KINDER MORGAN, INC.
Item 1A. Risk Factors.
You should carefully consider the risks described below, in addition to the other information contained in this document. Realization of any of the following risks could have a material adverse effect on our business, financial condition, cash flows and results of operations.
Risks Related to Our Business
We are dependent on cash distributions received from KMP and EPB.
For 2013, distributions from KMP and EPB represented approximately 87% of the sum of total cash generated by (i) distributions payable to us by our MLPs (on a declared basis) and (ii) distributable cash generated by assets we own and our share of cash generated by our joint venture investments. A decline in KMP’s and/or EPB’s revenues or increases in its general and administrative expenses, principal and interest payments under existing and future debt instruments, expenditures for taxes, working capital requirements or other cash needs will limit the amount of cash KMP and EPB can distribute to us, which would reduce the amount of cash available for dividends to our stockholders, which could be material.
New regulations, rulemaking and oversight, as well as changes in regulations, by regulatory agencies having jurisdiction over our operations could adversely impact our income and operations.
Our assets and operations are subject to regulation and oversight by federal, state and local regulatory authorities. Regulatory actions taken by these agencies have the potential to adversely affect our profitability. Regulation affects almost every part of our business and extends to such matters as (i) rates (which include reservation, commodity, surcharges, fuel and gas lost and unaccounted for), operating terms and conditions of service; (ii) the types of services we may offer to our customers; (iii) the contracts for service entered into with our customers; (iv) the certification and construction of new facilities; (v) the integrity, safety and security of facilities and operations; (vi) the acquisition of other businesses; (vii) the acquisition, extension, disposition or abandonment of services or facilities; (viii) reporting and information posting requirements; (ix) the maintenance of accounts and records; and (x) relationships with affiliated companies involved in various aspects of the natural gas and energy businesses.
Should we fail to comply with any applicable statutes, rules, regulations, and orders of such regulatory authorities, we could be subject to substantial penalties and fines. Furthermore, new laws or regulations sometimes arise from unexpected sources. For example, the Department of Homeland Security Appropriation Act of 2007 required the issuance of regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” New laws or regulations, or different interpretations of existing laws or regulations, including unexpected policy changes, applicable to us or our assets could have a material adverse impact on our business, financial condition and results of operations. For more information, see Items 1 and 2 “Business and Properties-(c) Narrative Description of Business-Regulation.”
The FERC, the CPUC or the NEB may establish pipeline tariff rates that have a negative impact on us. In addition, the FERC, the CPUC, the NEB or our customers could file complaints challenging the tariff rates charged by our pipelines, and a successful complaint could have an adverse impact on us.
The profitability of our regulated pipelines is influenced by fluctuations in costs and our ability to recover any increases in our costs in the rates charged to our shippers. To the extent that our costs increase in an amount greater than what we are permitted by the FERC, the CPUC or the NEB allows us to recover in our rates, or to the extent that there is a lag before we can file and obtain rate increases, such events can have a negative impact upon our operating results can be negatively impacted.
Our existing rates may also be challenged by complaint. Regulators and shippers on our pipelines have rights to challenge, and have challenged, the rates we charge under certain circumstances prescribed by applicable regulations. Some shippers on our pipelines have filed complaints with the regulators that seek substantial refunds for alleged overcharges during the years in question and prospective reductions in the tariff rates. Further, the FERC may initiate investigations to determine whether some interstate natural gas pipelines have over-collected on rates charged to shippers. We may face challenges, similar to those described in Note 16 “Litigation, Environmental and Other” to our consolidated financial statements, to the rates we charge on KMP’s, EPB’s and our other pipelines. Any successful challenge could materially adversely affect our future earnings, cash flows and financial condition.
Energy commodity transportation and storage activities involve numerous risks that may result in accidents or otherwise adversely affect our operations.
There are a variety of hazards and operating risks inherent to natural gas transmission and storage activities and refined petroleum products and CO2 transportation activities-such as leaks, explosions and mechanical problems-that could result in substantial financial losses. In addition, these risks could result in serious injury and loss of human life, significant damage to property and natural resources, environmental pollution and impairment of operations, any of which also could result in substantial financial losses. For pipeline and storage assets located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damage resulting from these risks may be greater. Incidents that cause an interruption of service, such as when unrelated third party construction damages a pipeline or a newly completed expansion experiences a weld failure, may negatively impact our revenues and earnings while the affected asset is temporarily out of service. In addition, losses in excess of our insurance coverage could have a material adverse effect on our business, financial condition and results of operations.
Increased regulatory requirements relating to the integrity of our pipelines may require us to incur significant capital and operating expense outlays to comply.
Primarily, through our regulated pipeline subsidiaries, we are subject to extensive laws and regulations related to pipeline integrity. There are, for example, federal guidelines for the U.S. DOT and pipeline companies in the areas of testing, education, training and communication. The ultimate costs of compliance with the integrity management rules are difficult to predict. The majority of the compliance costs are pipeline integrity testing and the repairs found to be necessary. Changes such as advances of in-line inspection tools, identification of additional threats to a pipeline’s integrity and changes to the amount of pipeline determined to be located in High Consequence Areas can have a significant impact on integrity testing and repair costs. We plan to continue our pipeline integrity testing programs to assess and maintain the integrity of our existing and future pipelines as required by the U.S. DOT rules. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.
Further, additional laws and regulations that may be enacted in the future or a new interpretation of existing laws and regulations could significantly increase the amount of these expenditures. There can be no assurance as to the amount or timing of future expenditures for pipeline integrity regulation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not deemed by regulators to be fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and prospects.
The Jones Act includes restrictions on ownership by non-U.S. citizens of our vessels, and failure to comply with the Jones Act, or changes to or repeal of the Jones Act, could limit our ability to operate our vessels in the U.S. coastwise trade or result in the forfeiture of our vessels otherwise adversely impact our income and operations.
Following our January 2014 acquisition of American Petroleum Tankers and State Class Tankers, we are subject to the Jones Act, which generally restricts U.S. point-to-point maritime shipping to vessels operating under the U.S. flag, built in the U.S., owned and operated by U.S.-organized companies that are controlled and at least 75% owned by U.S. citizens and manned by predominately U.S. crews. Our business would be adversely affected if we fail to comply with the Jones Act provisions on coastwise trade. If we do not comply with any of these requirements, we would be prohibited from operating our vessels in the U.S. coastwise trade and, under certain circumstances, we could be deemed to have undertaken an unapproved transfer to non-U.S. citizens that could result in severe penalties, including permanent loss of U.S. coastwise trading rights for our vessels, fines or forfeiture of vessels. Our business could by adversely affected if the Jones Act were to be modified or repealed so as to permit foreign competition that is not subject to the same U.S. government imposed burdens.
Environmental, health and safety laws and regulations could expose us to significant costs and liabilities.
Our operations are subject to federal, state, provincial and local laws, regulations and potential liabilities arising under or relating to the protection or preservation of the environment, natural resources and human health and safety. Such laws and regulations affect many aspects of our present and future operations, and generally require us to obtain and comply with various environmental registrations, licenses, permits, inspections and other approvals. Liability under such laws and regulations may be incurred without regard to fault under CERCLA, the Resource Conservation and Recovery Act, the Federal Clean Water Act or analogous state laws for the remediation of contaminated areas. Private parties, including the owners of properties through which our pipelines pass, also may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with such laws and regulations or for personal injury or property damage. Our insurance may not cover all environmental risks and costs and/or may not provide sufficient coverage in the event an environmental claim is made against us.
Failure to comply with these laws and regulations also may expose us to civil, criminal and administrative fines, penalties and/or interruptions in our operations that could influence our business, financial position, results of operations and prospects. For example, if an accidental leak, release or spill of liquid petroleum products, chemicals or other hazardous substances occurs at or from our pipelines or our storage or other facilities, we may experience significant operational disruptions and we may have to pay a significant amount to clean up or otherwise respond to the leak, release or spill, pay for government penalties, address natural resource damage, compensate for human exposure or property damage, install costly pollution control equipment or undertake a combination of these and other measures. The resulting costs and liabilities could materially and negatively affect our level of earnings and cash flows. In addition, emission controls required under the Federal Clean Air Act and other similar federal, state and provincial laws could require significant capital expenditures at our facilities.
We own and/or operate numerous properties that have been used for many years in connection with our business activities. While we have utilized operating, handling, and disposal practices that were consistent with industry practices at the time, hydrocarbons or other hazardous substances may have been released at or from properties owned, operated or used by us or our predecessors, or at or from properties where our or our predecessors’ wastes have been taken for disposal. In addition, many of these properties have been owned and/or operated by third parties whose management, handling and disposal of hydrocarbons or other hazardous substances were not under our control. These properties and the hazardous substances released and wastes disposed on them may be subject to laws in the U.S. such as CERCLA, which impose joint and several liability without regard to fault or the legality of the original conduct. Under the regulatory schemes of the various Canadian provinces, such as British Columbia’s Environmental Management Act, Canada has similar laws with respect to properties owned, operated or used by us or our predecessors. Under such laws and implementing regulations, we could be required to remove or remediate previously disposed wastes or property contamination, including contamination caused by prior owners or operators. Imposition of such liability schemes could have a material adverse impact on our operations and financial position.
In addition, our oil and gas development and production activities are subject to numerous federal, state and local laws and
regulations relating to environmental quality and pollution control. Due to the rise of oil and gas production in new areas of the
country and increased public scrutiny of fracturing and other practices in oil and gas drilling, many states are promulgating
stricter requirements not only for wells but also compressor stations and other facilities in the oil and gas industry sector. These
laws and regulations increase the costs of these activities and may prevent or delay the commencement or continuance of a
given operation. Specifically, these activities are subject to laws and regulations regarding the acquisition of permits before
drilling, restrictions on drilling activities and location, emissions into the environment, water discharges, transportation of
hazardous materials, and storage and disposition of wastes. In addition, legislation has been enacted that requires well and
facility sites to be abandoned and reclaimed to the satisfaction of state authorities.
Further, we cannot ensure that such existing laws and regulations will not be revised or that new laws or regulations will not be adopted or become applicable to us. There can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and prospects. For more information, see Items 1 and 2 “Business and Properties-(c) Narrative Description of Business-Environmental Matters-Climate Change.”
Climate change regulation at the federal, state, provincial or regional levels could result in significantly increased operating and capital costs for us.
Methane, a primary component of natural gas, and CO2, which is naturally occurring and also a byproduct of the burning of natural gas, are examples of greenhouse gases. The EPA regulates the greenhouse gas emissions and requires the reporting of greenhouse gas emissions in the U.S. for emissions from specified large greenhouse gas emission sources, fractionated NGL, and the production of naturally occurring CO2, like our McElmo Dome CO2 field, even when such production is not emitted to the atmosphere.
Because our operations, including our compressor stations and natural gas processing plants in our Natural Gas Pipelines segment, emit various types of greenhouse gases, primarily methane and CO2, such regulation could increase our costs related to operating and maintaining our facilities and could require us to install new emission controls on our facilities, acquire allowances for our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program and such increased costs could be significant. Recovery of such increased costs from our customers is uncertain in all cases and may depend on events beyond our control, including the outcome of future rate proceedings before the FERC. Any of the foregoing could have adverse effects on our business, financial position, results of operations or cash flows. For more information about climate change regulation, see Items 1 and 2 “Business and Properties-(c) Narrative Description of Business-Environmental Matters-Climate Change.
Increased regulation of exploration and production activities, including hydraulic fracturing, could result in reductions or delays in drilling and completing new oil and natural gas wells, which could adversely impact KMP’s and EPB’s revenues by decreasing the volumes of natural gas transported on their natural gas pipelines.
The natural gas industry is increasingly relying on natural gas supplies from unconventional sources, such as shale, tight sands and coal bed methane. The extraction of natural gas from these sources frequently requires hydraulic fracturing. Hydraulic fracturing involves the pressurized injection of water, sand, and chemicals into the geologic formation to stimulate gas production and is a commonly used stimulation process employed by oil and gas exploration and production operators in the completion of certain oil and gas wells. There have been initiatives at the federal and state levels to regulate or otherwise
restrict the use of hydraulic fracturing. Adoption of legislation or regulations placing restrictions on hydraulic fracturing activities could impose operational delays, increased operating costs and additional regulatory burdens on exploration and production operators, which could reduce their production of natural gas and, in turn, adversely affect our revenues and results of operations by decreasing the volumes of natural gas transported on our or our joint ventures’ natural gas pipelines, several of which gather gas from areas in which the use of hydraulic fracturing is prevalent.
We may face competition from other pipelines and other forms of transportation into the areas we serve as well as with respect to the supply for our pipeline systems.
Any current or future pipeline system or other form of transportation that delivers crude oil, petroleum products or natural gas into the areas that our pipelines serve could offer transportation services that are more desirable to shippers than those we provide because of price, location, facilities or other factors. To the extent that an excess of supply into these areas is created and persists, our ability to re-contract for expiring transportation capacity at favorable rates or otherwise to retain existing customers could be impaired. We also could experience competition for the supply of petroleum products or natural gas from both existing and proposed pipeline systems. Several pipelines access many of the same areas of supply as our pipeline systems and transport to destinations not served by us.
Cost overruns and delays on our expansion and new build projects could adversely affect our business.
KMP, EPB and our other pipelines regularly undertake major construction projects to expand their existing assets and to construct new assets. A variety of factors outside of their control, such as weather, natural disasters and difficulties in obtaining permits and rights-of-way or other regulatory approvals, as well as performance by third-party contractors, has resulted in, and may continue to result in, increased costs or delays in construction. Significant cost overruns or delays in completing a project could have a material adverse effect on our return on investment, results of operations and cash flows.
We must either obtain the right from landowners or exercise the power of eminent domain in order to use most of the land on which our pipelines are constructed, and we are subject to the possibility of increased costs to retain necessary land use.
We obtain the right to construct and operate pipelines on other owners’ land for a period of time. If we were to lose these rights or be required to relocate our pipelines, our business could be negatively affected. In addition, we are subject to the possibility of increased costs under our rental agreements with landowners, primarily through rental increases and renewals of expired agreements.
Whether KMP, EPB or our other pipelines have the power of eminent domain for their pipelines, other than interstate natural gas pipelines, varies from state to state depending upon the type of pipeline-petroleum liquids, natural gas, CO2 or crude oil-and the laws of the particular state. Our interstate natural gas pipelines have federal eminent domain authority. In either case, we must compensate landowners for the use of their property and, in eminent domain actions, such compensation may be determined by a court. Our inability to exercise the power of eminent domain could negatively affect our subsidiaries’ business if they were to lose the right to use or occupy the property on which pipelines are located.
KMP’s and EPB’s acquisition strategies and expansion programs require access to new capital. Limitations on their access to capital would impair our ability to grow.
Consistent with the terms of KMP’s and EPB’s partnership agreements, KMP and EPB distribute most of the cash generated by their operations. As a result, they have relied on external financing sources, including commercial borrowings and issuances of debt and equity securities, to fund acquisition and growth capital expenditures. However, to the extent our limited partnerships are unable to continue to finance growth externally; their cash distribution policy will significantly impair their ability to grow. KMP and/or EPB may need new capital to finance these activities. Limitations on access to capital, whether due to tightened capital markets, more expensive capital or otherwise, will impair their ability to execute this strategy.
KMP’s and EPB’s growth strategies may cause difficulties integrating and constructing new operations and they may not be able to achieve the expected benefits from any future acquisitions.
Part of KMP’s and EPB’s business strategy includes acquiring additional businesses, expanding existing assets and constructing new facilities. If they do not successfully integrate acquisitions, expansions or newly constructed facilities, anticipated operating advantages and cost savings may not occur. The integration of companies that have previously operated separately involves a number of risks, including (i) demands on management related to the increase in its size after an acquisition, expansion or completed construction project; (ii) the diversion of management’s attention from the management of
daily operations; (iii) difficulties in implementing or unanticipated costs of accounting, estimating, reporting and other systems; (iv) difficulties in the assimilation and retention of necessary employees; and (v) potential adverse effects on operating results.
Our limited partnerships may not be able to maintain the levels of operating efficiency that acquired companies have achieved or might achieve separately. Successful integration of each acquisition, expansion or construction project will depend upon their ability to manage those operations and to eliminate redundant and excess costs. Because of difficulties in combining and expanding operations, cost savings and other size-related benefits they expected may not be achieved, which could harm their financial condition and results of operations.
Our substantial debt could adversely affect our financial health and make us more vulnerable to adverse economic conditions.
As of December 31, 2013, we had approximately $34 billion of consolidated debt (including KMP and EPB, but excluding debt fair value adjustments). This level of debt could have important consequences, such as (i) limiting our ability to obtain additional financing to fund our working capital, capital expenditures, debt service requirements or potential growth or for other purposes; (ii) limiting our ability to use operating cash flow in other areas of our business or to pay dividends because we must dedicate a substantial portion of these funds to make payments on our debt; (iii) placing us at a competitive disadvantage compared to competitors with less debt; and (iv) increasing our vulnerability to adverse economic and industry conditions.
Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, many of which are beyond our control. If our operating results are not sufficient to service our indebtedness, or any future indebtedness that we incur, we will be forced to take actions which may include reducing dividends, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to affect any of these actions on satisfactory terms or at all. For more information about our debt, see Note 8 “Debt” to our consolidated financial statements.
Our large amount of variable rate debt makes us vulnerable to increases in interest rates.
As of December 31, 2013, approximately $8 billion (25%) of our approximately $34 billion consolidated debt (including KMP and EPB, but excluding debt fair value adjustments) was subject to variable interest rates, either as short-term or long-term debt of variable rate debt obligations, or as long-term fixed-rate debt effectively converted to variable rates through the use of interest rate swaps. Should interest rates increase, the amount of cash required to service this debt would increase and our earnings could be adversely affected. For more information about our interest rate risk, see Item 7A “Quantitative and Qualitative Disclosures About Market Risk-Interest Rate Risk.”
Our debt instruments may limit our financial flexibility and increase our financing costs.
The instruments governing our debt contain restrictive covenants that may prevent us from engaging in certain transactions that we deem beneficial and that may be beneficial to us. The agreements governing our debt generally require us to comply with various affirmative and negative covenants, including the maintenance of certain financial ratios and restrictions on (i) incurring additional debt; (ii) entering into mergers, consolidations and sales of assets; (iii) granting liens; and (iv) entering into sale-leaseback transactions. The instruments governing any future debt may contain similar or more restrictive restrictions. Our ability to respond to changes in business and economic conditions and to obtain additional financing, if needed, may be restricted.
There is the potential for a change of control of the general partners of KMP and EPB if we default on debt.
We own all of the common equity of the general partners of KMP and EPB. If we default on debt, then the lenders under such debt, in exercising their rights as lenders, could acquire control of the general partners of KMP and EPB through their control of us. A change of control of the general partners of KMP and EPB could materially adversely affect the distributions we receive from KMP and EPB, which could have a material adverse impact on us or our cash available for dividends to our stockholders.
Our business, financial condition and operating results may be affected adversely by increased costs of capital or a reduction in the availability of credit.
Adverse changes to the availability, terms and cost of capital, interest rates or our credit ratings could cause our cost of doing business to increase by limiting our access to capital, limiting our ability to pursue acquisition opportunities and reducing
our cash flows. Our credit ratings may be impacted by our leverage, liquidity, credit profile and potential transactions. Also, disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations on favorable terms. A significant reduction in the availability of credit could materially and adversely affect business, financial condition and results of operations.
In addition, any reduction in our credit ratings could negatively impact the credit ratings of our subsidiaries, which could increase their cost of capital and negatively affect their business and operating results. Although the ratings from credit agencies are not recommendations to buy, sell or hold our securities, our credit ratings will generally affect the market value of our and our subsidiaries’ debt instruments, as well as the market value of KMP’s and EPB’s common units.
Current or future distressed financial conditions of our customers could have an adverse impact on us in the event these customers are unable to pay us for the products or services we provide.
Some of our customers are experiencing, or may experience in the future severe financial problems that have had or may have a significant impact on their creditworthiness. We cannot provide assurance that one or more of our financially distressed customers will not default on their obligations to us or that such a default or defaults will not have a material adverse effect on our business, financial position, future results of operations or future cash flows. Furthermore, the bankruptcy of one or more of our customers, or some other similar proceeding or liquidity constraint, might make it unlikely that we would be able to collect all or a significant portion of amounts owed by the distressed entity or entities. In addition, such events might force such customers to reduce or curtail their future use of our products and services, which could have a material adverse effect on our results of operations, financial condition and cash flows.
Terrorist attacks or “cyber security” events, or the threat of them, may adversely affect our business.
The U.S. government has issued public warnings that indicate that pipelines and other assets might be specific targets of terrorist organizations or “cyber security” events. These potential targets might include our pipeline systems or operating systems and may affect our ability to operate or control our pipeline assets, our operations could be disrupted and/or customer information could be stolen. The occurrence of one of these events could cause a substantial decrease in revenues, increased costs to respond or other financial loss, damage to reputation, increased regulation or litigation and or inaccurate information reported from our operations.
There is no assurance that adequate sabotage and terrorism insurance will be available at rates we believe are reasonable in the near future. These developments may subject our operations to increased risks, as well as increased costs, and, depending on their ultimate magnitude, could have a material adverse effect on our business, results of operations and financial condition.
Our pipelines business is dependent on the supply of and demand for the commodities transported by our pipelines.
Our pipelines depend on production of natural gas, oil and other products in the areas served by our pipelines. Without reserve additions, production will decline over time as reserves are depleted and production costs may rise. Producers may shut down production at lower product prices or higher production costs, especially where the existing cost of production exceeds other extraction methodologies, such as in the Alberta Oil sands. Producers in areas served by us may not be successful in exploring for and developing additional reserves, and our gas plants and pipelines may not be able to maintain existing volumes of throughput. Commodity prices and tax incentives may not remain at levels that encourages producers to explore for and develop additional reserves, produce existing marginal reserves or renew transportation contracts as they expire.
Changes in the business environment, such as a decline in crude oil or natural gas prices, an increase in production costs from higher feedstock prices, supply disruptions, or higher development costs, could result in a slowing of supply from oil and natural gas producing areas. In addition, changes in the regulatory environment or governmental policies may have an impact on the supply of crude oil and natural gas. Each of these factors impact our customers shipping through our pipelines, which in turn could impact the prospects of new transportation contracts or renewals of existing contracts.
Throughput on KMP’s and/or EPB’s pipelines also may decline as a result of changes in business conditions. Over the long term, business will depend, in part, on the level of demand for oil, natural gas and refined petroleum products in the geographic areas in which deliveries are made by pipelines and the ability and willingness of shippers having access or rights to utilize the pipelines to supply such demand.
The implementation of new regulations or the modification of existing regulations affecting the oil and gas industry could reduce demand for natural gas, crude oil and refined petroleum products, increase our costs and have a material adverse effect on our results of operations and financial condition. We cannot predict the impact of future economic conditions, fuel
conservation measures, alternative fuel requirements, governmental regulation or technological advances in fuel economy and energy generation devices, all of which could reduce the demand for natural gas, crude oil and refined petroleum products.
The future success of KMP’s oil and gas development and production operations depends in part upon its ability to develop additional oil and gas reserves that are economically recoverable.
The rate of production from oil and natural gas properties declines as reserves are depleted. Without successful development activities, the reserves and revenues of the oil and gas producing assets within the CO2-KMP business segment will decline. KMP may not be able to develop or acquire additional reserves at an acceptable cost or have necessary financing for these activities in the future. Additionally, if KMP does not realize production volumes greater than, or equal to, its hedged volumes, it may suffer financial losses not offset by physical transactions.
KMP’s development of oil and gas properties involves risks that may result in a total loss of investment.
The business of developing and operating oil and gas properties involves a high degree of business and financial risk that even a combination of experience, knowledge and careful evaluation may not be able to overcome. Acquisition and development decisions generally are based on subjective judgments and assumptions that, while they may be reasonable, are by their nature speculative. It is impossible to predict with certainty the production potential of a particular property or well. Furthermore, the successful completion of a well does not ensure a profitable return on the investment. A variety of geological, operational and market-related factors, including, but not limited to, unusual or unexpected geological formations, pressures, equipment failures or accidents, fires, explosions, blowouts, cratering, pollution and other environmental risks, shortages or delays in the availability of drilling rigs and the delivery of equipment, loss of circulation of drilling fluids or other conditions, may substantially delay or prevent completion of any well or otherwise prevent a property or well from being profitable. A productive well may become uneconomic in the event water or other deleterious substances are encountered, which impair or prevent the production of oil and/or gas from the well. In addition, production from any well may be unmarketable if it is contaminated with water or other deleterious substances.
The volatility of natural gas and oil prices could have a material adverse effect on the CO2 -KMP business segment.
The revenues, profitability and future growth of the CO2-KMP business segment and the carrying value of its oil, NGL and natural gas properties depend to a large degree on prevailing oil and gas prices. For 2014, KMP estimates that every $1 change in the average WTI crude oil price per barrel would impact the CO2-KMP segment’s cash flows by approximately $7 million. Prices for oil, NGL and natural gas are subject to large fluctuations in response to relatively minor changes in the supply and demand for oil, NGL and natural gas, uncertainties within the market and a variety of other factors beyond KMP’s control. These factors include, among other things (i) weather conditions and events such as hurricanes in the U.S.; (ii) the condition of the U.S. economy; (iii) the activities of the Organization of Petroleum Exporting Countries; (iv) governmental regulation; (v) political stability in the Middle East and elsewhere; (vi) the foreign supply of and demand for oil and natural gas; (vii) the price of foreign imports; and (viii) the availability of alternative fuel sources.
A sharp decline in the prices of oil, NGL or natural gas would result in a commensurate reduction in KMP’s revenues, income and cash flows from the production of oil, NGL, and natural gas and could have a material adverse effect on the carrying value of KMP’s proved reserves. In the event prices fall substantially, KMP may not be able to realize a profit from its production and would operate at a loss. In recent decades, there have been periods of both worldwide overproduction and underproduction of hydrocarbons and periods of both increased and relaxed energy conservation efforts. Such conditions have resulted in periods of excess supply of, and reduced demand for, crude oil on a worldwide basis and for natural gas on a domestic basis. These periods have been followed by periods of short supply of, and increased demand for, crude oil and natural gas. The excess or short supply of crude oil or natural gas has placed pressures on prices and has resulted in dramatic price fluctuations even during relatively short periods of seasonal market demand. These fluctuations impact the accuracy of assumptions used in our budgeting process. For more information about our energy and commodity market risk, see Item 7A “Quantitative and Qualitative Disclosures About Market Risk-Energy Commodity Market Risk.”
Our use of hedging arrangements could result in financial losses or reduce our income.
We engage in hedging arrangements to reduce our exposure to fluctuations in the prices of oil and natural gas. These hedging arrangements expose us to risk of financial loss in some circumstances, including when production is less than expected, when the counterparty to the hedging contract defaults on its contract obligations, or when there is a change in the expected differential between the underlying price in the hedging agreement and the actual price received. In addition, these hedging arrangements may limit the benefit we would otherwise receive from increases in prices for oil and natural gas.
The accounting standards regarding hedge accounting are very complex, and even when we engage in hedging transactions (for example, to mitigate our exposure to fluctuations in commodity prices or currency exchange rates or to balance our exposure to fixed and variable interest rates) that are effective economically, these transactions may not be considered effective for accounting purposes. Accordingly, our consolidated financial statements may reflect some volatility due to these hedges, even when there is no underlying economic impact at the dates of those statements. In addition, it is not always possible for us to engage in hedging transactions that completely mitigate our exposure to commodity prices. Our consolidated financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge.
The adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to hedge risks associated with our business.
The Dodd-Frank Act requires the Commodities Futures Trading Commission, referred to as the CFTC, and the SEC to promulgate rules and regulations establishing federal oversight and regulation of the OTC derivatives market and entities that participate in that market. The CFTC has proposed new rules pursuant to the Dodd-Frank Act that would institute broad new aggregate position limits for OTC swaps and futures and options traded on regulated exchanges. As the law favors exchange trading and clearing, the Dodd-Frank Act also may require us to move certain derivatives transactions to exchanges where no trade credit is provided and also comply with margin requirements in connection with our derivatives activities that are not exchange traded, although the application of those provisions to us is uncertain at this time. The Dodd-Frank Act also requires many counterparties to our derivatives instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty, or cause the entity to comply with the capital requirements, which could result in increased costs to counterparties such as us. The Dodd-Frank Act and any related regulations could (i) significantly increase the cost of derivative contracts (including those requirements to post collateral, which could adversely affect our available liquidity); (ii) reduce the availability of derivatives to protect against risks we encounter; and (iii) reduce the liquidity of energy related derivatives.
If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Increased volatility may make us less attractive to certain types of investors. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our financial condition and results of operations.
The Kinder Morgan Canada-KMP segment is subject to U.S. dollar/Canadian dollar exchange rate fluctuations.
We are a U.S. dollar reporting company. As a result of the operations of the Kinder Morgan Canada-KMP business segment, a portion of our consolidated assets, liabilities, revenues and expenses are denominated in Canadian dollars. Fluctuations in the exchange rate between U.S. and Canadian dollars could expose us to reductions in the U.S. dollar value of our earnings and cash flows and a reduction in our stockholders’ equity under applicable accounting rules.
Our operating results may be adversely affected by unfavorable economic and market conditions.
Economic conditions worldwide have from time to time contributed to slowdowns in several industries, including the oil and gas industry, the steel industry and in specific segments and markets in which we operate, resulting in reduced demand and increased price competition for our products and services. Our operating results in one or more geographic regions also may be affected by uncertain or changing economic conditions within that region, such as the challenges that are currently affecting economic conditions in the U.S. and Canada. Volatility in commodity prices might have an impact on many of our customers, which in turn could have a negative impact on their ability to meet their obligations to us. In addition, decreases in the prices of crude oil and NGL will have a negative impact on the results of the CO2-KMP business segment. If global economic and market conditions (including volatility in commodity markets), or economic conditions in the U.S. or other key markets, remain uncertain or persist, spread or deteriorate further, we may experience material impacts on our business, financial condition and results of operations.
Hurricanes, earthquakes and other natural disasters could have an adverse effect on our business, financial condition and results of operations.
Some of our pipelines, terminals and other assets are located in areas that are susceptible to hurricanes, earthquakes and other natural disasters. These natural disasters could potentially damage or destroy our pipelines, terminals and other assets and disrupt the supply of the products we transport through our pipelines. Natural disasters can similarly affect the facilities of our customers. In either case, losses could exceed our insurance coverage and our business, financial condition and results of operations could be adversely affected, perhaps materially.
KMP’s and EPB’s tax treatment depends on their status as partnerships for U.S. federal income tax purposes, as well as not being subject to a material amount of entity-level taxation by individual states. If KMP and/or EPB were treated as corporations for U.S. federal income tax purposes or if they were to become subject to a material amount of entity-level taxation for state tax purposes, then cash available for distribution to their partners, including us, would be substantially reduced.
We own the general partner interests in both KMP and EPB and approximately 11% and 41% of the limited partner interests of KMP and of EPB, respectively. The anticipated after-tax economic benefit of our investment in KMP and EPB depends largely on their treatment as partnerships for U.S. federal income tax purposes. Neither KMP nor EPB has requested nor plans to request a ruling from the IRS on this or any other tax matter.
Despite the fact that KMP and EPB are organized as limited partnerships under Delaware law, it is possible in certain circumstances for partnerships such as KMP or EPB to be treated as corporations for U.S. federal income tax purposes. Although neither KMP nor EPB believes, based on its current operations, that it is or will be so treated, the IRS could disagree with the positions KMP or EPB takes or a change in KMP’s or EPB’s business (or a change in current law) could cause them to be treated as corporations for U.S. federal income tax purposes or otherwise subject them to taxation as an entity.
If they were treated as corporations for U.S. federal income tax purposes, they would pay U.S. federal income tax on taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income taxes at varying rates. Distributions by KMP and EPB to their partners, including us, would generally be taxed again as corporate dividends (to the extent of their current and accumulated earnings and profits) and no income, gains, losses, deductions or credits would flow through to their partners, including us. Because tax would be imposed on KMP and EPB as corporations, their after-tax cash available for distribution would be substantially reduced, likely causing a substantial reduction in the dividends we could pay and in the value of our common stock.
The present U.S. federal income tax treatment of publicly traded partnerships, including KMP and EPB, or an investment in them may be modified by administrative, legislative or judicial changes or differing interpretations at any time. Moreover, from time to time, members of the U.S. Congress propose and consider substantive changes to the existing U.S. federal income tax laws that could affect the tax treatment of certain publicly traded partnerships. We are unable to predict whether any of these changes or other proposals will ultimately be enacted.
In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. Any state income taxes imposed upon KMP or EPB as entities would reduce their cash available to be distributed to us. Any modification to the U.S. federal income or state tax laws, or interpretations thereof, may be applied retroactively and could negatively impact the value of our investment in KMP and EPB.
KMP’s and EPB’s partnership agreements provide that if a law is enacted that subjects them to corporate taxation or otherwise subjects them to entity-level taxation for U.S. federal income tax purposes, the minimum quarterly distribution amounts and the target distribution amounts will be adjusted to reflect the impact.
If KMP’s or EPB’s unitholders remove their respective general partner, we would lose our general partner interest in either KMP or EPB, including the right to incentive distributions, and the ability to manage them.
We own the general partners of KMP and EPB and with respect to KMP, all of the voting shares of KMR, to which the general partner has delegated its rights and powers to control the business and affairs of KMP, subject to the approval of the general partner for certain actions. KMP’s and EPB’s partnership agreements, however, give their respective unitholders the right to remove their general partner if (i) the holders of 66 2⁄3% of the respective partnership’s outstanding units (including the common units, Class B units and i-units, as applicable) voting as a single class vote for such removal; (ii) the holders of KMP’s and EPB’s outstanding units approve the election and succession of a new general partner by the same vote, respectively; and
(iii) KMP and/ or EPB receives opinion of counsel that the removal and succession of the general partner would not result in the loss of the limited liability of any limited partner or its operating partnership subsidiaries or cause either KMP or EPB or its operating partnership subsidiaries to be taxed as a corporation for federal income tax purposes.
If KMP’s or EPB’s unitholders removed their respective general partner, the general partner would lose its ability to manage KMP or EPB, and with respect to KMP, the delegation of authority to KMR by KMP’s general partner would terminate at the same time. The general partner would receive cash or common units in exchange for its general partner interest. While the cash or common units the general partner would receive are intended under the terms of KMP’s and EPB’s partnership agreements to fully compensate us, as the owner of the general partner, in the event such an exchange is required, the value of the investments we might make with the cash or the common units may not over time be equivalent to the value of the general partner interest and the related incentive distributions had the general partner retained its general partner interest.
If in the future KMR and the general partner cease to manage and control KMP, with respect to KMP and EPB’s general partner ceases to manage and control EPB either limited partnership may be deemed to be an investment company under the Investment Company Act of 1940.
If our subsidiaries, KMR and KMGP, which is the general partner of KMP, cease to manage and control KMP, or, El Paso Pipeline GP, L.L.C. ceases to manage and control EPB, either or both KMP and EPB may be deemed to be investment companies under the Investment Company Act of 1940. In that case, KMP and/or EPB would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the SEC or modify their organizational structure or contractual rights so as to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us and our affiliates, and could adversely affect the price of our common stock.
If we are unable to retain our executive officers, our growth may be hindered.
Our success depends in part on the performance of and our ability to retain our executive officers, particularly our Chairman and Chief Executive Officer, Richard D. Kinder, who is also one of our founders. Along with the other members of our senior management, Mr. Kinder has been responsible for developing and executing our growth strategy since 1997. If we are not successful in retaining Mr. Kinder or our other executive officers or replacing them, our business, financial condition or results of operations could be adversely affected. We do not maintain key personnel insurance.
Risks Related to the Ownership of Our Common Stock
The price of the common stock may be volatile, and holders of our common stock could lose a significant portion of their investments.
The market price of the common stock could be volatile, and our stockholders may not be able to resell their common stock at or above the price at which they purchased the common stock due to fluctuations in the market price of the common stock, including changes in price caused by factors unrelated to our operating performance or prospects.
Specific factors that may have a significant effect on the market price for the common stock include: (i) changes in stock market analyst recommendations or earnings estimates regarding the common stock, the common units of KMP and EPB, other companies comparable to us or KMP and EPB or companies in the industries we serve; (ii) actual or anticipated fluctuations in our operating results or future prospects; (iii) reaction to our public announcements; (iv) strategic actions taken by us or our competitors, such as acquisitions or restructurings; (v) the recruitment or departure of key personnel; (vi) new laws or regulations or new interpretations of existing laws or regulations applicable to our business and operations; (vii) changes in tax or accounting standards, policies, guidance, interpretations or principles; (viii) adverse conditions in the financial markets or general U.S. or international economic conditions, including those resulting from war, incidents of terrorism and responses to such events; (ix) sales of common stock by us, members of our management team or significant stockholders; and (x) the extent of analysts’ interest in following our company.
Non-U.S. holders of our common stock may be subject to U.S. federal income tax with respect to gain on the disposition of our common stock.
If we are or have been a ‘’U.S. real property holding corporation’’ within the meaning of the Code at any time within the shorter of (i) the five-year period preceding a disposition of our common stock by a non-U.S. holder, or (ii) such holder’s holding period for such common stock, and assuming our common stock is ‘’regularly traded,’’ as defined by applicable U.S. Treasury regulations, on an established securities market, the non-U.S. holder may be subject to U.S. federal income tax with respect to gain on such disposition if it held more than 5% of our common stock during the shorter of periods (i) and (ii) above. We believe we are, or may become, a U.S. real property holding corporation.
Risks Related to Our Dividend Policy
Holders of our common stock may not receive the anticipated level of dividends under our dividend policy or any dividends at all.
Our dividend policy provides that, subject to applicable law, we will pay quarterly cash dividends generally representing the cash we receive from our subsidiaries less any cash disbursements and reserves established by a majority vote of our board of directors, including for general and administrative expenses, interest and cash taxes. However, our board of directors, subject to the requirements of our bylaws and other governance documents, may amend, revoke or suspend our dividend policy at any time, and even while the current policy is in place, the actual amount of dividends on our capital stock will depend on many factors, including our financial condition and results of operations, liquidity requirements, market opportunities, capital requirements of our subsidiaries, legal, regulatory and contractual constraints, tax laws and other factors. Dividends other than as provided in our dividend policy require supermajority board approval while the Sponsor Investors maintain prescribed ownership thresholds.
Over time, our capital and other cash needs may change significantly from our current needs, which could affect whether we pay dividends and the amount of any dividends we may pay in the future. The terms of any future indebtedness we incur also may restrict us from paying cash dividends on our stock under certain circumstances. A decline in the market price or liquidity, or both, of our common stock could result if our board of directors establishes large reserves that reduce the amount of quarterly dividends paid or if we reduce or eliminate the payment of dividends. This may in turn result in losses by our stockholders, which could be substantial.
The general partners of KMP and EPB, with our consent but without the consent of our stockholders, may take steps to support KMP and EPB that have the effect of reducing cash we have or are entitled to receive, thereby reducing the cash we have available to pay dividends.
We utilize KMP and EPB as our vehicles for growth. We have historically received a significant portion of our cash flows from incentive distributions on the general partner interest. As the owner of the general partner of KMP, and now EPB, we may take steps we judge beneficial to KMP’s and EPB’s growth that in the short-run reduce the cash we receive and have available to pay dividends. The board of directors of the general partner of KMP or EPB may determine to support a desirable acquisition that may not be immediately accretive to cash available for distribution per KMP or EPB unit. For example, KMP’s general partner, with our consent, waived its incentive distributions from the second quarter of 2010 through 2011 on common units issued to finance a portion of KMP’s acquisition of the initial 50% interest in the KinderHawk joint venture and has agreed to waive its paid incentive distributions of $27 million and $4 million for 2012 and the first quarter of 2013, respectively, on common units issued to finance a portion of KMP’s subsequent acquisition of the remaining 50% interest in the KinderHawk joint venture. In addition, in connection with KMP’s acquisition of Copano, KMP’s general partner has agreed to waive incentive distributions of $75 million for 2013, $120 million for both 2014 and 2015, $110 million for 2016 and annual amounts thereafter decreasing by $5 million per year from this level.
Our dividend policy may limit our ability to pursue growth opportunities above the limited partnership level or impair our financial flexibility.
If we pay dividends at the level currently anticipated under our dividend policy, we may not retain a sufficient amount of cash to finance growth opportunities above the limited partnership level, meet any large unanticipated liquidity requirements or fund our operations in the event of a significant business downturn. In addition, because of the dividends required under our dividend policy, our ability to pursue any material expansion of our business above the limited partnership level, including through acquisitions, increased capital spending or other increases of our expenditures, will depend more than it otherwise would on our ability to obtain third party financing. We cannot assure our stockholders that such financing will be available to
us at all, or at an acceptable cost. If we are unable to take timely advantage of growth opportunities, our future financial condition and competitive position may be harmed, which in turn may adversely affect the market price of our common stock.
If we do not receive sufficient distributions from our subsidiaries, we may be unable to pay dividends.
All of our operations are conducted by our subsidiaries, and our cash flow and our ability to satisfy obligations and to pay dividends to our stockholders are dependent upon cash dividends and distributions or other transfers from our subsidiaries. In addition, our joint ventures and some of our subsidiaries, such as our limited partnerships, are not wholly owned by us. When funds are distributed to us by such joint ventures and subsidiaries, funds also will be distributed to their other owners.
Each of our subsidiaries is a distinct legal entity and has no obligation to transfer funds to us. A number of our subsidiaries are a party to credit facilities and are or may in the future be a party to other borrowing agreements that restrict the payment of dividends to us, and such subsidiaries are likely to continue to be subject to such restrictions and prohibitions for the foreseeable future. In addition, the ability of our subsidiaries to make distributions will depend on their respective operating results and may be subject to further restrictions under, among other things, the laws of their jurisdiction of organization.
The board of directors of KMR, which is the delegate of KMP’s general partner, and EPB’s general partner have broad authority to establish cash reserves for the prudent conduct of their businesses. The establishment of those reserves could result in smaller distributions to us and a corresponding reduction of our cash available for dividends and our anticipated dividend level. Further, the calculation of KMP’s and EPB’s available cash for distribution is discretionary and subject to the approval of the board of directors of KMR or EPB’s general partner, respectively taking into consideration their constituent agreements. Similarly, while the constituent agreements of NGPL provide that it is the intention of NGPL to make distributions of available cash, we own less than a majority of NGPL and do not control it. The same is true for joint ventures in which our limited partnerships own an interest.
The distributions we receive from KMP are largely attributable to the incentive distributions on our general partner interest. The distributions we receive are not as large if KMP distributes cash from interim capital transactions rather than cash from operations, or if KMP’s general partner waives receipt of a portion of those incentive distributions.
As a result of the foregoing, we may be unable to receive cash through distributions or other payments from our subsidiaries in sufficient amounts to pay dividends on our common stock. If we are unable to authorize the payment of dividends due to insufficient cash, a decline in the market price or liquidity, or both, of our common stock could result. This may in turn result in losses by our stockholders, which could be substantial.
Our ability to pay dividends is restricted by Delaware law.
Under the DGCL, our board of directors may not authorize payment of a dividend unless it is either paid out of surplus, as calculated in accordance with the DGCL, or if we do not have a surplus, it is paid out of net profits for the fiscal year in which the dividend is declared and/or the preceding fiscal year. Our bylaws require the declaration and payment of dividends to comply with the DGCL. If, as a result of these restrictions, we are unable to authorize payment of dividends, a decline in the market price or liquidity, or both, of our common stock could result. This may in turn result in losses by our stockholders.
Risks Related to Conflicts of Interest
KMP, EPB and their subsidiaries may compete with us.
Neither of KMP, EPB or any of their subsidiaries or entities in which they own an interest is restricted from competing with us. KMR manages KMP (subject to certain decisions requiring the approval of KMP’s general partner) and EPB’s general partner manages EPB, in what they consider to be the best interests of their respective limited partner interests. KMP, EPB and their subsidiaries may acquire, invest in or construct assets that may be in direct competition with us, which could have a material adverse effect on our business, financial condition, results of operations or prospects. Among other things, we and our limited partnerships have a policy that acquisition opportunities of businesses or operating assets will be pursued above the limited partnership level only if KMP and EPB elect not to pursue the opportunity.
Many of our directors and officers also serve as directors or officers of our non-wholly owned subsidiaries, including KMR and EPB, or entities in which we own an interest, such as NGPL, as a result of which conflicts of interest exist and will arise in the future.
Many of our directors and officers are also directors or officers of our non-wholly owned subsidiaries. Any officer or director of our non-wholly owned subsidiaries, who is also a director or officer of ours, in making decisions in such person’s capacity as our officer or director, is required to act in accordance with his or her fiduciary duties to us. However, in making decisions in such person’s capacity as a director or officer of one of our non-wholly owned subsidiaries or such other entities, such person may make a decision that favors the interests of such subsidiary over our interests or the interests of our stockholders and may be to our detriment. Further, the organizational documents of these entities may have provisions reducing or eliminating the duties of their officers or directors to those entities and their owners, including us. In addition, our directors are not required to work full time on our business and affairs and may devote significant time to the affairs of our non-wholly owned subsidiaries. There could be material competition for the time and effort of our directors who provide services to our non-wholly owned subsidiaries.
Item 1B. Unresolved Staff Comments.
None.
Item 3. Legal Proceedings.
See Note 16 “Litigation, Environmental and Other” to our consolidated financial statements.
Item 4. Mine Safety Disclosures.
The information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is in exhibit 95.1 to this annual report.
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
On December 26, 2012, the remaining outstanding shares of our Class A, Class B, and Class C common stock were converted into Class P shares and as of December 31, 2012 only our Class P common stock was outstanding. Our Class P common stock is listed for trading on the NYSE under the symbol “KMI.” During the period that our Class A, Class B, and Class C common stock was outstanding, none were traded on a public trading market. The high and low sale prices per Class P share as reported on the NYSE and the dividends declared per share by period for 2013 and 2012, are provided below.
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(a)
Dividend information is for dividends declared with respect to that quarter. Generally, our declared dividends are paid after we receive quarterly distributions from KMP and EPB, which are paid within 45 days after the end of each quarter.
As of January 31, 2014, we had 10,955 holders of our Class P common stock, which does not include beneficial owners whose shares are held by a clearing agency, such as a broker or bank.
For information on our equity compensation plans, see Item 12 “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters-Equity Compensation Plan Information.” Also see Note 9 “Share-based Compensation and Employee Benefits-Share-based Compensation-Kinder Morgan, Inc.” to our consolidated financial statements.
Our Purchases of Our Class P Shares and Warrants
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(a)
On October 16, 2013, we announced that our board of directors had approved a separate share and warrant repurchase program, authorizing us to repurchase in the aggregate up to $250 million of additional shares and warrants. This $250 million program is in addition to the previously announced repurchase programs, including our board authorized $350 million share and warrant repurchase program that was announced on July 17, 2013.
Item 6. Selected Financial Data.
The following tables set forth, for the periods and at the dates indicated, our summary historical financial and operating data. The table is derived from our consolidated financial statements and notes thereto, and should be read in conjunction with those audited financial statements. See also
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion and analysis should be read in conjunction with our consolidated financial statements and the notes thereto. Additional sections in this report which should be helpful to the reading of our discussion and analysis include the following: (i) a description of our business strategy found in Items 1 and 2 “Business and Properties-(c) Narrative Description of Business-Business Strategy;” (ii) a description of developments during 2013, found in Items 1 and 2 “Business and Properties-(a) General Development of Business-Recent Developments;” and (iii) a description of risk factors affecting us and our business, found in Item 1A “Risk Factors.”
We prepared our consolidated financial statements in accordance with GAAP. Accordingly, as discussed in Notes 1 “General”, 2 “Summary of Significant Accounting Policies”, and 3 “Acquisitions and Divestitures” to our consolidated financial statements, our financial statements reflect the reclassifications necessary to reflect the results of KMP’s FTC Natural Gas Pipelines disposal group as discontinued operations. We sold KMP’s FTC Natural Gas Pipelines disposal group to Tallgrass effective November 1, 2012 for approximately $1.8 billion in cash (before selling costs), or $3.3 billion including KMP’s share of joint venture debt. In 2013, KMP and Tallgrass trued up the final consideration for the sale of KMP’s FTC Natural Gas Pipelines disposal group and based both on this true up and certain incremental selling expenses KMP paid in 2013, we recognized an additional $4 million loss related to our sale of the disposal group. Except for this loss amount, we recorded no other financial results from the operations of the disposal group during 2013. Furthermore, we have excluded the disposal group’s financial results from the Natural Gas Pipelines business segment disclosures for each of the years ended December 31, 2012 and 2011.
Inasmuch as the discussion below and the other sections to which we have referred you pertain to management’s comments on financial resources, capital spending, our business strategy and the outlook for our business, such discussions contain forward-looking statements. These forward-looking statements reflect the expectations, beliefs, plans and objectives of management about future financial performance and assumptions underlying management’s judgment concerning the matters discussed, and accordingly, involve estimates, assumptions, judgments and uncertainties. Our actual results could differ materially from those discussed in the forward-looking statements. Factors that could cause or contribute to any differences include, but are not limited to, those discussed below and elsewhere in this report, particularly in Item 1A “Risk Factors” and at the beginning of this report in “Information Regarding Forward-Looking Statements.”
General
Our business model, through our ownership and operation of energy related assets, is built to support two principal components:
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helping customers by providing safe and reliable energy, bulk commodity and liquids products transportation, storage and distribution; and
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creating long-term value for our shareholders.
To achieve these objectives, we focus on providing fee-based services to customers from a business portfolio consisting of energy-related pipelines, natural gas storage, processing and treating facilities, and bulk and liquids terminal facilities. We also produce and sell crude oil. Our reportable business segments are based on the way our management organizes our enterprise, and each of our business segments represents a component of our enterprise that engages in a separate business activity and for which discrete financial information is available.
Our reportable business segments are:
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Natural Gas Pipelines-(i) the ownership and operation of major interstate and intrastate natural gas pipeline and storage systems; (ii) the ownership and/or operation of associated natural gas gathering systems and natural gas
processing and treating facilities; and (iii) the ownership and/or operation of NGL fractionation facilities and transportation systems;
•
CO2-KMP-(i) the production, transportation and marketing of CO2, to oil fields that use CO2 to increase production of oil; (ii) ownership interests in and/or operation of oil fields and gas processing plants in West Texas; and (iii) the ownership and operation of a crude oil pipeline system in West Texas;
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Products Pipelines-KMP- the ownership and operation of refined petroleum products and crude oil and condensate pipelines that deliver refined petroleum products (gasoline, diesel fuel and jet fuel), NGL, crude oil, condensate and bio-fuels to various markets, plus the ownership and/or operation of associated product terminals and petroleum pipeline transmix facilities;
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Terminals-KMP-the ownership and/or operation of liquids and bulk terminal facilities and rail transloading and materials handling facilities located throughout the U.S. and portions of Canada;
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Kinder Morgan Canada-KMP-the ownership and operation of the Trans Mountain pipeline system that transports crude oil and refined petroleum products from Edmonton, Alberta, Canada to marketing terminals and refineries in British Columbia, Canada and the state of Washington, plus the Jet Fuel aviation turbine fuel pipeline that serves the Vancouver (Canada) International Airport; and
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Other-primarily includes several physical natural gas contracts with power plants associated with EP’s legacy trading activities. These contracts obligate EP to sell natural gas to these plants and have various expiration dates ranging from 2012 to 2028.
As an energy infrastructure owner and operator in multiple facets of the U.S.’ and Canada’s various energy businesses and markets, we examine a number of variables and factors on a routine basis to evaluate our current performance and our prospects for the future.
With respect to our interstate natural gas pipelines and related storage facilities, the revenues from these assets are primarily received under contracts with terms that are fixed for various and extended periods of time. To the extent practicable and economically feasible in light of our strategic plans and other factors, we generally attempt to mitigate risk of reduced volumes and prices by negotiating contracts with longer terms, with higher per-unit pricing and for a greater percentage of our available capacity. These long-term contracts are typically structured with a fixed-fee reserving the right to transport natural gas and specify that we receive the majority of our fee for making the capacity available, whether or not the customer actually chooses to utilize the capacity. Similarly, in KMP’s Texas Intrastate Natural Gas Group, it currently derives approximately 75% of its sales and transport margins from long-term transport and sales contracts that include requirements with minimum volume payment obligations. As contracts expire, we have additional exposure to the longer term trends in supply and demand for natural gas. As of December 31, 2013, the remaining average contract life of our natural gas transportation contracts (including intrastate pipelines’ purchase and sales contracts) was approximately five and a half years.
During 2012 and 2013, we further expanded our midstream services through our (i) EP midstream asset operations, which we acquired 50% from KKR effective June 1, 2012, and 50% from the May 25, 2012 EP acquisition; and (ii) our Copano operations, which included the remaining 50% ownership interest in Eagle Ford Gathering LLC that we did not already own and which was acquired effective May 1, 2013. These fee-based gathering, processing and fractionation assets, along with our financial strength and extensive pipeline transportation and storage assets, should provide an excellent platform to further grow our midstream services footprint. The revenues and earnings we realize from gathering natural gas, processing natural gas in order to remove NGL from the natural gas stream, and fractionating NGL into their base components, are also affected by the volumes of natural gas made available to our systems, which are primarily driven by levels of natural gas drilling activity. Our midstream services are provided pursuant to a variety of arrangements, generally categorized (by the nature of the commodity price risk) as fee-based, percent-of-proceeds, percent-of-index and keep-whole. Contracts may rely solely on a single type of arrangement, but more often they combine elements of two or more of the above, which helps us and our counterparties manage the extent to which each shares in the potential risks and benefits of changing commodity prices.
The CO2 sales and transportation business primarily has third-party contracts with minimum volume requirements, which as of December 31, 2013, had a remaining average contract life of approximately ten years. CO2 sales contracts vary from customer to customer and have evolved over time as supply and demand conditions have changed. Our recent contracts have generally provided for a delivered price tied to the price of crude oil, but with a floor price. On a volume-weighted basis, for third-party contracts making deliveries in 2014, and utilizing the average oil price per barrel contained in our 2014 budget, approximately 69% of our contractual volumes are based on a fixed fee or floor price, and 31% fluctuate with the price of
oil. In the long-term, our success in this portion of the CO2-KMP business segment is driven by the demand for CO2. However, short-term changes in the demand for CO2 typically do not have a significant impact on us due to the required minimum sales volumes under many of our contracts. In the CO2-KMP business segment’s oil and gas producing activities, we monitor the amount of capital we expend in relation to the amount of production that we expect to add. In that regard, our production during any period is an important measure. In addition, the revenues we receive from our crude oil, NGL and CO2 sales are affected by the prices we realize from the sale of these products. Over the long-term, we will tend to receive prices that are dictated by the demand and overall market price for these products. In the shorter term, however, market prices are likely not indicative of the revenues we will receive due to our risk management, or hedging, program, in which the prices to be realized for certain of our future sales quantities are fixed, capped or bracketed through the use of financial derivative contracts, particularly for crude oil. The realized weighted average crude oil price per barrel, with all hedges allocated to oil, was $92.70 per barrel in 2013, $87.72 per barrel in 2012 and $69.73 per barrel in 2011. Had we not used energy derivative contracts to transfer commodity price risk, our crude oil sales prices would have averaged $94.94 per barrel in 2013, $89.91 per barrel in 2012 and $92.61 per barrel in 2011.
The profitability of our refined petroleum products pipeline transportation business is generally driven by the volume of refined petroleum products that we transport and the prices we receive for our services. Transportation volume levels are primarily driven by the demand for the refined petroleum products being shipped or stored. Demand for refined petroleum products tends to track in large measure demographic and economic growth, and with the exception of periods of time with very high product prices or recessionary conditions, demand tends to be relatively stable. Because of that, we seek to own refined petroleum products pipelines located in, or that transport to, stable or growing markets and population centers. The prices for shipping are generally based on regulated tariffs that are adjusted annually based on changes in the U.S. Producer Price Index.
The factors impacting the Terminals-KMP business segment generally differ depending on whether the terminal is a liquids or bulk terminal, and in the case of a bulk terminal, the type of product being handled or stored. As with our refined petroleum products pipeline transportation business, the revenues from our bulk terminals business are generally driven by the volumes we handle and/or store, as well as the prices we receive for our services, which in turn are driven by the demand for the products being shipped or stored. While we handle and store a large variety of products in our bulk terminals, the primary products are coal, petroleum coke, and steel. For the most part, we have contracts for this business that have minimum volume guarantees and are volume based above the minimums. Because these contracts are volume based above the minimums, our profitability from the bulk business can be sensitive to economic conditions. Our liquids terminals business generally has longer-term contracts that require the customer to pay regardless of whether they use the capacity. Thus, similar to our natural gas pipeline business, our liquids terminals business is less sensitive to short-term changes in supply and demand. Therefore, the extent to which changes in these variables affect our terminals business in the near term is a function of the length of the underlying service contracts (which on average is approximately four years), the extent to which revenues under the contracts are a function of the amount of product stored or transported, and the extent to which such contracts expire during any given period of time. To the extent practicable and economically feasible in light of our strategic plans and other factors, we generally attempt to mitigate the risk of reduced volumes and pricing by negotiating contracts with longer terms, with higher per-unit pricing and for a greater percentage of our available capacity. In addition, weather-related factors such as hurricanes, floods and droughts may impact our facilities and access to them and, thus, the profitability of certain terminals for limited periods of time or, in relatively rare cases of severe damage to facilities, for longer periods.
In 2013, KMI completed the drop-down of its remaining 50% interest in EPNG and its 50% interest in the EP midstream assets to KMP. KMI used proceeds from the drop-down transaction to (i) pay down $947 million of KMI’s senior secured term loan facility; and (ii) reduce borrowings under KMI’s credit facility. In 2014, KMI expects to drop-down its 50% interest in Ruby Pipeline Holding Company, L.L.C., its 50% interest in Gulf LNG Holdings Group, LLC and its 47.5% interest in Young Gas Storage Company, LTD to EPB. KMP and EPB have a successful history of making accretive acquisitions and economically advantageous expansions of existing businesses.
Thus, the amount that we are able to increase dividends to our shareholders will, to some extent, be a function of our and our subsidiaries’ ability to complete successful acquisitions and expansions (including drop-down transactions). We believe we will continue to have opportunities for expansion of our facilities in many markets, and we have budgeted approximately $3.9 billion for our 2014 capital expansion program (including small acquisitions and investment contributions). We and our subsidiaries, KMP and EPB, regularly consider and enter into discussions regarding potential acquisitions, including those from us or our affiliates, and are currently contemplating potential acquisitions.
Based on our historical record and because there is continued demand for energy infrastructure in the areas we serve, we expect to continue to have such opportunities in the future, although the level of such opportunities is difficult to predict. While there are currently no unannounced purchase agreements for the acquisition of any material business or assets, such
transactions can be effected quickly, may occur at any time and may be significant in size relative to our existing assets or operations. Furthermore, our ability to make accretive acquisitions is a function of the availability of suitable acquisition candidates at the right cost, and includes factors over which we have limited or no control. Thus, we have no way to determine the number or size of accretive acquisition candidates in the future, or whether we will complete the acquisition of any such candidates.
Our, or our subsidiaries’ (including EPB and KMP), ability to make accretive acquisitions or expand our assets is impacted by our ability to maintain adequate liquidity and to raise the necessary capital needed to fund such acquisitions. As MLPs, KMP and EPB distribute all of their available cash, and they access capital markets to fund acquisitions and asset expansions. Historically, KMP and EPB have succeeded in raising necessary capital in order to fund their acquisitions and expansions, and although we cannot predict future changes in the overall equity and debt capital markets (in terms of tightening or loosening of credit), we believe that KMP’s and EPB’s stable cash flows, credit ratings, and historical records of successfully accessing both equity and debt funding sources should allow us to continue to execute our current investment, distribution and acquisition strategies, as well as refinance maturing debt when required. For a further discussion of our liquidity, including KMP’s and EPB’s public debt and equity offerings in 2013, please see “-Liquidity and Capital Resources” below.
In our discussions of the operating results of individual businesses that follow (see “-Results of Operations” below), we generally identify the important fluctuations between periods that are attributable to acquisitions and dispositions separately from those that are attributable to businesses owned in both periods.
In addition, a portion of KMP’s business portfolio (including the Kinder Morgan Canada-KMP business segment, the Canadian portion of KMP’s Cochin Pipeline, and the bulk and liquids terminal facilities located in Canada) uses the local Canadian dollar as the functional currency for its Canadian operations and enters into foreign currency-based transactions, both of which affect segment results due to the inherent variability in U.S. - Canadian dollar exchange rates. To help understand our reported operating results, all of the following references to “foreign currency effects” or similar terms in this section represent our estimates of the changes in financial results, in U.S. dollars, resulting from fluctuations in the relative value of the Canadian dollar to the U.S. dollar. The references are made to facilitate period-to-period comparisons of business performance and may not be comparable to similarly titled measures used by other registrants.
Critical Accounting Policies and Estimates
Accounting standards require information in financial statements about the risks and uncertainties inherent in significant estimates, and the application of GAAP involves the exercise of varying degrees of judgment. Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time our financial statements are prepared. These estimates and assumptions affect the amounts we report for our assets and liabilities, our revenues and expenses during the reporting period, and our disclosure of contingent assets and liabilities at the date of our financial statements. We routinely evaluate these estimates, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates, and any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.
In preparing our consolidated financial statements and related disclosures, examples of certain areas that require more judgment relative to others include our use of estimates in determining: (i) the economic useful lives of our assets and related depletion rates; (ii) the fair values used to assign purchase price from business combinations, determine possible asset impairment charges, and calculate the annual goodwill impairment test; (iii) reserves for environmental claims, legal fees, transportation rate cases and other litigation liabilities; (iv) provisions for uncollectible accounts receivables; (v) exposures under contractual indemnifications; and (vi) unbilled revenues.
For a summary of our significant accounting policies, see Note 2 “Summary of Significant Accounting Policies” to our consolidated financial statements. We believe that certain accounting policies are of more significance in our consolidated financial statement preparation process than others, which policies are discussed as follows.
Acquisition Method of Accounting
For acquired businesses, we recognize the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values (with limited exceptions) on the date of acquisition. Determining the fair value of these items requires management’s judgment, the utilization of independent valuation experts and involves the use of significant estimates and assumptions with respect to the timing and amounts of future cash inflows and outflows, discount
rates, market prices and asset lives, among other items. The judgments made in the determination of the estimated fair value assigned to the assets acquired, the liabilities assumed and any noncontrolling interest in the investee, as well as the estimated useful life of each asset and the duration of each liability, can materially impact the financial statements in periods after acquisition, such as through depreciation and amortization expense. For more information on our acquisitions and application of the acquisition method, see Note 3 “Acquisitions and Divestitures” to our consolidated financial statements.
Environmental Matters
With respect to our environmental exposure, we utilize both internal staff and external experts to assist us in identifying environmental issues and in estimating the costs and timing of remediation efforts. We expense or capitalize, as appropriate, environmental expenditures that relate to current operations, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs. Generally, we do not discount environmental liabilities to a net present value, and we recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable. We record at fair value, where appropriate, environmental liabilities assumed in a business combination.
Our recording of our environmental accruals often coincides with our completion of a feasibility study or our commitment to a formal plan of action, but generally, we recognize and/or adjust our environmental liabilities following routine reviews of potential environmental issues and claims that could impact our assets or operations. These adjustments may result in increases in environmental expenses and are primarily related to quarterly reviews of potential environmental issues and resulting environmental liability estimates. In making these liability estimations, we consider the effect of environmental compliance, pending legal actions against us, and potential third party liability claims. For more information on environmental matters, see Item 1(c). For more information on our environmental disclosures, see Note 16 “Litigation, Environmental and Other Contingencies” to our consolidated financial statements.
Legal Matters
Many of our operations are regulated by various U.S. and Canadian regulatory bodies and we are subject to legal and regulatory matters as a result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. In general, we expense legal costs as incurred. When we identify contingent liabilities, we identify a range of possible costs expected to be required to resolve the matter. Generally, if no amount within this range is a better estimate than any other amount, we record a liability equal to the low end of the range. Any such liability recorded is revised as better information becomes available. Accordingly, to the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected.
As of December 31, 2013, our most significant ongoing legal matters involved KMP’s West Coast Products Pipelines and its Western Interstate Natural Gas Pipelines. Transportation rates charged by certain of these pipeline systems are subject to proceedings at the FERC and the CPUC involving shipper challenges to the pipelines’ interstate and intrastate (California) rates, respectively. For more information on regulatory proceedings, see Note 16 “Litigation, Environmental and Other Contingencies” to our consolidated financial statements.
Intangible Assets
Intangible assets are those assets which provide future economic benefit but have no physical substance. Identifiable intangible assets having indefinite useful economic lives, including goodwill, are not subject to regular periodic amortization, and such assets are not to be amortized until their lives are determined to be finite. Instead, the carrying amount of a recognized intangible asset with an indefinite useful life must be tested for impairment annually or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. We evaluate our goodwill for impairment on May 31 of each year. There were no impairment charges resulting from our May 31, 2013 impairment testing, and no event indicating an impairment has occurred subsequent to that date. Furthermore, our analysis as of that date did not reflect any reporting units at risk, and subsequent to that date, no event has occurred indicating that the implied fair value of each of our reporting units is less than the carrying value of its net assets. For more information on our goodwill, see Notes 2 “Summary of Significant Accounting Policies” and 7 “Goodwill and Other Intangibles” to our consolidated financial statements.
Excluding goodwill, our other intangible assets include customer contracts, relationships and agreements, lease value, and technology-based assets. These intangible assets have definite lives, are being amortized in a systematic and rational manner over their estimated useful lives, and are reported separately as “Other intangibles, net” in our accompanying consolidated balance sheets. For more information on our amortizable intangibles, see Note 7 “Goodwill and Other Intangibles” to our consolidated financial statements.
Estimated Net Recoverable Quantities of Oil and Gas
We use the successful efforts method of accounting for our oil and gas producing activities. The successful efforts method inherently relies on the estimation of proved reserves, both developed and undeveloped. The existence and the estimated amount of proved reserves affect, among other things, whether certain costs are capitalized or expensed, the amount and timing of costs depleted or amortized into income, and the presentation of supplemental information on oil and gas producing activities. The expected future cash flows to be generated by oil and gas producing properties used in testing for impairment of such properties also rely in part on estimates of net recoverable quantities of oil and gas.
Proved reserves are the estimated quantities of oil and gas that geologic and engineering data demonstrates with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Estimates of proved reserves may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change. For more information on our ownership interests in the net quantities of proved oil and gas reserves and our measures of discounted future net cash flows from oil and gas reserves, please see “Supplemental Information on Oil and Gas Producing Activities (Unaudited)”.
Hedging Activities
We engage in a hedging program that utilizes derivative contracts to mitigate (offset) our exposure to fluctuations in energy commodity prices and to balance our exposure to fixed and variable interest rates, and we believe that these hedges are generally effective in realizing these objectives. According to the provisions of GAAP, to be considered effective, changes in the value of a derivative contract or its resulting cash flows must substantially offset changes in the value or cash flows of the item being hedged, and any ineffective portion of the hedge gain or loss and any component excluded from the computation of the effectiveness of the derivative contract must be reported in earnings immediately. We may or may not apply hedge accounting to our derivative contracts depending on the circumstances. All of our derivative contracts are recorded at estimated fair value.
Since it is not always possible for us to engage in a hedging transaction that completely mitigates our exposure to unfavorable changes in commodity prices-a perfectly effective hedge-we often enter into hedges that are not completely effective in those instances where we believe to do so would be better than not hedging at all. But because the part of such hedging transactions that is not effective in offsetting undesired changes in commodity prices (the ineffective portion) is required to be recognized currently in earnings, our financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge. For example, when we purchase a commodity at one location and sell it at another, we may be unable to hedge completely our exposure to a differential in the price of the product between these two locations; accordingly, our financial statements may reflect some volatility due to these hedges. For more information on our hedging activities, see Note 13 “Risk Management” to our consolidated financial statements.
Employee Benefit Plans
We reflect an asset or liability for our pension and other postretirement benefit plans based on their overfunded or underfunded status. As of December 31, 2013, our pension plans were underfunded by $230 million and our other postretirement benefits plans were underfunded by $251 million. Our pension and other postretirement benefit obligations and net benefit costs are primarily based on actuarial calculations. We use various assumptions in performing these calculations, including those related to the return that we expect to earn on our plan assets, the rate at which we expect the compensation of our employees to increase over the plan term, the estimated cost of health care when benefits are provided under our plan and other factors. A significant assumption we utilize is the discount rate used in calculating our benefit obligations. We select our discount rates by matching the timing and amount of our expected future benefit payments for our pension and other postretirement benefit obligations to the average yields of various high-quality bonds with corresponding maturities. The selection of these assumptions is further discussed in Note 9 “Share-based Compensation and Employee Benefits” to our consolidated financial statements.
Actual results may differ from the assumptions included in these calculations, and as a result, our estimates associated with our pension and other postretirement benefits can be, and often are, revised in the future. The income statement impact of the changes in the assumptions on our related benefit obligations are deferred and amortized into income over either the period of expected future service of active participants, or over the expected future lives of inactive plan participants. We record these deferred amounts as either accumulated other comprehensive income (loss) or as a regulatory asset or liability for certain of our regulated operations. As of December 31, 2013, we had deferred net losses of approximately $27 million in pretax accumulated other comprehensive loss and noncontrolling interests related to our pension and other postretirement benefits.
The following table shows the impact of a 1% change in the primary assumptions used in our actuarial calculations associated with our pension and other postretirement benefits for the year ended December 31, 2013:
Income Taxes
We record a valuation allowance to reduce our deferred tax assets to an amount that is more likely than not to be realized. While we have considered estimated future taxable income and prudent and feasible tax planning strategies in determining the amount of our valuation allowance, any change in the amount that we expect to ultimately realize will be included in income in the period in which such a determination is reached. In addition, we do business in a number of states with differing laws concerning how income subject to each state’s tax structure is measured and at what effective rate such income is taxed. Therefore, we must make estimates of how our income will be apportioned among the various states in order to arrive at an overall effective tax rate. Changes in our effective rate, including any effect on previously recorded deferred taxes, are recorded in the period in which the need for such change is identified.
In determining the deferred income tax asset and liability balances attributable to our investments, we have applied an accounting policy that looks through our investments including our investment in KMP and EPB. The application of this policy resulted in no deferred income taxes being provided on the difference between the book and tax basis on the non-tax-deductible goodwill portion of our investment in KMP and EPB.
Going Private Transaction
A Going Private Transaction completed in May 2007 was accounted for as a purchase business combination. Accordingly, our assets and liabilities were recorded at their estimated fair values as of the date of the completion of the Going Private Transaction, with the excess of the purchase price over these combined fair values recorded as goodwill.
Results of Operations
Non-GAAP Measures
The non-GAAP, financial measures of (i) cash available to pay dividends, both in the aggregate and per share, and (ii) segment EBDA and certain items are presented below under “-Cash Available to Pay Dividends” and “-Consolidated Earnings Results.” Certain items are items that are required by GAAP to be reflected in net income, but typically either do not have a cash impact, or by their nature are separately identifiable from our normal business operations and, in our view, are likely to occur only sporadically.
We believe the GAAP measure most directly comparable to cash available to pay dividends is income from continuing operations. A reconciliation of cash available to pay dividends to income from continuing operations is provided below under “-Reconciliation of Cash Available to Pay Dividends to Income from Continuing Operation.” Our non-GAAP measures below should not be considered as an alternative to GAAP net income or any other GAAP measure. Cash available to pay dividends and segment EBDA and certain items are not financial measures in accordance with GAAP and have important limitations as analytical tools. You should not consider these non-GAAP measures in isolation or as a substitute for an analysis of our results as reported under GAAP. Our computation of cash available to pay dividends and segment EBDA and certain items may differ from similarly titled measures used by others. Management compensates for the limitations of these non-GAAP measures by reviewing our comparable GAAP measures, understanding the differences between the measures and taking this information into account in its analysis and its decision making processes.
Cash Available to Pay Dividends
Our board of directors has adopted the dividend policy set forth in our shareholders’ agreement, which provides that, subject to applicable law, we will pay quarterly cash dividends on all classes of our capital stock equal to the cash we receive from our subsidiaries and other sources less any cash disbursements and reserves established by a majority vote of our board of directors, including for general and administrative expenses, interest and cash taxes. See a further discussion on KMI dividends below under “- Financial Condition- KMI Dividends.” The calculation of our cash available to pay dividends, and a reconciliation of this non-GAAP measure to income from continuing operations, for each of the years ended December 31, 2013, 2012 and 2011 is as follows:
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(a)
Based on (i) KMP distributions of $5.33, $4.98 and $4.61 per common unit declared for the years ended December 31, 2013, 2012 and 2011, respectively; (ii) 381 million, 340 million and 319 million aggregate common units, Class B units and i-units (collectively KMP units) outstanding as of April 29, 2013, April 30, 2012 and April 29, 2011, respectively; (iii) 433 million, 347 million and 330 million KMP units outstanding as of July 31, 2013, July 31, 2012 and July 29, 2011, respectively; (iv) 438 million, 365 million and 333 million KMP units outstanding as of October 31, 2013, 2012 and 2011, respectively; (v) 444 million, 373 million and 336 million KMP units outstanding as of January 31, 2014, 2013 and 2012, respectively, and (vi) waived incentive distributions of $4 million, $26 million and $29 million for the years ended December 31, 2013, 2012 and 2011, respectively related to KMP’s acquisition of its initial 50% interest in May 2010, and subsequently, the remaining 50% interest in May 2011 of KinderHawk; and (vii) waived incentive distribution of $75 million for the year ended December 31, 2013, as a result of KMP’s acquisition of Copano. In addition, we as general partner of KMP, agreed to waive a portion of our future incentive distributions amounts equal to (i) $120 million for 2014, $120 million for 2015, $110 million for 2016, and annual amounts thereafter decreasing by $5 million per year from the 2016 level related to the Copano acquisition and (ii) $13 million for 2014, $19 million for 2015 and $6 million for 2016 related to KMP’s APT and SCT acquisitions.
(b)
Based on 28 million in 2013, 26 million as of September 30 and December 31, 2012 and 22 million in the prior periods, KMP units owned by us, multiplied by the KMP per unit distribution declared, as outlined in footnote (a) above.
(c)
Assumes that we sold the KMR shares that we received as distributions for the years ended December 31, 2013, 2012 and 2011. We did not sell any KMR shares in 2013, 2012 or 2011. We intend periodically to sell the KMR shares we receive as distributions to generate cash.
(d)
Based on (i) EPB distributions of $2.55 and $1.74 per common unit declared for the year ended December 31, 2013 and the nine months ended December 31, 2012; (ii) 216 million common units outstanding as of April 29, 2013; (iii) 218 million and 208 million common
units outstanding as of July 31, 2013 and 2012, respectively; (iv) 218 million and 216 million outstanding as of October 31, 2013 and 2012, respectively; and (v) 218 million and 216 million common units outstanding as of January 31, 2014 and 2013, respectively.
(e)
Based on 90 million EPB units owned by us as of December 31, 2013 and 2012, multiplied by the EPB per unit distribution declared, as outlined in footnote (d) above.
(f)
Represents corporate general and administrative expenses, corporate sustaining capital expenditures, and other income and expense.
(g)
2013 and 2012 Cash taxes were calculated based on the income and expenses included in the table, deductions related to the income included, and use of net operating loss carryforwards of $300 million and $200 million, respectively.
(h)
Represents cash available from former EP assets that remain at KMI, including TGP, EPNG and El Paso midstream assets for the periods presented prior to their drop-down to KMP, and our 20% interest in NGPL, net of general and administrative expenses related to KMI’s EP assets. Cash available includes our share (if applicable) of pre-tax earnings, plus DD&A, and less cash taxes and sustaining capital expenditures.
(i)
Represents interest expense on debt assumed from the May 25, 2012 EP acquisition.
(j)
Represents interest associated with Kinder Morgan, Inc.’s (KMI) remaining debt issued to finance the cash portion of EP acquisition purchase price.
(k)
Excludes $310 million in after-tax expenses associated with the EP acquisition and EP Energy sale for the year ended December 31, 2012. This included (i) $101 million in employee severance, retention and bonus costs; (ii) $55 million of accelerated EP stock based compensation allocated to the post-combination period under applicable GAAP rules; (iii) $37 million in advisory fees; (iv) $68 million write-off associated with the EP acquisition (primarily due to debt repayments) or amortization of capitalized financing fees; (v) $51 million for legal fees and reserves, net of recoveries; and (vi) $19 million benefit associated with pension income.
(l)
Includes weighted average common stock outstanding and (i) for 2013, approximately 6 million of unvested restricted stock awards issued to management employees that contain rights to dividends and (ii) for 2012, Class B shares, Class C shares and unvested restricted stock awards.
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(a)
Consists of the corresponding line items in our consolidated statements of income.
(b)
2012 and 2011 amounts primarily represent income from KMP’s FTC Natural Gas Pipelines disposal group, net of tax.
(c)
On May 25, 2012, we began recognizing income from our investment in EPB, and we received in the third quarter the full distribution for the second quarter as we were the holder of record as of July 31, 2012.
(d)
2012 and 2011 amounts include $7 million and $24 million, respectively, associated with KMP’s FTC Natural Gas Pipelines disposal group.
(e)
2013 and 2012 amounts exclude $65 million and $200 million, respectively, non-cash impairment charges on our investment in NGPL Holdco LLC. 2012 and 2011 amounts include $70 million and $87 million, respectively, associated with KMP’s FTC Natural Gas Pipelines disposal group.
(f)
Consists of the difference between cash available for distributions and the distributions received from our equity investments.
(g)
Consists of items such as hedge ineffectiveness, legal and environmental reserves, gain/loss on sale, insurance proceeds from casualty losses, and asset acquisition and/or disposition expenses. 2013 amount includes (i) $558 million gain on remeasurement of previously held equity interest in Eagle Ford Gathering to fair value; (ii) $177 million for legal reserves related to the rate case and other litigation and environmental matters on KMP’s west coast Products Pipelines; and (iii) $140 million, net of tax, gain on the sale of Express. 2011 amount includes (i) $167 million non-cash loss on remeasurement of KMP’s previously held equity interest in KinderHawk to fair value; (ii) $234 million increase to KMP’s legal reserve attributable to rate case and other litigation involving KMP’s products pipelines on the West Coast and (iii) KMP’s portion ($87 million) of a $100 million special bonus expense for non-senior employees, which KMP is required to recognize in accordance with GAAP. However, KMP had no obligation, nor did it pay any amounts in respect to such bonuses. The cost of the $100 million special bonus to non-senior employees was not borne by our Class P shareholders. In May of 2011 we paid for the $100 million of special bonuses, which included the amounts allocated to KMP, using $64 million (after-tax) in available earnings and profits reserved for this purpose and not paid in dividends to our Class A shareholders.
(h)
2013 and 2012 amounts include NGPL Holdco LLC non-cash impairment charges discussed above in footnote (e). 2012 amount also represents pre-tax (income) expense associated with the EP acquisition and EP Energy sale including (i) $160 million in employee severance, retention and bonus costs; (ii) $87 million of accelerated EP stock based compensation allocated to the post-combination period under applicable GAAP rules; (iii) $37 million in advisory fees; (iv) $108 million write-off (primarily due to repayments) or amortization of capitalized financing fees; (v) $68 million for legal fees and reserves, net of recoveries; and (vi) $29 million benefit associated with pension income.
(i)
2012 amounts represent an increase in our state effective tax rate as a result of the EP acquisition.
(j)
We define sustaining capital expenditures as capital expenditures which maintain the capacity or throughput of an asset.
(k)
Declared distribution multiplied by limited partner units outstanding on the applicable record date less units owned by us. Includes distributions on KMR shares. KMP must generate the cash to cover the distributions on the KMR shares, but those distributions are paid in additional shares and KMP retains the cash. We do not have access to that cash.
(l)
Declared distribution multiplied by EPB limited partner units outstanding on the applicable record date less units owned by us.
(m)
Consists of items such as timing and other differences between earnings and cash, KMP’s and EPB’s cash flow in excess of their distributions, non-cash purchase accounting adjustments related to the EP acquisition and going private transaction primarily associated with non-cash amortization of debt fair value adjustments, and in the year ended 2011 KMP’s crude hedges.
Consolidated Earnings Results
With regard to our reportable business segments, we consider segment earnings before all DD&A expenses, and amortization of excess cost of equity investments (defined in the “-Results of Operations” tables below and sometimes referred to in this report as EBDA) to be an important measure of our success in maximizing returns to our shareholders. We also use segment EBDA internally as a measure of profit and loss used for evaluating segment performance and for deciding how to allocate resources to our six reportable business segments. EBDA may not be comparable to measures used by other companies. Additionally, EBDA should be considered in conjunction with net income and other performance measures such as operating income, income from continuing operations or operating cash flows.
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(a)
Includes revenues, earnings from equity investments, allocable interest income and other, net, less operating expenses, allocable income taxes, and other expense (income). Operating expenses include natural gas purchases and other costs of sales, operations and maintenance expenses, and taxes, other than income taxes. Allocable income tax expenses included in segment earnings for the years ended December 31, 2013, 2012 and 2011 were $133 million, $12 million and $20 million, respectively.
(b)
2013 amount includes an increase in earnings of $489 million, and 2012 and 2011 amounts include decreases in earnings of $285 million and $374 million, respectively, related to the combined effect from all of the 2013, 2012 and 2011 certain items impacting continuing operations and disclosed below in our management discussion and analysis of segment results.
(c)
2013 amount includes a decrease to expense of $4 million, and 2012 and 2011 amounts include increases in expense of $401 million and $127 million, respectively, related to the combined effect from all of the 2013, 2012 and 2011 certain items related to general and administrative expenses disclosed below in “-General and Administrative, Interest, and Noncontrolling Interests.”
(d)
2013 and 2012 amounts include increases in expense of $30 million and $107 million, respectively, related to the combined effect from all of the 2013 and 2012 certain items related to interest expense disclosed below in “-General and Administrative, Interest, and Noncontrolling Interests.”
(e)
Represents amounts attributable to KMP’s FTC Natural Gas Pipelines disposal group. 2013 amount represents an incremental loss related to the sale of KMP’s disposal group effective November 1, 2012. 2012 amount includes a combined $937 million loss from the remeasurement of net assets to fair value and the sale of KMP’s disposal group. 2011 amount includes a $10 million increase in expense from the write-off of a receivable for fuel under-collected prior to 2011. 2012 and 2011 amounts also include depreciation and amortization expenses of $7 million and $27 million, respectively.
Year Ended December 31, 2013 vs. 2012
Our total revenues for 2013 and 2012 were $14.1 billion and $10.0 billion, respectively. Income from continuing operations before income taxes totaled $3,438 million for 2013 as compared to $1,343 million in 2012.
Our income from continuing operations before income taxes (excluding income taxes allocated to segment earnings, see footnote (a)) increased by $2,095 million (156%) from $1,343 million in 2012 to $3,438 million in 2013. However, this increase included a $1,256 million increase in income from continuing operations before income taxes from the combined effect of the certain items referenced in footnotes (b), (c) and (d) in the above table.
The remaining $839 million (39%) increase in income from continuing operations before income taxes was primarily due to better overall performance from our segments in 2013 driven by the Natural Gas Pipelines segment (primarily due to a full year of contributions from the EP operations, including EPB).
Year Ended December 31, 2012 vs. 2011
Our total revenues for 2012 and 2011 were $10.0 billion and $7.9 billion, respectively. Income from continuing operations before income taxes totaled $1,343 million for 2012 as compared to $810 million in 2011.
Our income from continuing operations before income taxes (excluding income taxes allocated to segment earnings, see footnote (a)) increased by $533 million (66%) from $810 million in 2011 to $1,343 million in 2012. However, this increase included a $292 million (pre-tax) decrease in income from continuing operations before income taxes from the combined effect of the certain items referenced in footnotes (b), (c) and (d) in the above table.
After adjusting for these items, the remaining $825 million (63%) increase in income from continuing operations before income taxes was primarily due to better performance in 2012 from all reportable business segments, driven mainly by increases attributable to the Natural Gas Pipelines, due to contributions from the EP operations, including EPB, the CO2-KMP and the Terminals-KMP business segments.
Impact of the Purchase Method of Accounting on Segment Earnings (Loss)
The impacts of the purchase method of accounting on segment earnings (loss) before DD&A relate primarily to the revaluation of the accumulated other comprehensive income related to derivatives accounted for as hedges in the CO2-KMP and Natural Gas Pipelines segments. Where there is an impact to segment earnings (loss) before DD&A from the Going Private Transaction, the impact is described in the individual business segment discussions, which follow. The effects on DD&A expense result from changes in the carrying values of certain tangible and intangible assets to their estimated fair values as of May 30, 2007. This revaluation results in changes to DD&A expense in periods subsequent to May 30, 2007. The purchase accounting effects on “Unallocable interest and other, net” result principally from the revaluation of certain debt instruments to their estimated fair values as of May 30, 2007, resulting in changes to interest expense in subsequent periods.
Segment earnings before depreciation, depletion and amortization expenses
Certain items included in earnings from continuing operations are either not allocated to business segments or are not considered by management in its evaluation of business segment performance. In general, the items not included in segment results are interest expense, general and administrative expenses, DD&A and unallocable income taxes. These items are not controllable by our business segment operating managers and therefore are not included when we measure business segment operating performance. Our general and administrative expenses include such items as employee benefits insurance, rentals, unallocated litigation and environmental expenses, and shared corporate services-including accounting, information technology, human resources and legal services.
We currently evaluate business segment performance primarily based on segment earnings before DD&A in relation to the level of capital employed. Because KMP’s and EPB’s partnership agreements require them to distribute 100% of their available cash to their partners on a quarterly basis (KMP’s and EPB’s available cash consists primarily of all of its cash receipts, less cash disbursements and changes in reserves), we consider each period’s earnings before all non-cash DD&A expenses to be an important measure of business segment performance for our segments that are also segments of KMP. We account for intersegment sales at market prices. We account for the transfer of net assets between entities under common control by carrying forward the net assets recognized in the balance sheets of each combining entity to the balance sheet of the combined entity, and no other assets or liabilities are recognized as a result of the combination. Transfers of net assets between entities under common control do not affect the income statement of the combined entity.
Natural Gas Pipelines
_______
(a)
2013 amount includes a $16 million decrease related to derivative contracts used to hedge forecasted natural gas, NGL and crude oil sales.
(b)
2013, 2012 and 2011 amounts include a $490 million increase in earnings, a $202 million decrease in earnings and $168 million decrease in earnings, respectively, related to the combined effect from certain items. 2013 amount consists of (i) a $558 million gain from the remeasurement of KMP’s previously held 50% equity interest in Eagle Ford to fair value; (ii) a $36 million gain from the sale of certain Gulf Coast offshore and onshore TGP supply facilities; (iii) a $16 million decrease in earnings related to derivative contracts, as described in footnote (a); (iv) a $4 million decrease in EBDA related to SNG’s certain items; and (v) a combined $1 million increase from other certain items. 2013 and 2012 amounts include $65 million and $200 million, respectively, non-cash equity investment impairment charges related to our 20% ownership interest in NGPL Holdco LLC. 2012 amount consists of a combined $11 million increase from other certain items. 2011 amount consists of a $167 million loss from the remeasurement of KMP’s previously held 50% equity interest in KinderHawk to fair value. Also, 2013, 2012 and 2011 amounts include decreases in earnings of $20 million, $13 million, and $1 million, respectively, related to assets sold, or adjusted, that had been revalued as part of the Going Private Transaction and recorded in the application of the purchase method of accounting.
(c)
Represents EBDA attributable to KMP’s FTC Natural Gas Pipelines disposal group. 2013 amount represents a loss from the sale of net assets. 2012 amount includes a combined loss of $937 million from the remeasurement of net assets to fair value and the sale of net assets. 2011 amount includes a $10 million increase in expense from the write-off of a receivable for fuel under-collected prior to 2011. 2012 and 2011 amounts also include revenues of $227 million and $322 million, respectively.
(d)
Includes pipeline volumes for TransColorado Gas Transmission Company LLC, Midcontinent Express Pipeline LLC, Kinder Morgan Louisiana Pipeline LLC, Fayetteville Express Pipeline LLC, TGP, EPNG, Copano South Texas, the Texas intrastate natural gas pipeline group, EPB, Florida Gas Transmission Company, and Ruby Pipeline, L.L.C. Volumes for acquired pipelines are included for all periods. However these contributions to EBDA are included only for the periods subsequent to their acquisition.
(e)
Represents volumes for the Texas intrastate natural gas pipeline group .
(f)
Includes Copano operations, EP midstream assets operations, KinderHawk, Endeavor, Bighorn Gas Gathering L.L.C., Webb Duval Gatherers, Fort Union Gas Gathering L.L.C., EagleHawk, and Red Cedar Gathering Company throughput volumes. Joint venture throughput is reported at KMP’s ownership share. Volumes for acquired pipelines are included for all periods. However these contributions to EBDA are included only for the periods subsequent to their acquisition.
The certain items described in the footnotes to the table above accounted for a $1,625 million increase in our Natural Gas Pipelines business segment’s EBDA (including discontinued operations) in 2013, and a $961 million decrease in segment EBDA in 2012, when compared to the respective prior year. The certain items also accounted for a $16 million decrease in segment revenues (including discontinued operations) in 2013 when compared to 2012. Following is information, including discontinued operations, related to the segment’s remaining (i) $1,174 million (46%) and $1,574 million (162%) increases in EBDA and (ii) $3,176 million (58%) increase and $1,192 million (28%) increase in revenues in 2013 and 2012, when compared with the respective prior year:
_______
n/a - not applicable
(a)
Equity investment until May 1, 2013. On that date, as part of KMP’s Copano acquisition, it acquired the remaining 50% ownership interest that it did not already own. Prior to that date, KMP recorded earnings under the equity method of accounting, but it received distributions in amounts essentially equal to equity earnings plus our share of depreciation and amortization expenses less our share of sustaining capital expenditures (those capital expenditures which do not increase the capacity or throughput).
(b)
Primarily represents EBDA from NGPL HoldCo and the following EP assets and investments: Ruby Pipeline Holding Company, L.L.C. and Young Gas Storage Company, LTD.
(c)
Represents amounts attributable to KMP’s FTC Natural Gas Pipelines disposal group.
The significant increases and decreases in the Natural Gas Pipelines business segment’s EBDA in the comparable years of 2013 and 2012 included the following:
•
incremental earnings of $1,064 million associated with full-year contributions from assets acquired from EP, including earnings from EPB, TGP, EPNG, EP midstream asset operations, Citrus and Gulf LNG Holdings Group, LLC;
•
incremental earnings of $233 million from the Copano operations, which KMP acquired effective May 1, 2013 (but excluding Copano’s 50% ownership interest in Eagle Ford, which is included below with the 50% ownership interest it previously owned);
•
incremental earnings of $56 million (166%) from KMP’s now wholly-owned Eagle Ford natural gas gathering operations, due primarily to the incremental 50% ownership interest it acquired as part of our acquisition of Copano effective May 1, 2013, and partly to higher natural gas gathering volumes from the Eagle Ford shale formation;
•
a $16 million (5%) increase from our Texas intrastate natural gas pipeline group, due largely to higher transport margins (primarily related to higher transportation volumes from the Eagle Ford shale formation in south Texas) and lower pipeline maintenance expenses (due to both higher pipeline integrity maintenance and unexpected well repair expenses incurred in the last half of 2012), but partially offset by both lower storage margins (due mainly to timing differences on storage settlements) and lower natural gas processing margins (due mainly to lower NGL prices). The growth in revenues across both comparable years reflect higher natural gas sales revenues, driven by higher natural gas sales volumes in 2013 versus 2012. However, because the intrastate group both purchases and sells significant volumes of natural gas, and because the group generally sells natural gas in the same price environment in which it is purchased, the increases in its natural gas sales revenues were largely offset by corresponding increases in its natural gas purchase costs;
•
incremental earnings of $13 million (8%) increase from KinderHawk Field Services, driven by increased CO2 treating fees, increased gathering rates and increased minimum volume commitments, partly offset by lower throughput volumes; and
•
a $26 million (32%) decrease from KMP’s natural gas treating operations, primarily due to lower sales volumes and margins from treating equipment manufacturing.
The period-to-period decreases in EBDA from discontinued operations was due to the sale of our FTC Natural Gas Pipelines disposal group effective November 1, 2012. For further information about this sale, see Note 3 “Acquisitions and Divestitures-Divestitures-KMP’s FTC Natural Gas Pipelines Disposal Group-Discontinued Operations” to our consolidated financial statements.
Year Ended December 31, 2012 versus Year Ended December 31, 2011
__________
n/a - not applicable
(a)
Primarily represents EBDA and revenues from the following EP assets and investments: Citrus, Gulf LNG Holdings Group, LLC, Ruby Pipeline Holding Company, L.L.C., Bear Creek Storage and Young Gas Storage Company, LTD.
(b)
For these equity investment we record earnings under the equity method of accounting, but we receive distributions in amounts essentially equal to equity earnings plus our share of depreciation and amortization expenses less our share of sustaining capital expenditures.
(c)
Represents amounts attributable to KMP’s FTC Natural Gas Pipelines disposal group.
The significant increases and decreases in the Natural Gas Pipelines business segment’s EBDA in the comparable years of 2012 and 2011 included the following:
•
incremental earnings of $1,524 million from assets acquired on May 25, 2012 from EP, including earnings from EPB, EPNG and TGP;
•
incremental earnings of $58 million from KMP’s wholly-owned KinderHawk Field Services, LLC, due principally to the inclusion of a full year of operations in 2012 (KMP acquired the remaining 50% ownership interest in KinderHawk that it did not already own and began accounting for the investment under the full consolidation method effective July 1, 2011);
•
incremental earnings of $33 million due principally to the inclusion of a full year of operations in 2012 from SouthTex Treaters, Inc., which was acquired by Kinder Morgan Treating operations effective November 30, 2011;
•
a $31 million (131%) increase in equity earnings from KMP’s 50% owned Fayetteville Express Pipeline LLC-driven by a ramp-up in firm contract transportation volumes, and to lower interest expense. Higher year-over-year transportation revenues reflected a 15% increase in natural gas transmission volumes, and the decrease in interest expense related to Fayetteville Express Pipeline LLC’s refinancing of its prior bank credit facility in July 2011;
•
incremental equity earnings of $23 million from KMP’s 50%-owned Eagle Ford, which initiated flow on its natural gas gathering system on August 1, 2011; and
•
a $6 million (2%) decrease from the Texas intrastate natural gas pipeline group-driven by higher operating and maintenance expenses, lower margins on natural gas processing activities, and lower margins on natural gas sales. The increase in expenses was driven by both higher pipeline integrity maintenance and unexpected repairs at the Markham storage facility. The decrease in processing margin was mostly due to lower NGL prices, and the year-over-year decrease in sales margin was due to lower average natural gas sales prices in 2012 compared to 2011.
The overall year-to-year decrease in EBDA from discontinued operations was largely due to the loss of income due to the sale of our discontinued operations effective November 1, 2012. EBDA from the Kinder Morgan Interstate Gas Transmission pipeline system, the Trailblazer pipeline system and KMP’s investment in the Rockies Express pipeline system decreased $29 million (33%), $20 million (59%) and $17 million (19%) respectively, in 2012 versus 2011. In addition to the loss of income due to our divestiture, earnings from both pipeline systems decreased during the ten months we owned the assets in 2012 compared to the same period in 2011. The decrease was driven by lower revenues in 2012, generally related to lower net fuel recoveries, lower margins on operational natural gas sales, and excess natural gas transportation capacity existing out of the Rocky Mountain region, relative to 2011.
CO2-KMP
_______
(a)
2013, 2012 and 2011 amounts include unrealized gains of $3 million, unrealized losses of $11 million and unrealized gains of $5 million, respectively, all relating to derivative contracts used to hedge forecasted crude oil sales. Also, 2011 amount includes an increase in segment earnings resulting from a valuation adjustment of $18 million related to derivative contracts in place at the time of the Going Private Transaction and recorded in the application of the purchase method of accounting.
(b)
2013, 2012 and 2011 amounts include certain items of a $3 million increase in earnings discussed in footnote (a) above, a $4 million decrease in earnings, (net of $11 million of loss discussed in footnote (a) above and $7 million gain from the sale of KMP’s ownership interest in the Claytonville oil field unit) and $23 million increase in earnings discussed in footnote (a) above, respectively.
(c)
Includes McElmo Dome and Doe Canyon sales volumes.
(d)
Represents 100% of the production from the field. KMP owns an approximately 97% working interest in the SACROC unit, an approximately 50% working interest in the Yates unit, an approximately 99% working interest in the Katz Strawn unit and a 100% working interest in the Goldsmith Landreth unit.
(e)
Net to KMP, after royalties and outside working interests.
(f)
Includes all of KMP’s crude oil production properties.
(g)
Includes production attributable to leasehold ownership and production attributable to KMP’s ownership in processing plants and third party processing agreements.
The CO2-KMP segment’s primary businesses involve the production, marketing and transportation of both CO2 and crude oil, and the production and marketing of natural gas and NGL. We refer to the segment’s two primary businesses as its Oil and Gas Producing Activities and Sales and Transportation Activities.
Combined, the certain items described in footnotes (a) and (b) to the table above accounted for a $7 million increase in segment EBDA in 2013, and a $27 million decrease in segment EBDA in 2012, when compared to the respective prior year. The certain items also accounted for a $14 million increase in segment revenues in 2013, and a $34 million decrease in segment revenues in 2012, when compared to the respective prior year. For each of the segment’s two primary businesses, following is information related to the remaining (i) $106 million (8%) and $232 million (21%) increases in EBDA; and (ii) $166 million (10%) and $277 million (20%) increases in revenues in both 2013 and 2012, when compared with the respective prior year:
Year Ended December 31, 2013 versus Year Ended December 31, 2012
The segment’s oil and gas producing activities include the operations associated with its ownership interests in oil-producing fields and natural gas processing plants. When compared to 2012, the increase in earnings from the segment’s oil and gas producing activities in 2013 was mainly due to the following:
•
a $148 million (13%) increase in crude oil sales revenues-due primarily to higher average realized sales prices for U.S. crude oil and partly due to higher oil sales volumes. KMP’s realized weighted average price per barrel of crude oil increased 6% in 2013 versus 2012. The overall increase in oil sales revenues were also favorably impacted by a 7% increase in crude oil sales volumes, due primarily to both higher production from the Katz and SACROC field units, and to incremental production from the Goldsmith Landreth unit, which KMP acquired effective June 1, 2013 (volumes presented in the results of operations table above);
•
a $9 million (5%) decrease in natural gas plant products sales-due to a 9% decrease in KMP’s realized weighted average price per barrel of NGL, but partially offset by a 4% increase in sales volumes; and
•
a $65 million (20%) increase in operating expenses-driven primarily by higher fuel and power expenses, and higher maintenance and well workover expenses, all related to both increased drilling activity in 2013 and incremental expenses associated with the Goldsmith Landreth field unit.
EBDA from the segment’s sales and transportation activities increased by $32 million (9%) in 2013 versus 2012. The year-to-year increase in earnings was driven by (i) higher CO2 sales revenues, due to an almost 10% increase in average sales prices; (ii) higher reimbursable project revenues, largely related to the completion of prior expansion projects on the Central Basin pipeline system; and (iii) higher third party storage revenues at the Yates field unit.
When compared to 2011, the increase in earnings from the segment’s oil and gas producing activities in 2012 was mainly due to the following:
•
a $256 million (29%) increase due to higher crude oil sales revenues-driven by higher average realizations for U.S. crude oil, and increased oil production at both the Katz and SACROC field units. When compared to 2011, KMP’s realized weighted average price per barrel of crude oil increased 26% in 2012 (from $69.73 per barrel in 2011 to $87.72 per barrel in 2012);
•
a $46 million (14%) decrease due to higher combined operating expenses-driven primarily by higher well workover expenses (due to increased drilling activity) and higher severance and property tax expenses; and
•
a $26 million (13%) decrease due to lower plant product sales revenues-due to a 22% year-over-year decrease in the realized weighted average price per barrel of NGL (from $65.61 per barrel in 2011 to $50.95 per barrel in 2012). The decrease in revenues from lower prices more than offset an increase in revenues related to an overall 12% increase in plant products sales volumes.
The increase in EBDA from the segment’s sales and transportation activities in 2012 compared to 2011 was primarily revenue related, attributable to the following:
•
a $24 million (10%) increase due to higher CO2 sales revenues-driven by a 17% increase in average sales prices, due primarily to two factors: (i) a change in the mix of contracts resulting in more CO2 being delivered under higher price contracts and (ii) heavier weighting of new CO2 contract prices to the price of crude oil; and
•
a $22 million (22%) increase in all other revenues-due largely to both higher non-consent revenues and higher reimbursable project revenues. The increase in non-consent revenues related to sharing arrangements pertaining to certain expansion projects completed at the McElmo Dome unit in Colorado since the end of 2011. The increase in reimbursable revenues related to the completion of prior expansion projects on the Central Basin pipeline system.
Products Pipelines-KMP
_______
(a)
2013, 2012 and 2011 amounts include decreases in earnings of $182 million, $35 million and $233 million, respectively, related to the combined effect from certain items. 2013 amount consists of a $162 million increase in expense associated with rate case liability adjustments, a $15 million increase in expense associated with a legal liability adjustment related to a certain West Coast terminal environmental matter and a $5 million loss from the write-off of assets at KMP’s Los Angeles Harbor West Coast terminal. 2012 amount consists of a $32 million increase in expense associated with environmental liability and environmental recoverable receivable adjustments, and a combined $1 million decrease in earnings from other certain items. 2011 amount consists of a $168 million increase in expense associated with rate case liability adjustments, a $60 million increase in expense associated with rights-of-way lease payment liability adjustments, and a combined $3 million decrease in earnings from other certain items. Also, 2012 and 2011 amounts include decreases in earnings of $2 million and $2 million, respectively, related to property disposal losses, which had been revalued as part of the Going Private Transaction and recorded in the application of the purchase method of accounting.
(b)
Volumes include ethanol pipeline volumes.
(c)
Includes Pacific, Plantation Pipe Line Company, Calnev, Central Florida and Parkway pipeline volumes.
(d)
Includes Cochin and Cypress pipeline volumes.
(e)
Includes Kinder Morgan Crude & Condensate and Double Eagle Pipeline LLC pipeline volumes.
(f)
Represents total ethanol volumes, including ethanol pipeline volumes included in gasoline volumes above.
Combined, the certain items described in footnote (a) to the table above accounted for a $147 million decrease in segment EBDA in 2013, and a $198 million increase in segment EBDA in 2012, when compared with the respective prior year. Following is information related to the segment’s (i) remaining $81 million (12%) and $9 million (1%) increases in EBDA and (ii) $483 million (35%) and $456 million (50%) increases in revenues in both 2013 and 2012, when compared with the respective prior year:
_______
n/a - not applicable
The primary increases and decreases in the Products Pipelines-KMP business segment’s EBDA in 2013 compared to 2012 were attributable to the following:
•
a $27 million (174%) increase from KMP ‘s transmix processing operations-due to higher margins on processing volumes, incremental earnings from third-party sales of excess renewable identification numbers (RINS) (generated through its ethanol blending operations), and to the recognition of unfavorable net carrying value adjustments to product inventory recognized in 2012. The period-to-period increases in revenues were mainly due to the expiration of certain transmix fee-based processing agreements since the end of the third quarter of 2012. Due to the expiration of these contracts, KMP now directly purchases incremental transmix volumes and sells incremental volumes of refined products, resulting in both higher revenues and higher costs of sales expenses;
•
a $25 million (34%) increase from KMP’s Cochin Pipeline-primarily due to higher transportation revenues, driven by an overall 33% increase in pipeline throughput volumes, partly attributable to incremental ethane/propane volumes as a result of pipeline modification projects completed in June 2012;
•
incremental earnings of $14 million from KMP’s Kinder Morgan Crude & Condensate Pipeline, which began transporting crude oil and condensate volumes from the Eagle Ford shale gas formation to multiple terminaling facilities along the Texas Gulf Coast in October 2012;
•
a $6 million (9%) increase from KMP’s Southeast terminal operations, driven by higher margins from ethanol blending operations, and higher revenues from refined products and bio-fuels throughput volumes;
•
a $4 million (6%) increase from KMP’s approximate 51% interest in Plantation Pipe Line Company-due largely to higher transportation revenues driven by an 11% increase in system delivery volumes, and by higher average tariff rates since the end of 2012;
•
incremental earnings of $3 million from KMP’s 50% interest in Double Eagle Pipeline LLC-which gathers condensate and crude oil for Eagle Ford shale producers and which KMP acquired as part of its Copano acquisition effective May 1, 2013;
•
a $7 million (3%) decrease from KMP’s Pacific operations, primarily attributable to a reduction in mainline transportation revenues with a nearly 2% increase in system-wide delivery volumes. The change to transport revenues related to reductions associated with various interstate and California intrastate rate case decisions; and
•
a $9 million (5%) increase from all other represents a number of small increases at various locations.
_______
n/a - not applicable
The primary increases and decreases in the Products Pipelines-KMP business segment’s EBDA in 2012 compared to 2011 were attributable to the following:
•
a $22 million (43%) increase from the Cochin NGL pipeline system-due mainly to a $10 million increase in gross margin, and due partly to both the favorable settlement of a pipeline access dispute and a favorable 2012 income tax adjustment. The increase in gross margin was mainly due to an overall 40% increase in pipeline throughput volumes, which included incremental ethane/propane volumes related primarily to completed expansion projects since the end of 2011;
•
incremental earnings of $5 million from the Kinder Morgan Crude & Condensate Pipeline, which began transporting crude oil and condensate volumes in October 2012;
•
a $4 million (7%) increase from KMP’s approximate 51% equity interest in Plantation Pipe Line Company-due largely to higher transportation revenues driven by higher average tariff rates since the end of 2011;
•
a $4 million (5%) increase from the Southeast terminal operations-due mainly to higher butane blending revenues and increased throughput volumes of refined products and biofuels;
•
an $18 million (54%) decrease from the transmix processing operations-due primarily to a decrease in processing volumes and unfavorable net carrying value adjustments to product inventory. The year-to-year increases in revenues was due mainly to the expiration of certain transmix fee-based processing agreements in March 2012. Due to the expiration of these contracts, KMP now directly purchases incremental volumes of transmix and sells incremental volumes of refined products, resulting in both higher revenues and higher costs of sales expenses;
•
a $9 million (3%) decrease from the Pacific operations-primarily attributable to a corresponding $9 million drop in mainline transportation revenues, due primarily to lower average FERC tariffs as a result of rate case rulings settlements made since the end of 2011, and due partly to a 2% decrease in mainline delivery volumes; and
•
an $8 million (16%) decrease from Calnev-chiefly due to an approximate 9% decrease in pipeline delivery volumes that were due in part to incremental services offered by a competing pipeline.
Terminals-KMP
_______
(a)
2013, 2012 and 2011 amounts include an increase of $38 million, a decrease of $44 million, and an increase of $1 million, respectively, related to the combined effect from certain items. 2013 amount consists of (i) a $109 million increase in earnings from casualty indemnification gains; (ii) an $8 million increase in revenues related to hurricane reimbursements; (iii) a $59 million increase in clean-up and repair expense, all related to 2012 hurricane activity at the New York Harbor and Mid-Atlantic terminals; and (iv) a $3 million increase in expense associated with the removal of certain physical assets at the Tampaplex bulk terminal located in Tampa, Florida. 2012 amount consists of a $51 million increase in expense related to hurricanes Sandy and Isaac clean-up and repair activities and the associated write-off of damaged assets, a $4 million increase in expense associated with environmental liability adjustments, and a $12 million casualty indemnification gain related to a 2010 casualty at the Myrtle Grove, Louisiana, International Marine Terminal facility. 2011 amount consists of a $5 million decrease in expense (reflecting tax savings) related to non-cash compensation expense allocated to KMP from us (however, KMP does not have any obligation, nor did it pay any amounts or realize any direct benefits related to this compensation expense) and a combined $2 million decrease from other certain items. Also, 2013, 2012 and 2011 amounts include decreases of earnings of $17 million, $1 million, and $2 million, respectively, related to assets sold, which had been revalued as part of the Going Private Transaction and recorded in the application of the purchase method of accounting.
(b)
Volumes for acquired terminals are included for all periods and include KMP’s proportionate share of joint venture tonnage.
(c)
The ratio of KMP’s actual leased capacity to its estimated potential capacity.
The Terminals-KMP business segment includes the operations of petroleum, chemical and other liquids terminal facilities (other than those included in the Products Pipelines-KMP segment), and all of coal, petroleum coke, fertilizer, steel, ores and other dry-bulk material services facilities. KMP groups its bulk and liquids terminal operations into regions based on geographic location and/or primary operating function. This structure allows the management to organize and evaluate segment performance and to help make operating decisions and allocate resources.
Combined, the certain items described in footnote (a) to the table above accounted for a $82 million increase in segment EBDA in 2013, a $45 million decrease in segment EBDA in 2012, and an $8 million increase in segment revenues in 2013, when compared with the respective prior year. Following is information related to the segment’s (i) remaining $46 million (6%) and $51 million (7%) increases in EBDA and (ii) $43 million (3%) and $44 million (3%) increases in revenues in both 2013 and 2012, when compared with the respective prior year:
The overall increase in the Terminals-KMP’s EBDA in 2013 versus 2012 was driven by incremental contributions from its Gulf Liquids terminals, due primarily to higher liquids revenues from its Pasadena and Galena Park liquids facilities located along the Houston Ship Channel. The facilities benefited from high gasoline export demand, increased rail services, and new and incremental customer agreements at higher rates. For all terminals included in the Terminals-KMP business segment, total liquids leaseable capacity increased to 68.1 MMBbl at year-end 2013, up 12.7% from a capacity of 60.4 MMBbl at the end of 2012. The increase in capacity was mainly due to the acquisition of KMP’s Norfolk and Chesapeake, Virginia facilities from Allied Terminals in June 2013 (incremental contributions from these two terminals are included within the “Acquired assets and businesses” line in the two tables above), and the partial in-service of BOSTCO and Edmonton Tank expansion projects. At the same time, KMP’s overall liquids utilization rate increased 1.8% since the end of 2012.
The Rivers region earnings and revenues increased due to the in-service of the IMT Phase I and II expansion projects at KMP’s International Marine Terminal (located at Myrtle Grove, Louisiana, near the mouth of the Mississippi River). The region also benefited from lower operating and maintenance costs.
Much of the Midwest’s improvement comes from the opening in August 2013 of the BP Whiting terminal (Whiting, Indiana). Salt and ethanol increases account for the rest of the improvement.
The period-to-period increases in earnings from KMP’s Northeast terminal operations were driven by incremental contributions from KMP’s Carteret New Jersey liquids facility and KMP’s Perth Amboy, New Jersey liquids terminal. Carteret benefited from both higher non-operating income (due to insurance indemnifications received for 2012 business interruptions caused by Hurricane Sandy) and higher revenues (due in part to new and restructured customer agreements at higher rates). KMP’s Perth Amboy terminal benefited from higher year-over-year revenues, due mainly to additional and restructured customer contracts at higher rates.
Earnings from KMP’s Mid-Atlantic terminals were flat across both 2013 and 2012, as higher earnings from its Fairless Hills, Pennsylvania bulk terminal were offset by lower earnings and revenues from its Pier IX terminal, located in Newport News, Virginia. The earnings increase from Fairless Hills was primarily due to higher margins and volumes from steel and fertilizer transfers, driven by rebounding manufacturing and agricultural demand in the last half of 2013, as well as fertilizer expansion projects coming on-line. The decreases in revenues and earnings from Pier IX were due primarily to an 8% drop in coal transfer volumes, due largely to some weakening in the coal export market relative to 2012, and due partly to scheduled maintenance at the facility in the second quarter of 2013.
The remaining increases and decreases in the Terminals-KMP segment’s earnings and revenues reported in the “All others” line in the table above represent increases and decreases in terminal results at various locations; however the overall decreases across the comparable years were due in large part to (i) the loss of business effective March 31, 2013 when TRANSFLO, a wholly owned subsidiary of CSX, elected to terminate their contract with KMP’s materials handling, wholly-owned subsidiary, Kinder Morgan Materials Services (KMMS), and (ii) higher income tax expense.
The overall increase in EBDA from the Terminals-KMP business segment in 2012 compared to 2011was driven by higher contributions from the terminal facilities included in the Gulf Liquids, Mid-Atlantic and Northeast regions. The increase from the Gulf Liquids facilities was driven by higher warehousing revenues (as a result of new and renewed customer agreements at higher rates) at the Galena Park and Pasadena, Texas facilities, higher ethanol volumes through the Deer Park, Texas rail terminal, and higher overall gasoline throughput volumes. KMP also benefited from both higher capitalized overhead associated with the ongoing construction of KMP’s majority-owned Battleground Oil Specialty Terminal Company LLC terminal located on the Houston Ship Channel, and higher earnings from its crude oil storage operations located in Cushing, Oklahoma.
The year-to-year earnings increase from the Mid-Atlantic region resulted primarily from higher export coal shipments from the Pier IX terminal, and higher import steel and iron ore imports from the Fairless Hills, Pennsylvania bulk terminal. Economic expansion in developing countries generated a growth cycle in the coal export market during 2012, and due both to this growth in demand and to completed infrastructure expansions since the end of 2011, KMP’s total export coal volumes (for all terminals combined) increased by 5.7 million tons (38%) in 2012, when compared to the prior year.
The increase in earnings from the Northeast terminal operations was driven by higher contributions from the Staten Island terminal due mainly to new and favorable contract changes. Despite being affected heavily by Hurricane Sandy in 2012, the liquids terminal in Carteret, New Jersey increased earnings primarily due to higher transfer and storage rates, and to new and renegotiated contracts. KMP also benefited from incremental earnings from the Philadelphia liquids terminal, due largely to new and restructured customer contracts at higher rates, and from the Perth Amboy, New Jersey liquids terminal, due primarily to higher gasoline throughput volumes and favorable contract changes.
The incremental earnings and revenues from acquired assets and businesses primarily represent contributions from KMP’s additional equity investment in the short-line railroad operations of Watco Companies, LLC (acquired in December 2011) and its bulk terminal (acquired in June 2011) that handles petroleum coke for the Total refinery located in Port Arthur, Texas. The incremental amounts represent earnings and revenues from acquired terminals’ operations during the additional months of ownership in 2012, and do not include increases or decreases during the same months KMP owned the assets in 2011.
The remaining increases and decreases in the Terminals-KMP segment’s earnings and revenues-reported in the “All others” line in the table above-represent increases and decreases in terminal results at various locations; however the overall decreases were driven by lower results from the combined terminal operations included in the Rivers region. The decreases were mainly due to lower domestic coal transload volumes, largely the result of a drop in domestic demand relative to 2011.
Kinder Morgan Canada-KMP
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(a)
2013 amount includes both a $224 million gain from the sale of KMP’s equity and debt investments in the Express pipeline system, and an associated $84 million increase in income tax expense related to the pre-tax gain amount. 2011 amount includes a $3 million increase in earnings associated with an income tax benefit (reflecting tax savings) related to non-cash compensation expense allocated to KMP from us (however, KMP does not have any obligation, nor did it pay any amounts related to this compensation expense).
(b)
Represents Trans Mountain pipeline system volumes.
The Kinder Morgan Canada-KMP business segment includes the operations of the Trans Mountain and Jet Fuel pipeline systems and until March 14, 2013, the effective date of sale, KMP’s one-third ownership interest in the Express crude oil pipeline system. Combined, the certain items described in footnote (a) to the table above accounted for a $140 million increase in segment EBDA in 2013, and a $3 million decrease in segment EBDA in 2012, when compared with the respective prior year.
Following is information related to the segment’s (i) remaining $29 million (13%) decrease and $30 million (15%) increase in EBDA in 2013 and 2012 and (ii) $9 million (3%) decrease and $9 million (3%) increase in revenues in 2013 and 2012, when compared with the respective prior year:
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(a)
Equity investment; accordingly, KMP recorded earnings under the equity method of accounting. However, KMP sold its debt and equity investments in Express effective March 14, 2013.
The period-to-period decreases in EBDA from Express were primarily due to both lower equity earnings and lower interest income resulting from the sale of KMP’s equity and debt investments in Express effective March 14, 2013.
The decreases in Trans Mountain’s earnings were driven by (i) higher income tax expenses (due largely to general increases in British Columbia’s income tax rates since the end of the third quarter of 2012); (ii) unfavorable impacts from foreign currency translation (due to the weakening of the Canadian dollar since the end of 2012, KMP translated Canadian denominated income and expense amounts into less U.S. dollars in 2013); and (iii) lower management incentive fees earned from the operation of the Express pipeline system (due to its sale in March 2013). The period-to-period decreases in Trans Mountain’s earnings were partially offset by incremental non-operating income from allowances for funds used during construction (representing an estimate of the cost of capital funded by equity contributions).
The year-to-year increase in Trans Mountain’s EBDA was driven by a $17 million decrease in income tax expenses, associated primarily with favorable tax adjustments, recorded in 2012, related to lower taxable income relative to 2011. Trans Mountain also benefited from higher non-operating income, related primarily to incremental management incentive fees earned from its operation of the Express pipeline system. The year-over-year increase in earnings from the equity investment in the Express pipeline system was mainly due to volumes moving at higher transportation rates on the Express (Canadian) portion of the system, and to higher domestic volumes on the Platte (domestic) portion of the segment.
Other
Our other segment activities include those operations that were acquired from EP on May 25, 2012 and are primarily related to several physical natural gas contracts with power plants associated with EP’s legacy trading activities. These contracts obligate EP to sell natural gas to these plants and have various expiration dates ranging from 2012 to 2028. This segment also included an interest in the Bolivia to Brazil Pipeline, which we sold for $88 million on January 18, 2013. This segment contributed a loss of $5 million and earnings of $7 million for the years ended 2013 and 2012.
General and Administrative, Interest, and Noncontrolling Interests
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(a)
2013 includes a decrease in expense of $80 million, 2012 includes an increase in expense of $251 million, and 2011 includes a decrease in expense of $2 million, related to the combined effect from certain items. 2013 amount includes a decrease in expense of (i) $59 million related to EP post-merger pension credits; (ii) $32 million elimination of intercompany rent expense included in KMP and EPB general and administrative expenses; (iii) $5 million for an overaccrual related to The Oil Insurance Limited exit premium; (iv) $3 million related to grantor trust credit; and (v) $2 million payroll tax overaccrual; partially offset by increases in expense of (i) $14 million related to rent expense and lease exit cost on unoccupied space and (ii) $7 million related to the EP acquisition. 2012 amount includes $251 million increase of pre-tax expense associated with the EP acquisition and EP Energy sale, which includes (i) $59 million (also see footnotes (c) and (d) below for KMP and EPB portion, respectively) in employee severance, retention and bonus costs; (ii) $87 million of accelerated EP stock based compensation allocated to the post-combination period under applicable GAAP rules; (iii) $37 million in advisory fees; (iv) $68 million for legal fees and reserves, net of recoveries; and (v) $29 million of other EP acquisitions expenses; partially offset by (i) $29 million benefit associated with pension income. 2011 amount includes a net $2 million decrease in expense, which includes (i) $46 million reduction to expense for a Going Private transaction litigation insurance reimbursement; net of
increases in expense for (ii) KMI’s portion ($13 million) of a $100 million special bonus to non-senior management employees; (iii) $11 million of expense associated with our initial public offering; (iv) a $9 million increase in expense related to the EP acquisition; and (v) $10 million increase in Going Private transaction litigation expense; and (vi) a combined $1 million increase in other expense related primarily to non-cash compensation expense. The cost of the $100 million special bonus was not borne by our Class P shareholders. In May of 2011, we paid for the $100 million of special bonuses, which included the amounts allocated to KMP, using $64 million (after-tax) in available earnings and profits reserved for this purpose and not paid in dividends to our Class A shareholders. See also footnote (c) below.
(b)
2013, 2012 and 2011 amounts include NGPL Holdco LLC general and administrative reimbursements of $36 million, $35 million, and $35 million, respectively. These amounts were recorded to the “Product sales and other” caption in our accompanying consolidated statements of income with the offsetting expenses primarily included in the “General and administrative” expense caption in our accompanying consolidated statements of income.
(c)
2013, 2012 and 2011 amounts include increases in expense of $40 million, $81 million and $94 million, respectively, related to the combined effect from certain items. 2013 amount consists of (i) a $34 million increase in expense associated with certain asset and business acquisition costs and unallocated legal expenses; (ii) a $10 million increase in unallocated severance expense associated with the asset drop-down groups and allocated to KMP from us (however, KMP does not have any obligation, nor did it pay any amounts related to this expense); and (iii) a combined $4 million decrease in expense from other certain items. 2012 amount consists of $67 million in severance, retention and bonus costs and a combined $14 million increase in expense from other certain items. 2011 amount consists of a combined $90 million increase in non-cash compensation expense (including $87 million related to a special non-cash bonus expense to non-senior management employees) allocated to KMP from us; however, it does not have any obligation, nor did it pay any amounts related to this expense, and a combined $4 million increase in expense from other certain items.
(d)
2012 amount includes $34 million for severance cost. This expense is attributable to non-cash severance costs allocated to EPB from us as a result of KMI’s and EP’s merger; however, EPB does not have any obligation, nor did EPB pay any amounts related to this expense.
(e)
2013 and 2012 amounts include $21 million and $108 million, respectively, write off of capitalized financing fees, almost all of which was associated with the EP acquisition financing that was written-off (primarily due to debt repayment) or amortized. 2013 amount also includes $14 million of interest on margin for marketing contracts.
(f)
2013 includes a decrease in expense of $5 million associated with debt fair value adjustments recorded in purchase accounting for KMP’s Copano acquisition. 2012 amount includes a decrease in expense of $1 million related to the combined effect from other certain items.
(g)
Includes expenses and transactions for the periods after the May 25, 2012 EP acquisition date.
(h)
2013, 2012 and 2011 amounts include an increase of $5 million, a decrease of $4 million and a decrease of $7 million, respectively, in net income attributable to KMP’s noncontrolling interests, related to the combined effect from all of the 2013, 2012 and 2011 items previously disclosed in the footnotes to the tables included in “-Results of Operations.”
Combined, the certain items described in footnotes (a) and (b) to the table above affected KMI’s general and administrative expenses by a $330 million decrease in 2013 and $253 million increase in 2012, when compared with the respective year. The remaining changes in KMI’s general and administrative expense was essentially flat in both 2013 and 2012, when compared with the respective year.
2013 and 2012 amounts also include $9 million and $43 million, respectively, of KMP expense attributable to KMP’s drop-down asset groups for the periods prior to the acquisition dates. Combined, the certain items described in footnote (c) to the table above, and the combined $34 million decrease in expense from the drop-down asset groups expense prior to the acquisition dates, decreased KMP’s general and administrative expenses by $75 million in 2013, and increased its general and administrative expenses by $30 million in 2012, when compared with the respective prior year. The remaining $88 million (21%) and $44 million (12%) increases in general and administrative expenses in 2013 and 2012, respectively, were driven by the acquisition of additional businesses, primarily associated with KMP’s acquisition of the drop-down asset groups from us (effective August 1, 2012 and March 1, 2013), and for 2013 versus 2012, its acquisition of Copano (effective May 1, 2013). KMP also realized higher year-over-year employee benefits and payroll tax expenses, due mainly to both cost inflation increases on work-based health and insurance benefits and higher wage rates.
In the table above, we report our interest expense as “net,” meaning that we have subtracted unallocated interest income and capitalized interest from our total interest expense to arrive at one interest amount. Combined, the certain items described in footnotes (e) and (f) to the table above affected our consolidated interest expense by a $77 million decrease in 2013 and a $107 million increase in 2012, when compared with the respective prior year. Our remaining consolidated interest expense, net of interest income, increased $324 million (24%) and $633 million (90%), respectively, in 2013 and 2012 when compared with the respective prior year.
The increase in KMI’s interest expense in 2013 and 2012 compared to respective prior years was primarily due to interest expense incurred from (i) EP acquisition debt and (ii) debt assumed in the EP acquisition, see Notes 3 “Acquisition and Divestitures-KMI Acquisition of El Paso Corporation” and Note 8 “Debt” to our consolidated financial statements.
For KMP, the 2013 and 2012 amounts also include $15 million and $69 million, respectively, of KMP expense attributable to KMP’s drop-down asset groups for the periods prior to the acquisition dates. After taking into effect the certain items
described in footnote (f) to the table above, and the combined $54 million decrease in expense from the drop-down asset groups expense prior to the acquisition dates, KMP’s unallocable interest expense increased $218 million (34%) in 2013 compared to 2012, and increased $101 million (19%) in 2012 compared to 2011. For both pairs of comparable years, the increase in interest expense was attributable to higher average borrowings, and for 2013 compared to 2012, to higher effective interest rates. KMP’s average debt balances increased 24% in 2013 and 23% in 2012, when compared to the respective prior year. The increases in average borrowings were largely due to the capital expenditures, business acquisitions (including debt assumed from the drop-down transactions), and joint venture contributions KMP has made since the beginning of 2011. For more information on the capital expenditures, capital contributions, and acquisition expenditures, see “-Liquidity and Capital Resources.”
The weighted average interest rate on all of KMP’s borrowings-including both short-term and long-term amounts-increased by 9% in 2013 versus 2012, but was essentially flat across both 2012 and 2011 (the weighted average interest rate on all of KMP’s borrowings was 4.62% during 2013, 4.24% during 2012 and 4.26% during 2011). The higher average rate in 2013 was driven primarily by higher interest rates on the debt obligations KMP assumed as part of the drop-down transactions.
We, and our subsidiary KMP, use interest rate swap agreements to transform a portion of the underlying cash flows related to our long-term fixed rate debt securities (senior notes) into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. As of December 31, 2013, approximately 27% of KMI’s and 29% of KMP’s debt balances (excluding debt fair value adjustments) were subject to variable interest rates-either as short-term or long-term variable rate debt obligations or as fixed-rate debt converted to variable rates through the use of interest rate swaps. EPB did not have variable rate debt obligations as of December 31, 2013. As of December 31, 2012, approximately 47% of KMI’s and 37% of KMP’s debt balances (excluding debt fair value adjustments) were subject to variable interest rates. For more information on our interest rate swaps, see Note 13 “Risk Management-Interest Rate Risk Management” to our consolidated financial statements.
Net income attributable to noncontrolling interests, which represents the allocation of our consolidated net income (or loss) attributable to all outstanding ownership interests in our consolidated subsidiaries (primarily KMP and EPB) that are not held by us. The $1,387 million (1,238%) increase for 2013 as compared to 2012 was primarily due to our noncontrolling interest’s portion of (i) KMP’s $558 million gain from the remeasurement of its previously held 50% equity interest in Eagle Ford to fair value; (ii) KMP’s $140 million after-tax gain on the sale of its investments in the Express pipeline system; (iii) KMP’s additional income from EP assets acquired by KMP from us; (iv) KMP’s additional income from its acquisition of Copano; and (v) the 2012 non-cash loss of $937 million net of tax loss from both costs to sell and the remeasurement of KMP’s FTC Natural Gas Pipeline disposal group net assets to fair value. The $46 million (70%) increase in 2012 as compared to 2011 was primarily due to our noncontrolling interests portion of the additional income from acquisitions and partially offset by non-cash loss of $937 million from both the costs to sell and a remeasurement of the FTC Natural Gas Pipeline disposal group net assets to fair value.
Income Taxes-Continuing Operations
Year Ended December 31, 2013 versus Year Ended December 31, 2012
Our tax expense for income from continuing operations for the year ended December 31, 2013 was $742 million, as compared with 2012 income tax expense of $139 million. The $603 million increase in tax expense is due primarily to (i) higher income in 2013 attributable to KMI’s investments in KMP and EPB as compared to 2012 and (ii) tax expense as a result of KMP’s 2013 sale of its one-third interest in the Express pipeline system. These increases are partially offset by a decrease in the deferred state tax rate as a result of the March 2013 drop-down transaction and KMP’s Copano acquisition.
Year Ended December 31, 2012 versus Year Ended December 31, 2011
Our income tax expense for income from continuing operations for the year ended December 31, 2012 was $139 million, as compared with 2011 income tax expense of $361 million. The $222 million decrease in tax expense is due primarily to (i) lower income attributable to KMI as a result of costs incurred in 2012 to facilitate the EP acquisition and a $200 million impairment of our NGPL investment and (ii) a 2012 adjustment to decrease our income tax reserve for uncertain tax positions. These decreases are partially offset by (i) a 2012 adjustment to increase the deferred tax liability for a change in non tax-deductible goodwill related to our investment in KMP and (ii) the tax impact of an increase in the deferred state tax rate in 2012 as a result of the EP acquisition.
Liquidity and Capital Resources
General
As of December 31, 2013, we had a combined $598 million of “Cash and cash equivalents,” a decrease of $116 million (16%) from December 31, 2012. We believe that our cash position and remaining borrowing capacity (discussed below in “-Short-term Liquidity”), and our access to financial resources are adequate to allow us to manage our day-to-day cash requirements and anticipated obligations.
We have relied primarily on cash provided from operations to fund our operations as well as our debt interest payments, sustaining capital expenditures (those capital expenditures which do not increase the capacity or throughput), quarterly dividend payments and our subsidiaries’ quarterly distributions.
Expansion capital expenditures, acquisitions and debt principal payments, as such debt principal payments become due, have historically been funded by us and our subsidiaries through (i) additional borrowings (including commercial paper issuances by KMP); (ii) the issuance of additional common stock by us; (iii) issuance of shares by KMR with proceeds used for its purchase of additional KMP i-units; (iv) issuance of common units by KMP or EPB; and (v) and in some instances, proceeds from divestitures.
In addition, KMP has funded a portion of its historical expansion capital expenditures with retained cash, from including i-units owned by KMR in the determination of KMP’s cash distributions per unit, but paying quarterly distributions on i-units in additional i-units rather than cash and from waived incentive distributions to KMGP, KMP’s general partner. Additional information regarding KMP’s distributions and waived incentive distributions is discussed in Note 10 “Stockholders’ Equity-Noncontrolling Interests-Distributions-KMP Distributions.”
In addition to results of operations, our, KMP and EPB’s debt and capital balances are affected by financing activities, as discussed below in “-Financing Activities.”
Credit Ratings and Capital Market Liquidity
Our and our subsidiaries’ credit ratings affect our ability to access the public and private debt markets (including the commercial paper market by KMP), as well as the terms and pricing of our debt (see Part I, Item 1A “Risk Factors”). Based on our and our subsidiaries’ credit ratings as discussed below, we and our subsidiaries expect that our respective short-term liquidity needs will be met primarily through short-term borrowings. Nevertheless, our and our subsidiaries’ ability to satisfy financing requirements or fund planned capital expenditures (including our share of planned expenditures of our joint ventures) will depend upon future operating performance, which will be affected by prevailing economic conditions in the energy pipeline and terminals industries and other financial and business factors, some of which are beyond our control. KMP’s short-term corporate debt rating is A-2, Prime-2 and at Standard and Poor’s, Moody’s Investor Services and Fitch Ratings, Inc., respectively.
The following table represents KMI, KMP and EPB’s debt ratings as of December 31, 2013.
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(a) Represents senior secured credit rating
(b) Represents senior unsecured credit rating
Short-term Liquidity
As of December 31, 2013, our principal sources of short-term liquidity are (i) KMI, KMP and EPB’s respective credit facilities (discussed following); (ii) KMP’s $2.7 billion short-term commercial paper program; and (iii) cash from operations. The loan commitments under the facilities can be used to fund borrowings for the respective entity’s general corporate or partnership purposes, and KMP’s facility can be used as a backup for its commercial paper program. We provide for liquidity by maintaining a sizable amount of excess borrowing capacity related to our credit facilities and have consistently generated strong cash flow from operations, providing a source of funds of $4,064 million and $2,795 million in 2013 and 2012, respectively (the year-to-year increase is discussed below in “Cash Flows-Operating Activities”).
The following represents our primary revolving credit facilities that were available to KMI and its subsidiaries, KMP and EPB, debt outstanding under the credit facilities, including commercial paper borrowings, and available borrowing capacity under the facilities after deducting (i) outstanding letters of credit and (ii) outstanding borrowings under KMI and EPB’s credit facilities, and KMP’s commercial paper program (supported by its credit facility).
Our combined balance of short-term debt as of December 31, 2013 was $2,306 million, primarily consisting of (i) $1,154 million combined outstanding borrowings under KMI’s $1.75 billion credit facility and KMP’s $2.7 billion commercial paper program; (ii) $500 million in principal amount of KMP’s 5.125% senior notes that mature November 15, 2014; (iii) a combined $193 million of borrowings outstanding under EP credit facilities; and (iv) $207 million in principal amount of EP’s 6.875% senior notes that mature on June 15, 2014. KMP intends to refinance its current short-term debt through a combination of long-term debt, equity, and/or the issuance of additional commercial paper or credit facility borrowings to replace maturing commercial paper and current maturities of long-term debt. KMI intends to refinance its short-term debt through additional credit facility borrowings to replace maturing credit facility borrowings, issuing new long-term debt, or with proceeds from asset sales. Our combined balance of short-term debt as of December 31, 2012 was $2,401 million.
We had working capital deficits of $2,207 million and $1,554 million as of December 31, 2013 and 2012, respectively. The overall $653 million (42%) unfavorable change from year-end 2012 was primarily due to (i) an increase in “Accrued contingencies,” due largely to certain KMP transportation rate case liabilities being reclassified from long-term liabilities to short-term liabilities; (ii) a net increase in KMP’s commercial paper borrowings; (iii) a net increase in KMI and its subsidiaries (excluding KMP and EPB and its subsidiaries’) current maturities; and (iv) the sale in 2013 of our investment in BBPP Holdings Ltda and KMP’s investment in the Express pipeline system, which were included at December 31, 2012 within “Assets held for sale.” The overall increase in our working capital deficit was partially offset by a net decrease in KMI’s credit facility borrowings. Generally, our working capital balance varies due to factors such as the timing of scheduled debt payments, timing differences in the collection and payment of receivables and payables, the change in fair value of our derivative contracts, and changes in our combined cash and cash equivalent balances as a result of our or our subsidiaries’ debt or equity issuances (discussed below in “-Long-term Financing”).
KMP and EPB each employ centralized cash management programs for their U.S.-based bank accounts that essentially concentrates the cash assets of their operating partnerships and their subsidiaries in joint accounts for the purpose of providing financial flexibility and lowering the cost of borrowing. These programs provide that funds in excess of the daily needs of their operating partnerships and their subsidiaries are concentrated, consolidated or otherwise made available for use by other
entities within their consolidated group. KMP and EPB place no material restrictions on the ability to move cash between entities, payment of intercompany balances or the ability to upstream dividends to parent companies other than restrictions that may be contained in agreements governing the indebtedness of those entities. However, KMP and EPB’s cash and the cash of their subsidiaries are not concentrated into accounts of KMI or any company not in our consolidated group of companies, and KMI has no rights with respect to KMP and EPB’s cash except as permitted pursuant to their respective partnership agreements.
Furthermore, certain of KMP and EPB’s operating subsidiaries are subject to FERC-enacted reporting requirements for oil and natural gas pipeline companies that participate in cash management programs. FERC-regulated entities subject to these rules must, among other things, place their cash management agreements in writing, maintain current copies of the documents authorizing and supporting their cash management agreements, and file documentation establishing the cash management program with the FERC.
Long-term Financing
From time to time, KMI, KMP or EPB issue long-term debt securities, often referred to as senior notes. All of the senior notes of KMI, KMP or EPB issued to date, other than those issued by KMP and EPB’s subsidiaries and its operating partnerships, generally have very similar terms, except for interest rates, maturity dates and prepayment premiums. KMI and its subsidiaries’ (other than KMP and its subsidiaries and EPB and its subsidiaries’) senior notes are secured equally and ratably with KMI’s $1.75 billion senior secured revolving credit facility. All of KMP and EPB’s outstanding senior notes are unsecured obligations that rank equally with all of its other senior debt obligations. Secured debt has also been incurred by some of KMP’s operating partnerships and subsidiaries. All of the fixed rate senior notes of KMI, KMP or EPB provide that the notes may be redeemed at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date, and, in most cases, plus a make-whole premium.
As of December 31, 2013 and 2012, the consolidated balances of long-term debt, including the current portion and the preferred interest in the general partner of KMP, but excluding debt fair value adjustments was $33,062 million and $30,154 million, respectively. To date, our and our subsidiaries’ debt balances have not adversely affected our operations, our ability to grow or our ability to repay or refinance our indebtedness.
During 2013, we paid down the EP acquisition debt using $947 million of proceeds from the March 2013 drop-down transaction and $239 million of proceeds from the sale of the remainder of the EPC building note to third parties in the second quarter of 2013. We anticipate that we will continue to reduce our debt balance with proceeds from future drop-down transactions.
Based on our historical record, we believe that our capital structure will continue to allow us to achieve our business objectives. We and our subsidiaries, including KMP and EPB, are subject, however, to conditions in the equity and debt markets and there can be no assurance we will be able or willing to access the public or private markets for equity and/or long-term senior notes in the future. If we were unable or unwilling to access the equity markets, we would be required to either restrict expansion capital expenditures and/or potential future acquisitions or pursue debt financing alternatives, some of which could involve higher costs or negatively affect our or our subsidiaries’ credit ratings. Furthermore, our subsidiaries’ ability to access the public and private debt markets is affected by their respective credit ratings. See “-Credit Ratings and Capital Market Liquidity” above for a discussion of our and our subsidiaries’ credit ratings.
KMI and some of its direct and indirect subsidiaries (referred to as the Combined Other Guarantor Subsidiaries), guarantee the payment of certain of El Paso’s (formerly known as El Paso Corporation) outstanding debt. As of the successor date of August 13, 2012, each series of El Paso outstanding notes in aggregate principal amount became guaranteed on a senior unsecured basis by KMI and the Combined Other Guarantor Subsidiaries. As of December 31, 2013 and 2012, approximately $3.8 billion and $3.9 billion, respectively, in aggregate principal amount of these series of El Paso senior notes is outstanding. See Note 19 “Guarantee of Securities of Subsidiaries” to our consolidated financial statements.
For additional information about our debt-related transactions in 2013, see Note 8 “Debt” to our consolidated financial statements. For information about our interest rate risk, see
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Generally, our market risk sensitive instruments and positions have been determined to be “other than trading.” Our exposure to market risk as discussed below includes forward-looking statements and represents an estimate of possible changes in fair value or future earnings that would occur assuming hypothetical future movements in energy commodity prices or interest rates. Our views on market risk are not necessarily indicative of actual results that may occur and do not represent the maximum possible gains and losses that may occur, since actual gains and losses will differ from those estimated based on actual fluctuations in energy commodity prices or interest rates and the timing of transactions.
Energy Commodity Market Risk
We are exposed to energy commodity market risk and other external risks in the ordinary course of business. However, we take steps to hedge, or limit our exposure to, these risks by executing a hedging strategy that seeks to protect us financially against adverse price movements and serves to minimize potential losses. Our strategy involves the use of certain energy commodity derivative contracts to reduce and minimize the risks associated with unfavorable changes in the market price of natural gas, NGL and crude oil. The derivative contracts that we or KMP use include energy products traded on the NYMEX and OTC markets, including, but not limited to, futures and options contracts, fixed price swaps and basis swaps.
As part of the EP acquisition, we acquired power forward and swap contracts. We have entered into offsetting positions that eliminate the price risks associated with our power contracts. As part of the May 1, 2013 Copano acquisition, KMP acquired derivative contracts related to natural gas, NGL and crude oil. None of these derivatives are designated as accounting hedges.
Fundamentally, our hedging strategy involves taking a simultaneous financial position in the futures market that is equal and opposite to our physical position, or anticipated position, in the cash market (or physical product) in order to minimize the risk of financial loss from an adverse price change. For example, as sellers of crude oil and natural gas, KMP often enters into fixed price swaps and/or futures contracts to guarantee or lock-in the sale price of its crude oil or the margin from the sale and purchase of its natural gas at the time of market delivery, thereby in whole or in part offsetting any change in prices, either positive or negative. A hedge is successful to the extent gains or losses in the cash market are neutralized by losses or gains in the futures transaction.
Our policies require that derivative contracts are only entered into with carefully selected major financial institutions or similar counterparties based upon their credit ratings and other factors, and we maintain strict dollar and term limits that correspond to our counterparties’ credit ratings. While it is our policy to enter into derivative transactions principally with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that losses will result from counterparty credit risk in the future.
The credit ratings of the primary parties from whom we transact in energy commodity derivative contracts (based on contract market values) are as follows (credit ratings per Standard & Poor’s Rating Service):
As discussed above, the principal use of energy commodity derivative contracts is to mitigate the market price risk associated with anticipated transactions for the purchase and sale of natural gas, NGL and crude oil. Using derivative contracts for this purpose helps provide increased certainty with regard to operating cash flows which helps us and our subsidiaries to undertake further capital improvement projects, attain budget results and meet dividend/distribution targets. We may categorize such use of energy commodity derivative contracts as cash flow hedges because the derivative contract is used to hedge the anticipated future cash flow of a transaction that is expected to occur but which value is uncertain. Cash flow hedges are defined as hedges made with the intention of decreasing the variability in cash flows related to future transactions, as opposed to the value of an asset, liability or firm commitment, and we are allowed special hedge accounting treatment for such derivative contracts.
In accounting for cash flow hedges, gains and losses on the derivative contracts are reported in other comprehensive income, outside “Net Income” reported in our consolidated statements of income, but only to the extent that the gains and losses from the change in value of the derivative contracts can later offset the loss or gain from the change in value of the hedged future cash flows during the period in which the hedged cash flows affect net income. That is, for cash flow hedges, all effective components of the derivative contracts’ gains and losses are recorded in other comprehensive income, pending occurrence of the expected transaction. Other comprehensive income consists of those financial items that are within “Accumulated other comprehensive loss” in our accompanying consolidated balance sheets but not included in our net income (portions attributable to our noncontrolling interests are within “Noncontrolling interests” and are not included in our net income). Thus, in highly effective cash flow hedges, where there is no ineffectiveness, other comprehensive income changes by exactly as much as the derivative contracts and there is no impact on earnings until the expected transaction occurs.
All remaining gains and losses on the derivative contracts (the ineffective portion and those contracts not designated as hedges) are included in current net income. The ineffective portion of the gain or loss on the derivative contracts is the difference between the gain or loss from the change in value of the derivative contract and the effective portion of that gain or loss. In addition, when the hedged forecasted transaction does take place and affects earnings, the effective part of the hedge is also recognized in the income statement, and the earlier recognized effective amounts are removed from “Accumulated other comprehensive loss” (and “Noncontrolling interests”) and are transferred to the income statement as well, effectively offsetting the changes in cash flows stemming from the hedged risk. If the forecasted transaction results in an asset or liability, amounts should be reclassified into earnings when the asset or liability affects earnings through cost of sales, depreciation, interest expense, etc.
We measure the risk of price changes in the natural gas, crude oil and power derivative instruments portfolios utilizing a sensitivity analysis model. The sensitivity analysis applied to each portfolio measures the potential income or loss (i.e., the change in fair value of the derivative instrument portfolio) based upon a hypothetical 10% movement in the underlying quoted market prices. In addition to these variables, the fair value of each portfolio is influenced by fluctuations in the notional amounts of the instruments and the discount rates used to determine the present values. As of December 31, 2013 and 2012, a hypothetical 10% movement in underlying commodity natural gas prices would affect the estimated fair value of natural gas derivatives, held by us and KMP, by $15 million and $7 million, respectively. As of both December 31, 2013 and 2012, a hypothetical 10% movement in underlying commodity crude oil prices would affect the estimated fair value of crude oil derivatives, held by KMP, by $201 million and $196 million, respectively. As of December 31, 2013, a hypothetical 10% movement in underlying commodity NGL prices would affect the estimated fair value of KMP’s NGL derivatives by $5 million. As of December 31, 2013, a hypothetical 10% movement in underlying commodity electricity prices would not affect the estimated fair value of our power derivatives. As of December 31, 2012, a hypothetical 10% movement in underlying commodity electricity prices would affect the estimated fair value of our power derivatives by $2 million. As discussed above, we enter into derivative contracts largely for the purpose of mitigating the risks that accompany certain of our business activities and, therefore both in the sensitivity analysis model and in reality, the change in the market value of the derivative contracts portfolio is offset largely by changes in the value of the underlying physical transactions.
Our sensitivity analysis represents an estimate of the reasonably possible gains and losses that would be recognized on the natural gas, crude oil, NGL and power portfolios of derivative contracts (including commodity futures and options contracts, fixed price swaps and basis swaps) assuming hypothetical movements in future market rates and is not necessarily indicative of actual results that may occur. It does not represent the maximum possible loss or any expected loss that may occur, since actual future gains and losses will differ from those estimated. Actual gains and losses may differ from estimates due to actual fluctuations in market rates, operating exposures and the timing thereof, as well as changes in our portfolio of derivatives during the year.
Interest Rate Risk
In order to maintain a cost effective capital structure, it is our policy to borrow funds using a mix of fixed rate debt and variable rate debt. The market risk inherent in our debt instruments and positions is the potential change arising from increases or decreases in interest rates as discussed below.
For fixed rate debt, changes in interest rates generally affect the fair value of the debt instrument, but not our earnings or cash flows. Conversely, for variable rate debt, changes in interest rates generally do not impact the fair value of the debt instrument, but may affect our future earnings and cash flows. Generally, there is not an obligation to prepay fixed rate debt prior to maturity and, as a result, interest rate risk and changes in fair value should not have a significant impact on the fixed rate debt until we would be required to refinance such debt.
As of December 31, 2013 and 2012, the carrying values of the fixed rate debt (including the debt fair value adjustments) were $33,129 million and $29,554 million, respectively. These amounts compare to, as of December 31, 2013 and 2012, fair values of $33,185 million and $31,882 million, respectively. Fair values were determined using quoted market prices, where applicable, or future cash flow discounted at market rates for similar types of borrowing arrangements. A hypothetical 10% change in the average interest rates applicable to such debt for 2013 and 2012, would result in changes of approximately $1,185 million and $1,048 million, respectively, in the fair values of these instruments.
The carrying value of the variable rate debt (which approximates the fair value), excluding the value of interest rate swap agreements (discussed following), was $3,064 million and $4,847 million as of December 31, 2013 and 2012, respectively. As of December 31, 2013, KMI and KMP were party to interest rate swap agreements with notional principal amounts of $725 million and $4,675 million, respectively. As of December 31, 2012, KMI and KMP were party to interest rate swap agreements with notional principal amounts of $725 million and $5,525 million, respectively. An interest rate swap agreement is a contractual agreement entered into between two counterparties under which each agrees to make periodic interest payments to the other for an agreed period of time based upon a predetermined amount of principal, which is called the notional principal amount. Normally at each payment or settlement date, the party who owes more pays the net amount; so at any given settlement date only one party actually makes a payment. The principal amount is notional because there is no need to exchange actual amounts of principal. A hypothetical 10% change in the weighted average interest rate on all of our borrowings (approximately 51 basis points in 2013 and approximately 49 basis points in 2012) when applied to our outstanding balance of variable rate debt as of December 31, 2013 and 2012, including adjustments for the notional swap amounts described above, would result in changes of approximately $43 million and $55 million, respectively, in our 2013 and 2012 annual pre-tax earnings. As of both December 31, 2013 and 2012, EPB had no interest rate swap agreements outstanding.
Interest rate swap agreements are entered into for the purpose of transforming a portion of the underlying cash flows related to long-term fixed rate debt securities into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. Since the fair value of fixed rate debt varies with changes in the market rate of interest, swap agreements are entered into to receive a fixed and pay a variable rate of interest. Such swap agreements result in future cash flows that vary with the market rate of interest, and therefore hedge against changes in the fair value of the fixed rate debt due to market rate changes.
We monitor the mix of fixed rate and variable rate debt obligations in light of changing market conditions and from time to time through our subsidiaries, may alter that mix by, for example, refinancing outstanding balances of variable rate debt with fixed rate debt (or vice versa) or by entering into interest rate swap agreements or other interest rate hedging agreements. In general, KMP attempts to maintain an overall target mix of approximately 50% fixed rate debt and 50% of variable rate debt, and typically KMI, excluding KMP, targets well below that level for variable rate debt. As of December 31, 2013, approximately 27% of KMI’s debt, excluding that of KMP and EPB, is variable rate debt.
For more information on our interest rate risk management and on our interest rate swap agreements, see Note 13 “Risk Management” to our consolidated financial statements.
Item 8. Financial Statements and Supplementary Data.
The information required in this Item 8 is in this report as set forth in the “Index to Financial Statements” on page 103.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A. Controls and Procedures.
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
As of December 31, 2013, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an assessment of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, our management concluded that our internal control over financial reporting was effective as of December 31, 2013.
The effectiveness of our internal control over financial reporting as of December 31, 2013, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their audit report, which appears herein.
We acquired the full ownership interest in Copano effective May 1, 2013. Copano provides comprehensive services to natural gas producers, including natural gas gathering, processing, treating and NGL fractionation. Its operations are located primarily in Texas, Oklahoma and Wyoming. We included most of Copano’s businesses within our Natural Gas Pipelines business segment; however, we included its 50% equity ownership interest in Double Eagle Pipeline LLC within our Products Pipelines business segment. We excluded all of the acquired Copano businesses from the scope of our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2013. Copano constituted 9% of our total revenues for 2013 and 8% of our total assets as of December 31, 2013.
Changes in Internal Control Over Financial Reporting
There has been no change in our internal control over financial reporting during the fourth quarter of 2013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information.
None.
PART III
Item 10. Directors, Executive Officers and Corporate Governance.
The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2013 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2013.
Item 11. Executive Compensation.
The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2013 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2013.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2013 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2013.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2013 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2013.
Item 14. Principal Accounting Fees and Services.
The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2013 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2013.
PART IV
Item 15. Exhibits, Financial Statement Schedules.
(a)
(1)Financial Statements and (2) Financial Statement Schedules
See “Index to Financial Statements” set forth on Page 103.
The financial statements, including the notes thereto, of KMP and EPB , consolidated subsidiaries of Kinder Morgan, Inc., are incorporated herein by reference to pages 106 through 185 of Kinder Morgan Energy Partners, L.P. Annual Report on Form 10-K for the year ended December 31, 2013 and pages 63 through 98 of El Paso Pipeline Partners, L.P. Annual Report on Form 10-K for the year ended December 31, 2013.
(3)
Exhibits
Exhibit
Number
Description
2.1*
-
Agreement and Plan of Merger, dated as of October 16, 2011, among Kinder Morgan, Inc., Sherpa Merger Sub, Inc., Sherpa Acquisition, LLC, Sirius Holdings Merger Corporation, Sirius Merger Corporation and El Paso Corporation (included as Annex A to the information statement/proxy statement/prospectus forming a part of Kinder Morgan, Inc.’s Registration Statement on Form S-4 (File No. 333-177895) filed on November 10, 2011)
2.2*
-
Agreement and Plan of Merger, dated as of October 16, 2011, by and among El Paso Corporation, Sirius Holdings Merger Corporation and Sirius Merger Corporation (included as Annex B to the information statement/proxy statement/prospectus forming a part of Kinder Morgan, Inc.’s Registration Statement on Form S-4 (File No. 333-177895) filed on November 10, 2011)
3.1*
-
Certificate of Incorporation of Kinder Morgan, Inc. (filed as Exhibit 3.1 to Kinder Morgan, Inc.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011 (File No. 1-35081) (the “KMI 10-Q”))
3.2*
-
Amended and Restated Bylaws of Kinder Morgan, Inc. (filed as Exhibit 3.1 to Kinder Morgan, Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2012 (File No. 1-35081))
4.1*
-
Form of certificate representing Class P common shares of Kinder Morgan, Inc. (filed as Exhibit 4.1 to Kinder Morgan, Inc.’s Registration Statement on Form S-1 filed on January 18, 2011 (File No. 333-170773))
4.2*
-
Shareholders Agreement among Kinder Morgan, Inc. and certain holders of common stock (filed as Exhibit 4.2 to the KMI 10-Q)
4.3*
-
Amendment No. 1 to the Shareholders Agreement among Kinder Morgan, Inc. and certain holders of common stock (filed as Exhibit 4.3 Kinder Morgan, Inc.’s Current Report on Form 8-K filed on May 30, 2012 (File No. 1-35081))
4.4*
-
Warrant Agreement, dated as of May 25, 2012, among Kinder Morgan, Inc., Computershare Trust Company, N.A. and Computershare Inc., as Warrant Agent (filed as Exhibit 4.1 to Kinder Morgan Inc.’s Current Report on Form 8-K filed on May 30, 2012 (File No. 1-35081))
10.1*
-
Kinder Morgan, Inc. 2011 Stock Incentive Plan (filed as Exhibit 10.1 to the KMI 10-Q)
10.2*
-
Form of Restricted Stock Agreement (filed as Exhibit 10.2 to the KMI 10-Q)
10.3*
-
Kinder Morgan, Inc. Stock Compensation Plan for Non-Employee Directors (filed as Exhibit 10.4 to the KMI 10-Q)
10.4*
-
Form of Non-Employee Director Stock Compensation Agreement (filed as Exhibit 10.3 to the KMI 10-Q)
10.5*
-
Kinder Morgan, Inc. Employees Stock Purchase Plan (filed as Exhibit 10.5 to the KMI 10-Q)
10.6*
-
Kinder Morgan, Inc. Annual Incentive Plan (filed as Exhibit 10.6 to the KMI 10-Q)
10.7*
-
Employment Agreement dated October 7, 1999, between K N Energy, Inc. and Richard D. Kinder (filed as Exhibit 99.D of the Schedule 13D filed by Mr. Kinder on November 16, 1999 (File No. 5-06259))
10.8*
-
Form of Purchase Provisions between Kinder Morgan Management, LLC and Kinder Morgan Kansas, Inc. (included as Annex B to the Second Amended and Restated Limited Liability Company Agreement of Kinder Morgan Management, LLC filed as Exhibit 3.1 to Kinder Morgan Management, LLC’s Current Report on Form 8-K filed on May 30, 2007 (File No. 1-16459))
10.9*
-
Credit Agreement, dated as of May 30, 2007, among Kinder Morgan Kansas, Inc. and Kinder Morgan Acquisition Co., as the borrower, the several lenders from time to time parties thereto, and Citibank, N.A., as administrative agent and collateral agent (filed as Exhibit 10.10 to Kinder Morgan, Inc.’s Registration Statement on Form S-1 filed on December 30, 2010 (File No. 333-170773))
10.10*
-
Registration Rights Agreement among Kinder Morgan Management, LLC, Kinder Morgan Energy Partners, L.P. and Kinder Morgan Kansas, Inc. dated May 18, 2001 (filed as Exhibit 4.7 to Kinder Morgan Kansas, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2002 (File No. 1-06446))
10.11*
-
Form of Indenture dated as of August 27, 2002 between Kinder Morgan Kansas, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.1 to Kinder Morgan Kansas, Inc.’s Registration Statement on Form S-4 filed on October 4, 2002 (File No. 333-100338))
10.12*
-
Form of First Supplemental Indenture dated as of December 6, 2002 between Kinder Morgan Kansas, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.2 to Kinder Morgan Kansas, Inc.’s Registration Statement on Form S-4 filed on January 31, 2003 (File No. 333-102873))
10.13*
-
Form of 6.50% Note due 2012 (included in the Indenture filed as Exhibit 4.1 to Kinder Morgan Kansas, Inc.’s Registration Statement on Form S-4 filed on October 4, 2002 (File No. 333-100338))
10.14*
-
Form of Senior Indenture between Kinder Morgan Kansas, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.2 to Kinder Morgan Kansas, Inc.’s Registration Statement on Form S-3 filed on February 4, 2003 (File No. 333-102963))
10.15*
-
Form of Senior Note of Kinder Morgan Kansas, Inc. (included in the Form of Senior Indenture filed as Exhibit 4.2 to Kinder Morgan Kansas, Inc.’s Registration Statement on Form S-3 filed on February 4, 2003 (File No. 333-102963))
10.16*
-
Indenture dated as of December 9, 2005, among Kinder Morgan Finance Company LLC (formerly Kinder Morgan Finance Company, ULC), Kinder Morgan Kansas, Inc. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.1 to Kinder Morgan Kansas, Inc.’s Current Report on Form 8-K filed on December 15, 2005 (File No. 1-06446))
10.17*
-
Forms of Kinder Morgan Finance Company LLC Notes (included in the Indenture filed as Exhibit 4.1 to Kinder Morgan Kansas, Inc.’s Current Report on Form 8-K filed on December 15, 2005 (File No. 1-06446))
10.18*
-
Form of Indemnification Agreement between Kinder Morgan Kansas, Inc. and each member of the Special Committee of the Board of Directors formed in connection with the Going Private Transaction (filed as Exhibit 10.1 to Kinder Morgan Kansas, Inc.’s Current Report on Form 8-K filed on June 16, 2006 (File No. 1-06446))
10.19*
-
Delegation of Control Agreement among Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan Energy Partners, L.P. and its operating partnerships (filed as Exhibit 10.1 to the Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter ended June 30, 2001 (File No. 1-11234))
10.20*
-
Amendment No. 1 to Delegation of Control Agreement, dated as of July 20, 2007, among Kinder Morgan G.P., Inc., Kinder Morgan Management, LLC, Kinder Morgan Energy Partners, L.P. and its operating partnerships (filed as Exhibit 10.1 to Kinder Morgan Energy Partners, L.P.’s Current Report on Form 8-K on July 20, 2007 (File No. 1-11234))
10.21*
-
Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 3.1 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter ended June 30, 2001 (File No. 1-11234))
10.22*
-
Amendment No. 1 dated November 19, 2004 to Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 99.1 to Kinder Morgan Energy Partners, L.P. Form 8-K filed November 22, 2004 (File No. 1-11234))
10.23*
-
Amendment No. 2 to Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 99.1 to Kinder Morgan Energy Partners, L.P. Form 8-K filed May 5, 2005 (File No. 1-11234))
10.24*
-
Amendment No. 3 to Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 3.1 to Kinder Morgan Energy Partners, L.P. Form 8-K filed April 21, 2008 (File No. 1-11234))
10.25*
-
Amendment No. 4 to Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 3.5 to Kinder Morgan Energy Partners, L.P. Form 10-K 2012 (File No. 1-11234))
10.26*
-
Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors (filed as Exhibit 10.2 to Kinder Morgan Energy Partners, L.P. Form 8-K filed January 21, 2005 (File No. 1-11234))
10.27*
-
Form of Common Unit Compensation Agreement entered into with Non-Employee Directors (filed as Exhibit 10.1 to Kinder Morgan Energy Partners, L.P. Form 8-K filed January 21, 2005 (File No. 1-11234))
10.28*
-
Credit Agreement dated as of June 23, 2010 among Kinder Morgan Energy Partners, L.P., Kinder Morgan Operating L.P. “B”, the lenders party thereto, Wells Fargo Bank, National Association as Administrative Agent, Bank of America, N.A., Citibank, N.A., JPMorgan Chase Bank, N.A., and DnB NOR Bank ASA (filed as exhibit 10.1 to Kinder Morgan Energy Partners, L.P. Current Report on Form 8-K filed June 24, 2010 (File No. 1-11234))
10.29*
-
First Amendment to Credit Agreement, dated as of July 1, 2011, among Kinder Morgan Energy Partners, L.P., Kinder Morgan Operating L.P. “B”, the lenders party thereto and Wells Fargo Bank, National Association, as Administrative Agent (filed as Exhibit 10.1 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 (File No. 1-11234))
10.30*
-
Indenture dated as of January 29, 1999 among Kinder Morgan Energy Partners, L.P., the guarantors listed on the signature page thereto and U.S. Trust Company of Texas, N.A., as trustee, relating to Senior Debt Securities (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Current Report on Form 8-K filed February 16, 1999 (File No. 1-11234))
10.31*
-
Indenture dated November 8, 2000 between Kinder Morgan Energy Partners, L.P. and First Union National Bank, as Trustee (filed as Exhibit 4.8 to Kinder Morgan Energy Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2001 (File No. 1-11234))
10.32*
-
Indenture dated January 2, 2001 between Kinder Morgan Energy Partners, L.P. and First Union National Bank, as trustee, relating to Senior Debt Securities (including form of Senior Debt Securities) (filed as Exhibit 4.11 to Kinder Morgan Energy Partners, L.P. Annual Report on Form 10-K for the year ended December 31, 2000 (File No. 1-11234))
10.33*
-
Certificate of Vice President and Chief Financial Officer of Kinder Morgan Energy Partners, L.P. establishing the terms of the 6.75% Notes due March 15, 2011 and the 7.40% Notes due March 15, 2031 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P. Current Report on Form 8-K filed on March 14, 2001 (File No. 1-11234))
10.34*
-
Specimen of 7.40% Notes due March 15, 2031 in book-entry form (filed as Exhibit 4.3 to Kinder Morgan Energy Partners, L.P. Current Report on Form 8-K filed on March 14, 2001(File No. 1-11234))
10.35*
-
Certificate of Vice President and Chief Financial Officer of Kinder Morgan Energy Partners, L.P. establishing the terms of the 7.125% Notes due March 15, 2012 and the 7.750% Notes due March 15, 2032 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P. Quarterly Report on Form 10-Q for the quarter ended March 31, 2002 (File No. 1-11234))
10.36*
-
Specimen of 7.750% Notes due March 15, 2032 in book-entry form (filed as Exhibit 4.3 to Kinder Morgan Energy Partners, L.P. Quarterly Report on Form 10-Q for the quarter ended March 31, 2002 (File No. 1-11234))
10.37*
-
Indenture dated August 19, 2002 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.1 to the Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-4 filed on October 4, 2002 (File No. 333-100346))
10.38*
-
First Supplemental Indenture to Indenture dated August 19, 2002, dated August 23, 2002 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-4 filed on October 4, 2002 (File No. 333-100346))
10.39*
-
Form of 7.30% Note (contained in the Indenture filed as Exhibit 4.1 to the Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-4 filed on October 4, 2002 (File No. 333-100346))
10.40*
-
Senior Indenture dated January 31, 2003 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National Association (filed as Exhibit 4.2 to the Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-3 filed on February 4, 2003 (File No. 333-102961))
10.41*
-
Form of Senior Note of Kinder Morgan Energy Partners, L.P. (included in the Form of Senior Indenture filed as Exhibit 4.2 to the Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-3 filed on February 4, 2003 (File No. 333-102961))
10.42*
-
Certificate of Vice President, Treasurer and Chief Financial Officer and Vice President, General Counsel and Secretary of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P. establishing the terms of the 5.00% Notes due December 15, 2013 (filed as Exhibit 4.25 to Kinder Morgan Energy Partners, L.P. Annual Report on Form 10-K for the year ended December 31, 2003 (File No. 1-11234))
10.43*
-
Certificate of Executive Vice President and Chief Financial Officer and Vice President, General Counsel and Secretary of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P. establishing the terms of the 5.125% Notes due November 15, 2014 (filed as Exhibit 4.27 to Kinder Morgan Energy Partners, L.P. Annual Report on Form 10-K for the year ended December 3, 2004 (File No. 1-11234))
10.44*
-
Certificate of Vice President, Treasurer and Chief Financial Officer and Vice President, General Counsel and Secretary of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P. establishing the terms of the 5.80% Notes due March 15, 2035 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P. Quarterly Report on Form 10-Q for the quarter ended March 31, 2005 (File No. 1-11234))
10.45*
-
Certificate of Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P. establishing the terms of the 6.00% Senior Notes due 2017 and 6.50% Senior Notes due 2037 (filed as Exhibit 4.28 to Kinder Morgan Energy Partners, L.P. Annual Report on Form 10-K for the year ended December 31, 2006 (File No. 1-11234))
10.46*
-
Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 6.95% Senior Notes due 2038 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 (File No. 1-11234))
10.47*
-
Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 5.85% Senior Notes due 2012 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Quarterly Report on Form 10-Q for the quarter ended September 30, 2007 (File No. 1-11234))
10.48*
-
Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 5.95% Senior Notes due 2018 (filed as Exhibit 4.28 to Kinder Morgan Energy Partners, L.P. Annual Report on Form 10-K for the year ended December 31, 2007 (File No. 1-11234))
10.49*
-
Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 9.00% Senior Notes due 2019 (filed as Exhibit 4.29 to Kinder Morgan Energy Partners, L.P. Annual Report on Form 10-K for the year ended December 31, 2008 (File No. 1-11234))
10.50*
-
Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 5.625% Senior Notes due 2015, and the 6.85% Senior Notes due 2020 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Quarterly Report on Form 10-Q for the quarter ended June 30, 2009 (File No. 1-11234))
10.51*
-
Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 5.80% Senior Notes due 2021, and the 6.50% Senior Notes due 2039 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Quarterly Report on Form 10-Q for the quarter ended September 30, 2009 (File No. 1-11234))
10.52*
-
Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 5.30% Senior Notes due 2020, and the 6.55% Senior Notes due 2040 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 (File No. 1-11234))
10.53*
-
Indenture, dated December 20, 2010, among Kinder Morgan Finance Company LLC, Kinder Morgan Kansas, Inc. and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to Kinder Morgan Kansas, Inc.’s Current Report on Form 8-K filed on December 23, 2010 (File No. 1-06446))
10.54*
-
Officers’ Certificate establishing the terms of the 6.000% Senior Notes due 2018 of Kinder Morgan Finance Company LLC (with the form of note attached thereto) (filed as Exhibit 4.2 to Kinder Morgan Kansas, Inc.’s Current Report on Form 8-K filed on December 23, 2010 (File No. 1-06446))
10.55*
-
Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 3.500% Senior Notes due 2016, and the 6.375% Senior Notes due 2041 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-K for the quarter ended March 31, 2011)
10.56*
-
Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 4.150% Senior Notes due 2022, and the 5.625% Senior Notes due 2041 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-K for the quarter ended September 30, 2011)
10.57*
-
Severance Agreement with C. Park Shaper (filed as Exhibit 10.7 to the KMI 10-Q)
10.58*
-
Severance Agreement with Steven J. Kean (filed as Exhibit 10.8 to the KMI 10-Q)
10.59*
-
Severance Agreement with Kimberly A. Dang (filed as Exhibit 10.9 to the KMI 10-Q)
10.60*
-
Severance Agreement with Joseph Listengart (filed as Exhibit 10.10 to the KMI 10-Q)
10.61*
-
Debt Commitment Letter between Kinder Morgan, Inc. and Barclays Capital PLC, dated as of October 16, 2011 (filed as Exhibit 10.71 to Kinder Morgan, Inc.’s Registration Statement on Form S-4 filed on December 14, 2011 (File No. 333-177895))
12.1
-
Statement re: computation of ratio of earnings to fixed charges.
21.1
-
Subsidiaries of Kinder Morgan, Inc.
23.1
-
Consent of PricewaterhouseCoopers LLP.
23.2
-
Consent of Netherland, Sewell & Associates, Inc.
23.3
-
Consent of Ryder Scott Company, L.P.
31.1
-
Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2
-
Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1
-
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2
-
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
95.1
-
Mine Safety Disclosures.
99.1*
-
The financial statements of Kinder Morgan Energy Partners, L.P. and subsidiaries (incorporated by reference to pages 106 through 185 of the Annual Report on Form 10-K of Kinder Morgan Energy Partners, L.P. for the year ended December 31, 2013, filed on February 18, 2014).
99.2*
-
The financial statements of El Paso Pipeline Partners, L.P. and subsidiaries (incorporated by reference to pages 63 through 98 of the Annual Report on Form 10-K of El Paso Pipeline Partners, L.P. for the year ended December 31, 2013, filed on February 19, 2014).
99.3
-
Netherland, Sewell & Associates, Inc.’s report of estimates of the net reserves and future net revenues, as of December 31, 2013, related to Kinder Morgan CO2 Company, L.P.’s interest in certain oil and gas properties located in the state of Texas.
99.4
-
Ryder Scott Company, L.P.’s report of estimates of the net reserves and future net revenues, as of December 31, 2013, related to Kinder Morgan CO2 Company, L.P.’s interest in certain oil and gas properties located in the state of Texas.
-
Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Statements of Income for the years ended December 31, 2013, 2012, and 2011; (ii) our Consolidated Statements of Comprehensive Income for the years ended December 31, 2013, 2012, and 2011; (iii) our Consolidated Balance Sheets as of December 31, 2013 and 2012; (iv) our Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012, and 2011; (v) our Consolidated Statement of Stockholders’ Equity as of and for the years ended December 31, 2013, 2012, and 2011; and (vi) the notes to our Consolidated Financial Statements.
_______
*Asterisk indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith, except as noted otherwise.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Kinder Morgan, Inc.:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of comprehensive income, of stockholders’ equity and of cash flows present fairly, in all material respects, the financial position of Kinder Morgan, Inc. and its subsidiaries (the “Company”) at December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing in Item 9A of the Company’s 2013 Annual Report on Form 10-K. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
As described in Management’s Report on Internal Control over Financial Reporting appearing in Item 9A of the Company’s 2013 Annual Report on Form 10-K, management has excluded Copano Energy, L.L.C. from its assessment of internal control over financial reporting as of December 31, 2013 because it was acquired in a purchase business combination by Kinder Morgan Energy Partners, L.P. on May 1, 2013. We have also excluded Copano Energy, L.L.C. from our audit of internal control over financial reporting. Copano Energy, L.L.C. is a wholly-owned subsidiary whose total assets and total revenues represent 8% and 9%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2013.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 21, 2014
The accompanying notes are an integral part of these consolidated financial statements.
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In Millions)
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Millions)
The accompanying notes are an integral part of these consolidated financial statements.
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)
(In Millions)
The accompanying notes are an integral part of these consolidated financial statements.
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In Millions)
The accompanying notes are an integral part of these consolidated financial statements.
KINDER MORGAN, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. General
Kinder Morgan, Inc. is the largest midstream and the third largest energy company in North America with a combined enterprise value, including its two publicly traded MLP subsidiaries, of approximately $110 billion and unless the context requires otherwise, references to “we,” “us,” “our,” or “KMI” are intended to mean Kinder Morgan, Inc. and its consolidated subsidiaries. We own an interest in or operate approximately 80,000 miles of pipelines and 180 terminals. Our pipelines transport natural gas, gasoline, crude oil, CO2 and other products, and our terminals store petroleum products and chemicals and handle such products as ethanol, coal, petroleum coke and steel.
We own an approximate 10% limited partner interest and the 2% general partner interest in KMP, a leading pipeline transportation and energy storage company and one of the largest publicly-traded pipeline limited partnerships in America. KMP’s limited partner units are traded on the NYSE under the ticker symbol “KMP.”
We also own an approximate 41% limited partner interest and the 2% general partner interest in EPB, as well as certain natural gas pipeline assets (see Notes 3 and 10). EPB’s limited partner units are traded on the NYSE under the ticker symbol “EPB.”
Our common stock trades on the NYSE under the symbol “KMI.”
On February 16, 2011, we completed the initial public offering of our common stock (the offering). All of the common stock that was sold in the offering was sold by our existing investors consisting of funds advised by or affiliated with Goldman Sachs & Co., Highstar Capital LP, The Carlyle Group and Riverstone Holdings LLC. No members of management sold shares in the offering, and we did not receive any proceeds from the offering. During 2012, the funds advised by or affiliated with Goldman Sachs & Co., The Carlyle Group and Riverstone Holdings LLC, sold their remaining interests in KMI and representatives of these funds are no longer on our board. For additional information on the offering, see Note 10.
KMR, is a publicly traded Delaware LLC. KMGP, the general partner of KMP and a wholly-owned subsidiary of ours, owns all of KMR’s voting shares. KMR, pursuant to a delegation of control agreement, has been delegated, to the fullest extent permitted under Delaware law, all of KMGP’s power and authority to manage and control the business and affairs of KMP, subject to KMGP’s right to approve certain transactions.
2. Summary of Significant Accounting Policies
Basis of Presentation
Our reporting currency is U.S. dollars, and all references to dollars are U.S. dollars, except where stated otherwise. Canadian dollars are designated as C$.
Our accompanying consolidated financial statements have been prepared under the rules and regulations of the SEC. These rules and regulations conform to the accounting principles contained in the FASB’s Accounting Standards Codification, the single source of GAAP. Under such rules and regulations, all significant intercompany items have been eliminated in consolidation. Additionally, certain amounts from prior years have been reclassified to conform to the current presentation.
Our consolidated financial statements include our accounts and the of our majority-owned and controlled subsidiaries as well as the accounts of KMP, EPB and KMR. Investments in jointly owned operations in which we hold a 50% or less interest (other than KMP, EPB and KMR, because we have the ability to exercise significant control over their operating and financial policies) are accounted for under the equity method.
Notwithstanding the consolidation of KMP and EPB and their respective subsidiaries into our financial statements, we are not liable for, and our assets are not available to satisfy, the obligations of KMP and EPB and/or their respective subsidiaries and vice versa, except as discussed in the following paragraph. Responsibility for payments of obligations reflected in our, KMP’s or EPB’s financial statements is a legal determination based on the entity that incurs the liability.
Effective November 1, 2012, we sold KMP’s FTC Natural Gas Pipelines disposal group to Tallgrass Energy Partners, L.P. for approximately $1.8 billion (before selling costs), or $3.3 billion including our share of joint venture debt, to satisfy terms of
a March 15, 2012 agreement with the U.S. FTC to divest certain of our assets in order to receive regulatory approval for our EP acquisition. KMP’s FTC Natural Gas Pipelines disposal group’s assets included (i) Kinder Morgan Interstate Gas Transmission natural gas pipeline system; (ii) Trailblazer natural gas pipeline system; (iii) Casper and Douglas natural gas processing operations; and (iv) 50% equity investment in the Rockies Express natural gas pipeline system. Accordingly, we (i) reclassified and excluded KMP’s FTC Natural Gas Pipelines disposal group’s results of operations from our results of continuing operations and reported the disposal group’s results of operations separately as “Income from operations of KMP’s FTC Natural Gas Pipelines disposal group and other, net of tax” within the discontinued operations section of our accompanying consolidated statements of income for all periods presented and (ii) separately reported a “Loss on sale and the remeasurement of KMP’s FTC Natural Gas Pipelines disposal group to fair value, net of tax” within the discontinued operations section of our accompanying consolidated statements of income for the years ended December 31, 2013 and 2012. In addition, we did not elect to present separately the operating, investing and financing cash flows related to the disposal group in our accompanying consolidated statements of cash flows.
For more information about the divestiture of KMP’s FTC Natural Gas Pipelines disposal group, see Note 3.
Use of Estimates
Certain amounts included in or affecting our financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time our financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities, our revenues and expenses during the reporting period, and our disclosure of contingent assets and liabilities at the date of our financial statements. We evaluate these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.
In addition, we believe that certain accounting policies are of more significance in our financial statement preparation process than others, and set out below are the principal accounting policies we apply in the preparation of our consolidated financial statements.
Cash Equivalents and Restricted Deposits
We define cash equivalents as all highly liquid short-term investments with original maturities of three months or less.
Restricted cash of $75 million and $52 million as of December 31, 2013 and 2012, respectively is included in “Other current assets,” and restricted cash of $2 million as of December 31, 2013, is included in “Deferred charges and other assets.”
Accounts Receivable
The amounts reported as “Accounts receivable, net” on our accompanying consolidated balance sheets as of December 31, 2013 and 2012 primarily consist of amounts due from customers.
Our policy for determining an appropriate allowance for doubtful accounts varies according to the type of business being conducted and the customers being served. Generally, we make periodic reviews and evaluations of the appropriateness of the allowance for doubtful accounts based on a historical analysis of uncollected amounts, and we record adjustments as necessary for changed circumstances and customer-specific information. When specific receivables are determined to be uncollectible, the reserve and receivable are relieved.
Inventories
Our inventories of products consist of materials and supplies, NGL, refined petroleum products and natural gas. We report these assets at the lower of weighted-average cost or market. We report materials and supplies inventories at cost, and periodically review for physical deterioration and obsolescence.
Gas Imbalances
We value gas imbalances due to or due from interconnecting pipelines at the lower of cost or market or index prices, per our quarterly imbalance valuation procedures. Gas imbalances represent the difference between customer nominations and actual gas receipts from, and gas deliveries to, our interconnecting pipelines and shippers under various operational balancing
and shipper imbalance agreements. Natural gas imbalances are either settled in cash or made up in-kind subject to the pipelines’ various tariff provisions. As of both December 31, 2013 and 2012, our gas imbalance receivables-including both trade and related party receivables-totaled $83 million and $18 million, respectively, and we included these amounts within “Other current assets” on our accompanying consolidated balance sheets. As of December 31, 2013 and 2012, our gas imbalance payables-consisting of only trade payables-totaled $34 million and $150 million, respectively, and we included these amounts within “Other current liabilities” on our accompanying consolidated balance sheets.
Property, Plant and Equipment
Capitalization, Depreciation and Depletion and Disposals
We report property, plant and equipment at its acquisition cost. We expense costs for maintenance and repairs in the period incurred. As discussed below, for assets used in our oil and gas producing activities or in our unregulated bulk and liquids terminal activities, the cost of property, plant and equipment sold or retired and the related depreciation are removed from our balance sheet in the period of sale or disposition, and we record any related gains and losses from sales or retirements to income or expense accounts. For our pipeline system assets, we generally charge the original cost of property sold or retired to accumulated depreciation and amortization, net of salvage and cost of removal. We do not include retirement gain or loss in income except in the case of significant retirements or sales. Gains and losses on minor operating unit sales, excluding land, are recorded to the appropriate accumulated depreciation reserve. Generally, gains and losses for operating unit sales and land sales are booked to income or expense accounts in accordance with regulatory accounting guidelines. In those instances where we receive recovery in tariff rates related to losses on dispositions of operating units, we record a regulatory asset for the estimated recoverable amount.
We generally compute depreciation using the straight-line method based on estimated economic lives; however, for certain depreciable assets, we employ the composite depreciation method, applying a single depreciation rate for a group of assets. Generally, we apply composite depreciation rates to functional groups of property having similar economic characteristics. The rates range from 0.9% to 23.0% excluding certain short-lived assets such as vehicles. Depreciation estimates are based on various factors, including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates included changes in laws and regulations relating to restoration and abandonment requirements, economic conditions, and supply and demand in the area. When assets are put into service, we make estimates with respect to useful lives (and salvage values where appropriate) that we believe are reasonable. However, subsequent events could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization expense. Historically, adjustments to useful lives have not had a material impact on our aggregate depreciation levels from year to year.
Our oil and gas producing activities are accounted for under the successful efforts method of accounting. Under this method costs that are incurred to acquire leasehold and subsequent development costs are capitalized. Costs that are associated with the drilling of successful exploration wells are capitalized if proved reserves are found. Costs associated with the drilling of exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of certain non-producing leasehold costs are expensed as incurred. The capitalized costs of our producing oil and gas properties are depreciated and depleted by the units-of-production method. Other miscellaneous property, plant and equipment are depreciated over the estimated useful lives of the asset.
A gain on the sale of property, plant and equipment used in our oil and gas producing activities or in our bulk and liquids terminal activities is calculated as the difference between the cost of the asset disposed of, net of depreciation, and the sales proceeds received. A gain on an asset disposal is recognized in income in the period that the sale is closed. A loss on the sale of property, plant and equipment is calculated as the difference between the cost of the asset disposed of, net of depreciation, and the sales proceeds received or the market value if the asset is being held for sale. A loss is recognized when the asset is sold or when the net cost of an asset held for sale is greater than the market value of the asset.
We engage in enhanced recovery techniques in which CO2 is injected into certain producing oil reservoirs. In some cases, the acquisition cost of the CO2 associated with enhanced recovery is capitalized as part of our development costs when it is injected. The acquisition cost associated with pressure maintenance operations for reservoir management is expensed when it is injected. When CO2 is recovered in conjunction with oil production, it is extracted and re-injected, and all of the associated costs are expensed as incurred. Proved developed reserves are used in computing units of production rates for drilling and development costs, and total proved reserves are used for depletion of leasehold costs. The units-of-production rate is determined by field.
As discussed in “-Inventories” above, we own and maintain natural gas in underground storage as part of our inventory. This component of our inventory represents the portion of gas stored in an underground storage facility generally known as working gas, and represents an estimate of the portion of gas in these facilities available for routine injection and withdrawal. In addition to this working gas, underground gas storage reservoirs contain injected gas which is not routinely cycled but, instead, serves the function of maintaining the necessary pressure to allow efficient operation of the facility. This gas, generally known as cushion gas, is divided into the categories of recoverable cushion gas and unrecoverable cushion gas, based on an engineering analysis of whether the gas can be economically removed from the storage facility at any point during its life. The portion of the cushion gas that is determined to be unrecoverable is considered to be a permanent part of the facility itself (thus, part of our “Property, plant and equipment, net” balance in our accompanying consolidated balance sheets), and this unrecoverable portion is depreciated over the facility’s estimated useful life. The portion of the cushion gas that is determined to be recoverable is also considered a component of the facility but is not depreciated because it is expected to ultimately be recovered and sold.
Impairments
We review long-lived assets for impairment whenever events or changes in circumstances indicate that our carrying amount of an asset may not be recoverable. We recognize impairment losses when estimated future cash flows expected to result from our use of the asset and its eventual disposition is less than its carrying amount.
We evaluate our oil and gas producing properties for impairment of value on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure, using undiscounted future cash flows based on total proved and risk-adjusted probable and possible reserves. For the purpose of impairment testing, adjustments for the inclusion of risk-adjusted probable and possible reserves, as well as forward curve pricing, will cause impairment calculation cash flows to differ from the amounts presented in our supplemental information on oil and gas producing activities disclosed in “Supplemental Information on Oil and Gas Producing Activities (Unaudited).”
Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future cash flows based on total proved and risk-adjusted probable and possible reserves or, if available, comparable market values. Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment.
Asset Retirement Obligations
We record liabilities for obligations related to the retirement and removal of long-lived assets used in our businesses. We record, as liabilities, the fair value of asset retirement obligations on a discounted basis when they are incurred, which is typically at the time the assets are installed or acquired. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities increase due to the change in their present value, and the initial capitalized costs are depreciated over the useful lives of the related assets. The liabilities are eventually extinguished when the asset is taken out of service.
Equity method of accounting
We account for investments-which we do not control, but do have the ability to exercise significant influence-by the equity method of accounting. Under this method, our equity investments are carried originally at our acquisition cost, increased by our proportionate share of the investee’s net income and by contributions made, and decreased by our proportionate share of the investee’s net losses and by distributions received.
Goodwill
Goodwill represents the excess of the cost of an acquisition price over the fair value of the acquired net assets, and such amounts are reported separately on our consolidated balance sheets. As of December 31, 2013 and 2012 our total goodwill was $24,504 million and $23,632 million, respectively. Goodwill is not amortized, but instead is tested for impairment annually or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. We perform our goodwill impairment test on May 31 of each year. There were no impairment charges resulting from our May 31, 2013, 2012 or 2011 impairment testing, and no event indicating an impairment has occurred subsequent to May 31, 2013.
If a significant portion of one of our business segments is disposed of (that also constitutes a business), we would allocate goodwill based on the relative fair values of the portion of the segment being disposed of and the portion of the segment remaining.
Revenue Recognition Policies
We recognize revenues as services are rendered or goods are delivered and, if applicable, title has passed. We recognize natural gas sales revenues and NGL sales revenue when the natural gas or NGL is sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, and collectability of the revenue is reasonably assured. Our sales and purchases of natural gas and NGL are primarily accounted for on a gross basis as natural gas sales or product sales, as applicable, and cost of sales.
In addition to storing and transporting a significant portion of the natural gas volumes we purchase and resell, we provide various types of natural gas storage and transportation services for third-party customers. Under these contracts, the natural gas remains the property of these customers at all times. In many cases, generally described as firm service, the customer pays a two-part rate that includes (i) a fixed fee reserving the right to transport or store natural gas in our facilities and (ii) a per-unit rate for volumes actually transported or injected into/withdrawn from storage. The fixed-fee component of the overall rate is recognized as revenue in the period the service is provided. The per-unit charge is recognized as revenue when the volumes are delivered to the customers’ agreed upon delivery point, or when the volumes are injected into/withdrawn from our storage facilities.
In other cases, generally described as interruptible service, there is no fixed fee associated with the services because the customer accepts the possibility that service may be interrupted at our discretion in order to serve customers who have purchased firm service. In the case of interruptible service, revenue is recognized in the same manner utilized for the per-unit rate for volumes actually transported under firm service agreements.
We provide crude oil and refined petroleum products transportation and storage services to customers. Revenues are recorded when products are delivered and services have been provided, and adjusted according to terms prescribed by the toll settlements with shippers and approved by regulatory authorities.
We recognize bulk terminal transfer service revenues based on volumes loaded and unloaded. We recognize liquids terminal tank rental revenue ratably over the contract period. We recognize liquids terminal throughput revenue based on volumes received and volumes delivered. We recognize transmix processing revenues based on volumes processed or sold, and if applicable, when title has passed. We recognize energy-related product sales revenues based on delivered quantities of product.
Revenues from the sale of crude oil, NGL, CO2 and natural gas production within the CO2-KMP business segment are recorded using the entitlement method. Under the entitlement method, revenue is recorded when title passes based on our net interest. We record our entitled share of revenues based on entitled volumes and contracted sales prices. Since there is a ready market for oil and gas production, we sell the majority of our products soon after production at various locations, at which time title and risk of loss pass to the buyer.
Environmental Matters
We expense or capitalize, as appropriate, environmental expenditures that relate to current operations. We expense expenditures that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation. We generally do not discount environmental liabilities to a net present value, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs. Generally, our recording of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action. We recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable. We record at fair value, where appropriate, environmental liabilities assumed in a business combination.
We routinely conduct reviews of potential environmental issues and claims that could impact our assets or operations. These reviews assist us in identifying environmental issues and estimating the costs and timing of remediation efforts. We also routinely adjust our environmental liabilities to reflect changes in previous estimates. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us, and potential third-party liability claims. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the period in which they are reasonably determinable.
Pensions and Other Postretirement Benefits
We recognize the difference between the fair value of plan assets and the plan’s benefit obligation of our consolidated subsidiaries’ pension and other postretirement benefit plans as either assets or liabilities on our balance sheet. We record deferred plan costs and income-unrecognized losses and gains, unrecognized prior service costs and credits, and any remaining unamortized transition obligations-in accumulated other comprehensive income or as a regulatory asset or liability for certain of our regulated operations, until they are amortized to be recognized as a component of benefit expense.
Noncontrolling Interests
Noncontrolling interests represents the outstanding ownership interests in our consolidated subsidiaries that are not owned by us. In our accompanying consolidated income statements, the noncontrolling interest in the net income (or loss) of our consolidated subsidiaries is shown as an allocation of our consolidated net income and is presented separately as “Net income attributable to noncontrolling interests.” In our accompanying consolidated balance sheets, noncontrolling interests represents the ownership interests in our consolidated subsidiaries’ net assets held by parties other than us. It is presented separately as “Noncontrolling interests” within “Stockholders’ Equity.”
Income Taxes
Income tax expense is recorded based on an estimate of the effective tax rate in effect or to be in effect during the relevant periods. Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. Deferred tax assets are reduced by a valuation allowance for the amount of any tax benefit we do not expect to be realized.
In determining the deferred income tax asset and liability balances attributable to us, we have applied an accounting policy that looks through its investments including its investment in KMP and EPB. The application of this policy resulted in no deferred income taxes being provided on the difference between the book and tax basis on the non-tax-deductible goodwill portion of our investment in KMP and EPB.
Foreign Currency Transactions and Translation
Foreign currency transaction gains or losses result from a change in exchange rates between (i) the functional currency, for example the Canadian dollar for a Canadian subsidiary and (ii) the currency in which a foreign currency transaction is denominated, for example the U.S. dollar for a Canadian subsidiary. In our accompanying consolidated statements of income, gains and losses from our foreign currency transactions are included within “Other Income (Expense)-Other, net.”
Foreign currency translation is the process of expressing, in U.S. dollars, amounts recorded in a local functional currency other than U.S. dollars, for example the Canadian dollar for a Canadian subsidiary. We translate the assets and liabilities of each of our consolidated foreign subsidiaries that have a local functional currency to U.S. dollars at year-end exchange rates. Income and expense items are translated at weighted-average rates of exchange prevailing during the year and stockholders’ equity accounts are translated by using historical exchange rates. The cumulative translation adjustments balance is reported as a component of “Accumulated other comprehensive loss.”
Comprehensive Income
For each of the years ended December 31, 2013, 2012 and 2011, the difference between our net income and our comprehensive income resulted from (i) unrealized gains or losses on derivative contracts accounted for as cash flow hedges; (ii) foreign currency translation adjustments; and (iii) unrealized gains or losses related to changes in pension and other postretirement benefit plan liabilities. For more information on our risk management activities, see Note 13.
Risk Management Activities
We utilize energy commodity derivative contracts for the purpose of mitigating our risk resulting from fluctuations in the market price of natural gas, NGL and crude oil. In addition, we enter into interest rate swap agreements for the purpose of hedging the interest rate risk associated with our debt obligations. We measure our derivative contracts at fair value and we report them on our balance sheet as either an asset or liability. If the derivative transaction qualifies for and is designated as a normal purchase and sale, it is exempted from fair value accounting and is accounted for using traditional accrual accounting.
Furthermore, changes in our derivative contracts’ fair values are recognized currently in earnings unless hedge accounting is applied. If a derivative contract meets specific accounting criteria, the contract’s gains and losses are allowed to offset related results on the hedged item in our income statement, and we may formally designate the derivative contract as a hedge and document and assess the effectiveness of the contract associated with the transaction that receives hedge accounting. Only designated qualifying items that are effectively offset by changes in fair value or cash flows during the term of the hedge are eligible to use the special accounting for hedging.
Our derivative contracts that hedge our energy commodity price risks involve our normal business activities, which include the purchase and sale of natural gas, NGL and crude oil, and we may designate these derivative contracts as cash flow hedges-derivative contracts that hedge exposure to variable cash flows of forecasted transactions-and the effective portion of these derivative contracts’ gain or loss is initially reported as a component of other comprehensive income (outside earnings) and subsequently reclassified into earnings when the forecasted transactions affect earnings. The ineffective portion of the gain or loss is reported in earnings immediately.
Regulatory Assets and Liabilities
Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or refunded to customers through the ratemaking process. We included the amounts of our regulatory assets and liabilities within “Other current assets,” “Deferred charges and other assets,” “Other current liabilities” and “Other long-term liabilities and deferred credits,” respectively, in our accompanying consolidated balance sheets. As of December 31, 2013, the recovery period for these regulatory assets was approximately one year to forty-two years.
The following table summarizes our regulatory asset and liability balances as of December 31, 2013 and 2012 (in millions):
_______
(a)
Includes an $88 million increase since December 31, 2012 (net of related amortization of $5 million) associated with TGP’s sale of certain natural gas facilities located offshore in the Gulf of Mexico and onshore in the state of Louisiana.
(b)
During the second quarter of 2013, we began applying regulatory accounting to the Trans Mountain pipeline systems due to a newly negotiated long-term tolling agreement approved by the system’s regulator that went into effect in April 2013. The primary impact of applying regulatory accounting was the reclassification of approximately $362 million of current and long-term deferred credits to regulatory liabilities. KMP expects this regulatory liability to be refunded to rate-payers over approximately the next four years. As of December 31, 2013, $113 million remains classified as a current regulatory liability.
On July 26, 2012, TGP filed an application with the FERC seeking authority to abandon by sale certain natural gas facilities located offshore in the Gulf of Mexico and onshore in the state of Louisiana, as well as a related offer of settlement that addressed the proposed rate and accounting treatment associated with the sale. The offer of settlement provided for a rate adjustment to TGP’s maximum tariff rates upon the transfer of the assets and established a regulatory asset for a portion of the unrecovered net book value of the facilities to be sold. Effective September 1, 2013, following the FERC’s approval of both the requested abandonment authorization and the offer of settlement, TGP sold these assets, and in 2013, TGP recognized both a $93 million increase in regulatory assets and a $36 million gain from the sale of assets.
Transfer of Net Assets Between Entities Under Common Control
We account for the transfer of net assets between entities under common control by carrying forward the net assets recognized in the balance sheets of each combining entity to the balance sheet of the combined entity, and no other assets or liabilities are recognized as a result of the combination. Transfers of net assets between entities under common control do not affect the historical income statement or balance sheet of the combined entity.
Earnings per Share
For the year ended December 31, 2013, earnings per share was calculated using the two-class method. Earnings were allocated to Class P shares of common stock and to participating securities based on the amount of dividends paid in the current period plus an allocation of the undistributed earnings or excess distributions over earnings to the extent that each security participates in earnings or excess distributions over earnings. Our unvested restricted stock awards do not participate in excess distributions over earnings. For the year ended December 31, 2013, the following potential weighted-average Class P common shares are antidilutive and, accordingly, are excluded from the determination of diluted earnings per share; (i) 4 million related to unvested restricted stock awards; (ii) 401 million related to outstanding warrants to purchase our Class P shares; and (iii) 10 million related to convertible trust preferred securities.
The following table sets forth the allocation of net income available to shareholders for Class P shares and for participating securities for the year ended December 31, 2013 (in millions):
_______
(a)
Participating securities are unvested restricted stock awards issued to management employees that contain non-forfeitable rights to dividend equivalent payments.
On December 26, 2012, the remaining series of our Class A, Class B, and Class C shares were fully-converted and as a result, only our Class P common stock was outstanding as of December 31, 2012 (see Note 10).
For the year ended December 31, 2012 and the period February 11, 2011 through December 31, 2011, earnings per share was calculated using the two-class method. Earnings were allocated to each class of common stock based on the amount of dividends paid in the current period for each class of stock plus an allocation of the undistributed earnings or excess distributions over earnings to the extent that each security participates in earnings or excess distributions over earnings. For the investor retained stock, the allocation of undistributed earnings or excess distributions over earnings was in direct proportion to the maximum number of Class P shares into which it could convert.
For the Class P diluted earnings per share computations, total net income attributable to Kinder Morgan, Inc. was divided by the adjusted weighted-average shares outstanding during the period, including all dilutive potential shares. This included the Class P shares into which the investor retained stock (collectively, our Class A, Class B and Class C common stocks) was convertible. The number of Class P shares on a fully-converted basis was the same before and after any conversion of our investor retained stock. Each time one Class P share was issued upon conversion of investor retained stock, the number of Class P shares went up by one, and the number of Class P shares into which the investor retained stock was convertible went down by one. Accordingly, there was no difference between Class P basic and diluted earnings per share because the conversion of Class A, Class B, and Class C shares into Class P shares did not impact the number of Class P shares on a fully-converted basis. Commencing with the acquisition of EP, dilutive potential shares also included the Class P shares issuable in connection with the warrants and the trust preferred securities (see Note 10). As no securities were convertible into Class A shares, the basic and diluted earnings per share computations for Class A shares were the same. For the year ended December 31, 2012, the following potential Class P common shares were antidilutive and, accordingly, were excluded from the determination of diluted earnings per share; (i) 451 million related to outstanding warrants to purchase our Class P shares; and (ii) 11 million related to convertible trust preferred securities.
The following tables set forth the computation of basic and diluted earnings per share from continuing operations for the year ending December 31, 2012 and the period ending February 11, 2011 through December 31, 2011 (the date of our initial public offering) (in millions, except per share amounts):
The following tables set forth the computation of basic and diluted earnings per share for the year ended December 31, 2012 and for the period February 11, 2011 through December 31, 2011 (in millions, except per share amounts):
_______
(a)
Participating securities included Class B shares, Class C shares, and unvested restricted stock awards issued to non-senior management employees that contained rights to dividend equivalents in the case of the restricted shares. Our Class B and Class C shares were entitled to participate in our earnings, only to the extent of cash distributions made to them. As a result, no earnings in excess of dividends received were allocated to the Class B and Class C shares in our determination of basic and diluted earnings per share.
(b)
The Class A shares earnings per share as compared to the Class P shares earnings per share were reduced due to the sharing of economic benefits (including dividends) amongst the Class A, B, and C shares. Class A, B and C shares owned by Richard Kinder, the sponsor investors, the original shareholders, and other management were referred to as “investor retained stock,” and were convertible into a fixed number of Class P shares. In the aggregate, our investor retained stock was entitled to receive a dividend per share on a fully-converted basis equal to the dividend per share on our common stock. The conversion of shares of investor retained stock into Class P shares did not increase our total fully-converted shares outstanding, impact the aggregate dividends we paid or the dividends we paid per share on our Class P common stock.
(c)
For the diluted earnings per share calculation, total net income attributable to each class of common stock was divided by the adjusted weighted-average shares outstanding during the period, including all dilutive potential shares.
(d)
The weighted-average shares outstanding calculation is based on the actual days in which the shares were outstanding for the period from February 11, 2011 to December 31, 2011.
3. Acquisitions and Divestitures
Business Combinations and Acquisitions of Investments
During 2013, 2012 and 2011, we and our subsidiary, KMP, completed the following significant acquisitions, and except for the acquisition of two separate equity interests in Watco Companies, LLC (noted as (2) and (6) in the table and discussion below), we accounted for these acquisitions in accordance with the “Business Combinations” Topic of the Codification.
After measuring all of the identifiable tangible and intangible assets acquired and liabilities assumed at fair value on the acquisition date, goodwill is an intangible asset representing the future economic benefits expected to be derived from an acquisition that are not assigned to other identifiable, separately recognizable assets. We believe the primary items that generated our and KMP’s goodwill are both the value of the synergies created between the acquired assets and its pre-existing assets, and its expected ability to grow the business acquired by leveraging pre-existing business experience. With the exception of KMP’s acquisitions of (i) KinderHawk and EagleHawk Field Services LLC and (ii) SouthTex Treaters (noted as (4) and (5), respectively, in the table and discussion below), we do not expect our recorded goodwill to be deductible for tax purposes.
The following table discloses our assignment of the purchase price for each of our significant acquisitions (in millions):
(1) EP
Effective on May 25, 2012, we acquired all of the outstanding shares of EP for an aggregate consideration of approximately $22.9 billion (excluding assumed debt, but including payments of $87 million for share based awards expensed in the post-combination period). In total, EP shareholders received (i) $11.6 billion in cash, (ii) 330 million KMI Class P shares with a fair value of $10.6 billion (based on the $32.11 closing market price of a Class P share on May 24, 2012) and (iii) 505 million KMI warrants with a fair value of $863 million (based on a fair value of $1.71 per warrant as of May 24, 2012). The warrants have an exercise price of $40 per share and a 5-year term.
During the second quarter of 2013, management completed its purchase accounting valuation estimates and, as a result, retrospectively adjusted the valuations of certain liabilities with a corresponding increase to goodwill as of the acquisition date. The retrospective adjustments amounted to approximately $60 million and primarily related to revisions of estimates related to certain environmental obligations, sales and use tax liabilities, and deferred income taxes.
The asset amount assigned to “Deferred charges & other” in the table above includes $4,211 million assigned to “Investments.” The “Other liabilities” assumed and shown in the table above includes $1,463 million assigned to “Total current liabilities.” The “Noncontrolling interests” assumed in the EP acquisition represents the fair value of noncontrolling interests associated with EP’s investment in EPB and was based on the 117 million EPB common units outstanding to the public as of May 24, 2012 valued at EPB’s May 24, 2012 closing price of $32.37 per common unit.
On May 24, 2012, EP sold its subsidiary, EP Energy LLC, which consisted of EP’s exploration and production business for $7.2 billion. Accordingly, the assets and liabilities of EP Energy LLC are not included in the purchase price allocation table above and the net sale proceeds were used to pay off the holders of EP Energy LLC’s $961 million long-term debt, and the remaining $6.2 billion (included in “Current assets” in the table above) was used to pay for a portion of the $11.6 billion cash portion of the purchase price. EP’s net operating loss carryforwards are expected to significantly offset the cash taxes associated with the sale of EP Energy LLC.
During the year 2012, we incurred $463 million, net of legal recoveries, of pre-tax expenses associated with the EP acquisition, and EP Energy sale, including (i) $160 million in employee severance, retention and bonus costs; (ii) $87 million of accelerated EP stock based compensation allocated to the post-combination period under applicable GAAP rules; (iii) $37 million in advisory fees; (iv) $68 million for legal fees and reserves, net of legal recoveries; (v) a $108 million write-off (due to debt repayments) or amortization of capitalized financing fees associated with the EP acquisition financing; and less (vi) a $29 million benefit associated with pension income.
Together, EP and its subsidiary EPB offered natural gas transmission services to a range of customers, including natural gas producers, marketers and end-users, as well as other natural gas transmission, distribution and electric generation companies. The pipelines group of EP and EPB were the nation’s largest interstate natural gas pipeline franchise, transporting natural gas through interstate natural gas pipelines that connect the nation’s principal supply regions to its major consuming regions (the Gulf Coast, California, the northeast, the southwest and the southeast). The pipelines business also included storage and LNG terminaling facilities. Most of the acquired assets are included in the Natural Gas Pipelines business segment.
(2) Watco Companies, LLC (1 of 2)
On January 3, 2011, KMP purchased 50,000 Class A preferred shares of Watco Companies, LLC for $50 million in cash in a private transaction. In connection with its purchase of these preferred shares, the most senior equity security of Watco, KMP entered into a limited liability company agreement with Watco that provides KMP certain priority and participating cash distribution and liquidation rights. Pursuant to the agreement, KMP receives priority, cumulative cash distributions from the preferred shares at a rate of 3.25% per quarter (13% annually), and it participates partially in additional profit distributions at a rate equal to 0.5%. The preferred shares have no conversion features and hold no voting powers, but do provide KMP certain approval rights, including the right to appoint one of the members to Watco’s Board of Managers. On December 28, 2011, KMP made an additional $50 million investment in Watco, as described below in “-(6) Watco Companies, LLC (2 of 2).”
Watco Companies, LLC is the largest privately held short line railroad company in the U.S., operating 22 short line railroads on approximately 3,500 miles of leased and owned track. KMP’s investment provided capital to Watco for further expansion of specific projects and complemented KMP’s existing terminal network. It also provides KMP’s customers more transportation services for many of the commodities that it currently handles, and offers it the opportunity to share in additional growth opportunities through new projects. As of December 31, 2013, KMP’s net equity investment in Watco totaled $103 million and is within “Investments” on our accompanying consolidated balance sheet. KMP accounts for its investment under the equity method of accounting, and we include it in the Terminals-KMP business segment.
(3) TGS Development, L.P. Terminal Acquisition
On June 10, 2011, KMP acquired a newly constructed petroleum coke terminal located in Port Arthur, Texas from TGS Development, L.P. (TGSD) for an aggregate consideration of $74 million, consisting of $43 million in cash, $24 million in common units, and an obligation to pay additional consideration of $7 million. In March 2012, KMP settled the $7 million liability by issuing additional common units to TGSD (KMP issued 87,162 common units and determined each unit’s value based on the $83.87 closing market price of the common units on the NYSE on the March 14, 2012 issuance date).
All of the acquired assets are located in Port Arthur, Texas, and include long-term contracts to provide petroleum coke handling and cutting services to improve the refining of heavy crude oil at Total Petrochemicals USA Inc.’s Port Arthur refinery. The acquisition complemented KMP’s existing Gulf Coast bulk terminal facilities and expanded its pre-existing petroleum coke handling operations. All of the acquired assets are included as part of the Terminals-KMP business segment.
(4) KinderHawk and EagleHawk
Effective July 1, 2011, KMP acquired from Petrohawk Energy Corporation (Petrohawk, now a subsidiary of BHP Billiton as discussed below) both the remaining 50% equity ownership interest in KinderHawk that it did not already own and a 25% equity ownership interest in EagleHawk, Petrohawk’s natural gas gathering and treating business located in the Eagle Ford shale formation in South Texas for an aggregate consideration of $912 million, consisting of $835 million in cash and assumed debt of $77 million (representing 50% of KinderHawk’s borrowings under its bank credit facility as of July 1, 2011). KMP then repaid the outstanding $154 million of borrowings and following this repayment, KinderHawk had no outstanding debt. KMP also terminated the revolving bank credit facility at the time of such repayment. All of the acquired operations are included in the Natural Gas Pipelines business segment.
Following this acquisition of the remaining ownership interest on July 1, 2011, KMP changed its method of accounting from the equity method to full consolidation, and due to the fact that KMP acquired a controlling financial interest in KinderHawk, KMP remeasured its previous 50% equity investment in KinderHawk to its fair value. KMP recognized a $167 million non-cash loss as a result of this remeasurement. The loss amount represented the excess of the carrying value of KMP’s investment ($910 million as of July 1, 2011) over its fair value ($743 million), and we reported this loss separately within the “Other Income (Expense)” section in our accompanying consolidated statement of income for the year ended December 31, 2011. Additionally, on August 25, 2011, mining and oil company BHP Billiton completed its previously announced acquisition of Petrohawk through a short-form merger under Delaware law. The merger was closed with Petrohawk being the surviving corporation as a wholly owned subsidiary of BHP Billiton. The acquisition did not affect the terms of KMP’s contracts with Petrohawk.
(5) SouthTex Treaters, Inc. Asset Acquisition
On November 30, 2011, KMP acquired a manufacturing complex and certain natural gas treating assets from SouthTex Treaters, Inc. for an aggregate consideration of $179 million, consisting of $152 million in cash and assumed liabilities of $27 million. SouthTex Treaters, Inc. is a leading manufacturer, designer and fabricator of natural gas treating plants that are used to remove impurities (CO2 and hydrogen sulfide) from natural gas before it is delivered into gathering systems and transmission pipelines to ensure that it meets pipeline quality specifications. The acquisition complemented and expanded KMP’s existing natural gas treating business, and all of the acquired operations are included in the Natural Gas Pipelines business segment.
(6) Watco Companies, LLC (2 of 2)
On December 28, 2011, KMP purchased an additional 50,000 Class A preferred shares of Watco Companies, LLC for $50 million in cash in a private transaction. The priority and participating cash distribution and liquidation rights associated with these shares are similar to the rights associated with the 50,000 Class A preferred shares KMP acquired on January 3, 2011-KMP receives priority, cumulative cash distributions from the preferred shares at a rate of 3.25% per quarter (13% annually), and participates partially in additional profit distributions at a rate equal to 0.5%.
(7) Copano
Effective May 1, 2013, KMP acquired all of Copano’s outstanding units for a total purchase price of approximately $5.2 billion (including assumed debt and all other assumed liabilities). The transaction was a 100% unit for unit transaction with an exchange ratio of 0.4563 of KMP’s common units for each Copano common unit. KMP issued 43,371,210 of its common units valued at $3,733 million as consideration for the Copano acquisition (based on the $86.08 closing market price of a common unit on the NYSE on the May 1, 2013 issuance date).
Also, due to the fact that KMP’s acquisition included the remaining 50% interest in Eagle Ford Gathering LLC that it did not already own, KMP remeasured its existing 50% equity investment in Eagle Ford to its fair value as of the acquisition date. As a result of this remeasurement, KMP recognized a $558 million non-cash gain, which represented the excess of the investment’s fair value ($704 million) over the carrying value as of May 1, 2013 ($146 million). We reported this gain separately within the “Other Income (Expense)” section in our accompanying consolidated statement of income for the year ended December 31, 2013.
The table above reflects the adjusted preliminary purchase price allocation as of December 31, 2013. Deferred charges & other includes $1,375 million assigned to “Other intangibles, net” and $387 million assigned to “Investments.” The intangible amount represents the fair value of acquired customer contracts and agreements, and we are currently amortizing these intangible assets over an estimated remaining useful life of 25 years. The investment amount represents an aggregate of seven
separate investments, each accounted for under the equity method of accounting. KMP’s evaluation of the assigned fair values is ongoing and subject to adjustment.
Our accounting policy is to apply the look-through method of recording deferred taxes on the outside book tax basis differences in our investments without regard to non-tax deductible goodwill. As a result of the goodwill recorded by KMP for its Copano acquisition, KMI’s deferred tax liability and goodwill were increased by $260 million for the portion of its outside basis difference associated with KMP’s underlying goodwill.
Copano provides comprehensive services to natural gas producers, including natural gas gathering, processing, treating and NGL fractionation. Copano owns an interest in or operates approximately 6,900 miles of pipelines with 2.7 Bcf/d of natural gas transportation capacity, and also owns nine natural gas processing plants with more than 1 Bcf/d of natural gas processing capacity and 315 MMcf/d of natural gas treating capacity. Its operations are located primarily in Texas, Oklahoma and Wyoming. Most of the acquired assets are included in the Natural Gas Pipelines business segment.
(8) Goldsmith Landreth Field Unit
On June 1, 2013, KMP acquired certain oil and gas properties, rights, and related assets in the Permian Basin of West Texas from Legado Resources LLC for an aggregate consideration of $298 million consisting of $280 million in cash and assumed liabilities of $18 million (including $12 million of long-term asset retirement obligations). The acquisition of the Goldsmith Landreth San Andres oil field unit includes more than 6,000 acres located in Ector County, Texas. The acquired oil field is in the early stages of CO2 flood development and includes a residual oil zone along with a classic San Andres waterflood. As of December 31, 2013, the field was producing approximately 1,230 Bbl/d of oil, and as part of the transaction, KMP obtained a long-term supply contract for up to 150 MMcf/d of CO2. The acquisition complemented KMP’s existing oil and gas producing assets in the Permian Basin, and we included the acquired assets as part of the CO2-KMP business segment. Our evaluation of the assigned fair values is ongoing and subject to adjustment.
Pro Forma Information
The following summarized unaudited pro forma consolidated income statement information for the years ended December 31, 2013 and 2012, assumes that the EP, Copano and the Goldsmith Landreth field unit acquisitions had occurred as of January 1, 2012. We prepared the following summarized unaudited pro forma financial results for comparative purposes only. The summarized unaudited pro forma financial results may not be indicative of the results that would have occurred if these acquisitions had been completed as of January 1, 2012 or the results that will be attained in the future. Amounts presented below are in millions, except for the per share amounts:
Acquisition Subsequent to December 31, 2013
Effective January 17, 2014, KMP acquired American Petroleum Tankers (APT) and State Class Tankers (SCT) from affiliates of The Blackstone Group and Cerberus Capital Management for an aggregate consideration of approximately $962 million in cash (pending final true-ups for both acquired working capital balances and capital spending prior to the closing date). KMP funded this transaction with borrowings made under its commercial paper program which is supported by a short-term liquidity facility dated January 17, 2014 (see Note 8 “Debt-Credit Facilities and Restrictive Covenants-KMP-
Subsequent Event”). Additionally, KMGP, as KMP’s general partner, has agreed to waive incentive distribution amounts of $13 million for 2014, $19 million for 2015 and $6 million for 2016 to facilitate the transaction.
APT and SCT are engaged in the marine transportation of crude oil, condensate and refined products in the U.S. domestic trade, commonly referred to as the Jones Act trade. APT’s primary assets consist of a fleet of five medium range Jones Act qualified product tankers, each with 330 MBbl of cargo capacity, and each operating pursuant to long-term time charters with high quality counterparties, including major integrated oil companies, major refiners and the U.S. Navy. The vessels’ time charters have an average remaining term of approximately four years, with renewal options to extend the initial terms by an average of two years. APT’s vessels are operated by Crowley Maritime Corporation.
SCT has commissioned the construction of four medium range Jones Act qualified product tankers, each with 330 MBbl of cargo capacity. The SCT vessels are scheduled to be delivered in 2015 and 2016 and are being constructed by General Dynamics’ NASSCO shipyard. KMP expects to invest approximately $214 million to complete the construction of the vessels. Upon delivery, the SCT vessels will be operated pursuant to long-term time charters with a major integrated oil company. Each of the time charters has an initial term of five years, with renewal options to extend the initial term by up to three years. The acquisition of APT and SCT complements and extends KMP’s existing crude oil and refined products transportation business, and all of the acquired assets are included in the Terminals-KMP business segment.
Drop-down of EP Assets to KMP
August 2012
Effective August 1, 2012, KMP acquired a 100% ownership interest in TGP and an initial 50% ownership interest in EPNG from us for an aggregate consideration of approximately $6.2 billion (including a proportional share of assumed debt borrowings as of August 1, 2012). The consideration that we received from KMP consisted of (i) $3.5 billion in cash; (ii)4,667,575 of KMP’s common units (valued at $0.4 billion based on KMP’s $81.52 closing market price of the common units on the NYSE on the August 1, 2012 issuance date); and (iii) $2.3 billion in assumed debt (consisting of the combined carrying value of 100% of TGP’s debt borrowings and 50% of EPNG’s debt borrowings as of August 1, 2012, excluding any debt fair value adjustments). We used the proceeds from the drop-down transaction to (i) pay down $2.3 billion on our 3-year term loan facility; (ii) pay off and terminate our 364-day bridge facility; and (iii) pay off an $839 million senior note which matured on September 1, 2012.
March 2013
Effective March 1, 2013, KMP acquired from us the remaining 50% ownership interest it did not already own in both EPNG and the EP midstream assets (see “-KMP Previously Held Investment in El Paso Midstream Investment Company, LLC” following) for an aggregate consideration of approximately $1.7 billion (including a proportional 50% share of assumed debt borrowings as of March 1, 2013). The consideration that we received from KMP consisted of (i) $994 million in cash (including $6 million in the second quarter of 2013 to settle the final working capital adjustment); (ii) 1,249,452 common units (valued at $108 million based on the $86.72 closing market price of KMP’s common unit on the NYSE on the March 1, 2013 issuance date); and (iii) $557 million in assumed debt (consisting of 50% of the outstanding principal amount of EPNG’s debt borrowings as of March 1, 2013, excluding any debt fair value adjustments). We used the proceeds from the March 1, 2013 drop-down transaction to (i) pay down $947 million of our senior secured term loan facility; and (ii) reduce borrowings under our credit facility.
In this report, we refer to these acquisitions of assets by KMP from us as the drop-down transactions and the combined group of assets acquired by KMP from us as the drop-down asset groups. The terms of the drop-down transactions were approved on our behalf by the independent members of our board of directors and on KMP’s behalf by the audit committees and the boards of directors of both KMGP, as KMP’s general partner, and KMR, in its capacity as the delegate of KMGP, following the receipt by our independent directors and by the audit committees of KMGP and KMR of separate fairness opinions from different independent financial advisors.
The drop-down transactions were accounted for as transfers of net assets between entities under common control. Specifically, we have retrospectively adjusted our consolidated financial statements to reflect the recognition by KMP of the acquired assets and assumed liabilities at our carrying value, including our EP purchase accounting adjustments as of May 25, 2012.
KMP Previously Held Investment in El Paso Midstream Investment Company, LLC
Effective June 1, 2012, KMP acquired from an investment vehicle affiliated with Kohlberg Kravis Roberts & Co. L.P. (together with its affiliates, referred to as KKR) a 50% ownership interest in El Paso Midstream Investment Company, LLC (EP Midstream), a joint venture that owns (i) the Altamont natural gas gathering, processing and treating assets located in the Uinta Basin in Utah and (ii) the Camino Real natural gas and oil gathering system located in the Eagle Ford shale formation in South Texas, collectively referred to in this report as the EP midstream assets. KMP acquired its initial 50% interest for an aggregate consideration of $289 million in common units (KMP issued 3,792,461 common units and determined each unit’s value based on KMP’s $76.23 closing market price of the common units on the NYSE on the June 4, 2012 issuance date).
We, through our EP acquisition, owned the remaining 50% of the EP Midstream assets, and as a result we consolidated EP Midstream in the accompanying consolidated financial statements effective June 1, 2012. The operating results of the EP midstream assets are included in the Natural Gas Pipelines business segment. No gain or loss on the previously held equity investment was recognized as the fair value of the equity investment acquired through our EP acquisition was determined to equal the $289 million purchase price paid by KMP for its 50% interest. As such, the fair value of 100% of EP Midstream was determined to be $578 million.
We measured the identifiable intangible assets acquired at fair value on the acquisition date, and as a result, we recognized $50 million in “Deferred charges and other assets,” representing the fair value of separate and identifiable relationships with existing customers. We estimated the remaining useful life of these existing customer relationships to be approximately 10 years. After measuring all of the identifiable tangible and intangible assets acquired and liabilities assumed at fair value on the acquisition date, we recognized $248 million of “Goodwill.” We believe the primary item that generated the goodwill is our ability to grow the business by leveraging our pre-existing natural gas operations, and we believe that this value contributed to our acquisition price exceeding the fair value of acquired identifiable net assets and liabilities. This goodwill is not deductible for tax purposes.
Income Tax Impact of the Drop-Down of EP Assets to KMP
As discussed above, we accounted for the acquisition of EP as a business combination and for the subsequent March 2013 and August 2012 drop-down transactions as transfers of net assets between entities under common control. For income tax purposes, the March 2013 drop-down transaction was treated as a contribution and the August 2012 drop-down transaction was treated as a partial sale, and a partial contribution.
Our accounting policy is to apply the look-through method of recording deferred taxes on the outside book tax basis differences in our investments without regard to non tax deductible goodwill. As a result of the drop-down transactions, a deferred tax liability arose related to the portion of the outside basis difference associated with the underlying goodwill that was contributed to KMP by us. However, since the drop-downs were transactions between entities under common control, we recognized an offsetting deferred charge of $448 million for the August 2012 and $53 million for the March 2013 drop-down transactions. These balances will be amortized to income tax expense over the remaining useful lives of the transferred assets of approximately 25 years Similar to the impact described above, KMP’s acquisition of a 50% ownership interest in the EP Midstream joint venture, also generated the recognition of a deferred charge and corresponding deferred tax liability and is included in the amount above. For the year ended December 31, 2013 and the period subsequent to the August 2012 drop-down through December 31, 2012, total income tax expense related to the amortization of the deferred charges was approximately $20 million and $7 million, respectively.
Divestitures
KMP’s FTC Natural Gas Pipelines Disposal Group - Discontinued Operations
As described above in Note 2, following our March 2012 agreement with the FTC, we began accounting for KMP’s FTC Natural Gas Pipelines disposal group as discontinued operations (prior to KMI’s sale announcement, we included the disposal group in the Natural Gas Pipelines business segment). Effective November 1, 2012, we then sold KMP’s FTC Natural Gas Pipelines disposal group to Tallgrass Energy Partners, LP (now known as Tallgrass Development, LP) (Tallgrass), and KMP received proceeds of $1,791 million (before cash selling expenses). In November 2012, we also paid selling expenses of $78 million (consisting of certain required tax payments to joint venture partners).
Additionally, during 2012, KMP remeasured the disposal group’s net assets to reflect its assessment of fair value as a result of the FTC mandated sale requirement, and as a result of this remeasurement of net assets to fair value and the sale of net assets, we recognized a combined $937 million loss. We reported this loss amount separately as “Loss on sale and the
remeasurement of KMP’s FTC Natural Gas Pipelines disposal group to fair value, net of tax” within the discontinued operations section of our accompanying consolidated statement of income for the year ended December 31, 2012. We reported the proceeds received from the sale separately as “Proceeds from disposal of discontinued operations” within the investing section of our accompanying consolidated statement of cash flows for the year ended December 31, 2012.
In 2013, KMP and Tallgrass trued up the final consideration for the sale of KMP’s FTC Natural Gas Pipelines disposal group and based both on this true up and certain incremental selling expenses paid in 2013, we recognized an additional $4 million loss. We reported this loss amount separately as “Loss on sale and the remeasurement of KMP’s FTC Natural Gas Pipelines disposal group to fair value, net of tax” within the discontinued operations section of our accompanying consolidated statement of income for the year ended December 31, 2013, and except for this loss amount, no other financial results from the operations of KMP’s FTC Natural Gas Pipelines disposal group were recorded in 2013.
Summarized financial information for KMP’s FTC Natural Gas Pipelines disposal group is as follows (in millions):
_______
(a)
2012 amounts represent financial information for the ten month period ended October 31, 2012. We sold KMP’s FTC Natural Gas Pipelines disposal group effective November 1, 2012.
Express Pipeline System
Effective March 14, 2013, KMP sold both its one-third equity ownership interest in the Express pipeline system and its subordinated debenture investment in Express to Spectra Energy Corp. KMP received net cash proceeds of $402 million (after paying both a final working capital settlement and certain transaction related selling expenses), and we reported the net cash proceeds received from the sale separately as “Proceeds from sales of assets and investments” within the investing section of our accompanying consolidated statement of cash flows. For the year ended December 31, 2013, we recognized a combined $224 million pre-tax gain with respect to this sale, and we reported this gain amount separately as “Gain on sale of investments in Express pipeline system” on our accompanying consolidated statement of income. We also recorded an income tax expense of $84 million related to this gain on sale, and we included this expense within “Income Tax Expense.”
As of the date of sale, KMP’s equity investment in Express totaled $67 million and its note receivable due from Express totaled $110 million. Prior to KMP’s sale, we (i) accounted for KMP’s equity investment under the equity method of accounting; (ii) accounted for KMP’s debt investment under the historical amortized cost method of accounting; and (iii) included the financial results of the Express pipeline system within the Kinder Morgan Canada-KMP business segment. As of December 31, 2012, KMP’s equity and debt investments in Express totaled $65 million and $114 million, respectively, and we included the combined $179 million amount within “Assets held for sale” on our accompanying consolidated balance sheet.
BOSTCO
Effective December 1, 2012, TransMontaigne exercised its previously announced option to acquire up to 50% of KMP’s Class A member interest in BOSTCO, KMP’s previously announced oil terminal joint venture located on the Houston Ship Channel. On this date, TransMontaigne acquired a 42.5% Class A member interest in BOSTCO from KMP for an aggregate consideration of $79 million, and following this acquisition, KMP now owns a 55% Class A member interest in BOSTCO (KMP sold a 2.5% Class A member interest in BOSTCO to a third party on January 1, 2012 for an aggregate consideration of $1 million). Because KMP retained a controlling financial interest in BOSTCO, we continued to account for KMP’s investment under the full consolidation method and we accounted for this change in KMP’s ownership interest as an equity transaction.
TGP’s Sale of Production Area Facilities
On September 1, 2013, TGP sold certain natural gas facilities located offshore in the Gulf of Mexico and onshore in the state of Louisiana for an aggregate consideration of $32 million in cash. TGP’s net assets sold in this transaction (including assets identified as “held for sale”) totaled $89 million, and as a result of the sale, TGP recognized both a $93 million increase in regulatory assets pursuant to a FERC order, and a $36 million gain from the sale of assets. We included the cash proceeds received from the sale in 2013 within “Sale or casualty of property, plant and equipment, investments and other net assets, net of removal costs” within the investing section of our accompanying consolidated statement of cash flows for the year ended December 31, 2013, and we included the gain amount within “Other Income (Expense)” on our accompanying consolidated statement of income for the year ended December 31, 2013.
BBPP Holdings Ltda
As of December 31, 2012, we owned a 2% interest in Gas Transboliviano S.A., and a 33 1/3% interest in BBPP Holdings Ltda which we acquired as a part of the May 25, 2012 EP acquisition. BBPP Holdings Ltda owned a 29% interest in Transportadora Brasileira Gasoduto Bolivia-Brasil S.A. which, together with Gas Transboliviano S.A., owned the Bolivia to Brazil Pipeline. On January 18, 2013, we completed the sale of our equity interests in the Bolivia to Brazil Pipeline for $88 million. As of December 31, 2012, our $88 million equity interests in the Bolivia to Brazil Pipeline was included within “Assets held for sale” on our accompanying consolidated balance sheet.
4. Income Taxes
The components of “Income from Continuing Operations Before Income Taxes” are as follows (in millions):
Components of the income tax provision applicable to continuing operations for federal, foreign and state taxes are as follows (in millions):
The difference between the statutory federal income tax rate and our effective income tax rate is summarized as follows (in millions, except percentages):
Deferred tax assets and liabilities result from the following (in millions):
Deferred Tax Assets and Valuation Allowances: As a result of our EP acquisition, we have deferred tax assets of $354 million related to net operating loss carryovers; alternative minimum and foreign tax credits of $308 million; and valuation allowances related to deferred tax assets of $95 million at December 31, 2013. In 2013, we also recorded an $11 million deferred tax asset related to the capital loss from our sale of the Pakistan power plant. No valuation allowance has been recorded as we fully expect to utilize this capital loss. As of December 31, 2012, the deferred tax asset related to net operating
loss carryovers was $823 million, alternative minimum, general business, and foreign tax credits were $298 million, and valuation allowances related to the deferred tax assets were $104 million.
Expiration Periods for Deferred Tax Assets: As of December 31, 2013, we have U.S. federal net operating loss carryforwards of $613 million, which will expire from 2017 - 2031; state losses of $1.4 billion which will expire from 2014 - 2032; and foreign losses of $191 million, of which approximately $140 million carries over indefinitely and $51 million expires from 2028 - 2032. We also have $297 million of federal alternative minimum tax credits which do not expire; and approximately $11 million of foreign tax credits, the majority of which will expire from 2015 - 2023. Use of our U.S. federal carryforwards is subject to the limitations provided under Sections 382 and 383 of the Internal Revenue Code as well as the separate return limitation rules of Internal Revenue Service regulations.
Unrecognized Tax Benefits: We recognize 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 not only on the technical merits of the tax position based on tax law, but also the past administrative practices and precedents of the taxing authority. The tax benefits recognized in the 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 resolution.
A reconciliation of our gross unrecognized tax benefit excluding interest and penalties is as follows (in millions):
Our continuing practice is to recognize interest and/or penalties related to income tax matters in income tax expense, and as of December 31, 2013, we had $29 million of accrued interest and $2 million in accrued penalties. As of December 31, 2012, we had $28 million of accrued interest and $2 million in accrued penalties. As of December 31, 2011, we had $5 million of accrued interest and $1 million of accrued penalties. All of the $209 million of unrecognized tax benefits, if recognized, would affect our effective tax rate in future periods. In addition, we believe it is reasonably possible that our liability for unrecognized tax benefits will decrease by approximately $2 million during the next year to approximately $207 million.
We are subject to taxation, and have tax years open to examination for the periods 2008-2013 in the U.S., 1999-2013 in various states and 2004-2013 in various foreign jurisdictions.
5. Property, Plant and Equipment
Classes and Depreciation
As of December 31, 2013 and 2012, our property, plant and equipment consisted of the following (in millions):
As of December 31, 2013 and 2012, we included regulated property, plant and equipment amounts of $14,957 million and $14,937 million, respectively, within “Property, plant and equipment, net” on our accompanying consolidated balance sheets. These regulated amounts constituted 42% and 48%, respectively, of our total property, plant and equipment amounts at each reporting date. Depreciation, depletion, and amortization expense charged against property, plant and equipment was $1,663 million, $1,324 million, and $1,022 million, for the year ended December 31, 2013, 2012, and 2011, respectively.
Asset Retirement Obligations
As of December 31, 2013 and 2012, we recognized asset retirement obligations in the aggregate amount of $204 million and $175 million, respectively. The majority of our asset retirement obligations are associated with the CO2-KMP business segment, where KMP is required to plug and abandon oil and gas wells that have been removed from service and to remove its surface wellhead equipment and compressors. We included $25 million and $31 million of asset retirement obligations as of December 31, 2013 and 2012, respectively, within “Other current liabilities” in our accompanying consolidated balance sheets. The remaining amounts are included within “Other long-term liabilities and deferred credits” at each reporting date.
We have various other obligations throughout our businesses to remove facilities and equipment on rights-of-way and other leased facilities. We currently cannot reasonably estimate the fair value of these obligations because the associated assets have indeterminate lives. These assets include pipelines, certain processing plants and distribution facilities, and certain bulk and liquids terminal facilities. An asset retirement obligation, if any, will be recognized once sufficient information is available to reasonably estimate the fair value of the obligation.
6. Investments
Our investments primarily consist of equity investments where we hold significant influence over investee actions and which we account for under the equity method of accounting. As of December 31, 2013 and 2012 our investments consisted of the following (in millions):
The overall change in the carrying amount of our equity investments, including those of KMP, since December 31, 2012, related primarily to the increases and decreases associated with KMP’s May 1, 2013 Copano acquisition. As part of this acquisition, KMP acquired an approximate 37% equity ownership interest in Fort Union Gas Gathering L.L.C., a 50% equity ownership interest in Double Eagle Pipeline LLC and the remaining 50% equity ownership interest in Eagle Ford that KMP did not already own (KMP exchanged its status as an owner of an equity investment in Eagle Ford for a full controlling financial interest, and KMP began accounting for its investment under the full consolidation method).
As shown in the table above, our remaining significant equity investments, including those of KMP (excluding the three investments described above), as of December 31, 2013 consisted of the following:
•
Citrus Corporation-We operate and own a 50% interest in Citrus Corporation, the sole owner of Florida Gas Transmission Company, L.L.C. (Florida Gas). Florida Gas transports natural gas to cogeneration facilities, electric utilities, independent power producers, municipal generators, and local distribution companies through a 5,300-mile natural gas pipeline. The remaining 50% interest is owned by Energy Transfer Partners L.P.;
•
Ruby Pipeline Holding Company, L.L.C.-We operate and own a 50% interest in Ruby Pipeline Holding Company, L.L.C., the sole owner of Ruby Pipeline natural gas transmission system. The remaining 50% interest is owned by Global Infrastructure Partners as convertible preferred interests;
•
Midcontinent Express Pipeline LLC-KMP operates and owns a 50% interest in MEP, the sole owner of the Midcontinent Express natural gas pipeline system. The remaining 50% ownership interest is owned by subsidiaries of Regency Energy Partners L.P.;
•
Gulf LNG Holdings Group, LLC-We operate and own a 50% interest in Gulf LNG Holdings Group, LLC, the owner of a LNG receiving, storage and regasification terminal near Pascagoula, Mississippi, as well as pipeline facilities to deliver vaporized natural gas into third party pipelines for delivery into various markets around the country. The remaining 50% ownership interests are wholly and partially owned by the subsidiaries of GE Financial Services;
•
Plantation-KMP operates and owns a 51.17% interest in Plantation, the sole owner of the Plantation refined petroleum products pipeline system. A subsidiary of Exxon Mobil Corporation owns the remaining interest. Each investor has an equal number of directors on Plantation’s board of directors, and board approval is required for certain corporate actions that are considered participating rights; therefore, KMP does not control Plantation, and it accounts for its investment under the equity method;
•
BHP Billiton Petroleum (Eagle Ford Gathering) LLC, f/k/a EagleHawk Field Services LLC and referred to in this report as EagleHawk-KMP owns a 25% interest in EagleHawk, the sole owner of a natural gas gathering system serving the producers of the Eagle Ford shale formation. A subsidiary of BHP Billiton operates EagleHawk and owns the remaining 75% ownership interest;
•
Red Cedar Gathering Company-KMP owns a 49% interest in the Red Cedar, the sole owner of the Red Cedar natural gas gathering, compression and treating system. The remaining 51% interest is owned by the Southern Ute Indian Tribe;
•
Fayetteville Express Pipeline LLC -KMP owns a 50% interest in Fayetteville Express Pipeline LLC, the sole owner of the Fayetteville Express natural gas pipeline system. Energy Transfer Partners, L.P. owns the remaining 50% interest and serves as operator of Fayetteville Express Pipeline LLC;
•
Parkway Pipeline LLC -KMP operates and owns a 50% interest in Parkway, the sole owner of the Parkway Pipeline refined petroleum products pipeline system. Valero Energy Corp. owns the remaining 50% interest;
•
Watco Companies, LLC-KMP holds a preferred equity investment in Watco Companies, LLC, the largest privately held short line railroad company in the U.S. KMP owns 100,000 Class A preferred shares and pursuant to the terms of its investment, it receives priority, cumulative cash distributions from the preferred shares at a rate of 3.25% per quarter, and participates partially in additional profit distributions at a rate equal to 0.5%. The preferred shares have no conversion features and hold no voting powers, but do provide KMP certain approval rights, including the right to appoint one of the members to Watco’s Board of Managers;
•
Cortez Pipeline Company-KMP operates and owns a 50% interest in the Cortez Pipeline Company, the sole owner of the Cortez carbon dioxide pipeline system. A subsidiary of Exxon Mobil Corporation owns a 37% interest and Cortez Vickers Pipeline Company owns the remaining 13% interest; and
•
NGPL Holdco LLC- KMI operates and owns a 20% interest in NGPL Holdco LLC, the owner of NGPL and certain affiliates, collectively referred to in this report as NGPL, a major interstate natural gas pipeline and storage system.
During 2012 and 2013, continued deteriorating natural gas market conditions characterized by excess gas supply, low commodity prices, reduced basis spreads and low volatility have negatively impacted NGPL’s operating results and its cash flows. We also determined that these market conditions would likely not improve in the near future. Therefore, these events caused us to evaluate the carrying value of our investment utilizing market conditions and have resulted in us recording impairments on our investment in NGPL Holdco LLC in 2012 and 2013. We recognized $200 million of pre-tax, non-cash impairment charges in 2012, and in 2013, we recognized $65 million of pre-tax, non-cash impairment charges writing down our remaining investment to its estimated fair value of zero.
Both 2013 and 2012 non-cash impairment charges are included in the caption “Earnings from equity investments” in our accompanying consolidated statements of income.
Our earnings (losses) from equity investments were as follows (in millions):
_______
(a)
2012 amounts are for the period from May 25, 2012 through December 31, 2012.
(b)
Effective May 1, 2013, KMP acquired the remaining 50% equity ownership interest in Eagle Ford that KMP did not already own and KMP changed its method of accounting from the equity method to full consolidation.
(c)
Effective July 1, 2011, KMP acquired the remaining 50% equity ownership interest in KinderHawk that KMP did not already own and KMP changed its method of accounting from the equity method to full consolidation.
(d)
2013 and 2012 amounts include non-cash investment impairment charges, which we recorded in the amount of $65 million and $200 million (pre-tax), respectively, as discussed above.
Summarized combined financial information for our significant equity investments (listed or described above) is reported below (in millions; amounts represent 100% of investee financial information):
7. Goodwill and Other Intangibles
Goodwill and Excess Investment Cost
We record the excess of the cost of an acquisition price over the fair value of acquired net assets as an asset on our balance sheet. This amount is referred to and reported separately as “Goodwill” in our accompanying consolidated balance sheets. Goodwill is not subject to amortization but must be tested for impairment at least annually. This test requires us to assign goodwill to an appropriate reporting unit and to determine if the implied fair value of the reporting unit’s goodwill is less than its carrying amount.
We evaluate goodwill for impairment on May 31 of each year. For this purpose, we have seven reporting units as follows: (i) Products Pipelines (excluding associated terminals); (ii) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (iii) Natural Gas Pipelines Regulated; (iv) Natural Gas Pipelines Non-Regulated; (v) CO2; (vi) Terminals; and (vii) Kinder Morgan Canada. During the quarter ended June 30, 2013, we created the Natural Gas Pipelines Non-Regulated reporting unit to include the non-regulated businesses KMP acquired from Copano on May 1, 2013 as well as other non-regulated businesses that were historically part of the former Natural Gas Pipelines reporting unit (now the Natural Gas Pipelines Regulated reporting unit). We then allocated goodwill between these two reporting units based on the relative fair values of the reporting units.
There were no impairment charges resulting from our May 31, 2013 impairment testing, and no event indicating an impairment has occurred subsequent to that date. We determined the fair value of each reporting unit as of May 31, 2013 based on a market approach utilizing an average dividend/distribution yield of comparable companies. The value of each reporting unit was determined on a stand-alone basis from the perspective of a market participant and represented the price estimated to be received in a sale of the unit as a whole in an orderly transaction between market participants at the measurement date.
Changes in the gross amounts of our goodwill and accumulated impairment losses for each of the years ended December 31, 2013 and 2012 are summarized as follows (in millions):
_______
(a)
2012 acquisition amount consists of the EP and EP Midstream acquisitions as discussed in Note 3.
(b)
2012 disposal amount relates to the sale of KMP’s FTC Natural Gas Pipelines disposal group as discussed in Note 3. Since the FTC Natural Gas Pipelines disposal group represented a significant portion of our Natural Gas Pipelines business segment, we allocated the goodwill of the segment based on the relative fair value of the portion being disposed of and the portion of the segment remaining.
(c)
2013 acquisition amount consists of $881 million relating to KMP’s May 1, 2013 Copano acquisition as discussed in Note 3, and $7 million relating to other EP acquisition assets.
For more information on our accounting for goodwill, see Note 2.
With regard to our equity investments in unconsolidated affiliates, in almost all cases, either (i) the price we paid to acquire our share of the net assets of such equity investees or (ii) the revaluation of our share of the net assets of any retained noncontrolling equity investment (from the sale of a portion of our ownership interest in a consolidated subsidiary, thereby losing our controlling financial interest in the subsidiary) differed from the underlying carrying value of such net assets. This differential consists of two pieces. First, an amount related to the difference between the investee’s recognized net assets at
book value and at current fair values (representing the appreciated value in plant and other net assets), and secondly, to any premium in excess of fair value (referred to as equity method goodwill) we paid to acquire the investment. We include both amounts within “Investments” on our accompanying consolidated balance sheets.
The first differential, representing the excess of the fair market value of our investees’ plant and other net assets over its underlying book value at either the date of acquisition or the date of the loss of control totaled $809 million and $714 million as of December 31, 2013 and 2012, respectively. In almost all instances, this differential, relating to the discrepancy between our share of the investee’s recognized net assets at book values and at current fair values, represents our share of undervalued depreciable assets, and since those assets (other than land) are subject to depreciation, we amortize this portion of our investment cost against our share of investee earnings. As of December 31, 2013, this excess investment cost is being amortized over a weighted average life of approximately fifteen years.
The second differential, representing total unamortized excess cost over underlying fair value of net assets acquired (equity method goodwill) totaled $138 million as of both December 31, 2013 and 2012. This differential is not subject to amortization but rather to impairment testing. Accordingly, in addition to our annual impairment test of goodwill, we periodically reevaluate the amount at which we carry the excess of cost over fair value of net assets accounted for under the equity method, as well as the amortization period for such assets, to determine whether current events or circumstances warrant adjustments to our carrying value and/or revised estimates of useful lives. Our impairment test considers whether the fair value of the equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. As of December 31, 2013, we believed no such impairment had occurred and no reduction in estimated useful lives was warranted.
Other Intangibles
Excluding goodwill, our other intangible assets include customer contracts, relationships and agreements, lease value, and technology-based assets. These intangible assets have definite lives, are subject to amortization, and are reported separately as “Other intangibles, net” in our accompanying consolidated balance sheets. As of December 31, 2013 and 2012, these intangible assets totaled $2,438 million and $1,171 million, respectively, and primarily consisted of customer contracts, relationships and agreements associated with the Natural Gas Pipelines and Terminals-KMP business segments.
Primarily, these contracts, relationships and agreements relate to the gathering of natural gas, and the handling and storage of petroleum, chemical, and dry-bulk materials, including oil, gasoline and other refined petroleum products, coal, petroleum coke, fertilizer, steel and ores. We determined the values of these intangible assets by first, estimating the revenues derived from a customer contract or relationship (offset by the cost and expenses of supporting assets to fulfill the contract), and second, discounting the revenues at a risk adjusted discount rate.
We amortize the costs of our intangible assets to expense in a systematic and rational manner over their estimated useful lives. The life of each intangible asset is based either on the life of the corresponding customer contract or agreement or, in the case of a customer relationship intangible (the life of which was determined by an analysis of all available data on that business relationship), the length of time used in the discounted cash flow analysis to determine the value of the customer relationship. Among the factors we weigh, depending on the nature of the asset, are the effect of obsolescence, new technology, and competition.
For each of the years ended December 31, 2013, 2012 and 2011, the amortization expense on our intangibles totaled $125 million, $86 million and $65 million, respectively. Our estimated amortization expense for our intangible assets for each of the next five fiscal years (2014 - 2018) is approximately $141 million, $136 million, $134 million, $132 million, and $130 million respectively. As of December 31, 2013, the weighted average amortization period for our intangible assets was approximately twenty years.
8. Debt
We classify our debt based on the contractual maturity dates of the underlying debt instruments. We defer costs associated with debt issuance over the applicable term. These costs are then amortized as interest expense in our accompanying consolidated statements of income using the effective interest rate method. The following table provides detail on the principal amount of our outstanding debt balances as of December 31, 2013 and 2012. The table amounts exclude all debt fair value adjustments, including debt discounts and premiums (in millions):
_______
(a)
Notes provide for the redemption at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make whole premium.
(b)
As of December 31, 2013 and 2012, the weighted average interest rates on KMI’s credit facility borrowings were 2.67% and 2.72%, respectively.
(c)
KMI’s business trusts, K N Capital Trust I and K N Capital Trust III, are obligated for $13 million of 8.56% Capital Trust Securities maturing on April 15, 2027 and $14 million of 7.63% Capital Trust Securities maturing on April 15, 2028, respectively, which it guarantees. The 2028 securities are redeemable in whole or in part, at KMI’s option at any time, at redemption prices as defined in the associated prospectus. The 2027 securities are redeemable in whole or in part at KMI’s option and at any time in certain limited circumstances upon the occurrence of certain events and at prices all defined in the associated prospectus supplements. Upon redemption by KMI or at maturity of the Junior Subordinated Deferrable Interest Debentures, the proceeds must be used to make redemptions of the Capital Trust Securities on a pro rata basis.
(d)
Each series of these notes is fully and unconditionally guaranteed by KMI on a senior secured basis as to principal, interest and any additional amounts required to be paid as a result of any withholding or deduction for Canadian taxes.
(e)
EPC Building, LLC, as the landlord, leases the property to KMI as a tenant.
(f)
Capital Trust I (Trust I), is a 100%-owned business trust that as of December 31, 2013, had $5.6 million of 4.75% trust convertible preferred securities outstanding (referred to as the EP Trust I Preferred Securities). Trust I exists for the sole purpose of issuing preferred securities and investing the proceeds in 4.75% convertible subordinated debentures, which are due 2028. Trust I’s sole source of income is interest earned on these debentures. This interest income is used to pay distributions on the preferred securities. EP provides a full and unconditional guarantee of the EP Trust I Preferred Securities. There are no significant restrictions on EP’s ability to obtain funds from its subsidiaries by distribution, dividend or loan. The EP Trust I Preferred Securities are non-voting (except in limited circumstances), pay quarterly distributions at an annual rate of 4.75%, carry a liquidation value of $50 per security plus accrued and unpaid distributions and are convertible at any time prior to the close of business on March 31, 2028, at the option of the holder, into the following mixed consideration: (i) 0.7197 of a share of KMI Class P common stock; (ii) $25.18 in cash without interest; and (iii) 1.100 warrants to purchase a share of KMI Class P common stock. We have the right to redeem these Trust I Preferred Securities at any time. Because of the substantive conversion rights of the securities into the mixed consideration, we bifurcated the fair value of the EP Trust I Preferred Securities into debt and equity components and as of December 31, 2013, the outstanding balance of $280 million (of which $141 million is classified as current) was bifurcated between debt ($247 million) and equity ($33 million). During the years ended December 31, 2013 and 2012, 107,618 and 781,633 EP Trust I Preferred Securities had been converted into (i) 77,442 and 562,521 shares of KMI Class P common stock; (ii) approximately $3 million and $20 million in cash; and (iii) 118,377 and 859,796 in warrants, respectively.
(g)
As of December 31, 2013, KMGP had outstanding 100,000 shares of its $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock due 2057. Until August 18, 2012, dividends accumulated, commencing on the issue date, at a fixed rate of 8.33% per annum and were payable quarterly in arrears, when and if declared by KMGP’s board of directors, on February 18, May 18, August 18 and November 18 of each year, beginning November 18, 2007. After August 18, 2012, dividends on the preferred stock accumulate at a floating rate of the 3-month LIBOR plus 3.8975% and are payable quarterly in arrears, when and if declared by KMGP’s board of directors, on February 18, May 18, August 18 and November 18 of each year, beginning November 18, 2012. The preferred stock has approval rights over a commencement of or filing of voluntary bankruptcy by KMP or its SFPP or Calnev subsidiaries. (see “-KMGP Preferred Shares” below).
(h)
Excludes debt fair value adjustments. As of December 31, 2013 and December 31, 2012, our total “Debt fair value adjustments” increased our combined debt balances by $1,977 million and $2,591 million, respectively. In addition to all unamortized debt discount/premium amounts and purchase accounting on our debt balances, our debt fair value adjustments also include (i) amounts associated with the offsetting entry for hedged debt; and (ii) any unamortized portion of proceeds received from the early termination of interest rate swap agreements. For further information about our debt fair value adjustments, see Note 13.
(i)
In May 2013, in association with the increase of capacity negotiated for KMP’s senior unsecured revolving bank credit facility (see “-Credit Facilities and Restrictive Covenants-KMP” below), KMP increased its commercial paper program by $500 million to provide for the issuance of up to $2.7 billion. As of December 31, 2013 and December 31, 2012, the average interest rates on KMP’s outstanding commercial paper borrowings were 0.28% and 0.45%, respectively. The borrowings under KMP’s commercial paper program were used principally to finance the acquisitions and capital expansions it made during 2013 and 2012.
(j)
See “Credit Facilities and Restrictive Covenants-KMP” below.
(k)
Consists of six separate series of fixed-rate unsecured senior notes that KMP assumed as part of the August 2012 drop-down transaction.
(l)
Consists of four separate series of fixed-rate unsecured senior notes that KMP assumed as part of the August 2012 and March 2013 drop-down transactions.
(m)
Consists of a single series of fixed-rate unsecured senior notes that KMP guaranteed as part of its May 1, 2013 Copano acquisition. The notes mature on April 1, 2021, and interest on the notes is payable semiannually on April 1 and October 1 of each year. For further information about these notes, see “-KMP’s Copano Debt” below.
(n)
Includes commercial paper borrowings.
(o)
EPB’s only operating asset is its investment in EPPOC, and EPPOC’s only operating assets are its investments in Wyoming Interstate Company, L.L.C. (WIC), CIG, SLNG, Elba Express, SNG, ELC and Cheyenne Plains Gas Pipeline Company, L.L.C. (CPG), (collectively, the non-guarantor operating companies). EPB and EPPOC’s independent assets and operations, other than those related to these investments and EPPOC’s debt are less than 3% of the total assets and operations of EPB, and thus substantially all of the operations and assets exist within these non-guarantor operating companies. Furthermore, there are no significant restrictions on EPPOC or EPB’s ability to access the net assets or cash flows related to its controlling interests in the operating companies either through dividend or loan. The restrictive covenants under these debt obligations are no more restrictive than the restrictive covenants under EPB’s credit facility.
(p)
LIBOR plus 1.75%.
(q)
CIG is subject to a number of restrictions and covenants under its debt obligation. The most restrictive of these include limitations on the incurrence of liens and limitations on sale-leaseback transactions.
(r)
The SLNG senior notes impose certain limitations on the ability of SLNG to, among other things, incur additional indebtedness, make certain restricted payments, enter into transactions with affiliates, and merge or consolidate with any other person, sell, assign, transfer,
lease, convey or otherwise dispose of all or substantially all of its assets. SLNG is required to comply with certain financial covenants, including a leverage ratio of no more than 5.0 to 1.0 and an interest coverage ratio of no less than 2.0 to 1.0. The SLNG senior notes are subject to a change of control prepayment offer in the event of a ratings downgrade within a 120-day period from and including the date on which a change of control with respect to SLNG occurs (as defined in the note purchase agreement). If a sufficient number of the rating agencies downgrade the ratings of the SLNG notes below investment grade within the 120-day period from and including the date of any such change of control, then SLNG is required to offer to prepay the entire unpaid principal amount of the notes held by each holder at 101% of the principal amount of such SLNG notes (without any make-whole amount or other penalty), together with interest accrued thereon to the date for such prepayment.
(s)
Under its indentures, SNG is subject to a number of restrictions and covenants. The most restrictive of these include limitations on the incurrence of liens. SNIC is a wholly owned finance subsidiary of SNG and is the co-issuer of certain of SNG's outstanding debt securities. SNIC has no material assets, operations, revenues or cash flows other than those related to its service as a co-issuer of the debt securities. Accordingly, it has no ability to service obligations on the debt securities.
(t)
In conjunction with the construction of the Totem Gas Storage facility (Totem) and the High Plains pipeline (High Plains), CIG's joint venture partner in WYCO funded 50% of the construction costs. EPB reflected the payments made by their joint venture partner as other long-term liabilities on the balance sheet during construction and upon project completion, the advances were converted into a financing obligation to WYCO. Upon placing these projects in service, EPB transferred its title in the projects to WYCO and leased the assets back. Although EPB transferred the title in these projects to WYCO, the transfer did not qualify for sale leaseback accounting because of EPB’s continuing involvement through its equity investment in WYCO. As such, the costs of the facilities remain on our balance sheets and the advanced payments received from EPB’s 50% joint venture partner were converted into a financing obligation due to WYCO. As of December 31, 2013, the principal amounts of the Totem and High Plains financing obligations were $75 million and $94 million, respectively, which will be paid in monthly installments through 2039, and extended for the term of related firm service agreements until 2060 and 2043, respectively. The interest rate on these obligations is 15.5%, payable on a monthly basis.
Credit Facilities and Restrictive Covenants
KMI
On February 10, 2012, KMI entered into the following agreements which were effective with the May 25, 2012 acquisition of EP: (i) an amendment to its existing $1 billion revolving credit facility to, among other things, permit the EP acquisition, to fund, in part, the transactions and related costs and expenses, and to provide for ongoing working capital and for other general corporate purposes; (ii) an incremental joinder agreement which provides for $750 million in additional commitments under the existing revolving credit facility; and (iii) an acquisition debt facilities credit agreement (Acquisition Credit Facility) containing a 364-day bridge facility and a $5 billion 3-year term loan facility, the proceeds of which were used to finance a portion of the cash consideration and related fees and expenses paid in connection with the EP acquisition.
The amended and restated credit facility provides that the $1.75 billion revolver bears interest, at KMI’s option, at either (i) the adjusted LIBOR plus an applicable margin per annum varying from 2.50% per annum to 4.25% per annum depending on the publicly announced debt ratings for senior secured non-credit enhanced long-term indebtedness for borrowed money of KMI or (ii) an alternate base rate plus an applicable margin varying from 1.50% per annum to 3.25% per annum depending on debt ratings of KMI. In August 2012, we repaid the remaining outstanding balance of the 364-day bridge facility and terminated the facility. In November 2012, the terms of KMI’s $1.75 billion senior secured revolving credit facility were amended to decrease the fixed spread component of our floating interest rate by 100 basis points and to extend the maturity of the revolver to December 31, 2014. As of December 31, 2013, KMI was in compliance with all required financial covenants (described following).
KMI’s credit facility included the following restrictive covenants as of December 31, 2013:
•
total debt divided by earnings before interest, income taxes, depreciation and amortization may not exceed 6.00: 1.00;
•
certain limitations on indebtedness, including payments and amendments;
•
certain limitations on entering into mergers, consolidations, sales of assets and investments;
•
limitations on granting liens; and
•
prohibitions on making any dividend to shareholders if an event of default exists or would exist upon making such dividend.
The Acquisition Credit Facility provides that:
•
the term loans under the term loan facility bears interest, at KMI’s option, at either (i) adjusted LIBOR plus an applicable margin varying from 3.00% per annum to 4.75% per annum depending on certain debt ratings of KMI or (ii) an alternate base rate plus an applicable margin varying from 2.00% per annum to 3.75% per annum depending on certain debt ratings of KMI.
As of December 31, 2013, we had $175 million outstanding under KMI’s $1.75 billion credit facility and $80 million in letters of credit. Our availability under this facility as of December 31, 2013 was $1,495 million.
KMP
On May 1, 2013, KMP replaced its previous $2.2 billion, senior unsecured revolving credit facility that was due July 1, 2016, with a new $2.7 billion five-year senior unsecured revolving credit facility expiring May 1, 2018. Borrowings under the credit facility can be used for general partnership purposes and as a backup for KMP’s commercial paper program, and borrowings under the commercial paper program reduce the borrowings allowed under KMP’s credit facility. KMP had no borrowings under the credit facility as of December 31, 2013, and there were no borrowings under its previous credit facility as of December 31, 2012. KMP’s new credit facility’s financial covenants are substantially similar to those in the previous facility, and as of December 31, 2013, KMP was in compliance with all required financial covenants (described following). KMP’s credit facility provides that both the margin KMP will pay with respect to borrowings and the facility fee KMP will pay on the total commitment, will vary based on its senior debt credit rating. Interest on the credit facility accrues at KMP’s option at a floating rate equal to either:
•
the administrative agent’s base rate, plus a margin, which varies depending upon the credit rating of KMP’s long-term senior unsecured debt (the administrative agent’s base rate is a rate equal to the greatest of (i) the Federal Funds Rate, plus 0.5%; (ii) the Prime Rate; or (iii) LIBOR for a one -month eurodollar loan, plus 1%); or
•
LIBOR for a one -month eurodollar loan, plus a margin, which varies depending upon the credit rating of KMP’s long-term senior unsecured debt.
As of December 31, 2013, KMP had $979 million of commercial paper borrowings outstanding under its $2.7 billion credit facility and $203 million in letters of credit. KMP’s availability under its facility as of December 31, 2013 was $1,518 million.
KMP’s credit facility included the following restrictive covenants as of December 31, 2013:
•
total debt divided by earnings before interest, income taxes, depreciation and amortization for the preceding four quarters may not exceed:
•
5.5, in the case of any such period ended on the last day of (i) a fiscal quarter in which KMP makes any Specified Acquisition (as defined in the credit facility) or (ii) the first or second fiscal quarter next succeeding such a fiscal quarter; or
•
5.0, in the case of any such period ended on the last day of any other fiscal quarter;
•
certain limitations on entering into mergers, consolidations and sales of assets;
•
limitations on granting liens; and
•
prohibitions on making any distribution to holders of units if an event of default exists or would exist upon making such distribution.
In addition to normal repayment covenants, under the terms of KMP’s credit facility, the occurrence at any time of any of the following would constitute an event of default: (i) KMP’s failure to make required payments of any item of indebtedness or any payment in respect of any hedging agreement, provided that the aggregate outstanding principal amount for all such indebtedness or payment obligations in respect of all hedging agreements is equal to or exceeds $75 million; (ii) KMP’s general partner’s failure to make required payments of any item of indebtedness, provided that the aggregate outstanding principal amount for all such indebtedness is equal to or exceeds $75 million; (iii) adverse judgments rendered against KMP for the payment of money in an aggregate amount in excess of $75 million, if this same amount remains undischarged for a period of thirty consecutive days during which execution shall not be effectively stayed; and (iv) voluntary or involuntary commencements of any proceedings or petitions seeking KMP’s liquidation, reorganization or any other similar relief under any federal, state or foreign bankruptcy, insolvency, receivership or similar law.
KMP’s credit facility does not contain a material adverse change clause coupled with a lockbox provision; however, the facility does provide that the margin KMP will pay with respect to borrowings, and the facility fee that it will pay on the total commitment, will vary based on its senior debt credit rating. None of KMP’s debt is subject to payment acceleration as a result of any change to its credit ratings.
EPB
In May 2011, EPPOC and WIC entered into an unsecured five-year credit facility with an initial aggregate borrowing capacity of $1 billion, expandable to $1.5 billion for certain expansion projects and acquisitions. EPPOC is a wholly owned subsidiary of EPB. In May 2012, EPB borrowed from the revolving credit facility to fund the acquisition of CPG and the
remaining interest in CIG. On May 24, 2012, Standard & Poor’s Rating Service raised EPB’s credit rating, triggering a pricing level change. EPB’s interest rate for borrowings under the credit facility has decreased from the LIBOR plus 2% to LIBOR plus 1.75% and the commitment fee paid for unutilized commitments decreased from 0.4% to 0.3% and these rates remained effective at December 31, 2013. As of December 31, 2013, EPB had no outstanding balance under its revolving credit facility. EPB’s remaining availability under this facility was $1 billion. Borrowings under the credit facility are guaranteed by EPB.
EPB’s credit facility included the following restrictive covenants as of December 31, 2013:
•
EPB and WIC’s consolidated total debt divided by earnings before interest, income taxes, depreciation and amortization as of the end of each quarter may not exceed:
•
5.0 to 1.0 for any trailing four consecutive quarter period; and
•
5.5 to 1.0 for any such four quarter period during the three full fiscal quarters subsequent to the consummation of specified permitted acquisitions having a value greater than $25 million;
•
certain limitations on entering into mergers, consolidations and sales of assets;
•
limitations on granting liens; and
•
prohibitions on making any distribution to holders of units if an event of default exists or would exist upon making such distribution.
EPB also has additional flexibility to the covenants for growth projects. In case of a capital construction or expansion project in excess of $20 million, pro forma adjustments to consolidated earnings before interest, income taxes, depreciation and amortization, approved by the lenders, may be made based on the percentage of capital costs expended and projected cash flows for the project. Such adjustments shall be limited to 25% of actual consolidated earnings before interest, income taxes, depreciation and amortization.
The credit facility contains certain customary events of default that affect EPB, the borrowers and EPB’s other restricted subsidiaries, including, without limitation, (i) nonpayment of principal when due or nonpayment of interest or other amounts within five business days when due; (ii) bankruptcy or insolvency with respect to EBP, its general partner, the borrowers or any of EPB’s other restricted subsidiaries; (iii) judgment defaults against EPB, its general partner, the borrowers or any of EPB’s other restricted subsidiaries in excess of $50 million; or (iv) the failure of El Paso to directly or indirectly own a majority of the voting equity of EPB’s general partner and a failure by EPB to directly or indirectly own 100% of the equity of EPPOC.
KMP’s Copano Debt
As of the May 1, 2013 Copano acquisition date, KMP assumed the following outstanding Copano debt amounts (i) $404 million of outstanding borrowings under Copano’s revolving credit facility due June 10, 2016; (ii) $249 million aggregate principal amount of Copano’s 7.75% unsecured senior notes due June 1, 2018; and (iii) $510 million aggregate principal amount of Copano’s 7.125% unsecured senior notes due April 1, 2021. Immediately following the acquisition, KMP repaid the outstanding $404 million of borrowings under Copano’s revolving credit facility, and terminated the credit facility at the time of such repayment. On June 1, 2013, KMP paid $259 million (based on a price of 103.875% of the principal amount) to fully redeem and retire the 7.75% series of senior notes in accordance with the terms and conditions of the indenture governing the notes. As part of its May 1, 2013 purchase price allocation, KMP valued the 7.75% senior notes equal to the $259 million redemption value and accordingly, no gain or loss was recorded from this debt retirement. KMP utilized borrowings under its commercial paper program for both of these debt retirements.
On September 4, 2013, KMP paid $191 million to complete the partial redemption and retirement of $178 million (35%) of the total $510 million outstanding principal amount of Copano’s 7.125% senior notes, (excluding a $6 million payment for accrued and unpaid interest on the redeemed notes as of September 4, 2013). As part of its May 1, 2013 purchase price allocation, KMP valued the repaid portion of the 7.125% senior notes equal to the $191 million redemption value and accordingly, KMP recorded no gain or loss from this debt retirement. As of December 31, 2013, an aggregate principal amount of $332 million of 7.125% senior notes remained outstanding.
Debt Issuances and Repayments
Apart from the changes in KMP’s Copano debt discussed above, following are significant long-term debt issuances and repayments made during 2013 and 2012:
_______
(a)
In December 2012, our subsidiary, EPC Building, LLC had issued $468 million of 3.967% amortizing promissory notes with payments due 2013 through 2035, of which $217 million was issued to third parties and the remaining $251 million was held by KMI until they were sold to third parties in April of 2013. Proceeds from the issuance of the notes were used to reduce KMI’s credit facility borrowings.
KMGP Preferred Shares
The following table provides information about KMGP’s distributions on 100,000 shares of its Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock:
_______
(a)
On January 15, 2014, KMGP declared a distribution for the three months ended December 31, 2013, of $10.570 per share, which was paid on February 18, 2014 to shareholders of record as of January 31, 2014.
Maturities of Debt
The scheduled maturities of the outstanding debt balances, excluding debt fair value adjustments as of December 31, 2013, are summarized as follows (in millions):
Interest Rates, Interest Rate Swaps and Contingent Debt
The weighted average interest rate on all of our borrowings was 5.08% during 2013 and 4.92% during 2012. Information on our interest rate swaps is contained in Note 13. For information about our contingent debt agreements, see Note 12.
Subsequent Events
On January 17, 2014, KMP entered into a short-term unsecured liquidity facility. This liquidity facility provides for borrowings up to $1.0 billion with a term of six months. The covenants of this facility are substantially similar to the covenants of KMP’s existing senior credit facility that is due May 1, 2018. In conjunction with the establishment of KMP’s liquidity facility, KMP increased its commercial paper program to provide for the issuance of up to $3.7 billion (up from $2.7 billion). KMP’s liquidity facility supports its commercial paper program and borrowings under its commercial paper program reduce the borrowings allowed under KMP’s liquidity facility. As of the date of this report, KMP has no borrowings under its liquidity facility.
On February 19, 2014, KMP priced in a public offering $750 million of 3.50% senior notes due March 1, 2021 and $750 million of 5.50% senior notes due March 1, 2044.
9. Share-based Compensation and Employee Benefits
Share-based Compensation
Kinder Morgan, Inc.
We completed an initial public offering in February 2011 as discussed further in Note 10 “Stockholders’ Equity-Kinder Morgan, Inc.-Initial Public Offering.” As a result of our initial public offering, our outstanding Class B units and Class A-1 units were converted to Class B shares and Class C shares, respectively. As of December 26, 2012, all class B and C shares had converted into Class P shares.
Class P Shares
Stock Compensation Plan for Non-Employee Directors
In connection with our initial public offering, we adopted the Stock Compensation Plan for Non-Employee Directors, in which our independent directors will participate. None of the 11 directors nominated by Richard D. Kinder or the Sponsor Investors participate in the plan. The plan recognizes that the compensation paid to each non-employee director is fixed by our board, generally annually, and that the compensation is payable in cash. Pursuant to the plan, in lieu of receiving some or all of the cash compensation, each non-employee director who was not nominated by Richard D. Kinder or one of the Sponsor Investors, referred to as “eligible directors,” may elect to receive shares of Class P common stock. Each election will be generally at or around the first board meeting in January of each calendar year and will be effective for the entire calendar year. An eligible director may make a new election each calendar year. The total number of shares of Class P common stock
authorized under the plan is 250,000. During 2013, 2012 and 2011, we made restricted Class P common stock grants to our non-employee directors of 5,710, 5,520 and 1,570, respectively. These grants were valued at time of issuance at $210,000, $185,000 and $45,000, respectively. All of the restricted stock grants made to non-employee directors vest during a six-month period.
Restricted Stock and Long-term Incentive Retention Award Plan
Upon our initial public offering, our restricted stock compensation program replaced our Long-term Incentive Retention Award Plan. Our restricted stock compensation program is available to employees eligible under the former Long-term Incentive Retention Award Plan, discussed below. The following table sets forth a summary of activity and related balances of our restricted stock excluding that issued to non-employee directors (in millions, except share amounts):
Restricted stock grants made to employees have vesting periods ranging from 2 years with variable vesting dates to 7 years. Following is a summary of the future vesting of our outstanding restricted stock grants:
The related expense less estimated forfeitures is recognized ratably over the vesting period of the restricted stock grants. Upon vesting, the grants will be paid in our Class P common shares.
During 2013, 2012 and 2011, we recorded $35 million, $14 million and $4 million, respectively, in expense related to restricted stock grants. In addition, in conjunction with the exchange for restricted shares discussed above, we recorded an increase to additional paid-in capital in the amount of $2 million in 2011. At December 31, 2013 and 2012, unrecognized restricted stock compensation expense, less estimated forfeitures, was approximately $177 million and $49 million, respectively.
From 2006 until our initial public offering, we elected not to make any restricted stock awards as a result of a 2007 going private transaction. To ensure that certain key employees who had previously received restricted stock and restricted stock unit
awards continued under a long-term retention and incentive program, the Company implemented the Long-term Incentive Retention Award plan. The plan provided cash awards approved by the compensation committees of the Company which were granted in July of each year to recommended key employees. Senior management was not eligible for these awards. These grants required the employee to sign a grant agreement. The grants vested 100% after the third year anniversary of the grant provided the employee remained with the Company. The remaining grants outstanding were made in July of 2010. During the years ended December 31,2013, 2012, and 2011, we expensed $2 million, $7 million and $13 million, respectively, related to these grants.
Awards of Participation Interests in a 2007 Going Private Transaction
In connection with our 2007 going private transaction, members of management were awarded Kinder Morgan Holdco LLC Class A-1 and Class B units. In accordance with generally accepted accounting principles, we were required to recognize compensation expense in connection with the Class A-1 and Class B units over the expected life of such units; however, we did not have any obligation, nor did we pay any amounts related to these compensation expenses as all expenses were borne by the Investors, and since we were not responsible for paying these expenses, we recognized the amounts allocated to us as both an expense on our income statement and a contribution to “Stockholders Equity” on our balance sheet. The awards and terms of the Class B units granted to members of management were determined after extensive negotiations between management and the Sponsor Investors with respect to which management agreed to forego any long-term executive compensation at least until the Sponsor Investors sell their interests in us or convert their Class A shares into Class P shares. The Class B units were converted into Class B shares, and the class A-1 units were converted into Class C shares in connection with our initial public offering. The aggregate amount of our Class P common stock into which the Class A shares, Class B shares and Class C shares could convert was fixed. The conversion of Class B shares into Class P shares reduced the number of Class P shares into which the Class A shares and Class C shares could convert. Therefore, we view the Class B shares, along with the Class A shares and Class C shares, as participation interests in a going private transaction, rather than as awards of stock-based compensation. As of December 26, 2012, all class B and C shares had converted into Class P shares.
Kinder Morgan Energy Partners, L.P.
On January 18, 2005, KMR’s compensation committee established the Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors. The plan is administered by KMR’s compensation committee and KMR’s board has sole discretion to terminate the plan at any time. The primary purpose of this plan is to promote KMP’s interests and the interests of its unitholders by aligning the compensation of the non-employee members of the board of directors of KMR with KMP unitholders’ interests. Further, since KMR’s success is dependent on its operation and management of KMP’s business and its resulting performance, the plan is expected to align the compensation of the non-employee members of the board with the interests of KMR’s shareholders.
The Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors recognizes that the compensation to be paid to each non-employee director is fixed by the KMR board, generally annually, and that the compensation is payable in cash. Pursuant to the plan, in lieu of receiving cash compensation, each non-employee director may elect to receive common units. Each election is made generally at or around the first board meeting in January of each calendar year and is effective for the entire calendar year. A non-employee director may make a new election each calendar year. The total number of common units authorized under this compensation plan is 100,000. All common units issued under this plan are subject to forfeiture restrictions that expire six months from the date of issuance. A total of 2,450 common units were issued to non-employee directors in 2011 as a result of their elections to receive common units in lieu of cash compensation.
Pension and Other Postretirement Benefit Plans
Overview of Retirement Benefit Plans
Savings Plan
We maintain a defined contribution plan covering eligible U.S. employees. We contribute 5% of eligible compensation for most of the plan participants. Certain plan participants’ contributions and Company contributions are based on collective bargaining agreements. In connection with the EP acquisition, we assumed EP’s defined contribution savings plan which was merged into our savings plan during 2012. In connection with KMP’s Copano acquisition, we assumed Copano’s defined contribution savings plan which was merged into our savings plan during 2013. The total amount charged to expense for our savings plan was approximately $40 million, $32 million, and $24 million for the years ended December 31, 2013, 2012, and 2011, respectively.
Pension Plans
Our pension plan is a defined benefit plan that covers substantially all of our U.S. employees and provides benefits under a cash balance formula. A participant in the cash balance plan accrues benefits through contribution credits based on a combination of age and years of service times eligible compensation. Interest is also credited to the participant’s plan account. A participant becomes fully vested in the plan after three years, and may take a lump sum distribution upon termination of employment or retirement. Certain collectively bargained and grandfathered employees continue to accrue benefits through a career pay formula.
In connection with the EP acquisition, we assumed EP’s defined benefit pension plans including a cash balance plan and a supplemental executive retirement plan (“SERP”). These plans had combined benefit obligations of $2,407 million and assets of $1,949 million as of the May 25, 2012 acquisition date. We merged the EP cash balance plan into our cash balance plan on December 31, 2012. We terminated the EP SERP and partially settled the plan’s benefit obligation during 2012. The $28 million SERP obligation that remained as of December 31, 2012 was settled in February 2013.
Other Postretirement Benefit Plans
We and certain of our U.S. subsidiaries provide other postretirement benefits (“OPEB”), including medical benefits for closed groups of retired employees and certain grandfathered employees and their dependents, and limited postretirement life insurance benefits for retired employees. Medical benefits for these closed groups of retirees may be subject to deductibles, co-payment provisions, dollar caps and other limitations on the amount of employer costs, and we reserve the right to change these benefits. Effective January 1, 2014, the plan was amended to provide a fixed subsidy to post-age 65 Medicare eligible participants to purchase coverage through a retiree Medicare exchange.
In connection with the EP acquisition, we assumed EP’s OPEB plans including retiree medical and life insurance benefits. These plans had aggregate benefit obligations of $606 million and assets of $273 million as of the May 25, 2012 acquisition date.
Additionally, KMP’s subsidiary SFPP has incurred certain liabilities for postretirement benefits to certain current and former employees, their covered dependents, and their beneficiaries. However, the net periodic benefit costs, contributions and liability amounts associated with the SFPP postretirement benefit plan are not material to our consolidated income statements or balance sheets.
Benefit Obligation, Plan Assets and Funded Status. The following table provides information about our pension and OPEB plans as of and for each of the years ended December 31, 2013 and 2012, and includes information regarding the EP Pension and OPEB plans since the May 25, 2012 acquisition date (in millions):
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(a) Reflects the acquisition date amount of benefit plan obligations and assets assumed from El Paso.
(b) Reflects the settlement of benefit obligations associated with certain participants in the acquired El Paso plans as a result of the sale of EP Energy, a reduction in force and termination of the SERP.
Components of Funded Status. The following table details the amounts recognized in our balance sheet at December 31, 2013 and 2012 related to our pension and OPEB plans (in millions):
Components of Accumulated Other Comprehensive Income (Loss). The following table details the amounts of pre-tax accumulated other comprehensive income (loss) at December 31, 2013 and 2012 related to our pension and OPEB plans which are included on our accompanying consolidated balance sheets, including the portion attributable to our noncontrolling interests, (in millions):
We anticipate that less than $1 million of pre-tax accumulated other comprehensive loss will be recognized as part of our net periodic benefit cost in 2014, including approximately $1 million of unrecognized net actuarial loss and approximately $1 million of unrecognized prior service credit.
Our accumulated benefit obligation for our defined benefit pension plans was $2,516 million and $2,773 million at December 31, 2013 and 2012, respectively.
Our accumulated postretirement benefit obligation for our OPEB plans, whose accumulated postretirement benefit obligations exceeded the fair value of plan assets, was $534 million and $569 million at December 31, 2013 and 2012, respectively. The fair value of these plans’ assets was approximately $60 million and $55 million at December 31, 2013 and 2012, respectively.
Plan Assets. The investment policies and strategies for the assets of each of the pension and OPEB plans are established by the Fiduciary Committee (the “Committee), which is responsible for investment decisions and management oversight of each plan. The stated philosophy of the Committee is to manage these assets in a manner consistent with the purpose for which the plans were established and the time frame over which the plans’ obligations need to be met. The objectives of the investment management program are to (1) meet or exceed plan actuarial earnings assumptions over the long term and (2) provide a reasonable return on assets within established risk tolerance guidelines and liquidity needs of the plans with the goal of paying benefit and expense obligations when due. In seeking to meet these objectives, the Committee recognizes that prudent investing requires taking reasonable risks in order to raise the likelihood of achieving the targeted investment returns. In order to reduce portfolio risk and volatility, the Committee has adopted a strategy of using multiple asset classes.
As of December 31, 2013, the target asset allocations in effect for the pension plan were 50%, equity, 45% fixed income and 5% company securities. As of December 31, 2013, the target asset allocations in effect for the retiree medical and retiree life insurance plans were 70% equity and 30% fixed income.
Below are the details of our pension and OPEB plan assets classified by level and a description of the valuation methodologies used for assets measured at fair value.
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Level 1 assets’ fair values are based on quoted market prices for the instruments in actively traded markets. Included in this level are dollar-denominated money market funds, common and preferred stock, exchange traded mutual funds and limited partnerships. These investments are valued at the closing price reported on the active market on which the individual securities are traded.
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Level 2 assets’ fair values are primarily based on pricing data representative of quoted prices for similar assets in active markets (or identical assets in less active markets). Included in this level are money market funds, common/collective trust funds, mutual funds, limited partnerships, trusts, fixed income and other securities. Money market funds are valued at amortized cost, which approximates fair value. The common/collective trust funds’, mutual funds’, limited partnerships’ and trusts’ fair values are based on the net asset value as reported by the issuer, which is determined based on the fair value of the underlying securities as of the valuation date. The fixed income securities’ fair values are primarily based on an evaluated price which is based on a compilation of primarily observable market information or a broker quote in a non-active market.
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Level 3 assets’ fair values are calculated using valuation techniques that require inputs that are both significant to the fair value measurement and are unobservable, or are similar to Level 2 assets and are also subject to certain restrictions associated with the timing of redemption which extend beyond 90 days as of December 31. Included in
this level are insurance contracts, mutual funds with significant redemption restrictions, limited partnerships and private equity. Insurance contracts are valued at contract value, which approximates fair value. The mutual funds’ fair values are primarily based on the net asset value as reported by the issuer, which is determined based on the fair value of the underlying securities as of the valuation date. The limited partnerships’ and private equity investments’ fair values are primarily based on the securities’ value as reported by the issuer, which may be determined utilizing discounted present value.
Listed below are the fair values of our pension and OPEB plans’ assets that are recorded at fair value classified in each level at December 31, 2013 and 2012 (in millions):
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(a)
For 2013, this category includes common/collective trust funds which are invested in approximately 36% fixed income, 62% equity and 2% short term securities. For 2012, this category includes common/collective trusts funds which are invested in approximately 59% fixed income, 36% equity and 5% short term securities.
(b)
For 2013, this category includes mutual funds which are invested in approximately 60% fixed income and 40% equity. For 2012, this category includes mutual funds which are invested in approximately 28% fixed income, 72% equity and other investments.
(c)
Plan assets include $229 million and $133 million of KMI Class P common stock for 2013 and 2012, respectively.
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(a)
For 2013, this category includes common/collective trust funds which are invested in approximately 70% equity and 30% fixed income securities. For 2012, this category includes common/collective trust funds which are invested in approximately 65% equity and 35% fixed income securities.
The following tables present the changes in our pension and OPEB plans’ assets included in Level 3 for the years ended December 31, 2013 and 2012, including the EP Pension and OPEB plans since the May 25, 2012 acquisition date (in millions):
Changes in the underlying value of Level 3 assets due to the effect of changes of fair value were immaterial for the years ended December 31, 2013 and 2012.
Expected Payment of Future Benefits and Employer Contributions. As of December 31, 2013, we expect to make the following benefit payments under our plans (in millions):
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(a)
Includes a reduction of approximately $3 million in each of the years 2014 - 2018 and approximately $13 million in aggregate for 2019 - 2023 for an expected subsidy related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.
In January 2014, we contributed $50 million to our pension plan. We expect to contribute approximately $32 million to our OPEB plan in 2014.
Actuarial Assumptions and Sensitivity Analysis. Benefit obligations and net benefit cost are based on actuarial estimates and assumptions. The following table details the weighted-average actuarial assumptions used in determining our benefit obligation and net benefit costs of our pension and OPEB plans for 2013, 2012 and 2011:
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(a)
The discount rate related to pension benefit cost was 4.50% for the period from January 1, 2012 to May 24, 2012, and 4.03% for the period from May 25, 2012 to December 31, 2012 (the period subsequent to the EP acquisition). The discount rate related to other postretirement benefit cost was 3.34% for the period from January 1, 2013 to July 31, 2013 (the period prior to an OPEB plan amendment that resulted in a remeasurement) and 4.00% for the period from August 1, 2013 to December 31, 2013, and 4.25% for the period from January 1, 2012 to May 24, 2012 and 4.01% for the period from May 25, 2012 to December 31, 2012.
(b)
The expected return on plan assets related to pension cost was 8.90% for the period from January 1, 2012 to May 24, 2012, and 8.11% for the period from May 25, 2012 to December 31, 2012 (the period subsequent to the EP acquisition). The expected return on plan assets related to other postretirement benefit cost was 8.90% for the period from January 1, 2012 to May 24, 2012, and 7.72% for the period from May 25, 2012 to December 31, 2012.
(c)
The expected return on plan assets listed in the table above is a pre-tax rate of return based on our targeted portfolio of investments. For the assumed EP OPEB plans, we utilize an after-tax expected return on plan assets to determine our benefit costs, which is based on unrelated business income taxes at a rate of 24% and 22% for 2013 and 2012, respectively.
The expected long-term rates of return on plan assets were determined by combining a review of the historical returns realized within the portfolio, the investment strategy included in the plans’ investment policy, and capital market projections for the asset classes in which the portfolio is invested and the target weightings of each asset class.
Actuarial estimates for our OPEB plans assumed a weighted-average annual rate of increase in the per capita cost of covered health care benefits of 6.57%, gradually decreasing to 5.00% by the year 2019. Assumed health care cost trends have a significant effect on the amounts reported for OPEB plans. A one-percentage point change in assumed health care cost trends would have the following effects as of December 31, 2013 and 2012 (in millions):
Components of Net Benefit Cost and Other Amounts Recognized in Other Comprehensive Income. For each of the years ended December 31, the components of net benefit cost and other amounts (including amounts associated with the EP Pension and OPEB plans since the May 25, 2012 acquisition date) recognized in pre-tax other comprehensive income related to our pension and OPEB plans are as follows (in millions):
Other Plans
Plans Associated with Foreign Operations
Two of KMP’s subsidiaries, Kinder Morgan Canada Inc. and Trans Mountain Pipeline Inc. (as general partner of Trans Mountain Pipeline L.P.) are sponsors of pension plans for eligible Trans Mountain pipeline system employees. The plans include registered defined benefit pension plans, supplemental unfunded arrangements (which provide pension benefits in excess of statutory limits) and defined contributory plans. These subsidiaries of KMP also provide postretirement benefits other than pensions for retired employees. KMP’s combined net periodic benefit costs for these Trans Mountain pension and other postretirement benefit plans for each of the years ended December 31, 2013, 2012 and 2011 were $11 million, $11 million and $7 million, respectively, recognized ratably over each year. As of December 31, 2013, KMP estimates its overall net
periodic pension and other postretirement benefit costs for these plans for the year 2014 will be approximately $11 million, although this estimate could change if there is a significant event, such as a plan amendment or a plan curtailment, which would require a remeasurement of liabilities. Furthermore, KMP expects to contribute approximately $10 million to these benefit plans in 2014.
Multiemployer Plans
As a result of acquiring several terminal operations, primarily KMP’s acquisition of Kinder Morgan Bulk Terminals, Inc. effective July 1, 1998, KMP participates in several multi-employer pension plans for the benefit of employees who are union members. KMP does not administer these plans and contributes to them in accordance with the provisions of negotiated labor contracts. Other benefits include a self-insured health and welfare insurance plan and an employee health plan where employees may contribute for their dependents’ health care costs. Amounts charged to expense for these plans were approximately $11 million, $11 million and $12 million for the years ended December 31, 2013, 2012 and 2011, respectively. KMP considers its overall multi-employer pension plan liability exposure to be minimal in relation to the value of its total consolidated assets and net income.
10. Stockholders’ Equity
Kinder Morgan, Inc. - Equity Interests
Common Equity
On May 23, 2012, we announced that our board of directors had approved a warrant repurchase program, authorizing us to repurchase in the aggregate up to $250 million of warrants, which repurchase was completed as of May 2013. In the second quarter of 2013, we repurchased an additional $38 million in warrants, which was approved by our board of directors separate and apart from the publicly announced repurchase program. On July 17, 2013, we announced that our board of directors had authorized an additional $350 million share and warrant repurchase program, which repurchase was completed as of December 2013. On October 16, 2013, we announced that our board of directors had approved an additional share and warrant repurchase program authorizing us to repurchase in the aggregate up to $250 million of additional shares or warrants. During December 2013, we repurchased $172 million of our Class P shares. During the years ended December 31, 2013 and 2012, we paid a total of $465 million and $157 million, respectively, for the repurchase of warrants. As of December 31, 2013, $156 million of the October 2013 $250 million repurchase program had been utilized.
The following table sets forth the changes in our outstanding shares during the years ended December 31, 2013 and 2012 and during 2011 since becoming public (see “-Initial Public Offering” following):
_______
(a) Represents Class P shares issued upon the settlement of an EP dissenter. The settlement of the dissenter’s 128 EP shares was determined based on the same conversion of EP shares into cash, KMI Class P shares and KMI warrants that was received by other EP shareholders at the time of the acquisition.
Share Repurchases Subsequent to December 31, 2013
Subsequent to December 31, 2013, we paid $94 million to repurchase approximately 3 million of our Class P shares effectively completing the October 16, 2013 share and warrant repurchase program.
Initial Public Offering
On February 10, 2011, we converted from a Delaware LLC named Kinder Morgan Holdco LLC to a Delaware corporation named Kinder Morgan, Inc. and our outstanding units were converted into classes of our capital stock. These transactions are referred to herein as the “Conversion Transaction.” On February 16, 2011, we completed the initial public offering of our Class P common stock, which is sometimes referred to herein as our “common stock.” All of the common stock that was sold in the offering was sold by our existing investors consisting of funds advised by or affiliated with Goldman Sachs & Co., Highstar Capital LP, The Carlyle Group and Riverstone Holdings LLC, referred to herein as the “Sponsor Investors.” No members of management sold shares in the offering, and we did not receive any proceeds from the offering.
Upon the completion of our initial public offering of Class P common stock we were owned by the public, and by individuals and entities that were the owners of Kinder Morgan Holdco LLC, which are referred to collectively in this report as the “Investors.” The Investors were Richard D. Kinder, our Chairman and Chief Executive Officer; the Sponsor Investors; Fayez Sarofim, one of our directors, and investment entities affiliated with him, and an investment entity affiliated with Michael C. Morgan, another of our directors, and William V. Morgan, one of our founders, whom we refer to collectively as the “Original Stockholders”; and a number of other members of our management, who are referred to collectively as “Other Management.”
The Investors owned all of our outstanding Class A shares, Class B shares and Class C shares, which are sometimes referred to in this report as the “investor retained stock.” Our Class A shares represented the total capital contributed by the Investors (and a notional amount of capital allocated to the contribution of the holders of the Class C shares) at the time of a 2007 going private transaction. The Class B shares and Class C shares represented incentive compensation that were held by members of our management, including Mr. Kinder only in the case of the Class B shares.
During the year ended December 31, 2012, certain of the Sponsor Investors (the Selling Stockholders) completed underwritten public offerings (the Offerings) of an aggregate of 198,996,921 shares of our Class P common stock (including 8,700,000 shares that were the subject of an underwriters’ option to purchase additional shares). Neither we nor our management sold any shares of common stock in the Offerings, and we did not receive any of the proceeds from the Offerings of shares by the Selling Stockholders. As a result of these offerings, the Sponsor Investors advised by or affiliated with Goldman Sachs & Co., The Carlyle Group, and Riverstone Holdings LLC no longer own any of our shares, and representatives of these Sponsor Investors are no longer on our board.
On December 26, 2012, the remaining series of the Class A, Class B and Class C shares held by the Investors automatically converted into shares of Class P common stock upon the election of the holders of at least two-thirds of the shares of each such series of Class A common stock and the holders of at least two-thirds of the shares of each such series of Class B common stock. Subsequent to these conversions, all our Class A, Class B and Class C shares were fully converted and as a result, only our Class P common stock was outstanding as of December 31, 2012. Additionally, as Class A, Class B and Class C shares converted, certain holders of Class P shares were paid out in cash and their Class P shares were immediately canceled. During the years ended December 31, 2012 and 2011, approximately 2 million and less than 1 million, respectively, Class P shares were canceled resulting in payments totaling approximately $71 million and $2 million, respectively, to the holders of those shares.
Dividends
Holders of our common stock share equally in any dividend declared by our board of directors, subject to the rights of the holders of any outstanding preferred stock. The following table provides information about our per share dividends:
_______
(a) Represents dividends subsequent to the initial public offering.
On February 11, 2011, our board of directors declared and paid a distribution to our then existing investors of $246 million with respect to the period for which we were not public. This consisted of $205 million for the fourth quarter of 2010 and $105 million for the first 46 days of 2011, representing the portion of the first quarter of 2011 that we were not public, less a one-time adjustment of $64 million in available earnings and profits reserved for the after tax cost of special cash bonuses (and premium pay) in an aggregate amount of approximately $100 million that was paid in May of 2011 to certain of our non-senior management employees. No holders of our Class B shares or Class C shares received such bonuses.
Dividends Subsequent to December 31, 2013
On January 15, 2014, our board of directors declared a cash dividend of $0.41 per share for the quarterly period ended December 31, 2013. This dividend was paid on February 18, 2014 to shareholders of record as of January 31, 2014. Since this dividend was declared after the end of the quarter, no amount is shown in our accompanying December 31, 2013 consolidated balance sheet as a dividend payable.
Warrants
Each of our warrants entitles the holder to purchase one share of our common stock for an exercise price of $40 per share, payable in cash or by cashless exercise, at any time until May 25, 2017. The table below sets forth the changes in our outstanding warrants during 2013 and 2012.
_______
(a)
See Note 3. 2013 amount represents warrants issued upon the settlement of an EP dissenter. The settlement of the dissenter’s 128 EP shares was determined based on the same conversion of EP shares into cash, KMI Class P shares and KMI warrants that was received by other EP shareholders at the time of the acquisition.
(b)
See Note 8.
Noncontrolling Interests
The caption “Noncontrolling interests” in our accompanying consolidated balance sheets consists of interests that we do not own in the following subsidiaries (in millions):
At December 31, 2013, we owned, directly, and indirectly in the form of i-units corresponding to the number of shares of KMR we owned, approximately 43 million limited partner units of KMP. These units, which consist of 22 million common units, 5 million Class B units and 16 million i-units, represent approximately 9.8% of the total outstanding limited partner interests of KMP. In addition, we indirectly own all the common equity of the general partner of KMP, which holds an effective 2% interest in KMP and its operating partnerships. Together, at December 31, 2013, our limited partner and general partner interests represented approximately 11.6% of KMP’s total equity interests and represented an approximate 50% economic interest in KMP. This difference results from the existence of incentive distribution rights (IDRs) held by KMGP, the general partner of KMP.
As of December 31, 2013, we owned approximately 90 million limited partner units of EPB, representing approximately 41% of the total equity interests of EPB. In addition, we are the sole owner of the general partner of EPB, which holds an effective 2% interest in EPB, including all of EPB’s IDRs.
At December 31, 2013, we owned approximately 16 million KMR shares representing approximately 13.0% of KMR’s outstanding shares.
Contributions
Contributions from our noncontrolling interests consist primarily of equity issuances by KMP, EPB and KMR. As of December 31, 2013, each of these subsidiaries has an equity distribution agreement in place which allows the subsidiary to sell its equity interests from time to time through a designated sales agent. The terms of each agreement are substantially similar. Sales of the subsidiary’s equity interests will be made by means of ordinary brokers’ transactions on the NYSE at market
prices, in block transactions or as otherwise agreed between the subsidiary equity issuer and its sales agent. The subsidiary equity issuer may also sell its equity interests to its sales agent as principal for the sales agent’s own account at a price agreed upon at the time of the sale. Any sale of the subsidiary’s equity interests to the sales agent as principal would be pursuant to the terms of a separate agreement between the subsidiary equity issuer and its sales agent. The equity distribution agreement provides the subsidiary with the right, but not the obligation to offer and sell its equity units or shares, at prices to be determined by market conditions. The subsidiary retains at all times complete control over the amount and the timing of sales under its respective equity distribution agreement, and it will designate the maximum number of equity units or shares to be sold through its sales agent, on a daily basis or otherwise as the subsidiary equity issuer and its sales agent agree.
The table below shows significant issuances to the public of common units or shares, the net proceeds from the issuances and the use of the proceeds during the years ended December 31, 2013 and 2012 by KMP, EPB and KMR (dollars in millions and shares in thousands).
_______
(a)
On June 3, 2013, KMP entered into a fourth amended and restated equity distribution agreement with UBS Securities LLC (UBS) which increased the aggregate offering price of KMP’s common units to up to $2.175 billion (up from $1.9 billion), and on August 7, 2013, KMP entered into a second and separate equity distribution agreement with UBS. The terms of this new equity distribution agreement are substantially similar to those in KMP’s previous agreement, and it allows KMP to offer and sell from time to time additional KMP common units having an aggregate offering price of up to $1.9 billion through UBS, as sales agent. On February 27, 2012, KMP entered into a third amended and restated equity distribution agreement with UBS which increased the aggregate offering price of its common units to up to $1.9 billion (up from $1.2 billion).
(b)
KMP valued these units at $3,733 million based on the $86.08 closing market price of a KMP common unit on the NYSE on May 1, 2013.
(c)
See Note 3.
(d)
Includes the underwriters’ exercise of the overallotment option.
(e)
On March 7, 2013, EPB entered into an equity distribution agreement with Global Markets, Inc. (Citigroup). Pursuant to the provisions of EPB’s equity distribution agreement, EPB may sell from time to time through Citigroup, as its sales agent, EPB’s common units representing limited partner interests having an aggregate offering price of up to $500 million.
(f)
Represents proceeds received from noncontrolling interests and excludes our $2 million contribution as the owner of EPB’s general partner.
(g)
Represents proceeds received from noncontrolling interests and excludes our $7 million contribution as the owner of EPB’s general partner.
(h)
On May 4, 2012, KMR entered into an equity distribution agreement with Credit Suisse Securities (USA) LLC (Credit Suisse). Pursuant to the provisions of KMR’s equity distribution agreement, it may sell from time to time through Credit Suisse, as its sales agent, KMR shares having an aggregate offering price of up to $500 million.
The above equity issuances by KMP, EPB and KMR during the years ended December 31, 2013 and 2012 had the associated effects of increasing our (i) noncontrolling interests by $5,059 million and $2,112 million, respectively; (ii) accumulated deferred income taxes by $93 million and $38 million, respectively; and (iii) additional paid-in capital by $161 million and $64 million, respectively.
Contributions Subsequent to December 31, 2013
Shares and units issued subsequent to December 31, 2013 include (i) 76,100 of KMR’s shares; and (ii) 198,110 of KMP’s common units both of which were issued in early January for the settlement of sales made on or before December 31, 2013 pursuant to KMR and KMP’s respective equity distribution agreements. KMR and KMP received net proceeds of $16 million and $6 million, respectively, for the issuance of these shares and common units and the combined proceeds were used to reduce borrowings under KMP’s commercial paper program.
On February 19, 2014, KMP priced in a public offering, 7,935,000 of its common units (including the exercise of the underwriters’ overallotment option) at a price of $78.32 per unit, less commissions and underwriting expenses.
Distributions
The following table provides information about distributions from our noncontrolling interests (in millions except per unit and i-unit distribution amounts):
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(a)
Represents distribution information since the May 2012 EP acquisition.
(b)
KMR’s distributions are paid in the form of additional shares or fractions thereof calculated by dividing the KMP cash distribution per common unit by the average of the market closing prices of a KMR share determined for a ten-trading day period ending on the trading day immediately prior to the ex-dividend date for the shares. Represents share distributions made in the period to noncontrolling interests and excludes 976,723, 902,367 and 941,895 of shares distributed in 2013, 2012 and 2011, respectively, on KMR shares we directly and indirectly own. On February 14, 2014, KMR paid a share distribution of 0.017841 shares per outstanding share (2,237,258 total shares) to shareholders of record as of January 31, 2014, based on the $1.36 per common unit distribution declared by KMP, of which 1,952,970 shares were distributed to the public.
KMP Distributions
KMP’s partnership agreement requires that it distribute 100% of “Available Cash,” as defined in its partnership agreement, to its partners within 45 days following the end of each calendar quarter. Available Cash consists generally of all of KMP’s cash receipts, including cash received by its operating partnerships and net reductions in reserves, less cash disbursements and net additions to reserves and amounts payable to its noncontrolling interests.
KMR, as the delegate of KMGP, of which we indirectly own all of the outstanding common equity, and the general partner of KMP, is granted discretion, subject to the approval of KMGP in certain cases, to establish, maintain and adjust reserves for the proper conduct of KMP’s business, which might include reserves for matters such as future operating expenses, debt service, sustaining capital expenditures and rate refunds, and for distributions for the next four quarters. These reserves are not restricted by magnitude, but only by type of future cash requirements with which they can be associated. When KMR determines KMP’s quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level.
Pursuant to KMP’s partnership agreement, distributions to its unitholders are characterized either as distributions of cash from operations or as distributions of cash from interim capital transactions. This distinction affects the distributions to owners of common units, Class B units and i-units relative to the distributions retained by KMGP as KMP’s general partner.
Cash from Operations. Cash from operations generally refers to KMP’s cash balance on the date it commenced operations, plus all cash generated by the operation of its business, after deducting related cash expenditures (including capital expenditures other than expansion capital expenditures), net additions to or reductions in reserves, debt service and various other items.
Cash from Interim Capital Transactions. Cash from interim capital transactions will generally result only from distributions that are funded from borrowings, sales of debt and equity securities and sales or other dispositions of assets for cash, other than inventory, accounts receivable and other current assets and assets disposed of in the ordinary course of business.
Rule for Characterizing Distributions. Generally, all available cash distributed by KMP from any source will be treated as distributions of cash from operations until the sum of all available cash distributed equals the cumulative amount of cash from operations actually generated from the date KMP commenced operations through the end of the calendar quarter prior to that distribution. Any distribution of available cash which, when added to the sum of all prior distributions, is in excess of the cumulative amount of cash from operations, will be considered a distribution of cash from interim capital transactions until the initial common unit price is fully recovered as described below under “-Allocation of Distributions from Interim Capital Transactions.” For purposes of calculating the sum of all distributions of available cash, the total equivalent cash amount of all distributions of i-units to KMR, as the holder of all i-units, will be treated as distributions of available cash, even though the distributions to KMR are made in additional i-units rather than cash and KMP retains this cash and uses it in its business. To date, all of KMP’s available cash distributions, other than a $177 million distribution of cash from interim capital transactions in 2010, have been treated as distributions of cash from operations.
Allocation of Distributions from Operations. Cash from operations for each quarter will be distributed effectively as follows:
Allocation of Distributions from Interim Capital Transactions. Any distribution by KMP of available cash that would constitute cash from interim capital transactions would be distributed effectively as follows:
•
98% to all owners of common units and Class B units pro rata in cash and to the holder of i-units in equivalent i-units; and
•
2% to KMGP, as KMP’s general partner, until KMP has distributed cash from this source in respect of a common unit outstanding since KMP’s original public offering in an aggregate amount per unit equal to the initial common unit price of $5.75, as adjusted for splits.
As cash from interim capital transactions is distributed, it would be treated as if it were a repayment of the initial public offering price of the common units. To reflect that repayment, the first three distribution target levels of cash from operations (described above) would be adjusted downward proportionately by multiplying each distribution target level amount by a fraction, the numerator of which is the unrecovered initial common unit price immediately after giving effect to that distribution and the denominator of which is the unrecovered initial common unit price immediately prior to giving effect to that distribution. When the initial common unit price is fully recovered, then each of the first three distribution target levels will have been reduced to zero and thereafter, all distributions of available cash from all sources will be treated as if they were cash from operations and available cash will be distributed 50% to all classes of units pro rata (with the distribution to i-units being made instead in the form of i-units), and 50% to KMGP as KMP’s general partner. With respect to the portion of our distribution of available cash for 2010 that was from interim capital transactions, KMGP, as KMP’s general partner, waived this resetting of the distribution target levels.
Distributions paid by KMP to KMGP during 2013 were reduced by a waived incentive amount of $50 million related to common units issued to finance KMP’s May 2013 Copano acquisition. Beginning with KMP’s distribution payments for the quarterly period ended June 30, 2013, and ending with its distribution payments for the quarterly period ended March 31, 2038, KMGP, as KMP’s general partner, agreed not to take certain incentive distributions related to KMP’s acquisition of Copano. For more information about KMP’s May 2013 Copano acquisition, see Note 3. In addition, distributions paid by KMP to KMGP during 2013, 2012 and 2011 were reduced by waived incentive amounts equal to $11 million, $27 million and $28 million, respectively, related to common units issued to finance a portion of KMP’s May 2010 and July 2011 KinderHawk acquisitions. Beginning with KMP’s distribution payments for the quarterly period ended June 30, 2010, and ending with its distribution payments for the quarterly period ended March 31, 2013, KMGP, as KMP’s general partner, has agreed not to take certain incentive distributions related to KMP’s acquisition of KinderHawk. For more information about KMP’s July 2011 KinderHawk acquisition, see Note 3.
EPB Distributions
Incentive Distribution Rights. El Paso Pipeline GP Company, L.L.C., as the general partner of EPB and the holder of EPB’s IDRs, has the right under EPB’s partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial cash target distribution levels and (upon satisfaction of certain conditions) to reset, at higher levels, the minimum quarterly distribution amount and cash target distribution levels upon which the incentive distribution payments to El Paso Pipeline GP Company, L.L.C., as EPB’s general partner, would be set. In connection with this election, El Paso Pipeline GP Company, L.L.C. , as EPB’s general partner, would be entitled to receive a number of newly issued Class B common units and general partner units based on a predetermined formula. Although the conditions have been met to entitle El Paso Pipeline GP Company, L.L.C. to elect to reset the minimum quarterly distribution amount and the target distribution levels, no such election has been made.
El Paso Pipeline GP Company, L.L.C. currently holds all of EPB’s IDRs, but may transfer these rights separately from its general partner interest, subject to restrictions in EPB’s partnership agreement.
Income Allocation and Declared Distributions. For the purposes of maintaining partner capital accounts, EPB’s partnership agreement specifies that items of income and loss shall be allocated among the partners in accordance with their percentage interests. Normal allocations according to percentage interests are made, however, only after giving effect to any priority income allocations in an amount equal to the incentive distributions that are allocated 100% to El Paso Pipeline GP Company, L.L.C., as the holder of EPB’s IDRs. Incentive distributions are generally defined as all cash distributions paid to El Paso Pipeline GP Company, L.L.C., as EPB’s general partner, that are in excess of 2% of the aggregate value of cash distributions made to all partners.
EPB’s partnership agreement requires that it distribute all of its available cash from operating surplus each quarter. EPB determines the allocation of incentive distributions to El Paso Pipeline GP Company, L.L.C., as EPB’s general partner, by the amount quarterly distributions to unitholders exceed certain specified target levels, according to the provisions of EPB’s partnership agreement summarized in the table below. The percentage interests set forth below for El Paso Pipeline GP Company, L.L.C., as EPB’s general partner, include its 2% general partner interest and assume El Paso Pipeline GP Company, L.L.C. has contributed any additional capital necessary to maintain its 2% general partner interest and has not transferred its IDRs.
Distributions Subsequent to December 31, 2013
On January 15, 2014, KMP declared a cash distribution of $1.36 per unit for the quarterly period ended December 31, 2013. The distribution was paid on February 14, 2014 to KMP’s unitholders of record as of January 31, 2014, of which $445 million was paid to the public holders (represented in noncontrolling interests). Related to this February 14, 2014 distribution, KMGP, waived an incentive distribution amount equal to $25 million to support KMP’s May 2013 Copano acquisition.
On January 15, 2014, EPB declared a cash distribution of $0.65 per unit for the quarterly period ended December 31, 2013. The distribution was paid on February 14, 2014 to EPB’s unitholders of record as of January 31, 2014.
11. Related Party Transactions
Affiliated Balances
The following table summarizes our balance sheet affiliate balances (in millions):
_______
(a)
2012 amount related to KMP’s equity investment in the Express pipeline system (see Note 2).
(b)
EPB has financing obligations payable to WYCO.
Notes Receivable
Plantation
KMP and ExxonMobil have a term loan agreement covering a note receivable due from Plantation. KMP owns a 51.17% equity interest in Plantation and KMP’s proportionate share of the outstanding principal amount of the note receivable was $48 million as of December 31, 2013 and $49 million as of December 31, 2012. The note bears interest at the rate of 4.25% per annum and provides for semiannual payments of principal and interest on December 31 and June 30 each year, with a final principal payment of $45 million (for KMP’s portion of the note) due on July 20, 2016. We included $1 million of the note
receivable balance within “Other current assets” on our accompanying consolidated balance sheets as of both December 31, 2013 and December 31, 2012, and we included the remaining outstanding balance within “Deferred charges and other assets.”
Express US Holdings LP
As discussed in Note 3 “Acquisitions and Divestitures-Divestitures-Express Pipeline System,” KMP sold both its 33 1/3% equity ownership interest in the Express pipeline system and a subordinated debenture investment in Express to Spectra Energy Corp. effective March 14, 2013. KMP’s long-term debt investment consisted of a C$114 million debt security issued by Express US Holdings LP (the obligor), the partnership that maintained ownership of the U.S. portion of the Express pipeline system. The debenture was denominated in Canadian dollars, bore interest at a rate of 12.0% per annum, and was due in full on January 9, 2023. As of December 31, 2012 the outstanding note receivable balance, representing the translated amount included in our consolidated financial statements in U.S. dollars, was $114 million. Since KMP had entered into a definitive agreement to sell its debt investment in Express as of this date, we included this note balance within “Assets held for sale” on our accompanying consolidated balance sheet as of that date.
Gulf LNG Holdings Group, LLC
In conjunction with the acquisition of EP, KMI acquired a long-term note receivable, bearing interest at 12% per annum, that was due from Gulf LNG Holdings Group, LLC, a 50% equity investee, with a remaining principal amount of $85 million. Subsequent to the EP acquisition and through the end of 2012, we received payments on this note totaling $75 million. We received payments for the remaining note balance of $10 million during the first quarter of 2013. The balance of $10 million at December 31, 2012 was included in our accompanying consolidated balance sheet within “Other current assets.”
Subsequent Event
On February 4, 2014, KMP entered into a loan agreement with Midcontinent Express Pipeline LLC, KMP’s 50%-owned equity investee. The loan agreement allows KMP, at their sole option, to make loans from time to time to Midcontinent Express to fund its working capital needs and for other limited liability company purposes. Each individual loan must be in an amount not less than $2 million, and the aggregate loan balance outstanding must not exceed $40 million. All loans mature on February 3, 2015, however, the loan agreement includes renewal provisions for one or more additional one-year terms if approved by both parties. Borrowings under the loan agreement bear interest at a rate per annum equal to LIBOR plus 1.5875%, and all borrowings can be prepaid before maturity without penalty or premium. As of the date of this report, there was no amount outstanding pursuant to this loan agreement.
12. Commitments and Contingent Liabilities
Leases
The table below depicts future gross minimum rental commitments under our operating leases as of December 31, 2013 (in millions):
The remaining terms on our operating leases, including probable elections to exercise renewal options, range from one to forty. Total lease and rental expenses were $126 million, $94 million and $146 million for each of the years ended December 31, 2013, 2012 and 2011, respectively. The increase in our lease and rental expenses in 2011 compared to 2013 and 2012 was driven by a $70 million increase in expense in 2011 associated with adjustments to KMP’s Pacific operations’ rights-of-way liabilities. The amount of capital leases included within “Property, plant and equipment, net” in our accompanying consolidated balance sheets as of December 31, 2013 and 2012 are not material to our consolidated balance sheets.
Commitments
Capital Contributions for Elba Island Liquefaction Project
In January 2013, SLC, a subsidiary of EPB, and Shell US Gas and Power, LLC (Shell G&P), a subsidiary of Royal Dutch Shell plc (Shell), formed ELC, EPB’s equity method investment, to develop and own a natural gas liquefaction plant at SLNG’s existing Elba Island LNG terminal. In connection with the formation of ELC, SLC and Shell G&P entered into a LLC agreement in which SLC owns 51% of ELC and Shell G&P owns the remaining membership interest. Under the terms of the LLC agreement, SLC and Shell G&P are both obligated to make certain capital contributions in proportion to their membership interests in ELC to fund the construction of the liquefaction facilities. EPB’s investment at the terminal in Phase I, including both the liquefaction facilities and SLNG ancillary facilities, is estimated to be approximately$800 million . Phase I of the project requires no additional Department of Energy (DOE) approval.
Contingent Debt
KMP’s contingent debt disclosures pertain to certain types of guarantees or indemnifications KMP has made and cover certain types of guarantees included within debt agreements, even if the likelihood of requiring KMP’s performance under such guarantee is remote. As of December 31, 2013 and 2012, KMP’s contingent debt obligations, as well as KMP’s obligations with respect to related letters of credit, totaled $74 million and $86 million, respectively. This amount is primarily related to the debt obligations of KMP’s 50%-owned investee, Cortez Pipeline Company (KMP is severally liable for its percentage ownership share (50%) of the Cortez Pipeline Company debt).
Contingent Lease Liabilities
KMP has agreed to guarantee certain lease payments from 2014 through 2035 made by us to EPC Building, LLC, a wholly owned subsidiary of KMI, related to our principal executive offices located at 1001 Louisiana Street in Houston, Texas. KMP would be required to perform under this guarantee only if we were unable to perform. During the term of this lease, the payments KMP guarantees increase from $27 million in 2014 to $38 million in 2035.
KMI Guarantee of KMP and EPB Debt
In conjunction with KMP’s acquisition of certain natural gas pipelines from us, we agreed to indemnify KMP with respect to approximately $5.9 billion of its debt. This indemnification primarily includes $5.2 billion associated with KMP’s August 2012 purchase of TGP and the purchase of EPNG and EP Midstream assets through both the August 2012 and the March 2013 drop-down transactions. In conjunction with our EP acquisition, we have agreed to indemnify EPB with respect to $470 million of its debt. We would be obligated to perform under these indemnities only if KMP’s or EPB’s assets, as applicable, were unable to satisfy its obligations.
Guarantees and Indemnifications
We are involved in joint ventures and other ownership arrangements that sometimes require financial and performance guarantees. In a financial guarantee, we are obligated to make payments if the guaranteed party fails to make payments under, or violates the terms of, the financial arrangement. In a performance guarantee, we provide assurance that the guaranteed party will execute on the terms of the contract. If they do not, we are required to perform on their behalf. We also periodically provide indemnification arrangements related to assets or businesses we have sold. These arrangements include, but are not limited to, indemnifications for income taxes, the resolution of existing disputes and environmental matters.
Our potential exposure under guarantee and indemnification agreements can range from a specified to an unlimited dollar amount, depending on the nature of the claim and the particular transaction. While many of these agreements may specify a maximum potential exposure, or a specified duration to the indemnification obligation, there are circumstances where the amount and duration are unlimited. Those arrangements with a specified dollar amount have a maximum stated value of approximately $814 million, which primarily represents indemnification agreements that we assumed in the EP acquisition associated with EP’s prior discontinued and foreign operations. We are unable to estimate a maximum exposure for our guarantee and indemnification agreements that do not provide for limits on the amount of future payments due to the uncertainty of these exposures.
For additional information regarding our, KMP’s and EPB’s debt facilities see Note 8.
13. Risk Management
Certain of our business activities expose us to risks associated with unfavorable changes in the market price of natural gas, NGL and crude oil. We also have exposure to interest rate risk as a result of the issuance of our debt obligations. Pursuant to our management’s approved risk management policy, we use derivative contracts to hedge or reduce our exposure to certain of these risks.
As part of the EP acquisition, we acquired power forward and swap contracts. We have entered into offsetting positions that eliminate the price risks associated with our power contracts. As part of the May 1, 2013 Copano acquisition, KMP acquired derivative contracts related to natural gas, NGL and crude oil. None of these derivatives are designated as accounting hedges.
Energy Commodity Price Risk Management
As of December 31, 2013, KMP and KMI had entered into the following outstanding commodity forward contracts to hedge their forecasted energy commodity purchases and sales:
As of December 31, 2013, the maximum length of time over which we have hedged our exposure to the variability in future cash flows associated with energy commodity price risk is through December 2017.
Interest Rate Risk Management
As of December 31, 2013, KMI and KMP had a combined notional principal amount of $725 million and $4,675 million, respectively, of fixed-to-variable interest rate swap agreements, effectively converting the interest expense associated with certain series of senior notes from fixed rates to variable rates based on an interest rate of LIBOR plus a spread. All of KMI and KMP ‘s swap agreements have termination dates that correspond to the maturity dates of the related series of senior notes and, as of December 31, 2013, the maximum length of time over which we have hedged a portion of our exposure to the variability in the value of this debt due to interest rate risk is through March 15, 2035.
In June 2013, KMP terminated three of their existing fixed-to-variable interest rate swap agreements in separate transactions. These swap agreements had a combined notional principal amount of $975 million, and received combined proceeds of $96 million from the early termination of these swap agreements. In August 2013, KMP entered into six separate fixed-to-variable interest rate swap agreements having a combined notional principal amount of $500 million. Four of these agreements effectively convert a portion of the interest expense associated with KMP’s 2.65% senior notes due February 1, 2019 from a fixed rate to a variable rate based on an interest rate of LIBOR plus a spread and the remaining two agreements effectively convert a portion of the interest expense associated with KMP’s 4.15% senior notes due February 1, 2024, from a fixed rate to a variable rate based on an interest rate of LIBOR plus a spread. In December 2013, three separate fixed-to-variable interest rate swap agreements having a combined notional amount of $375 million associated with KMP’s 5.00% senior notes terminated upon the maturing of the associated notes.
As of December 31, 2012, KMI and KMP each had a combined notional principal amount of $725 million and $5,525 million, respectively, of fixed-to-variable interest rate swap agreements.
Fair Value of Derivative Contracts
The following table summarizes the fair values of our derivative contracts included on our accompanying consolidated balance sheets as of December 31, 2013 and 2012 (in millions):
Certain of our derivative contracts are subject to master netting agreements. As of December 31, 2013 and 2012, we presented the fair value of our derivative contracts on a gross basis on our accompanying consolidated balance sheets. The following tables present our derivative contracts subject to such netting agreements as of the dates indicated (in millions):
_______
(a)
Cash margin deposits held by KMP associated with its energy commodity contract positions and OTC swap agreements and reported within “Other current liabilities” in our accompanying consolidated balance sheets.
(b)
$17 million and $5 million of cash margin deposits posted by KMP at December 31, 2013 and December 31, 2012, respectively, associated with energy commodity contract positions and OTC swap agreements and reported within “Other current assets” in our accompanying consolidated balance sheets.
Debt Fair Value Adjustments
The offsetting entry to adjust the carrying value of the debt securities whose fair value was being hedged is included within “Debt fair value adjustments” on our accompanying consolidated balance sheets. Our “Debt fair value adjustments” also include all unamortized debt discount/premium amounts, purchase accounting on our debt balances, and any unamortized portion of proceeds received from the early termination of interest rate swap agreements. As of December 31, 2013 and 2012, these fair value adjustments to our debt balances included (i) $1,379 million and $1,470 million, respectively, associated with fair value adjustments to our debt previously recorded in purchase accounting; (ii) $143 million and $664 million, respectively, associated with the offsetting entry for hedged debt; (iii) $517 million and $490 million respectively, associated with unamortized premium from the termination of interest rate swap agreements; and offset by (iv) $62 million and $33 million, respectively, associated with unamortized debt discount amounts. As of December 31, 2013, the weighted-average amortization period of the unamortized premium from the termination of the interest rate swaps was approximately 16 years.
Effect of Derivative Contracts on the Income Statement
The following two tables summarize the impact of our derivative contracts on our accompanying consolidated statements of income for each of the years ended December 31, 2013, 2012 and 2011 (in millions):
_______
(a) Amounts reflect the change in the fair value of interest rate swap agreements and the change in the fair value of the associated fixed rate debt, which exactly offset each other as a result of no hedge ineffectiveness.
_______
(a)
We expect to reclassify an approximate $1 million loss associated with energy commodity price risk management activities and included in our accumulated other comprehensive loss and noncontrolling interest balances as of December 31, 2013 into earnings during the next
twelve months (when the associated forecasted sales and purchases are also expected to occur), however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices.
(b)
Amounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchases actually occurred).
For the years ended December 31, 2013 and 2012, we recognized losses of $10 million and $4 million, respectively, in income and included these amounts within “Revenues-Product sales and other” from derivative contracts not designated as accounting hedges. For the year ended December 31, 2011, such amounts were not significant.
Credit Risks
We and our subsidiary, KMP, have counterparty credit risk as a result of our use of financial derivative contracts. Our counterparties consist primarily of financial institutions, major energy companies, natural gas and electric utilities and local distribution companies. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions.
We maintain credit policies with regard to our counterparties that we believe minimize our overall credit risk. These policies include (i) an evaluation of potential counterparties’ financial condition (including credit ratings); (ii) collateral requirements under certain circumstances; and (iii) the use of standardized agreements which allow for netting of positive and negative exposure associated with a single counterparty. Based on our policies, exposure, credit and other reserves, our management does not anticipate a material adverse effect on our financial position, results of operations, or cash flows as a result of counterparty performance.
Our OTC swaps and options are entered into with counterparties outside central trading organizations such as futures, options or stock exchanges. These contracts are with a number of parties, all of which have investment grade credit ratings. While we enter into derivative transactions with investment grade counterparties and actively monitor their ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk in the future.
In conjunction with the purchase of exchange-traded derivative contracts or when the market value of our derivative contracts with specific counterparties exceeds established limits, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of both December 31, 2013 and 2012, KMP had no outstanding letters of credit supporting its hedging of energy commodity price risks associated with the sale of natural gas, NGL and crude oil. As of December 31, 2013 and 2012, KMI had $167 million and $300 million, respectively, of outstanding letters of credit supporting its commodity price risks associated with the sale of natural gas and power.
KMP and KMI also have agreements with certain counterparties to their derivative contracts that contain provisions requiring the posting of additional collateral upon a decrease in their credit rating. As of December 31, 2013, we estimate that if KMP’s credit rating was downgraded one notch, KMP would be required to post no additional collateral to its counterparties. If KMP was downgraded two notches (that is below investment grade), KMP would be required to post $8 million of additional collateral. As of December 31, 2013, we estimate that if KMI’s credit rating was downgraded one or two notches, KMI would be required to post no additional collateral to its counterparties.
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income
Cumulative revenues, expenses, gains and losses that under GAAP are included within our comprehensive income but excluded from our earnings are reported as “Accumulated other comprehensive loss” within “Stockholders’ Equity” in our consolidated balance sheets. Changes in the components of our “Accumulated other comprehensive loss” for the year ended December 31, 2013 are summarized as follows (in millions):
14. Fair Value
The fair values of our financial instruments are separated into three broad levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. Each fair value measurement must be assigned to a level corresponding to the lowest level input that is significant to the fair value measurement in its entirety.
The three broad levels of inputs defined by the fair value hierarchy are as follows:
•
Level 1 Inputs-quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date;
•
Level 2 Inputs-inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability; and
•
Level 3 Inputs-unobservable inputs for the asset or liability. These unobservable inputs reflect the entity’s own assumptions about the assumptions that market participants would use in pricing the asset or liability, and are developed based on the best information available in the circumstances (which might include the reporting entity’s own data).
Fair Value of Derivative Contracts
The following two tables summarize the fair value measurements of our (i) energy commodity derivative contracts and (ii) interest rate swap agreements as of December 31, 2013 and 2012, based on the three levels established by the Codification. The fair value measurements in the tables below do not include cash margin deposits made by us, which are reported within “Other current assets” in our accompanying consolidated balance sheets (in millions).
_______
(a)
Level 1 consists primarily of NYMEX natural gas futures. Level 2 consists primarily of OTC WTI swaps and OTC natural gas swaps that are settled on NYMEX. Level 3 consists primarily of WTI options, NGL options and power derivative contracts.
The table below provides a summary of changes in the fair value of our Level 3 energy commodity derivative contracts for each of the years ended December 31, 2013 and 2012 (in millions):
Significant unobservable inputs (Level 3)
_______
(a)
2012 purchases include a net liability of $197 million of Level 3 energy commodity derivative contracts associated with the EP acquisition. 2013 purchases include a net asset of $18 million of Level 3 energy commodity derivative contracts assumed in conjunction with KMP’s May 1, 2013 Copano acquisition.
As of December 31, 2013, our Level 3 derivative assets and liabilities consisted primarily of WTI options, NGL options and power derivative contracts, where a significant portion of fair value is calculated from underlying market data that is not readily observable. The derived values use industry standard methodologies that may consider the historical relationships among various commodities, modeled market prices, time value, volatility factors and other relevant economic measures. The use of these inputs results in management’s best estimate of fair value.
The significant unobservable inputs used in the fair value measurement of our power-related derivatives are illiquid pricing points. As the delivery points in our power contracts are in an illiquid market and not actively traded, we adjust the Pennsylvania-New Jersey-Maryland (PJM) forward curves by the difference between the 12-month rolling average of actual settled prices at delivery points in the PJM East region. As of December 31, 2012, the adjusted prices over the contract term ranged from $28.50 per MW/h to $57.32 per MW/h. However, we have entered into offsetting positions that eliminate the price risks associated with our PJM power contracts. Significant increases (decreases) in these inputs in isolation would result in a significantly lower (higher) fair value measurement.
Fair Value of Financial Instruments
The estimated fair value of our outstanding debt balance (both short-term and long-term and including debt fair value adjustments), is disclosed below (in millions):
We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both December 31, 2013 and 2012.
15. Reportable Segments
We divide our operations into the following reportable business segments. These segments and their principal sources of revenues are as follows:
•
Natural Gas Pipelines-the sale, transport, processing, treating, fractionation, storage and gathering of natural gas and NGL;
•
CO2-KMP-the production, sale and transportation of crude oil from fields in the Permian Basin of West Texas and the production, transportation and marketing of CO2 used as a flooding medium for recovering crude oil from mature oil fields;
•
Products Pipelines-KMP- the transportation and terminaling of refined petroleum products (including gasoline, diesel fuel and jet fuel) NGL, crude and condensate, and bio-fuels;
•
Terminals-KMP-the transloading and storing of refined petroleum products and dry and liquid bulk products, including coal, petroleum coke, cement, alumina, salt and other bulk chemicals;
•
Kinder Morgan Canada-KMP-the transportation of crude oil and refined products from Alberta, Canada to marketing terminals and refineries in British Columbia and the state of Washington. As further described in Note 3, Kinder Morgan Canada divested its interest in the Express pipeline system effective March 14, 2013; and
•
Other-primarily includes several physical natural gas contracts with power plants associated with EP’s legacy trading activities. These contracts obligate EP to sell natural gas to these plants and have various expiration dates ranging from 2012 to 2028.
We evaluate performance principally based on each segment’s EBDA (including amortization of excess cost of equity investments), which excludes general and administrative expenses, third-party debt costs and interest expense, unallocable interest income, and unallocable income tax expense. Our reportable segments are strategic business units that offer different products and services, and they are structured based on how our chief operating decision makers organize their operations for optimal performance and resource allocation. Each segment is managed separately because each segment involves different products and marketing strategies.
Because KMP’s and EPB’s partnership agreements require them to distribute 100% of their available cash to their partners on a quarterly basis (available cash consists primarily of all cash receipts, less cash disbursements and changes in reserves), we consider each period’s earnings before all non-cash DD&A expenses to be an important measure of business segment performance for our segments that are also segments. We account for intersegment sales at market prices, while we account for asset transfers at either market value or, in some instances, book value.
During 2013, 2012 and 2011, we did not have revenues from any single external customer that exceeded 10% of our consolidated revenues.
Financial information by segment follows (in millions):
_______
(a)
The changes in the 2012 amount versus the 2011 amount include the effects of the acquisition of EP and for 2013 versus 2012 only, KMP’s acquisition of Copano. See Note 3.
(b)
Primarily represents a reimbursement of general and administrative costs for services we perform for NGPL Holdco LLC.
(c)
Includes natural gas purchases and other costs of sales, operations and maintenance expenses, and taxes, other than income taxes.
(d)
2013 and 2012 amounts include impairment charges of $65 million and $200 million, respectively, to reduce the carrying value of our investment in NGPL Holdco LLC (see Note 6).
(e)
2013 amount includes a $558 million gain from the remeasurement of our previously held 50% equity interest in Eagle Ford to fair value (discussed further in Note 3). 2011 amount includes a $167 million loss from the remeasurement of KMP’s previously held 50% equity interest in KinderHawk to fair value (see Note 3).
(f)
2013 amount includes a $224 million gain from the sale of our equity and debt investments in the Express pipeline system (discussed further in Note 3).
(g)
2013 amount includes an $84 million increase in expense related to the pre-tax gain amount described in footnote (f).
(h)
Includes revenues, earnings from equity investments, allocable interest income, and other, net, less operating expenses, allocable income taxes, and other expense (income).
(i)
2012 amount includes $352 million of pretax expense associated with the EP acquisition and EP Energy sale.
(j)
Includes (i) interest expense and (ii) miscellaneous other income and expenses not allocated to business segments. 2012 amount includes $108 million of expense for capitalized financing fees associated with the EP acquisition financing that were written-off (due to debt repayments) or amortized.
(k)
Represents amounts from KMP’s FTC Natural Gas Pipelines disposal group and other, net of tax (see Note 3).
(l)
Includes cash and cash equivalents, margin and restricted deposits, unallocable interest receivable, prepaid assets and deferred charges, risk management assets related to debt fair value adjustments and miscellaneous corporate assets (such as information technology and telecommunications equipment) not allocated to individual segments.
(m)
Primarily represents amounts attributable to KMP’s Express pipelines system and our ownership interest in Bolivia to Brazil Pipeline.
We do not attribute interest and debt expense to any of our reportable business segments. For each of the years ended December 31, 2013, 2012 and 2011, we reported total consolidated interest expense of $1,690 million, $1,427 million, and $703 million, respectively.
Following is geographic information regarding the revenues and long-lived assets of our business segments (in millions):
_______
(a)
Includes operations in Mexico and until August 31, 2011, the Netherlands.
(b)
Long-lived assets exclude goodwill and other intangibles, net.
16. Litigation, Environmental and Other Contingencies
We and our subsidiaries are parties to various legal, regulatory and other matters arising from the day-to-day operations of our businesses that may result in claims against the Company. Although no assurance can be given, we believe, based on our experiences to date and taking into account established reserves, that the ultimate resolution of such items will not have a material adverse impact on our business, financial position, results of operations or dividends to our shareholders. We believe we have meritorious defenses to the matters to which we are a party and intend to vigorously defend the Company. When we determine a loss is probable of occurring and is reasonably estimable, we accrue an undiscounted liability for such contingencies based on our best estimate using information available at that time. If the estimated loss is a range of potential outcomes and there is no better estimate within the range, we accrue the amount at the low end of the range. We disclose contingencies where an adverse outcome may be material, or in the judgment of management, we conclude the matter should otherwise be disclosed.
Federal Energy Regulatory Commission Proceedings
The tariffs and rates charged by SFPP and EPNG are subject to a number of ongoing proceedings at the FERC. A substantial portion of our legal reserves relate to these FERC cases and the CPUC cases described below them.
SFPP
The tariffs and rates charged by SFPP are subject to a number of ongoing proceedings at the FERC, including the complaints and protests of various shippers. In general, these complaints and protests allege the rates and tariffs charged by SFPP are not just and reasonable under the Interstate Commerce Act (ICA). If the shippers are successful in proving their claims, they are entitled to seek reparations (which may reach back up to two years prior to the filing of their complaints) or refunds of any excess rates paid, and SFPP may be required to reduce its rates going forward. These proceedings tend to be protracted, with decisions of the FERC often appealed to the federal courts. The issues involved in these proceedings include, among others, whether indexed rate increases are justified, and the appropriate level of return and income tax allowance KMP may include in its rates. With respect to all of the SFPP proceedings at the FERC, we estimate that the shippers are seeking approximately $20 million in annual rate reductions and approximately $100 million in refunds. However, applying the principles of several recent FERC decisions in SFPP cases, as applicable, to pending cases would result in substantially lower rate reductions and refunds than those sought by the shippers. We do not expect refunds in these cases to have an impact on KMP’s distributions to its limited partners or our dividends to our shareholders.
EPNG
The tariffs and rates charged by EPNG are subject to two ongoing FERC proceedings (the “2008 rate case” and the “2010 rate case”). With respect to the 2008 rate case, the FERC issued its decision (Opinion 517) in May 2012. EPNG implemented certain aspects of that decision and believes it has an appropriate reserve related to the findings in Opinion 517. EPNG has sought rehearing on Opinion 517. With respect to the 2010 rate case, the FERC issued its decision (Opinion 528) on October 17, 2013. The FERC ordered EPNG to file within 60 days of issuance of Opinion 528 revised pro forma recalculated rates consistent with the terms of Opinion 528. The FERC has ordered additional proceedings concerning one of the issues in Opinion 528. EPNG has filed for rehearing on certain issues in Opinion 528. We have evaluated all recent decisions and believe our reserve is appropriate.
California Public Utilities Commission Proceedings
KMP has previously reported ratemaking and complaint proceedings against SFPP pending with the CPUC. The ratemaking and complaint cases generally involve challenges to rates charged by SFPP for intrastate transportation of refined petroleum products through its pipeline system in the state of California and request prospective rate adjustments and refunds with respect to tariffed and previously untariffed charges for certain pipeline transportation and related services. These matters have generally been consolidated and assigned to two administrative law judges.
On May 26, 2011, the CPUC issued a decision in several intrastate rate cases involving SFPP and a number of its shippers, (the “Long” cases). The decision includes determinations on issues, such as SFPP’s entitlement to an income tax allowance, allocation of environmental expenses, and refund liability, which KMP believes are contrary both to CPUC policy and precedent and to established federal regulatory policies for pipelines. On March 8, 2012, the CPUC issued another decision related to the Long cases. This decision largely reflected the determinations made on May 26, 2011, including the denial of an income tax allowance for SFPP. The CPUC’s order denied SFPP’s request for rehearing of the CPUC’s income tax allowance treatment, while granting requested rehearing of various, other issues relating to SFPP’s refund liability and staying the payment of refunds until resolution of the outstanding issues on rehearing. On March 23, 2012, SFPP filed a petition for writ of review in the California Court of Appeals, seeking a court order vacating the CPUC’s determination that SFPP is not entitled to recover an income tax allowance in its intrastate rates. The Court denied SFPP’s petition, and on October 16, 2013, the California Supreme Court declined SFPP’s request for further review. SFPP is currently assessing the precise impact of the now final state rulings denying SFPP an income tax allowance and is awaiting CPUC decisions that will determine the impact related to the denial of an income tax allowance.
On April 6, 2011, in proceedings unrelated to the above-referenced CPUC dockets, a CPUC administrative law judge issued a proposed decision (Bemesderfer case) substantially reducing SFPP’s authorized cost of service and ordering SFPP to pay refunds from May 24, 2007 to the present of revenues collected in excess of the authorized cost of service. The proposed decision was subsequently withdrawn, and the presiding administrative law judge is expected to reissue a proposed decision at some indeterminate time in the future.
On January 30, 2012, SFPP filed an application reducing its intrastate rates by approximately 7%. This matter remains pending before the CPUC, with a decision expected in the second quarter of 2014.
On July 19, 2013, Calnev filed an application with the CPUC requesting a 36% increase in its intrastate rates. A decision from the CPUC approving the request rate increase was issued on November 14, 2013.
On November 27, 2013, the CPUC issued its Order to Show Cause directing SFPP to demonstrate whether or not the CPUC should require immediate refund payments associated with various pending SFPP rate matters. Subsequently, the CPUC issued an order directing SFPP and its shippers to engage in mandatory settlement discussions. If the matter is not settled, a decision addressing, if not resolving, all pending SFPP rate matters at the CPUC is anticipated in the second quarter of 2014.
Based on KMP’s review of these CPUC proceedings and the shipper comments thereon, it estimates that the shippers are requesting approximately $400 million in reparation payments and approximately $30 million in annual rate reductions. The actual amount of reparations will be determined through further proceedings at the CPUC. As of December 31, 2013, we believe our legal reserve, including an adjustment of the reserve made in the second quarter of 2013 related in part to this matter, is adequate such that the resolution of pending CPUC matters will not have a material adverse impact on KMP’s business, financial position or results of operations. Furthermore, we do not expect any reparations that KMP would pay in this matter to impact the per unit cash distributions it expects to pay to its limited partners for 2014.
Copano Shareholders’ Litigation
Three putative class action lawsuits were filed in connection with KMP’s merger with Copano: (i) Schultes v. Copano Energy, L.L.C., et al. (Case No. 06966), in the District Court of Harris County, Texas, which is referred to as the Texas State Action; (ii) Bruen v. Copano Energy, L.L.C., et al. (Case No. 4:13-CV-00540) in the U.S. District Court for the Southern District of Texas, which is referred to as the Texas Federal Action; and (iii) In re Copano Energy, L.L.C. Shareholder Litigation, Case No. 8284-VCN in the Court of Chancery of the State of Delaware, which is referred to as the Delaware Action, which reflects the consolidation of three actions originally filed in the Court of Chancery. The Texas State Action, the Texas Federal Action and the Delaware Action are collectively referred to as the “Actions.”
The Actions name Copano, R. Bruce Northcutt, William L. Thacker, James G. Crump, Ernie L. Danner, T. William Porter, Scott A. Griffiths, Michael L. Johnson, Michael G. MacDougall, Kinder Morgan G.P., Inc., KMEP and Javelina Merger Sub
LLC as defendants. The Actions were purportedly brought on behalf of a putative class seeking to enjoin the merger and allege, among other things, that the members of Copano’s board of directors breached their fiduciary duties by agreeing to sell Copano for inadequate and unfair consideration and pursuant to an inadequate and unfair process, and that Copano, KMEP, Kinder Morgan G.P., Inc. and Javelina Merger Sub LLC aided and abetted such alleged breaches. In addition, the plaintiffs in each of the Texas State Action and the Delaware Action alleged that the Copano directors breached their duty of candor to unitholders by failing to provide the unitholders with all material information regarding the merger and/or made misstatements in the preliminary proxy statement. The plaintiffs in the Texas Federal Action also asserted a claim under the federal securities laws alleging that the preliminary proxy statement omits and/or misrepresents material information in connection with the merger.
On April 21, 2013, the parties in all the Actions executed a Memorandum of Understanding pursuant to which Copano agreed to make certain additional disclosures concerning the merger in a Form 8-K, which Copano filed on April 22, 2013, and the plaintiffs agreed to enter into a stipulation of settlement providing for full settlement and dismissal with prejudice of each of the Actions. The parties then prepared and filed a Stipulation of Settlement with the Delaware Chancery Court, and on June 28, 2013, Copano announced that we had reached an agreement with the plaintiffs to settle all claims asserted against all defendants. The settlement does not require the defendants to pay any monetary consideration to the proposed settlement class. Following notice to the putative class, the Delaware Chancery Court held a settlement hearing and issued a final order approving the settlement on September 9, 2013. The order, among other things, dismissed the Delaware Action with prejudice and provided for a release in favor of all of the defendants for any and all claims by any of the putative class members arising out of the merger. The order also awarded plaintiffs’ counsel in the Delaware action $450,000 for their fees and expenses, to be paid by defendants. The plaintiff in the Texas Federal Action dismissed his case on May 13, 2013 and intervened in the Texas State Action on August 12, 2013 for the sole purpose of advancing a joint motion and petition for attorneys’ fees and expenses. On October 11, 2013, the court in the Texas State Action entered an order and final judgment denying plaintiffs’ joint motion for fees and expenses.
Other Commercial Matters
Union Pacific Railroad Company Easements
SFPP and Union Pacific Railroad Company (UPRR) are engaged in a proceeding to determine the extent, if any, to which the rent payable by SFPP for the use of pipeline easements on rights-of-way held by UPRR should be adjusted pursuant to existing contractual arrangements for the ten-year period beginning January 1, 2004 (Union Pacific Railroad Company v. Santa Fe Pacific Pipelines, Inc., SFPP, L.P., Kinder Morgan Operating L.P. “D”, Kinder Morgan G.P., Inc., et al., Superior Court of the State of California for the County of Los Angeles, filed July 28, 2004). In September 2011, the judge determined that the annual rent payable as of January 1, 2004 was, $15 million subject to annual consumer price index increases. SFPP has appealed the judge’s determination, but if that determination is upheld, SFPP would owe approximately $90 million in back rent. Accordingly, KMP increased its rights-of-way liability to cover this potential liability for back rent. In addition, the judge determined that UPRR is entitled to an estimated $20 million for interest on the outstanding back rent liability. KMP believes the award of interest is without merit and are pursuing our appellate rights. By notice dated October 25, 2013, UPRR demanded the payment of $22.25 million in rent for the first year of the next ten-year period beginning January 1, 2014. SFPP rejected the demand and the parties are pursuing the dispute resolution procedure in their contract to determine the rental adjustment, if any, for such period.
SFPP and UPRR are also engaged in multiple disputes over the circumstances under which SFPP must pay for a relocation of its pipeline within the UPRR right-of-way and the safety standards that govern relocations. In July 2006, a trial before a judge regarding the circumstances under which SFPP must pay for relocations concluded, and the judge determined that SFPP must pay for any relocations resulting from any legitimate business purpose of the UPRR. SFPP appealed this decision, and in December 2008, the appellate court affirmed the decision. In addition, UPRR contends that SFPP must comply with the more expensive American Railway Engineering and Maintenance-of-Way Association (AREMA) standards in determining when relocations are necessary and in completing relocations. Each party is seeking declaratory relief with respect to its positions regarding the application of these standards with respect to relocations. A trial occurred in the fourth quarter of 2011, with a verdict having been reached that SFPP was obligated to comply with AREMA standards in connection with a railroad project in Beaumont Hills, California. A judgment has not been entered on the verdict and SFPP is continuing to evaluate its post-trial and appellate options.
Since SFPP does not know UPRR’s plans for projects or other activities that would cause pipeline relocations, it is difficult to quantify the effects of the outcome of these cases on SFPP. Even if SFPP is successful in advancing its positions, significant relocations for which SFPP must nonetheless bear the expense (i.e., for railroad purposes, with the standards in the federal Pipeline Safety Act applying) would have an adverse effect on our financial position, our results of operations, our cash flows,
and our distributions to our limited partners. These effects would be even greater in the event SFPP is unsuccessful in one or more of these litigations.
Severstal Sparrows Point Crane Collapse
On June 4, 2008, a bridge crane owned by Severstal and located in Sparrows Point, Maryland collapsed while being operated by our subsidiary Kinder Morgan Bulk Terminals, Inc. (KMBT). According to KMP’s investigation, the collapse was caused by unexpected, sudden and extreme winds. On June 24, 2009, Severstal filed suit against KMBT in the U.S. District Court for the District of Maryland, Case No. 09CV1668-WMN. Severstal and its successor in interest, RG Steel, allege that KMBT was contractually obligated to replace the collapsed crane and that its employees were negligent in failing to properly secure the crane prior to the collapse. RG Steel seeks to recover in excess of $30 million for the alleged value of the crane and lost profits. KMBT denies each of RG Steel’s allegations. A bench trial occurred in November 2013 and we are awaiting the court’s decision.
Plains Gas Solutions, LLC v. Tennessee Gas Pipeline Company, L.L.C. et al
On October 16, 2013, Plains Gas Solutions, LLC (Plains) filed a petition in the 151st Judicial District Court for Harris County, Texas (Case No. 62528) against TGP, Kinetica Partners, LLC and two other Kinetica entities. The suit arises from the sale by TGP of the Cameron System in Louisiana to Kinetica Partners, LLC on September 1, 2013. Plains alleges that defendants breached a straddle agreement requiring that gas on the Cameron System be committed to Plains’ Grand Chenier gas-processing facility, that requisite daily volume reports were not provided, that TGP improperly assigned its obligations under the straddle agreement to Kinetica, and that defendants interfered with Plains’ contracts with producers. The petition alleges damages of at least $100 million. Under the Amended and Restated Purchase and Sale Agreement with Kinetica, Kinetica has agreed to indemnify TGP in connection with the gas commitment and reporting claims. We intend to vigorously defend the suit.
Brinckerhoff v. El Paso Pipeline GP Company, LLC., et al.
In December 2011 (Brinckerhoff I), March 2012, (Brinckerhoff II) and May 2013 (Brinckerhoff III) derivative lawsuits were filed in Delaware Chancery Court against EP, El Paso Pipeline GP Company, L.L.C., the general partner of EPB, and the directors of the general partner. EPB was named in these lawsuits as a “Nominal Defendant.” The lawsuits arise from the March 2010, November 2010 and May 2012 drop-down transactions involving EPB’s purchase of SLNG, Elba Express, CPG and interests in SNG and CIG. The lawsuits allege various conflicts of interest and that the consideration paid by EPB was excessive. Defendants’ motion to dismiss in Brinckerhoff I was denied in part. Brinckerhoff I and II have been consolidated into one proceeding. The parties’ motions for summary judgment filed by Plaintiff and Defendants are pending. A motion to dismiss has been filed in Brinckerhoff III. Defendants continue to believe that these actions are without merit and intend to defend against them vigorously.
Allen v. El Paso Pipeline GP Company, L.L.C., et al.
In May 2012, a unitholder of EPB filed a purported class action in Delaware Chancery Court, alleging both derivative and non derivative claims, against EPB, and EPB’s general partner and its board. EPB was named in the lawsuit as both a “Class Defendant” and a “Derivative Nominal Defendant.” The complaint alleges a breach of the duty of good faith and fair dealing in connection with the March 2011 sale to EPB of a 25% ownership interest in SNG. Defendants’ motion to dismiss was denied, and Defendants’ motion for summary judgment is pending. Defendants continue to believe this action is without merit, and intend to defend against it vigorously.
Price Reporting Litigation
Beginning in 2003, several lawsuits were filed against El Paso Marketing L.P. (EPM) alleging that EP, EPM and other energy companies conspired to manipulate the price of natural gas by providing false price information to industry trade publications that published gas indices. Several of the cases have been settled or dismissed. The remaining cases, which were pending in Nevada federal court, were dismissed, but the dismissal was reversed by the 9th Circuit Court of Appeals. A petition for certiorari is pending before the U.S. Supreme Court. Although damages in excess of $140 million have been alleged in total against all defendants in one of the remaining lawsuits where a damage number is provided, there remains significant uncertainty regarding the validity of the causes of action, the damages asserted and the level of damages, if any, that may be allocated to us. Therefore, our costs and legal exposure related to the remaining outstanding lawsuits and claims are not currently determinable.
Pipeline Integrity and Releases
From time to time, despite our best efforts, our pipelines experience leaks and ruptures. These leaks and ruptures may cause explosions, fire, and damage to the environment, damage to property and/or personal injury or death. In connection with these incidents, we may be sued for damages caused by an alleged failure to properly mark the locations of our pipelines and/or to properly maintain our pipelines. Depending upon the facts and circumstances of a particular incident, state and federal regulatory authorities may seek civil and/or criminal fines and penalties.
General
As of December 31, 2013 and 2012, our total reserve for legal matters was $624 million and $425 million, respectively. The reserve primarily relates to various claims from regulatory proceedings arising from KMP’s products pipeline and natural gas pipeline transportation rates. The overall change in the reserve from December 31, 2012 was primarily due to increases in expense in 2013 associated with adjustments to interstate and California intrastate transportation rate case liabilities.
Other
Slotoroff v. Kinder Morgan, Inc., Kinder Morgan G.P., Inc., et al.
On February 5, 2014, a putative class action and derivative complaint was filed in the Court of Chancery in the State of Delaware (Case No. 9318) against defendants Kinder Morgan, Inc., Kinder Morgan G.P., Inc. and nominal defendant Kinder Morgan Energy Partners, L.P. The suit was filed by a purported unitholder of KMP and seeks to assert claims both individually and on behalf of a putative class consisting of all public holders of KMP units during the period of February 5, 2011 through the date of the filing of the suit. The suit alleges direct and derivative causes of action for breach of the Partnership Agreement, breach of the duty of good faith and fair dealing, aiding and abetting, and tortious interference. Among other things, the suit alleges that defendants made a bad faith allocation of capital expenditures to expansion capital expenditures rather than maintenance capital expenditures for the alleged purpose of “artificially” inflating KMP’s distributions and growth rate. The suit seeks disgorgement of any distributions to KMGP, KMI and any related entities, beyond amounts that would have been distributed in accordance with a “good faith” allocation of KMP’s maintenance capital expenses, together with other unspecified monetary damages including punitive damages and attorney fees. Defendants believe that this suit is without merit and intend to defend it vigorously.
Environmental Matters
We and our subsidiaries are subject to environmental cleanup and enforcement actions from time to time. In particular, CERCLA generally imposes joint and several liability for cleanup and enforcement costs on current and predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct, subject to the right of a liable party to establish a “reasonable basis” for apportionment of costs. Our operations are also subject to federal, state and local laws and regulations relating to protection of the environment. Although we believe our operations are in substantial compliance with applicable environmental law and regulations, risks of additional costs and liabilities are inherent in pipeline, terminal and CO2 field and oil field operations, and there can be no assurance that we will not incur significant costs and liabilities. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies under the terms of authority of those laws, and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us.
We are currently involved in several governmental proceedings involving alleged violations of environmental and safety regulations. As we receive notices of non-compliance, we attempt to negotiate and settle such matters where appropriate. We do not believe that these alleged violations will have a material adverse effect on our business, financial position, results of operations or dividends to our shareholders.
We are also currently involved in several governmental proceedings involving groundwater and soil remediation efforts under administrative orders or related state remediation programs. We have established a reserve to address the costs associated with the cleanup.
In addition, we are involved with and have been identified as a potentially responsible party in several federal and state superfund sites. Environmental reserves have been established for those sites where our contribution is probable and reasonably estimable. In addition, we are from time to time involved in civil proceedings relating to damages alleged to have occurred as a result of accidental leaks or spills of refined petroleum products, NGL, natural gas and CO2.
Colorado Oil and Gas Conservation Commission Inspections
In Fall 2012, the Colorado Oil and Gas Conservation Commission, referred to as COGCC, performed inspections at multiple well sites in Southwestern Colorado owned by KMCO2 and some of these inspections resulted in alleged violations of COGCC’s rules. KMCO2 took immediate steps to correct the alleged deficiencies and has engaged COGCC and other agencies in its efforts to maintain compliance. In June 2013, the parties settled the matter through an Administrative Order on Consent under which KMCO2 agreed to pay $220,000 of which up to $80,000 may be paid toward a public project. The agreed public project, has been completed and this matter is concluded.
New Jersey Department of Environmental Protection v. Occidental Chemical Corporation, et al. (Defendants), Maxus Energy Corp. and Tierra Solutions, Inc. (Third Party Plaintiffs) v. 3M Company et al., Superior Court of New Jersey, Law Division - Essex County, Docket No. L-9868-05
The New Jersey Department of Environmental Protection (NJDEP) sued Occidental Chemical and others under the New Jersey Spill Act for contamination in the Newark Bay Complex including numerous waterways and rivers. In 2009, Occidental et al. asserted claims for contribution against approximately 300 third party defendants. NJDEP claimed damages related to 40 years of discharges of TCDD (a form of dioxin), DDT and “other hazardous substances.” GATX Terminals Corporation (n/k/a Kinder Morgan Liquids Terminals LLC) (KMLT) was named as a third party defendant because of the noted hazardous substances language and because the Carteret, New Jersey facility (a former GATX Terminals facility) is located on the Arthur Kill River, one of the waterways included in the litigation. KMLT, as part of a joint defense group, entered a settlement agreement (Consent Judgment) with the NJDEP whereby the settling parties for a prescribed payment, obtained a contribution bar against first party defendants Occidental, Maxus and Tierra in addition to a release of claims. The Consent Judgment was published in the New Jersey Register for a 60-day comment period and no significant comments were received. Additionally, the NJDEP reached a settlement agreement with Maxus and Tierra. Occidental is not part of the settlement. On December 12, 2013, the court approved the settlements between NJDEP and the third-party defendants and between NJDEP and the Maxus Tierra parties. Pursuant to the Consent Judgment, KMLT submitted its settlement payment by the January 27, 2014 deadline and is awaiting a court order formally dismissing KMLT from the litigation.
Portland Harbor Superfund Site, Willamette River, Portland, Oregon
In December 2000, the EPA issued General Notice letters to potentially responsible parties including GATX Terminals Corporation (n/k/a KMLT). At that time, GATX owned two liquids terminals along the lower reach of the Willamette River, an industrialized area known as Portland Harbor. Portland Harbor is listed on the National Priorities List and is designated as a Superfund Site under CERCLA. A group of potentially responsible parties formed what is known as the Lower Willamette Group (LWG), of which KMLT is a non-voting member and pays a minimal fee to be part of the group. The LWG agreed to conduct the Remedial Investigation and Feasibility Study leading to the proposed remedy for cleanup of the Portland Harbor site. Once the EPA determines the cleanup remedy from the remedial investigations and feasibility studies conducted during the last decade at the site, it will issue a Record of Decision. Currently, KMLT and 90 other parties are involved in an allocation process to determine each party’s respective share of the cleanup costs. This is a non-judicial allocation process. KMP is participating in the allocation process on behalf of both KMLT and KMBT. Each entity has two facilities located in Portland Harbor. KMP expects the allocation to conclude in 2014 and the EPA to issue its Record of Decision in 2015. It is anticipated that the cleanup activities will begin within one year of the issuance of the Record of Decision.
Roosevelt Irrigation District v. Kinder Morgan G.P., Inc., Kinder Morgan Energy Partners, L.P. , U.S. District Court, Arizona
This is a CERCLA case brought by a water purveyor whose wells have allegedly been contaminated due to the presence of a number of contaminants. The First Amended Complaint sought $175 million in damages against approximately 70 defendants. On August 6, 2013 plaintiffs filed its Second Amended Complaint (SAC) seeking monetary damages in unspecified amounts and reducing the number of defendants to 26 including KMEP and SFPP. The claims now presented in the SAC against KMEP and SFPP are related to alleged releases from a specific parcel within the SFPP Phoenix Terminal and the alleged impact of such releases on water wells owned by the plaintiffs and located in the vicinity of the Terminal. On October 24, 2013, we moved to dismiss the SAC.
The City of Los Angeles v. Kinder Morgan Liquids Terminals, LLC, Shell Oil Company, Equilon Enterprises LLC; California Superior Court, County of Los Angeles, Case No. NC041463
KMLT was a defendant in a lawsuit filed in 2005 alleging claims for environmental cleanup costs at the former Los Angeles Marine Terminal in the Port of Los Angeles. On April 9, 2013, KMLT and the Port of Los Angeles entered into a
Settlement and Release Agreement the terms of which provide for the dismissal of the litigation by the Port and KMLT’s agreement to pay 60% of the Port’s costs to remediate the former terminal site up to a $15 million cap. Further, according to terms of the Settlement and Release, KMP received a 5-year lease extension that allows KMLT to continue fuel loading and offloading operations at another KMLT Port of Los Angeles terminal property. The Court approved the parties’ Good Faith Settlement motion in the Superior Court and dismissed the case.
The City of Los Angeles, KMLT, Chevron and Phillips 66 remain named on a Cleanup and Abatement Order from the California Regional Water Quality Control Board as parties responsible for the cleanup of the former Los Angeles Marine Terminal. The private parties have all settled with the City of Los Angeles and agreed to pay a percentage of the City’s costs to perform the required cleanup at the site.We anticipate that cleanup activities by the Port will begin within the first quarter of 2014.
Exxon Mobil Corporation v. GATX Corporation, Kinder Morgan Liquids Terminals, LLC and ST Services, Inc.
On April 23, 2003, ExxonMobil filed a complaint in the Superior Court of New Jersey, Gloucester County. The lawsuit relates to environmental remediation obligations at a Paulsboro, New Jersey liquids terminal owned by ExxonMobil from the mid-1950s through November 1989, by GATX Terminals Corporation from 1989 through September 2000, and later owned by Support Terminals and Pacific Atlantic Terminals, LLC. The terminal is now owned by Plains Products, which is also a party to the lawsuit.
On June 25, 2007, the NJDEP, the Commissioner of the New Jersey Department of Environmental Protection and the Administrator of the New Jersey Spill Compensation Fund, referred to collectively as the plaintiffs, filed a complaint against ExxonMobil and KMLT, formerly known as GATX Terminals Corporation, alleging natural resource damages related to historic contamination at the Paulsboro terminal. The complaint was filed in Gloucester County, New Jersey. Both ExxonMobil and KMLT filed third party complaints against Support Terminals/Plains. The court consolidated the two cases.
In mid 2011, KMLT and Plains Products entered into a settlement agreement and subsequent Consent Judgment with the NJDEP which resolved the state’s alleged natural resource damages claim. The natural resource damage settlement includes a monetary award of $1 million and a series of remediation and restoration activities at the terminal site. KMLT and Plains Products have joint responsibility for this settlement. Simultaneously, KMLT and Plains Products entered into an agreement that settled each party’s relative share of responsibility (50/50) to the NJDEP under the Consent Judgment noted above. The Consent Judgment is now entered with the Court and the settlement is final. According to the agreement, Plains will conduct remediation activities at the site and KMLT will provide oversight and 50% of the costs. We anticipate remediation activities to begin by second quarter 2014.
The settlement with the state did not resolve the original complaint brought by ExxonMobil. On or around, April 10, 2013, KMLT, Plains and ExxonMobil settled the original Exxon complaint for past remediation costs for $750,000 to be split 50/50 between KMLT and Plains. All parties have now executed the agreement and the litigation is settled and dismissed.
Mission Valley Terminal Lawsuit
In August 2007, the City of San Diego, on its own behalf and purporting to act on behalf of the People of the State of California, filed a lawsuit against KMP and several affiliates seeking injunctive relief and unspecified damages allegedly resulting from hydrocarbon and methyl tertiary butyl ether (MTBE) impacted soils and groundwater beneath the City’s stadium property in San Diego arising from historic operations at the Mission Valley terminal facility. The case was filed in the Superior Court of California, San Diego County, case number 37-2007-00073033-CU-OR-CTL. On September 26, 2007, KMP removed the case to the U.S. District Court, Southern District of California, case number 07CV1883WCAB. The City disclosed in discovery that it is seeking approximately $170 million in damages for alleged lost value/lost profit from the redevelopment of the City’s property and alleged lost use of the water resources underlying the property. Later, in 2010, the City amended its initial disclosures to add claims for restoration of the site as well as a number of other claims that increased their claim for damages to approximately $365 million.
On November 29, 2012, the Court issued a Notice of Tentative Rulings on the parties’ summary adjudication motions. The Court tentatively granted our partial motions for summary judgment on the City’s claims for water and real estate damages and the State’s claims for violations of California Business and Professions Code § 17200, tentatively denied the City’s motion for summary judgment on its claims of liability for nuisance and trespass, and tentatively granted our cross motion for summary judgment on such claims. On January 25, 2013, the Court issued its final order reaffirming in all respects its tentative rulings and rendered judgment in favor of all defendants on all claims asserted by the City.
On February 20, 2013, the City of San Diego filed a notice of appeal of this case to the U.S. Court of Appeals for the Ninth Circuit. The appeal is currently pending.
This site has been, and currently is, under the regulatory oversight and order of the California Regional Water Quality Control Board. SFPP continues to conduct an extensive remediation effort at the City’s stadium property site.
On May 7, 2013, the City of San Diego filed a writ of mandamus to the California Superior Court seeking an order from the Court setting aside the California Regional Water Quality Control Board’s (RWQCB) approval of KMP’s permit request to increase the discharge of water from KMP’s groundwater treatment system to the City of San Diego’s municipal storm sewer system. KMEP is coordinating with the RWQCB to oppose the City’s writ.
Uranium Mines in Vicinity of Cameron, Arizona
In the 1950s and 1960s, Rare Metals Inc., an historical subsidiary of EPNG, operated approximately twenty uranium mines in the vicinity of Cameron, Arizona, many of which are located on the Navajo Indian Reservation. The mining activities were in response to numerous incentives provided to industry by the U.S. to locate and produce domestic sources of uranium to support the Cold War-era nuclear weapons program. In May 2012, EPNG received a general notice letter from the EPA notifying EPNG of the EPA’s investigation of certain sites and its determination that the EPA considers EPNG to be a potentially responsible party within the meaning of CERCLA. In August 2013, EPNG and the EPA entered into an Administrative Order on Consent and Scope of Work pursuant to which EPNG will conduct a radiological assessment of the surface of the mines. We are also seeking contribution from the applicable federal government agencies toward the cost of environmental activities associated with the mines, given their pervasive control over all aspects of the nuclear weapons program.
PHMSA Inspection of Carteret Terminal, Carteret, NJ
On April 4, 2013, the PHMSA, Office of Pipeline Safety issued a Notice of Probable Violation, Proposed Civil Penalty and Proposed Compliance Order (NOPV) arising from an inspection at the KMLT, Carteret, New Jersey location on March 15, 2011 following a release and fire that occurred during maintenance activity on March 14, 2011. On July 17, 2013, KMLT entered into a Consent Agreement and Order with the PHMSA, pursuant to which KMLT paid a penalty of $63,100 and is required to complete ongoing pipeline integrity testing and other corrective measures by May, 2015.
Southeast Louisiana Flood Protection Litigation
On July 24, 2013, the Board of Commissioners of the Southeast Louisiana Flood Protection Authority - East (Flood Protection Authority) filed a petition for damages and injunctive relief in state district court for Orleans Parish, Louisiana (Case No. 13-6911) against TGP, SNG and approximately one hundred other energy companies, alleging that defendants’ drilling, dredging, pipeline and industrial operations since the 1930’s have caused direct land loss and increased erosion and submergence resulting in alleged increased storm surge risk, increased flood protection costs and unspecified damages to the plaintiff. The Flood Protection Authority asserts claims for negligence, strict liability, public nuisance, private nuisance, and breach of contract. Among other relief, the petition seeks unspecified monetary damages, attorney fees, interest, and injunctive relief in the form of abatement and restoration of the alleged coastal land loss including but not limited to backfilling and re-vegetation of canals, wetlands and reef creation, land bridge construction, hydrologic restoration, shoreline protection, structural protection, and bank stabilization. On August 13, 2013, the suit was removed to the U.S. District Court for the Eastern District of Louisiana. On September 10, 2013, the Flood Protection Authority filed a motion to remand the case to the state district court for Orleans Parish. On December 18, 2013, a hearing was conducted on the remand motion and it remains under consideration by the court.
Plaquemines Parish Louisiana Coastal Zone Litigation
On November 8, 2013, the Parish of Plaquemines, Louisiana filed a petition for damages in the state district court for Plaquemines Parish, Louisiana (Docket No. 60-999) against TGP and 17 other energy companies, alleging that defendants’ oil and gas exploration, production and transportation operations in the Bastian Bay, Buras, Empire and Fort Jackson oil and gas fields of Plaquemines Parish caused substantial damage to the coastal waters and nearby lands (Coastal Zone) within the Parish, including the erosion of marshes and the discharge of oil waste and other pollutants which detrimentally affected the quality of state waters and plant and animal life, in violation of the State and Local Coastal Resources Management Act of 1978 (Coastal Zone Management Act). As a result of such alleged violations of the Coastal Zone Management Act, Plaquemines Parish seeks, among other relief, unspecified monetary relief, attorney fees, interest, and payment of costs necessary to restore the
allegedly affected Coastal Zone to its original condition, including costs to clear, vegetate and detoxify the Coastal Zone. On December 18, 2013, defendants removed the case to the U.S. District Court for the Eastern District of Louisiana. On January 14, 2014, the plaintiff filed a motion to remand the case to state court and such motion remains pending.
Pennsylvania Department of Environmental Protection Notice of Alleged Violations
The Pennsylvania Department of Environmental Protection (PADEP) has notified TGP of alleged violations of certain conditions to the construction permits issued to TGP for the construction of TGP’s 300 Line Project in 2011. The alleged violations arise from field inspections performed during construction by county conservation districts, as delegates of the PADEP, and generally involve the alleged failure by TGP to implement and maintain best practices to achieve sufficient erosion and sediment controls, stabilization of the right of way, and prevention of potential discharge of sediment into the waters of the commonwealth during construction and before placing the line into service. To resolve such alleged violations, the PADEP initially proposed a collective penalty of approximately $1.5 million. TGP and the PADEP are seeking to reach a mutually agreeable resolution of the alleged notices of violations, including an agreed penalty amount.
General
Although it is not possible to predict the ultimate outcomes, we believe that the resolution of the environmental matters set forth in this note, and other matters to which we and our subsidiaries are a party, will not have a material adverse effect on our business, financial position, results of operations or cash flows. As of December 31, 2013 and 2012, we have accrued a total reserve for environmental liabilities in the amount of $378 million and $421 million, respectively, of which $208 million and $253 million, respectively, are associated with KMI (excluding KMP and EPB) and primarily relate to legacy sites acquired in the May 25, 2012 EP acquisition. In addition, as of December 31, 2013 and December 31, 2012, we have recorded a receivable of $14 million and $22 million, respectively, for expected cost recoveries that have been deemed probable.
17. Recent Accounting Pronouncements
Accounting Standards Updates
On March 5, 2013, the FASB issued ASU No. 2013-05, “Parent’s Accounting for the Cumulative Translation Adjustment upon Derecognition of Certain Subsidiaries or Groups of Assets within a Foreign Entity or of an Investment in a Foreign Entity (a consensus of the FASB Emerging Issues Task Force).” This ASU amends the FASB’s Accounting Standards Codification (ASC) 830, “Foreign Currency Matters,” and ASC 810, “Consolidation,” to address diversity in practice related to the release of cumulative translation adjustments (CTA) into earnings upon the occurrence of certain derecognition events. ASU No. 2013-05 precludes the release of CTA for derecognition events that occur within a foreign entity, unless such events represent a complete or substantially complete liquidation of the foreign entity; however, derecognition events related to investments in a foreign entity result in the release of all CTA related to the derecognized foreign entity, even when a noncontrolling financial interest is retained. ASU No. 2013-05 also amends ASC 805, “Business Combinations,” for transactions that result in a company obtaining control of a business in a step acquisition by increasing an investment in a foreign entity from one accounted for under the equity method to one accounted for as a consolidated investment. For us, ASU No. 2013-05 was effective January 1, 2014, and the adoption of this ASU is not expected to have a material impact on our consolidated financial statements.
18. Reconciliation of Significant Asset and Liability Balances
The following is a reconciliation between KMP’s and EPB’s significant asset balances as reported in KMP’s and EPB’s Annual Report on Form 10-K as of December 31, 2013 and 2012 and our consolidated asset balances as shown on our accompanying consolidated balance sheets (in millions):
_______
(a)
Includes assets and liabilities of KMI’s consolidated subsidiaries, excluding KMP and EPB.
(b)
Excludes debt fair value adjustments. Decrease to long-term debt for debt fair value adjustments totaled $8 million as of both December 31, 2013 and 2012.
19. Guarantee of Securities of Subsidiaries
KMI had guaranteed the payment of the outstanding senior notes issued by El Paso LLC (formerly known as El Paso Corporation) as a result of the EP acquisition. These notes were also guaranteed by El Paso Holdco LLC (“El Paso Holdco”), El Paso LLC’s direct parent. El Paso Issuing Corporation (“Finance Corp”), a direct subsidiary of El Paso LLC, is the co-issuer of these notes. The aggregate principal amount of these series of El Paso LLC senior notes are referred to as the “Guaranteed Notes”. On October 3, 2013, El Paso LLC transferred substantially all of its assets to El Paso Holdco pursuant to an internal restructuring transaction. In connection with such internal restructuring, El Paso Holdco succeeded El Paso LLC as issuer with respect to the Guaranteed Notes, and El Paso LLC ceased to be an obligor with respect to the Guaranteed Notes. Prior to the internal restructuring, El Paso Holdco had been presented as the “Guarantor Subsidiary” and is now presented as one of the “Subsidiary Issuers.” KMI continues to guarantee the payment of the Guaranteed Notes. Finance Corp’s obligations as a co-issuer and primary obligor continue to be joint and several with the obligations of El Paso Holdco as issuer. As of both December 31, 2013, and 2012, approximately $3.8 billion and $3.9 billion, respectively, of these guaranteed notes are outstanding. Subject to the limitations set forth in the applicable supplemental indentures, the guarantee of KMI is full and unconditional and joint and several, and guarantee the Guaranteed Notes through their respective maturity dates, the latest of which is in 2037. Finance Corp has no subsidiaries and no independent assets or operations. A significant amount of KMI’s
income and cash flow are generated by its subsidiaries. As a result, the funds necessary to meet KMI’s debt service and/or guarantee obligations are provided in large part by distributions or advances from its subsidiaries. Included among the non-guarantor subsidiaries are KMP, KMR and EPB, along with KMGP, the general partner of KMP and El Paso Pipeline GP Company, L.L.C., the general partner of EPB. In the following condensed consolidating financial information, KMI is “Parent Guarantor,” and El Paso Holdco and Finance Corp are the “Subsidiary Issuers.” Both of the Subsidiary Issuers are 100% owned by KMI.
The condensed consolidating financial information for all periods presented below reflect the internal restructuring transaction described above.
Supplemental Information on Oil and Gas Producing Activities (Unaudited)
Operating statistics from our oil and gas producing activities for each of the years ended December 31, 2013, 2012 and 2011 are shown in the following table:
_______
(a)
Amounts relate to KMCO2 and its consolidated subsidiaries.
(b)
Computed using production costs, excluding transportation costs, as defined by the SEC. Natural gas volumes were converted to barrels of oil equivalent using a conversion factor of six Mcf (thousand cubic feet) of natural gas to one barrel of oil.
(c)
Production costs include labor, repairs and maintenance, materials, supplies, fuel and power, and general and administrative expenses directly related to oil and gas producing activities.
(d)
Includes only production attributable to leasehold ownership.
(e)
Includes production attributable to KMP’s ownership in processing plants and third party processing agreements.
(f)
Excludes natural gas production used as fuel.
(g)
Hedge gains/losses for crude oil and NGL are included with crude oil.
(h)
Natural gas sales were not hedged.
The following three tables provide supplemental information on oil and gas producing activities, including (i) capitalized costs related to oil and gas producing activities; (ii) costs incurred for the acquisition of oil and gas producing properties and for exploration and development activities; and (iii) the results of operations from oil and gas producing activities.
Our capitalized costs consisted of the following (in millions):
_______
(a)
Amounts relate to KMCO2 and its consolidated subsidiaries. Includes capitalized asset retirement costs and associated accumulated depreciation.
(b)
As of December 31, 2013, capitalized costs related to the unproved property for the Katz Strawn unit, was $20 million, Residual Oil Zone (ROZ) unproved exploration property was $13 million, and other miscellaneous unproved property was $5 million.
For each of the years ended December 31, 2013 , 2012 and 2011, our costs incurred for property acquisition, development and exploration were as follows (in millions):
_______
(a)
Acquisition of Goldsmith Landreth San Andreas Unit effective June 1, 2013.
(b)
Amounts relate to KMCO2 and its consolidated subsidiaries.
(c)
Amounts relate to exploration wells drilled in the Residual Oil Zone (ROZ).
Our results of operations from oil and gas producing activities for each of the years ended December 31, 2013, 2012 and 2011 are shown in the following table (in millions):
_______
(a)
Amounts relate to KMCO2 and its consolidated subsidiaries.
(b)
Revenues include losses attributable to our hedging contracts of $31 million, $28 million and $285 million for each of the years ended December 31, 2013, 2012 and 2011, respectively.
(c)
Consists primarily of CO2 expense.
Supplemental information is also provided for the following three items (i) estimated quantities of proved oil and gas reserves; (ii) the standardized measure of discounted future net cash flows associated with proved oil and gas reserves; and (iii) a summary of the changes in the standardized measure of discounted future net cash flows associated with proved oil and gas reserves.
The technical persons responsible for preparing the reserves estimates presented in this Note meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the standards pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. They are independent petroleum engineers, geologists, geophysicists, and petrophysicists; they do not own an interest in our oil and gas properties; and we do not employ them on a contingent basis.
The reserves estimates shown herein, other than the reserve estimates for the Goldsmith Landreth San Andreas Unit which we acquired effective June 1, 2013, have been independently evaluated by Netherland, Sewell & Associates, Inc. (NSAI), a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No.. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Derek Newton and Mr. Mike Norton. Mr. Newton has been practicing consulting petroleum engineering at NSAI since 1997. Mr. Newton is a Licensed Professional Engineer in the State of Texas (No. 97689) and has over 28 years of practical experience in petroleum engineering, with over 16 years experience in the estimation and evaluation of reserves. He graduated from University College, Cardiff, Wales, in 1983 with a Bachelor of Science Degree in Mechanical Engineering and from Strathclyde University, Scotland, in 1986 with a Master of Science Degree in Petroleum Engineering. Mr. Norton has been practicing consulting petroleum geology at NSAI since 1989. Mr. Norton is a Licensed Professional Geoscientist in the State of Texas, Geology (No. 441) and has over 30 years of practical experience in petroleum geosciences, with over 24 years experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1978 with a Bachelor of Science Degree in Geology. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines. The proved reserve estimates in NSAI’s reserves report constitute approximately 58% of all proved oil and gas reserves owned by KMP.
The reserves estimates for the Goldsmith Landreth San Andreas Unit have been independently evaluated by Ryder Scott
Company L.P. (RSC). The proved reserve estimates in RSC’s reserves report constitute approximately 42% of all proved oil and gas reserves owned by KMP. RSC is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy-five years. These reserve estimates are the result of technical analysis conducted by teams of geoscientists and engineers from RSC. Mr. Michael F. Stell was the primary technical
person responsible for overseeing the estimate of the reserves, future production and income. Mr. Stell, an employee of RSC since 1992, is an Advising Senior Vice President and is responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining RSC, Mr. Stell served in a number of engineering positions with Shell Oil Company and Landmark Concurrent Solutions. For more information regarding Mr. Stell’s geographic and job specific experience, please refer to the RSC website at www.ryderscott.com/Experience/Employees. Mr. Stell earned a Bachelor of Science degree in Chemical Engineering from Purdue University in 1979 and a Master of Science Degree in Chemical Engineering from the University of California, Berkeley, in 1981. He is a licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers. In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Stell fulfills. For each of the years 2011 through 2013, Mr. Stell has 20 hours of continuing education hours relating to reserves, reserve evaluations, and ethics. Based on his educational background, professional training and over 30 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Stell has attained the professional qualifications for a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.
Our employee who is primarily responsible for overseeing both NSAI and RSC’s preparation of the reserves estimates is a registered Professional Engineer in the states of Texas and Kansas with a Doctorate of Engineering from the University of Kansas. He is a member of the Society of Petroleum Engineers and has over 30 years of professional engineering experience. We believe the geologic and engineering data examined provides reasonable assurance that the proved reserves are recoverable in future years from known reservoirs under existing economic and operating conditions. Estimates of proved reserves are subject to change, either positively or negatively, as additional information become available and contractual and economic conditions change.
Furthermore, our management is responsible for establishing and maintaining adequate internal control over financial reporting, which includes the estimation of our oil and gas reserves. We maintain internal controls and guidance to ensure the reliability of our crude oil, NGL and natural gas reserves estimations, as follows:
•
no employee’s compensation is tied to the amount of recorded reserves;
•
we follow comprehensive SEC compliant internal policies to determine and report proved reserves, and our reserve estimates are made by experienced oil and gas reservoir engineers or under their direct supervision;
•
we review our reported proved reserves at each year-end, and at each year-end, the CO2-KMP business segment managers and the Vice President (President, CO2) review all significant reserves changes and all new proved developed and undeveloped reserves additions; and
•
the CO2-KMP business segment reports independently of our four remaining reportable business segments.
For more information on our controls and procedures, see Item 9A “Controls and Procedures-Management’s Report on Internal Control Over Financial Reporting” included in our Annual Report on Form 10-K for the year ended December 31, 2013.
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and NGL which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, that is, current prices and costs calculated as of the date the estimate is made. Pricing is applied based upon the twelve month unweighted arithmetic average of the first day of the month price for the year. Future development and production costs are determined based upon actual cost at year-end. Proved developed reserves are the quantities of crude oil, NGL and natural gas expected to be recovered through existing investments in wells and field infrastructure under current operating conditions. Proved undeveloped reserves require additional investments in wells and related infrastructure in order to recover the production.
As of December 31, 2011, we had 55.7 MMBbl of crude oil and 1.8 MMBbl of NGL classified as proved developed reserves. Also, as of year end 2011, we had 23.8 MMBbl of crude oil and 2.3 MMBbl of NGL classified as proved undeveloped reserves. Total proved reserves as of December 31, 2011, were 79.4 MMBbl of crude oil and 4.1 MMBbl of NGL.
During 2012, production from the fields totaled 12.8 MMBbl of crude oil and 1.4 MMBbl of NGL. In addition, we incurred $353 million in capital costs, which resulted in the development of 6.0 MMBbl of crude oil and 1.8 MMBbl of NGL and their transfer from the proved undeveloped category to the proved developed category. During 2012, we also sold our interest in the Claytonville Canyon Sand unit which reduced proved developed reserves by 0.2 MMBbl of crude oil. The
reclassifications from proved undeveloped to proved developed reserves reflect the transfer of 25.4% of crude oil and 79.4% of NGL from the proved undeveloped reserves reported as of December 31, 2011 to the proved developed classification of reserves reported as of December 31, 2012.
Also during 2012, previous estimates of proved developed reserves were revised upwards by 4.3 MMBbl of crude oil and 0.2 MMBbl of NGL, and proved undeveloped reserves were revised upward by 11.2 MMBbl of crude oil and 3.0 MMBbl of NGL. These revisions were attributed to utilizing higher projected CO2 flood recoveries resulting from updated performance at SACROC used to calculate reserves. There were 2.6 MMBbl of crude oil reserves attributed to future development of the Katz (Strawn) unit CO2 flood where the produced gas containing NGL is injected with the CO2. The proved undeveloped reserves for the Katz (Strawn) unit CO2 flood represent 9.0% of proved undeveloped reserves.
These revisions to the previous estimates, as well as the transfer of proved undeveloped reserves to the proved developed category as discussed above, resulted in the percentage of proved undeveloped reserves increasing from 31.0% at year end 2011 to 36.4% at year end 2012. After giving effect to production and revisions to previous estimates during 2012, total proved reserves of crude oil increased by 2.5 MMBbl and total proved reserves of NGL increased by 1.8 MMBbl.
As of December 31, 2012, we had 53.0 MMBbl of crude oil and 2.4 MMBbl of NGL classified as proved developed reserves. Also, as of year end 2012, we had 28.9 MMBbl of crude oil and 3.5 MMBbl of NGL classified as proved undeveloped reserves. Total proved reserves as of December 31, 2012, were 82.0 MMBbl of crude oil and 6.0 MMBbl of NGL.
During 2013, production from the fields totaled 13.7 MMBbl of crude oil and 1.5 MMBbl of NGL. For 2013, we incurred $452 million in capital costs, and this capital investment resulted in the development of 11.0 MMBbl of crude oil and 1.3 MMBbl of NGL and their transfer from the proved undeveloped category to the proved developed category. During 2013, we acquired the Goldsmith Landreth San Andres Field Unit which increased proved developed reserves by 15.5 MMBbl of crude oil and 3.9 MMBbl of NGL. The reclassifications from proved undeveloped to proved developed reserves reflect the transfer of 38.1% of crude oil and 37.5% of NGL from the proved undeveloped reserves reported as of December 31, 2012 to the proved developed classification of reserves reported as of December 31, 2013. The developed reserves for the Goldsmith Landreth San Andres Field Unit represent 25.9% of proved developed reserves.
Also during 2013, previous estimates of proved developed reserves were revised upward by 1.7 MMBbl of crude oil and 0.6 MMBbl of NGL, and proved undeveloped reserves were revised downward by 4.3 MMBbl of crude oil and 0.65 MMBbl of NGL. These revisions are mainly attributed to the elimination of uneconomic proved developed nonproducing reserves and proved undeveloped reserves in Katz due to higher operating costs. The proved developed reserves for Katz represent 6.3% of proved developed reserves.
These revisions to our previous estimates, as well as the transfer of proved undeveloped reserves to the proved developed category as discussed above, resulted in the percentage of proved undeveloped reserves increasing from 36.4% at year end 2012 to 39.0% at year end 2013. After giving effect to production and revisions to previous estimates during 2013, total proved reserves of crude oil increased by 25.1 MMBbl and total proved reserves of NGL increased by 8.8 MMBbl.
As of December 31, 2013, we had 67.4 MMBbl of crude oil and 6.7 MMBbl of NGL classified as proved developed reserves. Also, as of year end 2013, we had 39.6 MMBbl of crude oil and 8.0 MMBbl of NGL classified as proved undeveloped reserves. Total proved reserves as of December 31, 2013, were 107.0 MMBbl of crude oil and 14.8 MMBbl of NGL. We currently expect that the proved undeveloped reserves we report as of December 31, 2013 will be developed within the next five years.
During 2013, we filed estimates of our oil and gas reserves for the year 2012 with the Energy Information Administration of the U. S. Department of Energy on Form EIA-23. The data on Form EIA-23 was presented on a different basis, and included 100% of the oil and gas volumes from our operated properties only, regardless of our net interest. The difference between the oil and gas reserves reported on Form EIA-23 and those reported in this Note exceeds 5%.
The following Reserve Quantity Information table discloses estimates, as of December 31, 2013, of proved crude oil, NGL and natural gas reserves, prepared by NSAI and RSC (independent oil and gas consultants), of KMCO2 and its consolidated subsidiaries’ interests in oil and gas properties, all of which are located in the state of Texas. This data has been prepared using current prices and costs, as discussed above, and the estimates of reserves and future revenues in this Note conform to the guidelines of the SEC.
_______
(a)
Amounts relate to KMCO2 and its consolidated subsidiaries.
(b)
Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.
(c)
Predominantly due to higher product prices used to determine reserve volumes.
(d)
Represents volumes added with the development of the Katz (Strawn) unit CO2 flood.
(e)
Predominantly due to higher CO2 flood recoveries based on updated performance at the SACROC Unit.
(f)
Predominantly due to higher operating costs at the Katz Strawn Unit.
(g)
Represents volumes added with acquisition of the Goldsmith Landreth San Andreas Unit in June 2013.
(h)
Proved developed reserves include reserves attributable to the Goldsmith Landreth San Andreas Unit of 15,450 MBbl for oil and 3,862 MBbl for NGL’s.
(i)
Proved undeveloped reserves include reserves attributable to the Goldsmith Landreth San Andreas Unit of 25,935 MBbl for oil and 6,484 MBbl for NGL’s.
The standardized measure of discounted cash flows and summary of the changes in the standardized measure computation from year-to-year are prepared in accordance with the “Extractive Activities-Oil and Gas” Topic of the Codification. The assumptions that underly the computation of the standardized measure of discounted cash flows, presented in the table below, may be summarized as follows:
•
the standardized measure includes our estimate of proved crude oil, NGL and natural gas reserves and projected future production volumes based upon year-end economic conditions;
•
pricing is applied based upon the 12 month unweighted arithmetic average of the first day of the month price for the year;
•
future development and production costs are determined based upon actual cost at year-end;
•
the standardized measure includes projections of future abandonment costs based upon actual costs at year-end; and
•
a discount factor of 10% per year is applied annually to the future net cash flows.
The standardized measure of discounted future net cash flows from proved reserves were as follows (in millions):
_______
(a)
Amounts relate to KMCO2 and its consolidated subsidiaries.
(b)
Includes abandonment costs.
(c)
Standardized Measure of discounted future net cash flows as of December 31, 2013 includes $843 million attributable to the Goldsmith Landreth San Andreas Unit acquired in June 2013.
The following table represents our estimate of changes in the standardized measure of discounted future net cash flows from proved reserves (in millions):
_______
(a)
Amounts relate to KMCO2 and its consolidated subsidiaries.
(b)
Excludes the effect of losses attributable to our hedging contracts of $31 million, $28 million and $285 million for each of the years ended December 31, 2013, 2012 and 2011, respectively.
(c)
Primarily due to the extension of the SACROC unit.
(d)
Sale of the Claytonville field unit.
(e)
2013 revisions were primarily due to increased operating costs at the Katz Strawn Unit. 2012 revisions were primarily due to higher projected CO2 flood recoveries resulting from updated performance at SACROC and the addition of proved undeveloped reserve volumes at the Katz (Strawn) unit CO2 flood. 2011 revisions were primarily due to higher product prices used to determine reserve volumes and the addition of the Katz (Strawn) unit CO2 flood.
(f)
Acquisition of the Goldsmith Landreth San Andreas Unit in June 2013.
(g)
Standardized Measure discounted cash flows as of December 31, 2013 includes $843 million attributable to the Goldsmith Landreth San Andreas Unit acquired in June 2013.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
KINDER MORGAN, INC.
Registrant
By: /s/ KIMBERLY A. DANG
Kimberly A. Dang
Vice President and Chief Financial Officer
(principal financial and accounting officer)
Date:
February 21, 2014
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the dates indicated.
Signature
Title
Date
/s/ KIMBERLY A. DANG
Vice President and Chief Financial Officer (principal financial officer and principal accounting officer)
February 21, 2014
Kimberly A. Dang
/s/ RICHARD D. KINDER
Director, Chairman and Chief Executive Officer (principal executive officer)
February 21, 2014
Richard D. Kinder
/s/ ANTHONY W. HALL, JR.
Director
February 21, 2014
Anthony W. Hall, Jr.
/s/ STEVEN J. KEAN
Director
February 21, 2014
Steven J. Kean
/s/ DEBORAH A. MACDONALD
Director
February 21, 2014
Deborah A. Macdonald
/s/ MICHAEL MILLER
Director
February 21, 2014
Michael Miller
/s/ MICHAEL C. MORGAN
Director
February 21, 2014
Michael C. Morgan
/s/ FAYEZ SAROFIM
Director
February 21, 2014
Fayez Sarofim
/s/ C. PARK SHAPER
Director
February 21, 2014
C. Park Shaper
/s/ JOEL V. STAFF
Director
February 21, 2014
Joel V. Staff
Director
John Stokes
/s/ ROBERT F. VAGT
Director
February 21, 2014
Robert F. Vagt
Representing a majority of the Board of Directors of Kinder Morgan, Inc.