years. As required by the OREA, the OPUC has approved an automatic adjustment clause to allow an electric utility, including PacifiCorp, to recover prudently incurred costs of its investments in renewable energy generating facilities and associated transmission costs.
In April 2011, the California governor signed into law Senate Bill 2 of the First Extraordinary Session that expanded the RPS to require all California retail sellers to procure an average of 20% of retail load from renewable resources by December 31, 2013, 25% by December 31, 2016 and 33% by December 31, 2020 and each year thereafter. In December 2011, the CPUC adopted a decision confirming that multi-jurisdictional utilities, such as PacifiCorp, are not subject to the percentage limits within the three categories of RPS-eligible resources established by the legislation that have been imposed on other California retail sellers. The CPUC is in the process of an extensive rulemaking to implement the new requirements under the legislation.
In March 2008, Utah's governor signed Utah Senate Bill 202. Among other things, this law provides that, beginning in the year 2025, 20% of adjusted retail electric sales of all Utah utilities be supplied by renewable energy, if it is cost effective. Retail electric sales will be adjusted by deducting the amount of generation from sources that produce zero or reduced carbon emissions, and for sales avoided as a result of energy efficiency and DSM programs. Qualifying renewable energy sources can be located anywhere in the WECC areas, and renewable energy credits can be used.
Water Quality Standards
The federal Water Pollution Control Act ("Clean Water Act") establishes the framework for maintaining and improving water quality in the United States through a program that regulates, among other things, discharges to and withdrawals from waterways. The Clean Water Act requires that cooling water intake structures reflect the "best technology available for minimizing adverse environmental impact" to aquatic organisms. In July 2004, the EPA established significant new technology-based performance standards for existing electric generating facilities that take in more than 50 million gallons of water per day. These rules were aimed at minimizing the adverse environmental impacts of cooling water intake structures by reducing the number of aquatic organisms lost as a result of water withdrawals. In response to a legal challenge to the rule, in January 2007, the Second Circuit remanded almost all aspects of the rule to the EPA, without addressing whether companies with cooling water intake structures were required to comply with these requirements. On appeal from the Second Circuit, in April 2009, the United States Supreme Court ruled that the EPA permissibly relied on a cost-benefit analysis in setting the national performance standards regarding "best technology available for minimizing adverse environmental impact" at cooling water intake structures and in providing for cost-benefit variances from those standards as part of the §316(b) Clean Water Act Phase II regulations. The United States Supreme Court remanded the case back to the Second Circuit to conduct further proceedings consistent with its opinion.
In March 2011, the EPA released a proposed rule under §316(b) of the Clean Water Act to regulate cooling water intakes at existing facilities. The proposed rule establishes requirements for all power generating facilities that withdraw more than two million gallons per day, based on total design intake capacity, of water from waters of the United States and use at least 25% of the withdrawn water exclusively for cooling purposes. PacifiCorp's Dave Johnston generating facility and all of MidAmerican Energy's coal-fueled generating facilities, except Louisa, Ottumwa and Walter Scott, Jr. Unit 4, which have water cooling towers, withdraw more than two million gallons per day of water from waters of the United States. PacifiCorp's Jim Bridger, Naughton, Gadsby, Hunter, Carbon and Huntington generating facilities currently utilize closed cycle cooling towers but withdraw more than two million gallons of water per day. The proposed rule includes impingement (i.e., when fish and other organisms are trapped against screens when water is drawn into a facility's cooling system) mortality standards to be met through average impingement mortality or intake velocity design criteria and entrainment (i.e., when organisms are drawn into the facility) standards to be determined on a case-by-case basis. The standards are required to be met as soon as possible after the effective date of the final rule, but no later than eight years thereafter. The rule is required to be finalized by the EPA by July 2012. Assuming the final rule is issued by July 2012, PacifiCorp's and MidAmerican Energy's generating facilities impacted by the final rule will be required to complete impingement and entrainment studies in 2013. The costs of compliance with the cooling water intake structure rule cannot be determined until the rule is final and the prescribed studies are conducted. In the event that PacifiCorp's or MidAmerican Energy's existing intake structures require modification, the costs are not anticipated to be significant.
Coal Combustion Byproduct Disposal
In December 2008, an ash impoundment dike at the Tennessee Valley Authority's Kingstonpower plant collapsed after heavy rain, releasing a significant amount of fly ash and bottom ash, coal combustion byproducts, and water to the surrounding area. In light of this incident, federal and state officials have called for greater regulation of the storage and disposal of coal combustion byproducts. In May 2010, the EPA released a proposed rule to regulate the management and disposal of coal combustion byproducts, presenting two alternatives to regulation under the RCRA. Under the first option, coal combustion byproducts would be regulated as special waste under RCRA Subtitle C and the EPA would establish requirements for coal combustion byproducts from the point of generation to disposition, including the closure of disposal units. Alternatively, the EPA is considering regulation under RCRA Subtitle D under which it would establish minimum nationwide standards for the disposal of coal combustion byproducts. Under both options, surface impoundments utilized for coal combustion byproducts would have to be cleaned and closed unless they could meet more stringent regulatory requirements; in addition, more stringent requirements would be implemented for new ash landfills and expansions of existing ash landfills. PacifiCorp operates 16 surface impoundments and six landfills that contain coal combustion byproducts. MidAmerican Energy operates eight surface impoundments and four landfills that contain coal combustion byproducts. These ash impoundments and landfills may be impacted by the newly proposed regulation, particularly if the materials are regulated as hazardous or special waste under RCRA Subtitle C, and could pose significant additional costs associated with ash management and disposal activities at the Company's coal-fueled generating facilities. The public comment period closed in November 2010. The EPA has not indicated when the rule will be finalized, and the substance of the final rule is not known. The United States House of Representatives passed H.R. 2273 in October 2011, which would regulate coal combustion byproducts under RCRA Subtitle D. A Senate bill similar to the House bill has been introduced, but action has not been taken on the bill. The impact of the proposed regulations on coal combustion byproducts cannot be determined at this time; however, both PacifiCorp and MidAmerican Energy have begun developing surface impoundment and landfill compliance plan options to ensure that physical infrastructure decisions are aligned with the potential outcomes of the rulemaking.
Other
Other laws, regulations and agencies to which the Company is subject to include, but are not limited to:
The federal Comprehensive Environmental Response, Compensation and Liability Act and similar state laws may require any current or former owners or operators of a disposal site, as well as transporters or generators of hazardous substances sent to such disposal site, to share in environmental remediation costs.
The Nuclear Waste Policy Act of 1982, under which the United States Department of Energy is responsible for the selection and development of repositories for, and the permanent disposal of, spent nuclear fuel and high-level radioactive wastes. Refer to Note 13 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding nuclear decommissioning obligations.
The federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes establish operational, reclamation and closure standards that must be met during and upon completion of mining activities.
The FERC oversees the relicensing of existing hydroelectric systems and is also responsible for the oversight and issuance of licenses for new construction of hydroelectric systems, dam safety inspections and environmental monitoring. Refer to Note 16 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the relicensing of certain of PacifiCorp's existing hydroelectric facilities.
MEHC expects its Domestic Regulated Businesses will be allowed to recover the prudently incurred costs to comply with the environmental laws and regulations discussed above. The Company's planning efforts take into consideration the complexity of balancing factors such as: (a) pending environmental regulations and requirements to reduce emissions, address waste disposal, ensure water quality, and protect wildlife; (b) avoidance of excessive reliance on any one generation technology; (c) costs and trade-offs of various resource options including energy efficiency, demand response programs, and renewable generation; (d) state-specific energy policies, resource preferences, and economic development efforts; (e) additional transmission investment to reduce power costs and increase efficiency and reliability of the integrated transmission system; and (f) keeping rates as affordable as possible. Due to the number of generating units impacted by environmental regulations, deferring installation of compliance-related projects is often not feasible or cost effective and places the Company at risk of not having access to necessary capital, material, and labor while attempting to perform major equipment installations in a compressed timeframe concurrent with other utilities across the country. Therefore, the Company has established installation schedules with permitting agencies that coordinate compliance timeframes with construction and tie-in of major environmental compliance projects as units are scheduled off-line for planned maintenance outages; these coordinated efforts help reduce costs associated with replacement power and maintain system reliability.
Collateral and Contingent Features
Debt and preferred securities of MEHC and certain of its subsidiaries are rated by credit rating agencies. Assigned credit ratings are based on each rating agency's assessment of the rated company's ability to, in general, meet the obligations of its issued debt or preferred securities. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time.
MEHC and its subsidiaries have no credit rating downgrade triggers that would accelerate the maturity dates of outstanding debt, and a change in ratings is not an event of default under the applicable debt instruments, except for those discussed in Note 23 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K related to the Topaz financing. The Company's unsecured revolving credit facilities do not require the maintenance of a minimum credit rating level in order to draw upon their availability, but, under certain instances, must maintain sufficient covenant tests if ratings drop below a certain level. However, commitment fees and interest rates under the credit facilities are tied to credit ratings and increase or decrease when the ratings change. A ratings downgrade could also increase the future cost of commercial paper, short- and long-term debt issuances or new credit facilities.
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain provisions that require certain of MEHC's subsidiaries, principally the Utilities, to maintain specific credit ratings on their unsecured debt from one or more of the three recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance" in the event of a material adverse change in the subsidiary's creditworthiness. These rights can vary by contract and by counterparty. As of December 31, 2011, these subsidiary's credit ratings from the three recognized credit rating agencies were investment grade. If all credit-risk-related contingent features or adequate assurance provisions for these agreements had been triggered as of December 31, 2011, the Company would have been required to post $569 million of additional collateral. The Company's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors. Refer to Note 7 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for a discussion of the Company's collateral requirements specific to the Company's derivative contracts.
In July 2010, the President signed into law the Dodd-Frank Reform Act. The Dodd-Frank Reform Act reshapes financial regulation in the United States by creating new regulators, regulating new markets and firms, and providing new enforcement powers to regulators. Virtually all major areas of the Dodd-Frank Reform Act, including collateral requirements on derivative contracts, are the subject of regulatory interpretation and implementation rules requiring rulemaking proceedings, some of which have been completed and others that are expected to be finalized in 2012.
The Company is a party to derivative contracts, including over-the-counter derivative contracts. The Dodd-Frank Reform Act provides for extensive new regulation of over-the-counter derivative contracts and certain market participants, including imposition of mandatory clearing, exchange trading, capital and margin requirements for "swap dealers" and "major swap participants." The Dodd-Frank Reform Act provides certain exemptions from these regulations for commercial end-users that use derivatives to hedge and manage the commercial risk of their businesses. Although the Company generally does not enter into over-the-counter derivative contracts for purposes unrelated to hedging of commercial risk and does not believe it will be considered a swap dealer or major swap participant, the outcome of the rulemaking proceedings cannot be predicted and, therefore, the impact of the Dodd-Frank Reform Act on the Company's consolidated financial results cannot be determined at this time.
Inflation
Historically, overall inflation and changing prices in the economies where MEHC's subsidiaries operate have not had a significant impact on the Company's consolidated financial results. In the United States, MEHC's regulated subsidiaries operate under cost-of-service based rate structures administered by various state commissions and the FERC. Under these rate structures, MEHC's regulated subsidiaries are allowed to include prudent costs in their rates, including the impact of inflation. The price control formula used by the United Kingdom Distribution Companies incorporates the rate of inflation in determining rates charged to customers. MEHC's subsidiaries attempt to minimize the potential impact of inflation on their operations by employing prudent risk management and hedging strategies and by considering, among other areas, its impact on purchases of energy, operating expenses, materials and equipment costs, contract negotiations, future capital spending programs and long-term debt issuances. There can be no assurance that such actions will be successful.
Off-Balance Sheet Arrangements
The Company has certain investments that are accounted for under the equity method in accordance with accounting principles generally accepted in the United States of America ("GAAP"). Accordingly, an amount is recorded on the Company's Consolidated Balance Sheets as an equity investment and is increased or decreased for the Company's pro-rata share of earnings or losses, respectively, less any dividends from such investments.
As of December 31, 2011, the Company's investments that are accounted for under the equity method had short- and long-term debt of $1.045 billion, unused revolving credit facilities of $147 million and letters of credit outstanding of $57 million. As of December 31, 2011, the Company's pro-rata share of such short- and long-term debt was $508 million, unused revolving credit facilities was $73 million and outstanding letters of credit was $29 million. The entire amount of the Company's pro-rata share of the outstanding short- and long-term debt and unused revolving credit facilities is non-recourse to the Company. $25 million of the Company's pro-rata share of the outstanding letters of credit is recourse to the Company. Although the Company is generally not required to support debt service obligations of its equity investees, default with respect to this non-recourse short- and long-term debt could result in a loss of invested equity.
New Accounting Pronouncements
For a discussion of new accounting pronouncements affecting the Company, refer to Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Critical Accounting Estimates
Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. The following critical accounting estimates are impacted significantly by the Company's methods, judgments and assumptions used in the preparation of the Consolidated Financial Statements and should be read in conjunction with the Company's Summary of Significant Accounting Policies included in Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Accounting for the Effects of Certain Types of Regulation
The Domestic Regulated Businesses prepare their financial statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, the Domestic Regulated Businesses are required to defer the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates.
The Company continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition which could limit the Domestic Regulated Businesses' ability to recover their costs. Based upon this continuous evaluation, the Company believes the application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at both the federal and state levels and is subject to change in the future. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be written off to net income, returned to customers or re-established as accumulated other comprehensive income (loss) ("AOCI"). Total regulatory assets were $2.918 billion and total regulatory liabilities were $1.731 billion as of December 31, 2011. Refer to Note 5 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the Domestic Regulated Businesses' regulatory assets and liabilities.
Derivatives
The Company is exposed to the impact of market fluctuations in commodity prices, interest rates and foreign currency exchange rates. The Company is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk primarily through MEHC's ownership of the Utilities as they have an obligation to serve retail customer load in their regulated service territories. MidAmerican Energy also provides nonregulated retail electricity and natural gas services in competitive markets. The Utilities' load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity, wholesale electricity that is purchased and sold, and natural gas supply for regulated and nonregulated retail customers. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints.Interest rate risk exists on variable-rate debt and future debt issuances. Additionally, the Company is exposed to foreign currency exchange rate risk from its business operations and investments in Great Britain. Each of $28the Company's business platforms has established a risk management process that is designed to identify, assess, monitor, report, manage and mitigate each of the various types of risk involved in its business. The Company employs a number of different derivative contracts, which may include forwards, futures, options, swaps and other agreements, to manage price risk for electricity, natural gas and other commodities; interest rate risk; and foreign currency exchange rate risk. The Company does not hedge all of its commodity price, interest rate and foreign currency exchange rate risks, thereby exposing the unhedged portion to changes in market prices. Refer to Notes 6 and 7 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the Company's derivative contracts.
Measurement Principles
Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which the Company transacts. When quoted prices for identical contracts are not available, the Company uses forward price curves. Forward price curves represent the Company's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. The Company bases its forward price curves upon market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent energy brokers, exchanges, direct communication with market participants and actual transactions executed by the Company. Market price quotations for certain major electricity and natural gas trading hubs are generally readily obtainable for the applicable term of the Company's outstanding derivative contracts; therefore, the Company's forward price curves for those locations and periods reflect observable market quotes. As of December 31, 2011, the Company had a net derivative liability of $468 million partially related to contracts valued using either quoted prices or forward price curves based upon observable market quotes. Market price quotations for other electricity and natural gas trading hubs are not as readily obtainable due to the length of the contract. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, the Company uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these derivative contracts is a function of underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of contracts. The assumptions used in these models are critical, since any changes in assumptions could have a significant impact on the estimated fair value of the contracts. As of December 31, 2011, the Company had a net derivative asset of $23 million related to contracts where the Company uses internal models with unobservable inputs.
Classification and Recognition Methodology
Almost all of the Company's derivative contracts are probable of inclusion in the rates of its rate-regulated subsidiaries and changes in the estimated fair value of derivative contracts are generally recorded as net regulatory assets or liabilities. Accordingly, amounts are generally not recognized in earnings until the contracts are settled and the forecasted transaction has occurred. As of December 31, 2011, the Company had $400 million recorded as net regulatory assets related to derivative contracts on the Consolidated Balance Sheets. If it becomes no longer probable that a derivative contract will be included in regulated rates, the regulatory asset or liability will be written off and recognized in earnings.
Impairment of Long-Lived Assets and Goodwill
The Company evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value. The impacts of regulation are considered when evaluating the carrying value of regulated assets. Substantially all property, plant and equipment was used in regulated businesses as of December 31, 2011. For all other assets, any resulting impairment loss is reflected on the Consolidated Statements of Operations.
The estimate of cash flows arising from the future use of the asset that are used in the impairment analysis requires judgment regarding what the Company would expect to recover from the future use of the asset. Changes in judgment that could significantly alter the calculation of the fair value or the recoverable amount of the asset may result from significant changes in the regulatory environment, the business climate, management's plans, legal factors, market price of the asset, the use of the asset or the physical condition of the asset, future market prices, load growth, competition and many other factors over the life of the asset. Any resulting impairment loss is highly dependent on the underlying assumptions and could significantly affect the Company's results of operations.
The Company's Consolidated Balance Sheet as of December 31, 2011 includes goodwill of acquired businesses of $4.996 billion. The Company evaluates goodwill for impairment at least annually and completed its annual review as of October 31. Additionally, no indicators of impairment were identified as of December 31, 2011. A significant amount of judgment is required in estimating the fair value of the reporting unit and performing goodwill impairment tests. The Company uses a variety of methods to estimate a reporting unit's fair value, principally discounted projected future net cash flows. Key assumptions used include, but are not limited to, the use of estimated future cash flows; multiples of earnings; and an appropriate discount rate. Estimated future cash flows are impacted by, among other factors, growth rates, changes in regulations and rates, ability to renew contracts and estimates of future commodity prices. In estimating future cash flows, the Company incorporates current market information, as well as historical factors. Refer to Note 22 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the Company's goodwill.
Pension and Other Postretirement Benefits
The Company sponsors defined benefit pension and other postretirement benefit plans that cover the majority of its employees. The Company recognizes the funded status of its defined benefit pension and other postretirement benefit plans on the Consolidated Balance Sheets. Funded status is the fair value of plan assets minus the benefit obligation as of the measurement date. As of December 31, 2011, the Company recognized a net liability totaling $794 million for the funded status of the Company's defined benefit pension and other postretirement benefit plans. As of December 31, 2011, amounts not yet recognized as a component of net periodic benefit cost that were included in net regulatory assets and AOCI totaled $822 million and $673 million, respectively.
The expense and benefit obligations relating to these defined benefit pension and other postretirement benefit plans are based on actuarial valuations. Inherent in these valuations are key assumptions, including discount rates, expected long-term rate of return on plan assets and healthcare cost trend rates. These key assumptions are reviewed annually and modified as appropriate. The Company believes that the assumptions utilized in recording obligations under the plans are reasonable based on prior plan experience and current market and economic conditions. Refer to Note 14 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for disclosures about the Company's defined benefit pension and other postretirement benefit plans, including the key assumptions used to calculate the funded status and net periodic benefit cost for these plans as of and for the year ended December 31, 2011.
The Company chooses a discount rate based upon high quality debt security investment yields in effect as of the measurement date that corresponds to the expected benefit period. The pension and other postretirement benefit liabilities increase as the discount rate is reduced.
In establishing its assumption as to the expected long-term rate of return on plan assets, the Company utilizes the expected asset allocation and return assumptions for each asset class based on historical performance and forward-looking views of the financial markets. Pension and other postretirement benefits expense increases as the expected long-term rate of return on plan assets decreases. The Company regularly reviews its actual asset allocations and rebalances its investments to its targeted allocations when considered appropriate.
The Company chooses a healthcare cost trend rate that reflects the near and long-term expectations of increases in medical costs and corresponds to the expected benefit payment periods. The healthcare cost trend rate gradually declines to 5% in 2016 at which point the rate is assumed to remain constant. Refer to Note 14 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for healthcare cost trend rate sensitivity disclosures.
The key assumptions used may differ materially from period to period due to changing market and economic conditions. These differences may result in a significant impact to pension and other postretirement benefits expense and the funded status. If changes were to occur for the following key assumptions, the approximate effect on the Consolidated Financial Statements would be as follows (in millions):
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Domestic Plans | | |
| | | | | | Other Postretirement | | United Kingdom |
| | Pension Plans | | Benefit Plans | | Pension Plan |
| | +0.5% | | -0.5% | | +0.5% | | -0.5% | | +0.5% | | -0.5% |
| | | | | | | | | | | | |
| Effect on December 31, 2011 | | | | | | | | | | | |
| Benefit Obligations: | | | | | | | | | | | |
| Discount rate | $ | (103 | ) | | $ | 114 |
| | $ | (41 | ) | | $ | 45 |
| | $ | (137 | ) | | $ | 157 |
|
| | | | | | | | | | | | |
| Effect on 2011 Periodic Cost: | | | | | | | | | | | |
| Discount rate | $ | (4 | ) | | $ | 4 |
| | $ | (2 | ) | | $ | 3 |
| | $ | (13 | ) | | $ | 13 |
|
| Expected rate of return on plan assets | (8 | ) | | 8 |
| | (3 | ) | | 3 |
| | (8 | ) | | 8 |
|
A variety of factors affect the funded status of the plans, including asset returns, discount rates, plan changes and the Company's funding policy for each plan. Additionally, federal laws may require the Company to increase future contributions to its domestic pension plans, which may create more volatility in annual contributions than historically experienced and could have a material impact on the Company's consolidated financial results.
Income Taxes
In determining the Company's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by the Company's various regulatory jurisdictions. The Company's income tax returns are subject to continuous examinations by federal, state, local and foreign income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. The Company recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. Although the ultimate resolution of the Company's federal, state, local and foreign income tax examinations is uncertain, the Company believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations, if any, is not expected to have a material adverse impact on the Company's consolidated financial results. Refer to Note 15 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the Company's income taxes.
The Utilities are required to pass income tax benefits related to certain property-related basis differences and other various differences on to their customers in certain state jurisdictions. These amounts were recognized as a net regulatory asset totaling $1.003 billion as of December 31, 2011 and will be included in regulated rates when the temporary differences reverse. Management believes the existing net regulatory assets are probable of inclusion in regulated rates. If it becomes no longer probable that these costs will be included in regulated rates, the related regulatory asset will be charged to net income.
The Company has not established deferred income taxes on the undistributed foreign earnings of Northern Powergrid Holdings or the related currency translation adjustment that have been determined by management to be reinvested indefinitely. The cumulative earnings were approximately$2.0 billion as of December 31, 2011. The Company periodically evaluates its capital requirements. If circumstances change in the future and a portion of Northern Powergrid Holdings' undistributed earnings were repatriated, the dividends would be subject to taxation in the United States. However, any United States income tax liability would be offset, in part, by available United States income tax credits with respect to corporate income taxes previously paid principally in the United Kingdom. Because of the availability of foreign income tax credits, it is not practicable to determine the United States income tax liability that would be recognized if such cumulative earnings were not reinvested indefinitely. The Company has established deferred income taxes on all other undistributed foreign earnings.
Revenue Recognition - Unbilled Revenue
Unbilled revenue was $474 million as of December 31, 2011. Revenue from energy business customers is recognized as electricity or natural gas is delivered or services are provided. The determination of customer billings is based on a systematic reading of meters, fixed reservation charges based on contractual quantities and rates or, in the case of the United Kingdom distribution businesses, when information is received from the national settlement system. At the end of each month, amounts of energy provided to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recorded. Factors that can impact the estimate of unbilled energy include, but are not limited to, seasonal weather patterns, total volumes supplied to the system, line losses, economic impacts and composition of sales among customer classes. Estimates are reversed in the following month and actual revenue is recorded based on subsequent meter readings.
| |
| Item 7A. | Quantitative and Qualitative Disclosures About Market Risk |
The Company's Consolidated Balance Sheets include assets and liabilities with fair values that are subject to market risks. The Company's significant market risks are primarily associated with commodity prices, interest rates, equity prices, foreign currency exchange rates and the extension of credit to counterparties with which the Company transacts. The following discussion addresses the significant market risks associated with the Company's business activities. Each of the Company's business platforms has established guidelines for credit risk management. Refer to Notes 2 and 7 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the Company's contracts accounted for as derivatives.
Commodity Price Risk
The Company is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk primarily through MEHC's ownership of the Utilities as they have an obligation to serve retail customer load in their regulated service territories. MidAmerican Energy also provides nonregulated retail electricity and natural gas services in competitive markets. The Utilities' load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity, wholesale electricity that is purchased and sold, and natural gas supply for regulated and nonregulated retail customers. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints.The Company does not engage in a material amount of proprietary trading activities.To mitigate a portion of its commodity price risk, the Company uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. The Company does not hedge all of its commodity price risk, thereby exposing the unhedged portion to changes in market prices. The Company's exposure to commodity price risk is generally limited by its ability to include the costs in regulated rates, which is subject to regulatory lag that occurs between the time the costs are incurred and when the costs are included in regulated rates.
The table that follows summarizes the Company's price risk on commodity contracts accounted for as derivatives, excluding collateral netting of $156 million and $141 million as of December 31, 2011 and 2010, respectively, and shows the effects of a hypothetical 10% increase and 10% decrease in forward market prices with the contracted or expected volumes. The selected hypothetical change does not reflect what could be considered the best or worst case scenarios (dollars in millions).
|
| | | | | | | | | | | |
| | Fair Value - | | Estimated Fair Value after |
| | Net Asset | | Hypothetical Change in Price |
| | (Liability) | | 10% increase | | 10% decrease |
| As of December 31, 2011: | | | | | |
| Not designated as hedging contracts | $ | (399 | ) | | $ | (341 | ) | | $ | (457 | ) |
| Designated as hedging contracts | (46 | ) | | (7 | ) | | (85 | ) |
| Total commodity derivative contracts | $ | (445 | ) | | $ | (348 | ) | | $ | (542 | ) |
| | | | | | |
| As of December 31, 2010: | | | | | |
| Not designated as hedging contracts | $ | (565 | ) | | $ | (537 | ) | | $ | (593 | ) |
| Designated as hedging contracts | (48 | ) | | (9 | ) | | (87 | ) |
| Total commodity derivative contracts | $ | (613 | ) | | $ | (546 | ) | | $ | (680 | ) |
The majority of the Company's commodity derivative contracts not designated as hedging contracts are recoverable from customers in regulated rates and, therefore, net unrealized gains and losses associated with interim price movements on commodity derivative contracts do not expose the Company to earnings volatility. As of December 31, 2011 and 2010, a net regulatory asset of $400 million and $564 million, respectively, was recorded related to the net derivative liability of $399 million and $565 million, respectively. For the Company's commodity derivative contracts designated as hedging contracts, net unrealized gains and losses associated with interim price movements on commodity derivative contracts, to the extent the hedge is considered effective, generally do not expose the Company to earnings volatility. The settled cost of these commodity derivative contracts is generally included in regulated rates. Consolidated financial results would be negatively impacted if the costs of wholesale electricity, natural gas or fuel are higher than what is included in regulated rates, including the impacts of adjustment mechanisms.
Interest Rate Risk
The Company is exposed to interest rate risk on its outstanding variable-rate short- and long-term debt issuancesand future debt issuances. The Company manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in 2009interest rates. As a result of the fixed interest rates, the Company's fixed-rate long-term debt does not expose the Company to the risk of loss due to changes in market interest rates. Additionally, because fixed-rate long-term debt is not carried at fair value on the Consolidated Balance Sheets, changes in fair value would impact earnings and cash flows only if the Company were to reacquire all or a portion of these instruments prior to their maturity. The Company may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate the Company's exposure to interest rate risk. The nature and amount of the Company's short- and long-term debt can be expected to vary from period to period as a result of future business requirements, market conditions and other factors. Refer to Notes 6, 9, 10, 11 and 12 of Notes to Consolidated Financial Statements in Item 1 of this Form 10-K for additional discussion of the Company's short- and long-term debt.
As of December 31, 2011 and 2010, the Company had short- and long-term variable-rate obligations totaling $1.715 billion and $1.170 billion, respectively, that expose the Company to the risk of increased interest expense in the event of increases in short-term interest rates. The market risk related to the Company's variable-rate debt as of December 31, 2011 is not hedged. If variable interest rates were to increase by 10% from December 31 levels, it would not have a material effect on the Company's consolidated annual interest expense. The carrying value of the variable-rate obligations approximates fair value as of December 31, 2011 and 2010.
Equity Price Risk
Market prices for equity securities are subject to fluctuation and consequently the amount realized in the subsequent sale of an investment may significantly differ from the reported market value. Fluctuation in the market price of a security may result from perceived changes in the underlying economic characteristics of the investee, the relative price of alternative investments and general market conditions.
As of December 31, 2011 and 2010, the Company's investment in BYD Company Limited common stock represented approximately 68% and 84%, respectively, of the total fair value of the Company's equity securities. The Company's remaining equity securities are primarily related to certain trust funds in which realized and unrealized gains and losses are recorded as net regulatory assets or liabilities since the Company expects to recover costs for these activities through regulated rates. The following table summarizes our investment in BYD Company Limited as of December 31, 2011 and 2010 and the effects of a hypothetical 30% increase and a 30% decrease in market price as of those dates. The selected hypothetical change does not reflect what could be considered the best or worst case scenarios (dollars in millions).
|
| | | | | | | | | | | | |
| | | | | | Estimated | | Hypothetical |
| | | | Hypothetical | | Fair Value after | | Percentage Increase |
| | Fair | | Price | | Hypothetical | | (Decrease) in MEHC |
| | Value | | Change | | Change in Prices | | Shareholders' Equity |
| | | | | | | | |
| As of December 31, 2011 | $ | 488 |
| | 30% increase | | $ | 634 |
| | 1 | % |
| | | | 30% decrease | | 342 |
| | (1 | ) |
| | | | | | | | |
| As of December 31, 2010 | $ | 1,182 |
| | 30% increase | | $ | 1,537 |
| | 2 | % |
| | | | 30% decrease | | 827 |
| | (2 | ) |
Foreign Currency Exchange Rate Risk
MEHC's business operations and investments outside of the United States increase its risk related to fluctuations in foreign currency exchange rates primarily in relation to the British pound. MEHC's reporting currency is the United States dollar, and the value of the assets and liabilities, earnings, cash flows and potential distributions from MEHC's foreign operations changes with the fluctuations of the currency in which they transact.
Northern Powergrid Holdings' functional currency is the British pound. At December 31, 2011, a 10% devaluation in the British pound to the United States dollar would result in the Company's Consolidated Balance Sheet being negatively impacted by a $270 million cumulative translation adjustment in AOCI. A 10% devaluation in the average currency exchange rate would have resulted in lower reported earnings for Northern Powergrid Holdings of $39 million in 2011.
Credit Risk
Domestic Regulated Operations
The Utilities extend unsecured credit to other utilities, energy marketing companies, financial institutions and other market participants in conjunction with their wholesale energy supply and marketing activities. Credit risk relates to the risk of loss that might occur as a result of nonperformance by counterparties on their contractual obligations to make or take delivery of electricity, natural gas or other commodities and to make financial settlements of these obligations. Credit risk may be concentrated to the extent that one or more groups of counterparties have similar economic, industry or other characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in market or other conditions. In addition, credit risk includes not only the risk that a counterparty may default due to circumstances relating directly to it, but also the risk that a counterparty may default due to circumstances involving other market participants that have a direct or indirect relationship with the counterparty.
The Utilities analyze the financial condition of each significant wholesale counterparty before entering into any transactions, establish limits on the amount of unsecured credit to be extended to each counterparty and evaluate the appropriateness of unsecured credit limits on an ongoing basis. To mitigate exposure to the financial risks of wholesale counterparties, the Utilities enter into netting and collateral arrangements that may include margining and cross-product netting agreements and obtain third-party guarantees, letters of credit and cash deposits. Counterparties may be assessed fees for delayed payments. If required, the Utilities exercise rights under these arrangements, including calling on the counterparty's credit support arrangement.
As of December 31, 2011, PacifiCorp's aggregate credit exposure from wholesale activities totaled $338 million, based on settlement and mark-to-market exposures, net of collateral. As of December 31, 2011, $333 million, or 99%, of PacifiCorp's credit exposure was with counterparties having investment grade credit ratings by either Moody's Investor Service or Standard & Poor's Rating Services. As of December 31, 2011, $5 million, or 1%, of such credit exposure was with counterparties having externally rated "non-investment grade" credit ratings. As of December 31, 2011, four counterparties comprised $274 million, or 81%, of the aggregate credit exposure. All four counterparties are rated investment grade by Moody's Investor Service and Standard & Poor's Rating Services, and PacifiCorp is not aware of any factors that would likely result in a downgrade of the counterparties' credit ratings to below investment grade over the remaining term of transactions outstanding as of December 31, 2011.
During 2011, approximately 89% of MidAmerican Energy's electric wholesale sales revenues resulted from participation in RTOs, including the MISO and MEHCthe PJM. MidAmerican Energy has potential indirect credit exposure to other market participants in these RTO markets. In the event of a default by a RTO market participant on its market-related obligations, losses are allocated among all other market participants in proportion to each participant's share of overall market activity during the period of time the loss was incurred, diversifying MidAmerican Energy's exposure to credit losses from individual participants. Transactional activities of MidAmerican Energy and other participants in 2008 at PacifiCorp,organized RTO markets are governed by credit policies specified in each respective RTO's governing tariff or related business practices. Credit policies of RTO's, which have been developed through extensive stakeholder participation, generally seek to minimize potential loss in the event of a market participant default without unnecessarily inhibiting access to the marketplace. MidAmerican Funding and Energy's share of historical losses from defaults by other RTO market participants has not been material. As of December 31, 2011, MidAmerican Energy's aggregate direct credit exposure from electric wholesale marketing counterparties was not material.
Northern Natural Gas.Gas' primary customers include utilities in the upper Midwest. Kern River's primary customers are major oil and natural gas companies or affiliates of such companies, electric generating companies, energy marketing and trading companies, financial institutions and natural gas distribution utilities which provide services in Utah, Nevada and California. As a general policy, collateral is not required for receivables from creditworthy customers. Customers' financial condition and creditworthiness, as defined by the tariff, are regularly evaluated and historical losses have been minimal. In order to provide protection against credit risk, and as permitted by the separate terms of each of Northern Natural Gas' and Kern River's tariffs, the companies have required customers that lack creditworthiness to provide cash deposits, letters of credit or other security until their creditworthiness improves.
Northern Powergrid Holdings
The Distribution Companies charge fees for the use of their electrical infrastructure to supply companies and generators connected to their networks. The supply companies, which purchase electricity from generators and traders and sell the electricity to end-use customers, use the Distribution Companies' distribution networks pursuant to the multilateral "Distribution Connection and Use of System Agreement." The Distribution Companies' customers are concentrated in a small number of electricity supply businesses with RWE Npower PLC accounting for approximately 29% of distribution revenue in 2011. Ofgem has determined a framework which sets credit limits for each supply business based on its credit rating or payment history and requires them to provide credit cover if their value at risk (measured as being equivalent to 45 days usage) exceeds the credit limit. Acceptable credit typically is provided in the form of a parent company guarantee, letter of credit or an escrow account. Ofgem has indicated that, provided the Distribution Companies have implemented credit control, billing and collection in line with best practice guidelines and can demonstrate compliance with the guidelines or are able to satisfactorily explain departure from the guidelines, any bad debt losses arising from supplier default will be recovered through an increase in future allowed income. Losses incurred to date have not been material.
Capitalized Interest
Capitalized interest decreased $14 million for 2011 compared to 2010 due to lower construction work-in-progress balances at PacifiCorp, partially offset by higher construction work-in-progress balances at MidAmerican Energy and Kern River.
Capitalized interest increased $13 million for 2010 compared to 2009 due to higher construction in progresswork-in-progress balances at PacifiCorp and decreased $13 million for 2009 compared to 2008 due to lower construction in progress at MidAmeric an Funding.PacifiCorp.
Interest and Dividend Income
Interest and dividend income decreased $10 million for 2011 compared to 2010 due to an $11 million dividend received in 2010 from BYD Company Limited.
Interest and dividend income decreased $14 million for 2010 compared to 2009 primarily due to interest associated with SB 408 refunds received in 2009 at PacifiCorp, income earned in 2009 related to the Constellation Energy investments and lower average cash balances, partially offset by athe dividend received in 2010 from the BYD Company Limited ("BYD") common stock investment totaling $11 million.Limited.
Interest and dividend income decreased $37 million for 2009 compared to 2008 due to dividends received in 2008 related to the investment in the Constellation Energy 8% preferred stock and less favorable cash positions and lower rates in 2009.
Other, net
Other, net decreased $59 million for 2011 compared to 2010 due to costs associated with the early redemption of MEHC subordinated debt totaling $40 million, lower equity AFUDC of $17 million and lower Rabbi Trust earnings, partially by the impairment of an asset in 2010 totaling $8 million at MidAmerican Funding. Equity AFUDC decreased due to lower construction work-in-progress balances at PacifiCorp, partially offset by higher construction work-in-progress balances at MidAmerican Energy and Kern River.
Other, net decreased $36 million for 2010 compared to 2009 due primarily to a $37 million pre-tax gain on the Constellation Energy common stock investme ntinvestment in 2009 and the impairment of an asset in 2010 totaling $8 million at MidAmerican Funding, partially offset by higher allowance for equity funds used during constructionAFUDC in 2010, primarily at PacifiCorp and MidAmerican Energy.
Other, net decreased $1.042 billion for 2009 compared to 2008 due primarily to the 2008 termination of the merger agreement with Constellation Energy, which resulted in the receipt of a $175 million termination fee and the conversion of the Constellation Energy 8% preferred stock into $418 million of cash and 19.9 million shares of Constellation Energy common stock valued at $499 million. In 2009, the Company recognized a pre-tax gain on the Constellation Energy common stock investment totaling $37 mil lion.
Income Tax Expense
Income tax expense increased $96 million for 2011 compared to 2010. The effective tax rates were 18% and 14% for 2011 and 2010, respectively. The increase in the effective tax rate was due to the effects of ratemaking, lower tax benefits received at MidAmerican Energy for changes related to the tax capitalization and repairs deductions policies totaling $26 million and higher United States income taxes on foreign earnings, partially offset by additional production tax credits in 2011 totaling $29 million, higher deferred income tax benefits in 2011 related to enacted changes in the United Kingdom's corporate income tax rate discussed below and lower state income taxes.
In July 2011, the Company recognized $40 million of deferred income tax benefits upon the enactment of a reduction in the United Kingdom corporate income tax rate from 27% to 26% effective April 1, 2011, and a further reduction to 25% effective April 1, 2012. In July 2010, the Company recognized $25 million of deferred income tax benefits upon the enactment of the reduction in the United Kingdom corporate income tax rate from 28% to 27% effective April 1, 2011.
Federal renewable electricity production tax credits are earned on qualifying wind-powered generation placed in service. In 2004, the Utilities began placing qualified wind-powered generation in service and that has continued through 2011. Federal renewable electricity production tax credits are recognized as energy from wind-powered generating facilities is sold based on a per kilowatt rate as prescribed pursuant to the applicable federal income tax law and are eligible for the credit for 10 years from the date the qualifying generating facilities were placed in service. A credit of $0.022 per kilowatt hour was applied to 2011 production.
Income tax expense decreased $84 million for 2010 compared to 2009. The effective tax rates were 14% and 20% for 2010 and 2009, respectively. The decrease in the effective tax rate was primarily due to deferred income tax benefits totaling $25 million upon the enactment of the reduction in the United Kingdom corporate income tax rate from 28% to 27%, additional production tax credits totaling $20 million, a non-taxable gain on the sale of CE Gas (Australia) Limited and higher tax benefits received at MidAmerican Energy for changes related to the tax capitalization policy and repairs deductio nsdeductions totaling $21$6 million, additional production tax credits totaling $20 million and a non-taxable gain on the sale of CE Gas (Australia) Limited, partially offset by the impact of ratemaking. The benefits for changes to the tax capitalization policy and the repairs deductions were realized as MidAmerican Energy changed the method by which it determines current income tax deductions for overhead costs and repairs on certain of its regulated utility assets, which results in current deductibility for costs that are capitalized for book purposes. Iowa, MidAmerican Energy's largest jurisdiction for rate-regulated operations, requires immediate income recognition of such temporary differences.
Equity Income tax expense decreased $700
Equity income increased $10 million for 20092011 compared to 20 08. The effective tax rates were 20%2010 due to continued investment at ETT and 35% for 2009 and 2008, respectively. The decrease in income tax expense andhigher earnings at CE Generation due to improved results at the effective tax rate weregas plants, partially offset by lower earnings at HomeServices' mortgage joint venture due to lower pre-tax income, income tax benefits recognized in 2009 totaling $55 million for a change in tax accounting method for repairs deductionsrefinancing activity and the related regulatory treatment in Iowa, which requires immediate income recognition of such temporary differences, additional production tax credits, lower United States income taxes on foreign earnings and the effects of ratemaking.higher compliance costs.
Equity Income
Equity income decreased $12 million for 2010 compared to 2009 due to lower equity earnings at CE Generation, LLC, primarily due to the expiration of a favorable power purchase contract in the second quarter of 2009 at the Saranac project.
Equity income increased $14 million for 2009 compared to 2008 due primarily to higher equity earnings at HomeServices related to refinance acti vity in its mortgage business. Equity income increased $5 million for 2008 compared to 2007 due primarily to the sale and write-off of an investment in a mortgage joint venture at HomeServices in 2007.
Net Income Attributable to Noncontrolling Interests
Net income attributable to noncontrolling interests decreased $51 million for 2011 compared to 2010 and increased $41 million for 2010 compared to 2009 primarily due to the settlement of a noncontrolling interest dispute totaling $38 million.
Net income attributable to noncontrolling interests increased $10$54 million for 2009 compared to 2008 due mainly to higher earnings attributable to PacifiCorp's majority owned coal mining operations. Net income attributable to noncontrolling interests decreased $9 million for 2008 compared to 2007 due to additional expensepre-tax charge in 20072010 related to the minority ownership of theCE Casecnan project.noncontrolling interest settlement.
Liquidity and Capital Resources
Each of MEHC's direct and indirect subsidiaries is organized as a legal entity separate and apart from MEHC and its other subsidiaries. Pursuant to separate financing agreements, substantially all or most of the properties of each of MEHC's subsidiaries are pledged or encumbered to support or otherwise provide the security for the related subsidiary debt. It should not be assumed that the assets of any subsidiary will be available to satisfy MEHC's obligations or the obligations of its other subsidiaries. However, unrestricted cash or other assets that are available for distribution may, subject to applicable law, regulatory commitments and the terms of financing and ring-fencing arrangements for such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to MEHC or affiliates thereof. The long-term debt of subsidiaries may include provis ionsprovisions that allow MEHC's subsidiaries to redeem it in whole or in part at any time. These provisions generally include make-whole premiums. Refer to Note 17 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding the limitation of distributions from MEHC's subsidiaries.
As of December 31, 20102011, the Company's total net liquidity was $6.2143.741 billion. The components of total net liquidity are as follows (in millions ):millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | CE | | | | |
| | | | | | MidAmerican | | Electric | | | | |
| | MEHC | | PacifiCorp | | Funding | | UK(1) | | Other | | Total(2) |
| | | | | | | | | | | | |
| Cash and cash equivalents | $ | 18 | | | $ | 31 | &nbs p; | | $ | 203 | | | $ | 9 | | | $ | 209 | | | $ | 470 | |
| | | | | | | | | | | | | | |
| Credit facilities | $ | 585 | | | $ | 1,395 | | | $ | 654 | | | $ | 655 | | | $ | 50 | | | $ | 3,339 | |
| Less: | | | | | | | | | | | | |
| Short-term debt | (284 | ) | | (36 | ) | | — | | | — | | | — | | | (320 | ) |
| Tax-exempt bond support, letters of credit | | | | | | | | | | | |
| and EIB borrowings | (40 | ) | | (304 | ) | | ( 195 | ) | | (236 | ) | | — | | | (775 | ) |
| Net credit facilities | $ | 261 | | | $ | 1,055 | | | $ | 459 | | | $ | 419 | | | $ | 50 | | | $ | 2,244 | |
| | | | | | | | | | | | |
| Net liquidity before Berkshire | | | | | | | | | | | |
| Equity Commitment | $ | 279 | | | $ | 1,086 | | | $ | 662 | | | $ | 428 | | | $ | 259 | | | $ | 2,714 | |
Berkshire Equity Commitment(3) | 3,500 | | | | | | | | | | | | | | | 3,500 | |
| Total net liquidity | $ | 3,779 | | | | | | | | | | | | | | | $ | 6,214 | |
| Unsecured revolving credit facilities: | | | | | | | | | | | | | | | | | |
Maturity date(4) | 2013 | | | 2012, 2013 | | | 2011, 2013 | | | 2013 | | | 2013 | | | | |
| Largest single bank commitment as a | | | | | | | | | | | |
% of total revolving credit facilities(5) | 17 | % | | 15 | % | | 23 | % | | 33 | % | | 100 | % | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | Northern | | | | |
| | | | | | MidAmerican | | Powergrid | | | | |
| | MEHC | | PacifiCorp | | Funding | | Holdings | | Other | | Total |
| | | | | | | | | | | | |
| Cash and cash equivalents | $ | 13 |
| | $ | 47 |
| | $ | 1 |
| | $ | 21 |
| | $ | 204 |
| | $ | 286 |
|
| | |
| | | | | | | | | | |
|
| Credit facilities | 552 |
| | 1,355 |
| | 654 |
| | 233 |
| | 50 |
| | 2,844 |
|
| Less: | | | | | | | | | | | |
|
| Short-term debt | (108 | ) | | (688 | ) | | — |
| | (69 | ) | | — |
| | (865 | ) |
Tax-exempt bond support and letters of credit | (25 | ) | | (304 | ) | | (195 | ) | | — |
| | — |
| | (524 | ) |
| Net credit facilities | 419 |
| | 363 |
| | 459 |
| | 164 |
| | 50 |
| | 1,455 |
|
| | | | | | | | | | | | |
Net liquidity before Berkshire Equity Commitment | $ | 432 |
| | $ | 410 |
| | $ | 460 |
| | $ | 185 |
| | $ | 254 |
| | $ | 1,741 |
|
Berkshire Equity Commitment(1) | 2,000 |
| | |
| | |
| | |
| | |
| | 2,000 |
|
| Total net liquidity | $ | 2,432 |
| | |
| | |
| | |
| | |
| | $ | 3,741 |
|
| Unsecured revolving credit facilities: | |
| | |
| | |
| | |
| | |
| | |
|
| Maturity date | 2013 |
| | 2012, 2013 |
| | 2012, 2013 |
| | 2013 |
| | 2013 |
| | |
|
Largest single bank commitment as a % of total revolving credit facilities(2) | 18 | % | | 16 | % | | 23 | % | | 33 | % | | 100 | % | | |
|
| |
| (1) | In July 2010, Yorkshire closed on a £151 million finance contractMEHC has an Equity Commitment Agreement with the European Investment Bank ("EIB") and issued £151 million of 4.13% notes due July 20, 2022. The net proceeds are being used to fund capital expenditures. Also in July 2010, Northern closed on a £119 million finance contract with the EIB. In January and February 2011, Northern Electric issued £119 million of notes with maturity dates ranging from 2018 to 2020 at interest rates ranging from 3.901% to 4.586%. |
| |
(2) | The above table does not include unused revolving credit facilities and letters of credit for investments that are accounted for under the equity method. |
| |
(3) | In March 2006, MEHC and Berkshire Hathaway entered into the Berkshire(the "Berkshire Equity CommitmentCommitment") pursuant to which Berkshire Hathaway has agreed to purchase up to $3.5$2.0 billion of MEHC's common equity upon any requests authorized from time to time by MEHC's Board of Directors. The proceeds of any such equity contribution shall only be used for the purpose of (a) paying when due MEHC's debt obligations and (b) funding the general corporate purposes and capital requirements of MEHC's regulated subsidiaries. In March 2010, MEHC and Berkshire Hathaway amended theThe Berkshire Equity Commitment extending the term fromexpires on February 28, 2011 to February 28, 2014 and reducing the $3.5 billion to $2.0 billion effective March 1, 2011.2014. |
| |
(4) | For further discussion regarding the Company's credit facilities, refer to Note 9 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K. |
| |
(5) (2) | An inability of financial institutions to honor their commitments could adversely affect the Company's short-term liquidity and ability to meet long-term commitmen ts.commitments. |
The above table does not include unused revolving credit facilities and letters of credit for investments that are accounted for under the equity method.
In September 2010, the President signed the Small Business Jobs ActJanuary 2012, MEHC entered into law, extending retroactivelya $500 million revolving loan agreement with a subsidiary of Berkshire Hathaway that expires June 30, 2012. Refer to January 1, 2010 the 50% bonus depreciationNote 9 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for qualifying property purchased and placed in-service in 2010. In December 2010, the President signed the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 into law, which provided for 100% bonus depreciation for qualifying property purchased and placed in-service after September 8, 2010. As a result of the new laws,further discussion regarding the Company's December 31, 2010 tax provision reflected bonus depreciation on qualifying assets placed in-service during 2010. Accordingly,credit facilities.
In January 2012, subsidiaries of MEHC acquired ownership interests in two solar projects. Refer to Note 23 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding the Company's receivable for income taxes increased to $396 million asequity commitments, letters of December 31, 2010.credit and other related items.
Operating Activities
Net cash flows from operating activities for the years ended December 31, 2011 and 2010 were $3.220 billion and $2.759 billion, respectively. The increase was primarily due to higher income tax receipts of $270 million mainly attributable to bonus depreciation, improved operating results, changes in collateral posted for derivative contracts and a Kern River customer rate refund in 2010, partially offset by changes in working capital.
Net cash flows from operating activities for the years ended December 31, 2010and 2009 were $2.759 billion and $3.572 billion, respectively. The decrease was mainly due to lower income tax receipts of $391 million due to the timing of repairs deductions and bonus depreciation, changes in collateral posted for derivative contracts, $128 million of net cash flows in 2009 related to the Constellation Energy transaction, which is comprised of $536 million of proceeds received from the sale of Constellation Energy common stock and $408 million of income taxes paid on gains recognized on the termination of the Constellation Energy merger agreement in December 2008 and the sale of stock in 2009, higher contributions to pension and other postretirement benefit plans and rate case refunds paid in 2010 at Kern River.
NetIn September 2010, the President signed the Small Business Jobs Act into law, extending retroactively to January 1, 2010 the 50% bonus depreciation for qualifying property purchased and placed in service in 2010. In December 2010, the President signed the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 into law, which provided for 100% bonus depreciation for qualifying property purchased and placed in service after September 8, 2010 and prior to January 1, 2012, and extended 50% bonus depreciation for qualifying property purchased and placed in service after December 31, 2010 and prior to January 1, 2013. As a result of the new laws, the Company's cash flows from operating activit ies for 2009operations benefited in 2011 and 2008 were $3.572 billion and $2.587 billion, respectively. Operating cash flows for 2009 include $128 million of net cash flows relatedare expected to the Constellation Energy transaction, which is comprised of $536 million of proceeds received from the sale of Constellation Energy common stock and $408 million of income tax paid on gains recognized on the termination of the Constellation Energy merger agreementbenefit in December 2008 and the sale of stock in 2009. Operating cash flows for 2008 include a termination fee of $175 million received from Constellation Energy. The remaining increase in operating cash flows was2012 due to higher income tax receipts, changesbonus depreciation on qualifying assets placed in collateral posted for derivative contracts of $201 million, lower customer refunds related to the Kern River rate case in 2008 of $179 million and working capital, partially offset by the impact from the foreign currency exchange rate. Income tax receipts were higher due primarily to lower pre-tax income, the increased tax deductions on capital projects and additional production tax credits.service.
Investing Activities
Net cash flows from investing activities for the years ended December 31, 2011 and 2010 were $(2.816) billion and $(2.484) billion, respectively. The change was primarily due to higher capital expenditures of $91 million, proceeds received from the sale of certain Australian hydrocarbon exploration and development assets during the second quarter of 2010 totaling $78 million and 2 009net proceeds received from the sale of CE Gas (Australia) Limited during the third quarter of 2010 totaling $59 million and higher investments in companies accounted for under the equity method totaling $58 million.
Net cash flows from investing activities for the years ended December 31, 2010 and 2009 were $(2.484) billion and $(2.669) billion, respectively. Capital expenditures decreased $820 million. In January 2009, the Company received $1 billion, plus accrued interest, in full satisfaction of the 14% Senior Notes from Constellation Energy. In July 2009, the Company purchased 225 million shares, representing approximately a 10% interest, of BYD Company Limited common stock for $232 million. Additionally, the Company received proceeds from the salesales of certain Australian hydrocarbon exploration and developmentCE Gas assets in 2010 totaling $78 million and net proceeds from the sale of CE Gas (Australia) Limited in 2010 totaling $59$137 million, partially offset by higher investments in companies accounted for under the equity method.method totaling $32 million.
Net cash flows from investing activities for the years ended December 31, 2009 and 2008 were $(2.669) billion and $(4.344) billion, respectively. In February 2008, the Company received proceeds from the maturity of a guaranteed investment contract of $393 million. In September 2008, the Company made a $1.0 billion investment in Constellation Energy's 8% preferred stock and acquired Chehalis Power Generation, LLC for $308 million. In December 2008, MEHC and Constellation Energy entered into a termination agreement, which resulted in, among other things, the conversion of the $1.0 billion investment in Constellation Energy's 8% preferred stock into $1.0 billion of 14% Senior Notes due from Constellation Energy, 19.9 million shares of Constellation Energy common stock and cash totaling $418 million. In January 2009, the Company received $1.0 billion, plus accrued interest, in full satisfaction of the 14%&n bsp;Senior Notes from Constellation Energy. In July 2009, the Company purchased 225 million shares, representing approximately a 10% interest, of BYD common stock for $232 million. Capital expenditures decreased $524 million due primarily to lower capital expenditures in 2009 associated with the construction of wind-powered generating facilities at MidAmerican Funding, partially offset by higher capital expenditures at PacifiCorp associated with wind-powered generating facilities, including payments for wind-powered facilities placed in-service in December 2008, and transmission system investment.
Capital Expenditures
Capital expenditures, which exclude amounts for non-cash equity AFUDC and other non-cash items, by reportable segment for the years ended December 31 are summarized as follows (in millions):
| | | 2010 | | 2009 | | 2008 | | | | | | | |
Capital expenditures(1): | | | | | | |
| | | 2011 | | 2010 | | 2009 |
| Capital expenditures: | | | | | | |
| PacifiCorp | $ | 1,607 | | | $ | 2,328 | | | $ | 1,789 | | $ | 1,506 |
| | $ | 1,607 |
| | $ | 2,328 |
|
| MidAmerican Funding | 338 | | | 439 | | | 1,473 | | 566 |
| | 338 |
| | 439 |
|
| Northern Natural Gas | 136 | | | 177 | | | 196 | | |
| Kern River | 157 | | | 73 | | | 24 | | |
| CE Electric UK | 349 | | | 387 | | | 440 | | |
| MidAmerican Energy Pipeline Group | | 289 |
| | 293 |
| | 250 |
|
| Northern Powergrid Holdings | | 309 |
| | 349 |
| | 387 |
|
| Other | 6 | | | 9 | | | 15 | | 14 |
| | 6 |
| | 9 |
|
| Total capital expenditures | $ | 2,593 | | | $ | 3,413 | | | $ | 3,937 | | $ | 2,684 |
| | $ | 2,593 |
| | $ | 3,413 |
|