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 position, results of operations or cash flows. There are also risks associated with being an owner of common units in a partnership that are different than being an owner of common stock in a corporation. Investors in our common units should be aware that the realization of any of those risks could result in a decline in the trading price of our common units, and they might lose all or part of their investment.
Risks Related to Our Business
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, 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 to our consolidated financial statements, to the rates we charge on our 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.
We are subject to extensive laws and regulations related to pipeline integrity. There are, for example, federal guidelines for the 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 compliance costs are pipeline integrity testing and the repairs. 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 integrity testing programs to assess and maintain the integrity of our existing and future pipelines as required by the 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 be 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 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 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 our revenues by decreasing the volumes of natural gas transported on our or our joint ventures’ 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 recontract 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.
We regularly undertake major construction projects to expand our existing assets and to construct new assets. A variety of factors outside of our 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 we have the power of eminent domain for our 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 business if we were to lose the right to use or occupy the property on which our pipelines are located.
Our business, financial condition and operating results may be adversely affected 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 our business, financial condition and results of operations.
In addition, due to our relationship with KMI, our credit ratings, and thus our ability to access the capital markets and the terms and pricing we receive therein, may be adversely affected by any impairment to KMI’s financial condition or adverse changes in its credit ratings. Similarly, 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 debt instruments, as well as the market value of our common units.
Our acquisition strategy and expansion programs require access to new capital. Limitations on our access to capital would impair our ability to grow.
Consistent with the terms of our partnership agreement, we have distributed most of the cash generated by our operations. As a result, we have relied on external financing sources, including commercial borrowings and issuances of debt and equity securities, to fund our acquisition and growth capital expenditures. However, to the extent we are unable to continue to finance growth externally, our cash distribution policy will significantly impair our ability to grow. We may need new capital to finance these activities. Limitations on our access to capital, whether due to tightened capital markets, more expensive capital or otherwise, will impair our ability to execute this strategy.
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 $19.9 billion of consolidated debt (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 distributions 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 distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all. For more information about our debt, see Note 8 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 $5.7 billion (29%) of our total $19.9 billion consolidated debt (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 growth strategy may cause difficulties integrating and constructing new operations, and we may not be able to achieve the expected benefits from any future acquisitions or expansions.
Part of our business strategy includes acquiring additional businesses, some of which may occur in drop-down transactions from KMI, expanding existing assets and constructing new facilities. If we do not successfully integrate acquisitions, expansions or newly constructed facilities, we may not realize anticipated operating advantages and cost savings. The integration of acquired companies or new assets involves a number of risks, including (i) demands on management related to the increase in our size; (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.
We 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 our ability to manage those operations and to eliminate redundant and excess costs. Difficulties in integration may be magnified if we make multiple acquisitions over a relatively short period of time. Because of difficulties in combining and expanding operations, we may not be able to achieve the cost savings and other size-related benefits that we hoped to achieve after these acquisitions, which would harm our financial condition and results of operations.
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 our crude oil, natural gas and refined petroleum products 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 our oil and gas development and production operations depends in part upon our 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 our CO2 business segment will decline. We 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 we do not realize production volumes greater than, or equal to, our hedged volumes, we may suffer financial losses not offset by physical transactions.
The 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 our CO2 business segment.
The revenues, profitability and future growth of our CO2 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, we estimate that every $1 change in the average WTI crude oil price per barrel would impact our CO2 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 our 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 our 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 our proved reserves. In the event prices fall substantially, we may not be able to realize a profit from our 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. For more information about our hedging activities, see Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Critical Accounting Policies and Estimates-Hedging Activities” and Note 13 to our consolidated financial statements.
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 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.
Our Kinder Morgan Canada 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 our Kinder Morgan Canada 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 partners’ capital 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 our CO2 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.
Our business requires the retention and recruitment of a skilled workforce and the loss of such workforce could result in the failure to implement our business plans.
Our operations and management require the retention and recruitment of a skilled workforce, including engineers, technical personnel and other professionals. We and our affiliates compete with other companies in the energy industry for this skilled workforce. In addition, many of our current employees are retirement eligible and have significant institutional knowledge that must be transferred to other employees. If we are unable to (a) retain current employees, (b) successfully complete the knowledge transfer and/or (c) recruit new employees of comparable knowledge and experience, our business could be negatively impacted. In addition, we could experience increased allocated costs to retain and recruit these professionals.
Risks Related to Ownership of Our Common Units
The interests of KMI may differ from our interests and the interests of our unitholders.
KMI indirectly owns all of the common stock of our general partner and elects all of its directors. Our general partner owns all of KMR’s voting shares and elects all of its directors. Furthermore, some of KMR’s and our general partner’s directors and officers are also directors and officers of KMI and its other subsidiaries, including EPB, and have fiduciary duties to manage the businesses of KMI and its other subsidiaries in a manner that may not be in the best interests of our unitholders. KMI has a number of interests that differ from the interests of our unitholders. As a result, there is a risk that important business decisions will not be made in the best interests of our unitholders.
Our partnership agreement and the KMR LLC agreement restrict or eliminate a number of the fiduciary duties that would otherwise be owed by our general partner and/or its delegate to our unitholders.
Modifications of state law standards of fiduciary duties may significantly limit the ability of our unitholders to successfully challenge the actions of our general partner in the event of a breach of fiduciary duties. These state law standards include the duties of care and loyalty. The duty of loyalty, in the absence of a provision in the limited partnership agreement to the contrary, would generally prohibit our general partner from taking any action or engaging in any transaction as to which it has a conflict of interest. Our limited partnership agreement contains provisions that prohibit limited partners from advancing claims that otherwise might raise issues as to compliance with fiduciary duties or applicable law. For example, that agreement provides that the general partner may take into account the interests of parties other than us in resolving conflicts of interest. It also provides that in the absence of bad faith by the general partner, the resolution of a conflict by the general partner will not be a breach of any duty. The provisions relating to the general partner apply equally to KMR as its delegate. It is not necessary for a limited partner to sign our limited partnership agreement in order for the limited partnership agreement to be enforceable against that person.
Common unitholders have limited voting rights and limited control.
Holders of common units have only limited voting rights on matters affecting us. Our general partner manages partnership activities. Under a delegation of control agreement, our general partner has delegated the management and control of our and our subsidiaries’ business and affairs to KMR. Holders of common units have no right to elect the general partner or any of the directors of the general partner or KMR on an annual or other ongoing basis. If the general partner withdraws, however, its successor may be elected by the holders of a majority of the outstanding units of all classes (excluding common units and Class B units owned by the departing general partner and its affiliates and excluding the number of i-units corresponding to the number of any KMR shares owned by the departing general partner and its affiliates).
The limited partners may remove the general partner only if (i) the holders of at least 66 2/3% of the outstanding units of all classes, excluding common units and Class B units owned by the general partner and its affiliates and excluding the number of i-units corresponding to the number of any KMR shares owned by the general partner and its affiliates, vote to remove the general partner; (ii) a successor general partner is approved by the same vote; and (iii) we receive an opinion of counsel opining that the removal would not result in the loss of the limited liability of any limited partner or of the limited partner of an operating partnership, or cause us or an operating partnership to be taxed as a corporation or otherwise to be taxed as an entity for federal income tax purposes.
A person or group owning 20% or more of the common units and KMR shares on a combined basis cannot vote.
Any common units or KMR shares held by a person or group that owns 20% or more of the aggregate number of common units and KMR shares on a combined basis cannot be voted. This limitation does not apply to the general partner and its affiliates. This provision may (i) discourage a person or group from attempting to remove the general partner or otherwise change management and (ii) reduce the price at which the common units will trade under certain circumstances. For example, a third party will probably not attempt to take over our management by making a tender offer for the common units at a price above their trading market price without removing the general partner and substituting an affiliate of its own.
The general partner’s liability to us and our unitholders may be limited.
Our partnership agreement contains language limiting the liability of the general partner to us or the holders of common units. For example, our partnership agreement provides that (i) the general partner does not breach any duty to us or the holders of common units by borrowing funds or approving any borrowing (the general partner is protected even if the purpose or effect of the borrowing is to increase incentive distributions to the general partner); (ii) the general partner does not breach any duty to us or the holders of common units by taking any actions consistent with the standards of reasonable discretion outlined in the definitions of available cash and cash from operations contained in our partnership agreement; and (iii) the general partner does not breach any standard of care or duty by resolving conflicts of interest unless the general partner acts in bad faith.
Unitholders may have liability to repay distributions.
Unitholders will not be liable for assessments in addition to their initial capital investment in the common units. Under certain circumstances, however, holders of common units may have to repay us amounts wrongfully returned or distributed to them. Under Delaware law, we may not make a distribution to unitholders if the distribution causes our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and non-recourse liabilities are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that for a period of three years from the date of such a distribution, a limited partner who receives the distribution and knew at the time of the distribution that the distribution violated Delaware law will be liable to the limited partnership for the distribution amount. Under Delaware law, an assignee who becomes a substituted limited partner of a limited partnership is liable for the obligations of the assignor to make contributions to the partnership. However, such an assignee is not obligated for liabilities unknown to the assignee at the time the assignee became a limited partner if the liabilities could not be determined from the partnership agreement.
Unitholders may be liable if we have not complied with state partnership law.
We conduct our business in a number of states. In some of those states the limitations on the liability of limited partners for the obligations of a limited partnership have not been clearly established. The unitholders might be held liable for the partnership’s obligations as if they were a general partner if (i) a court or government agency determined that we were conducting business in the state but had not complied with the state’s partnership statute; or (ii) unitholders’ rights to act together to remove or replace the general partner or take other actions under our partnership agreement constitute “control” of our business.
The general partner may buy out minority unitholders if it owns 80% of the aggregate number of common units and KMR shares.
If at any time the general partner and its affiliates own 80% or more of the aggregate number of issued and outstanding common units and KMR shares, the general partner will have the right to purchase all, and only all, of the remaining common units, but only if KMI elects to purchase all, and only all, of the outstanding KMR shares that are not held by KMI and its affiliates pursuant to the purchase provisions that are a part of the LLC agreement of KMR. Because of this right, a unitholder could have to sell its common units at a time or price that may be undesirable. The purchase price for such a purchase will be the greatest of (i) the 20-day average closing price for the common units or the KMR shares as of the date five days prior to the
date the notice of purchase is mailed; or (ii) the highest purchase price paid by the general partner or its affiliates to acquire common units or KMR shares during the prior 90 days. The general partner can assign this right to its affiliates or to us.
We may sell additional limited partner interests, diluting existing interests of unitholders.
Our partnership agreement allows the general partner to cause us to issue additional common units and other equity securities. When we issue additional equity securities, including additional i-units to KMR when it issues additional shares, unitholders’ proportionate partnership interest in us will decrease. Such an issuance could negatively affect the amount of cash distributed to unitholders and the market price of common units. Issuance of additional common units will also diminish the relative voting strength of the previously outstanding common units. Our partnership agreement does not limit the total number of common units or other equity securities we may issue.
The general partner can protect itself against dilution.
Whenever we issue equity securities to any person other than the general partner and its affiliates, the general partner has the right to purchase additional limited partnership interests on the same terms. This allows the general partner to maintain its proportionate partnership interest in us. No other unitholder has a similar right. Therefore, only the general partner may protect itself against dilution caused by issuance of additional equity securities.
Our partnership agreement contains provisions that may limit the rights with respect to the ownership of our common units by individuals and entities that are not U.S. citizens within the meaning of the Jones Act. This may affect the liquidity of our common units and may result in non-U.S. citizens having their distribution and voting rights suspended or their common units redeemed by us.
We are subject to the Jones Act and, as a result, at least 75% of our outstanding units must be owned and controlled by U.S. citizens within the meaning of the Jones Act. Our partnership agreement includes provisions that may limit the rights of non-U.S. citizens with respect to ownership of our common units. These provisions are intended to facilitate compliance with laws and regulations, including the Jones Act and others to which we may become subject, that provide for the forfeiture of any property in which we have an interest based on the nationality or citizenship of our unitholders, and they may have an adverse effect on holders of our common units.
Our partnership agreement permits us to require that any unitholder provide us from time to time with certain documentation concerning such person’s citizenship. In the event that a unitholder does not submit such requested or required documentation to us, our partnership agreement provides us with certain remedies, including the suspension of the distribution and voting rights of such unitholder and the redemption by us of such unitholder’s common units.
In addition to the risks described above, the foregoing restrictions on ownership of our units by non-U.S. citizens could delay, defer or prevent a transaction or change in control that might involve a premium price for our common units or otherwise be in the best interest of our unitholders.
Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation for U.S. federal income tax purposes or if we were to become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution to our unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS with respect to our classification as a partnership for U.S. federal income tax purposes.
Despite the fact that we are organized as a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for U.S. federal income tax purposes. Although we do not believe, based on our current operations, that we are or will be so treated, the IRS could disagree with the positions we take or a change in our business (or a change in current law) could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and we would likely pay additional state
income taxes at varying rates. Distributions to our unitholders would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions or credits would flow through to our unitholders. Because tax would be imposed on us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation for U.S. federal income tax purposes would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, 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. For example, the Texas franchise tax is imposed at a maximum effective rate of 0.7% of our gross income that is apportioned to Texas. If any additional state income taxes were imposed upon us as an entity, our cash available for distribution would be reduced. 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 an investment in our common units.
If the IRS contests the U.S. federal income tax positions we take, the market for our common units may be adversely affected and the cost of such contest will reduce our cash available for distribution to our unitholders.
The IRS may adopt positions that differ from the positions we take, and the IRS’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of our the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders because the costs will reduce our cash available for distribution.
Our common unitholders will be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
Because our unitholders are treated as partners to whom we will allocate taxable income that could be different in amount than the cash we distribute, they are required to pay any U.S. federal income taxes and, in some cases, state and local income taxes on their share of our taxable income whether or not they receive cash distributions from us. Common unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability resulting from their share of that income.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If a common unitholder sells common units, the common unitholder will recognize a gain or loss equal to the difference between the amount realized in the sale and that common unitholder’s adjusted tax basis in those common units. Because distributions in excess of a common unitholder’s allocable share of our net taxable income decrease that unitholder’s tax basis in its common units, the amount, if any, of such prior excess distributions with respect to the common units sold will, in effect, become taxable income to that unitholder if the unitholder sells such common units at a price greater than that unitholder’s tax basis in those common units, even if the price received is less than the unitholder’s original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a common unitholder’s share of our nonrecourse liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of cash received from the sale.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to unitholders who are organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by
withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. Tax-exempt entities and non-U.S. persons should consult their tax advisor before investing in our common units.
We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of common units, we treat each purchaser of our common units as having the same tax benefits with regard to the actual common units purchased and we adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to a common unitholder. It also could affect the timing of these tax benefits or the amount of gain from a sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to the unitholder’s tax returns.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations, and although the U.S. Treasury Department issued proposed Treasury Regulations allowing a similar monthly simplifying convention, such regulations are not final and do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our common unitholders.
Our valuation methodologies may result in a shift of income, gain, loss and deduction between our general partner and the common unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.
When we issue additional common units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our common unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our general partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our common unitholders and our general partner. It also could affect the amount of gain from our common unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our common unitholders’ or our general partner’s tax returns without the benefit of additional deductions.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in a termination of our partnership for U.S. federal income tax purposes.
We will be considered to have technically terminated our partnership for U.S. federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if certain relief were unavailable) for one fiscal year. The termination could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a common unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income being includable in the common unitholder’s taxable income for the year of termination. Under current law, a technical termination would not affect our classification as a partnership for U.S. federal income tax purposes, but instead, after our termination we would be treated as a new partnership for U.S. federal
income tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.
The IRS has announced a publicly traded partnership technical relieve procedure, whereby, if a publicly traded partnership that has a technical termination requests and the IRS grants special relief, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year, notwithstanding two partnership tax years resulting from the technical terminations.
A common unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of those common units. If so, the common unitholder would no longer be treated for U.S. federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.
Because a common unitholder whose common units are loaned to a “short seller” to effect a short sale may be considered as having disposed of the loaned common units, the unitholder may no longer be treated for U.S. federal income tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the common unitholder and any cash distributions received by the common unitholder as to those common units could be fully taxable as ordinary income. Common unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax adviser to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.
The issuance of additional i-units may cause more taxable income and gain to be allocated to the common units.
The i-units we issue to KMR generally are not allocated income, gain, loss or deduction for U.S. federal income tax purposes until such time as we are liquidated. Therefore, the issuance of additional i-units may cause more taxable income and gain to be allocated to the common unitholders.
As a result of investing in our common units, a common unitholder will likely be subject to state, local and non-U.S. taxes and return filing requirements in jurisdictions where they do not live as a result of investing in our common units.
In addition to U.S. federal income taxes, our common unitholders will likely be subject to other taxes, including state and local taxes, non-U.S. taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Our common unitholders will likely be required to file state, local and non-U.S. income tax returns and pay state, local and non-U.S. income taxes in some or all of these various jurisdictions. Further, our common unitholders may be subject to penalties for failure to comply with those requirements. We currently own assets and conduct business in numerous states in the U.S. and in Canada. It is the responsibility of each common unitholder to file all required U.S. federal, state, local and non-U.S. tax returns.
There is the potential for a change of control of our general partner if KMI defaults on debt.
KMI indirectly owns all the common stock of Kinder Morgan G.P., Inc., our general partner. If KMI defaults on its debt, then the lenders under such debt, in exercising their rights as lenders, could acquire control of our general partner or otherwise influence our general partner through control of KMI.
Item 1B.
Item 1B. Unresolved Staff Comments.
None.
Item 3.
Item 3. Legal Proceedings.
See Note 16 to our consolidated financial statements.
Item 4.
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.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
The following table sets forth, for the periods indicated, the high and low sale prices per common unit, as reported on the NYSE, the principal market in which our common units are traded, the amount of cash distributions declared per common and Class B unit, and the fractional i-unit distribution declared per i-unit.
Distribution information is for distributions declared for the respective quarter. The declared distributions were paid within 45 days after the end of the quarter.
Our common units are traded on the NYSE under the symbol “KMP.” As of January 31, 2014, we had 1,485 unitholders of record, which does not include beneficial owners whose shares are held by a clearing agency, such as a broker or bank. Additionally, as of January 31, 2014, there was one holder of our Class B units and one holder of our i-units.
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” and Note 12 “Commitments and Contingent Liabilities-KMEP Common Unit Compensation Plan for Non-Employee Directors” to our consolidated financial statements.
We did not repurchase any units during the fourth quarter of 2013 or sell any unregistered units in the fourth quarter of 2013.
Item 6.
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
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, 2, and 3 to our consolidated financial statements, our financial statements reflect:
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our August 1, 2012 and March 1, 2013 acquisitions from KMI as if such acquisitions had taken place on the effective dates of common control. We refer to these two separate transfers of net assets from KMI to us as the drop-down transactions, and we refer to the transferred assets as our drop-down asset groups. We accounted for the drop-down transactions as a combination of entities under common control, and accordingly, the financial information contained in this Management’s Discussion and Analysis of Financial Condition and Results of Operations include the financial results of the drop-down asset groups for all periods subsequent to the effective dates of common control; and
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the reclassifications necessary to reflect the results of our FTC Natural Gas Pipelines disposal group as discontinued operations. We sold our 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 our share of joint venture debt. In 2013, we and Tallgrass trued up the final consideration for the sale of our FTC Natural Gas Pipelines disposal group and based both on this true up and certain incremental selling expenses we 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 our 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 energy, bulk commodity and liquids products transportation, storage and distribution; and
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creating long-term value for our unitholders.
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;
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CO2-(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-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-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; and
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Kinder Morgan Canada-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.
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 our Texas Intrastate Natural Gas Group, we currently derive approximately 75% of our 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 our 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 KMI effective March 1, 2013 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.
Our 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 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 our CO2 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. Our 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 our Terminals 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 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. Continuing our history of making accretive acquisitions and economically advantageous expansions of existing businesses, in 2013, we invested approximately $3.5 billion for both strategic business acquisitions and expansions of existing assets (not including our March 1, 2013 drop-down transaction with KMI and our May 1, 2013 Copano acquisition). Our capital investments have helped us to achieve compound annual growth rates in cash distributions to our limited partners of 7.0%, 6.6% and 5.8%, respectively, for the one-year, three-year and five-year periods ended December 31, 2013.
Thus, the amount that we are able to increase distributions to our unitholders will, to some extent, be a function of our ability to complete successful acquisitions and expansions. We believe we will continue to have opportunities for expansion of our facilities in many markets, and we have budgeted approximately $3.6 billion for our 2014 capital expansion program (including small acquisitions and investment contributions, but excluding asset acquisitions from KMI). We regularly consider and enter into discussions regarding potential acquisitions, including those from KMI or its affiliates, and we 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 other 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 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.
In addition, a portion of our business portfolio (including our Kinder Morgan Canada business segment, the Canadian portion of our Cochin Pipeline, and our 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 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.
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 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 our West Coast Products Pipelines and our 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 our regulatory proceedings, see Note 16.
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 and 7 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 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 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 to our consolidated financial statements.
Results of Operations
Non-GAAP Measures
The non-GAAP financial measures of (i) distributable cash flow before certain items, both in the aggregate and per unit, and (ii) segment earnings before depreciation, depletion, and amortization (DD&A); amortization of excess cost of equity investments; and certain items, are presented below under “-Distributable Cash Flow” and “-Consolidated Earnings Results,” respectively. 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.
Our non-GAAP measures described below should not be considered as an alternative to GAAP net income or any other GAAP measure. Distributable cash flow before certain items, and segment earnings before DD&A, amortization of excess cost of equity investments, and certain items, are not financial measures in accordance with GAAP and have important limitations as analytical tools. You should not consider any of these non-GAAP measures in isolation or as a substitute for an analysis of our results as reported under GAAP. Because distributable cash flow before certain items excludes some but not all items that affect net income, and because distributable cash flow measures are defined differently by different companies in our industry, our distributable cash flow before certain items may not be comparable to distributable cash flow measures of other companies. Segment earnings before DD&A, amortization of excess cost of equity investments, and certain items, has similar limitations. Our 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.
Distributable Cash Flow
Our partnership agreement requires us to distribute 100% of our available cash to our partners on a quarterly basis (available cash as defined in our partnership agreement generally consists of all our cash receipts, less cash disbursements and changes in reserves). For more information, see Note 11 to our consolidated financial statements. Distributable cash flow, sometimes referred to in this report as DCF, is an overall performance metric we use to estimate the ability of our assets to generate cash flows on an ongoing basis and as a measure of available cash. The following table discloses the calculation of our DCF for each of the years ended December 31, 2013, 2012 and 2011 (calculated before the combined effect from all of the 2013, 2012 and 2011 certain items disclosed in the footnotes to the tables below):
________
(a)
Equal to the combined effect from (i) all of the 2013, 2012 and 2011 certain items disclosed in the footnotes to the “-Results of Operations” table below, excluding footnote (g) (and described in more detail below in both our management discussion and analysis of segment results and “-Other”) and (ii) net income attributable to noncontrolling interests.
(b)
2013 amount includes a $75 million general partner incentive distribution waiver related to common units issued to finance our May 2013 Copano acquisition. 2013, 2012 and 2011 amounts also include reductions of $4 million, $26 million and $29 million, respectively, for waived general partner incentive distribution amounts related to common units issued to finance a portion of our July 2011 KinderHawk acquisition. In addition, our general partner has also agreed to waive incentive distribution 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 to support the Copano acquisition and (ii) $13 million for 2014, $19 million for 2015 and $6 million for 2016 to support our APT and SCT acquisitions.
(c)
2013, 2012 and 2011 amounts include expense amounts of $87 million, $176 million and $171 million, respectively, for our proportionate share of the DD&A expenses of our unconsolidated joint ventures. 2012 and 2011 amounts also include expense amounts of $7 million and $27 million, respectively, from our FTC Natural Gas Pipelines disposal group. 2013 and 2012 amounts also exclude expense amounts of $19 million and $97 million, respectively, attributable to our drop-down asset groups for periods prior to our acquisition.
(d)
2013, 2012 and 2011 amounts include expenditures of $3 million, $19 million and $10 million, respectively, for our proportionate share of the sustaining capital expenditures (those capital expenditures which do not increase the capacity or throughput) of certain unconsolidated joint ventures.
(e)
In order to more closely track the cash distributions we receive from our unconsolidated joint ventures, our calculation of DCF (i) adds back our proportionate share of the DD&A expenses of certain joint ventures and (ii) subtracts our proportionate share of the sustaining expenditures (those capital expenditures which do not increase the capacity or throughput) of certain joint ventures.
Consolidated Earnings Results
With regard to our reportable business segments, we consider segment earnings before all depreciation, depletion and amortization expenses, and amortization of excess cost of equity investments, to be an important measure of our success in maximizing returns to our partners. This measure, sometimes referred to in this report as segment EBDA, is more fully defined in footnote (a) to the “-Results of Operations” table below. 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 five 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.
____________
(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.
(b)
2013, 2012 and 2011 amounts include an increase in earnings of $657 million, an increase in earnings of $275 million and a decrease in earnings of $387 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 and 2012 amounts include increases in expense of $19 million and $97 million, respectively, attributable to our drop-down asset groups for periods prior to our acquisition dates.
(d)
2013, 2012 and 2011 amounts include increases in expense of $49 million, $124 million and $94 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 “-Other.”
(e)
2013 and 2012 amounts include increases in expense of $10 million and $68 million, respectively, related to the combined effect from all of the 2013 and 2012 certain items related to interest expense disclosed below in “-Other.”
(f)
Represents amounts attributable to our FTC Natural Gas Pipelines disposal group. 2013 amount represents an incremental loss related to the sale of our disposal group effective November 1, 2012. 2012 amount includes a combined $829 million loss from the remeasurement of net assets to fair value and the sale of our 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.
(g)
2013, 2012 and 2011 amounts include an increase of $5 million, a decrease of $4 million and a decreases of $7 million, respectively, in net income attributable to our noncontrolling interests, related to the combined effect from all of the 2013, 2012 and 2011 certain items disclosed below in both our management discussion and analysis of segment results and “-Other.”
For the comparable years of 2013 and 2012, total segment EBDA increased $1,715 million (38%) in 2013; however, this overall increase:
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included a $382 million increase in EBDA from the effect of the certain items described in footnote (b) to the “-Results of Operations” table above; and
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excluded a $167 million decrease in EBDA from discontinued operations (as described in footnote (f) to the “-Results of Operations” table above).
After adjusting for these two items, the remaining $1,166 million (27%) increase in segment EBDA in 2013 versus 2012 resulted from higher earnings from our Natural Gas Pipelines, CO2, Products Pipelines and Terminals business segments. The
yearly increase in total segment EBDA was partially offset by a decrease in EBDA from our Kinder Morgan Canada business segment.
For the comparable years of 2012 and 2011, total segment EBDA increased $1,478 million (49%) in 2012; however, this overall increase:
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included a $662 million increase in EBDA from the effect of the certain items described in footnote (b) to the “-Results of Operations” table above; and
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excluded a $71 million decrease in EBDA from discontinued operations (as described in footnote (f) to the “-Results of Operations” table above).
After adjusting for these two items, the remaining $745 million (20%) increase in segment EBDA in 2012 versus 2011 resulted from higher earnings from all five of our reportable business segments, driven mainly by increases attributable to our Natural Gas Pipelines and CO2 business segments.
Natural Gas Pipelines
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(a)
2013 and 2012 amounts include increases of $111 million and $574 million, respectively, attributable to our drop-down asset groups for periods prior to our acquisition dates. 2013 amount also 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 $641 million increase in earnings, a $355 million increase in earnings and a $167 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 our previously held 50% equity interest in Eagle Ford to fair value; (ii) a $62 million increase in earnings attributable to our drop-down asset groups for periods prior to our acquisition dates; (iii) a $36 million gain from the sale of certain Gulf Coast offshore and onshore TGP supply facilities; (iv) a $16 million decrease in earnings related to derivative contracts, as described in footnote (a); and (v) a combined $1 million increase from other certain items. 2012 amount consists of a $344 million increase in earnings attributable to our drop-down asset groups for periods prior to our acquisition dates, and a combined $11 million increase from other certain items. 2011 amount consists of a $167 million loss from the remeasurement of our previously held 50% equity interest in KinderHawk to fair value.
(c)
Represents EBDA attributable to our FTC Natural Gas Pipelines disposal group. 2013 amount represents a loss from the sale of net assets. 2012 amount includes a combined loss of $829 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 and the Texas intrastate natural gas pipeline group. Volumes for acquired pipelines are included for all periods.
(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 our ownership share. Volumes for acquired pipelines are included for all periods.
The certain items described in the footnotes to the table above accounted for a $1,111 million increase in our Natural Gas Pipelines business segment’s EBDA (including discontinued operations) in 2013, and a $297 million decrease in segment EBDA in 2012, when compared to the respective prior year. The certain items also accounted for a $479 million decrease in segment revenues (including discontinued operations) in 2013, and a $574 million increase in segment revenues in 2012, when compared to the respective prior year. Following is information, including discontinued operations, related to the segment’s remaining (i) $962 million (70%) and $423 million (44%) increases in EBDA and (ii) $3,043 million (77%) increase and $293 million (7%) decrease in revenues in 2013 and 2012, when compared with the respective prior year:
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n/a - not applicable
(a)
Equity investment until May 1, 2013. On that date, as part of our Copano acquisition, we acquired the remaining 50% ownership interest that we did not already own. Prior to that date, we recorded earnings under the equity method of accounting, but we 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)
Represents amounts attributable to our FTC Natural Gas Pipelines disposal group.
The significant increases and decreases in our Natural Gas Pipelines business segment’s EBDA in the comparable years of 2013 and 2012 included the following:
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incremental earnings of $494 million from TGP, which we acquired from KMI effective August 1, 2012;
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incremental earnings of $284 million from EPNG, which we acquired 50% from KMI effective August 1, 2012, and 50% from KMI effective March 1, 2013;
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incremental earnings of $233 million from our Copano operations, which we acquired effective May 1, 2013 (but excluding Copano’s 50% ownership interest in Eagle Ford, which is included below with the 50% ownership interest we previously owned);
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incremental earnings of $63 million from our EP midstream assets, which we acquired 50% from KKR effective June 1, 2012, and 50% from KMI effective March 1, 2013;
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incremental earnings of $56 million (166%) from our now wholly-owned Eagle Ford natural gas gathering operations, due primarily to the incremental 50% ownership interest we 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;
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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 our 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;
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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
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a $26 million (32%) decrease from our 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-FTC Natural Gas Pipelines Disposal Group - Discontinued Operations” to our consolidated financial statements.
__________
n/a - not applicable
(a)
Equity investment until July 1, 2011. See Note (b).
(b)
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 our FTC Natural Gas Pipelines disposal group.
The significant increases and decreases in our Natural Gas Pipelines business segment’s EBDA in the comparable years of 2012 and 2011 included the following:
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incremental earnings of $344 million from our August 2012 drop-down asset group (our wholly-owned TGP and our 50%-owned EPNG), which we acquired from KMI effective August 1, 2012;
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incremental earnings of $58 million from our wholly-owned KinderHawk Field Services, LLC, due principally to the inclusion of a full year of operations in 2012 (we acquired the remaining 50% ownership interest in KinderHawk that we did not already own and began accounting for our investment under the full consolidation method effective July 1, 2011);
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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;
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a $31 million (131%) increase in equity earnings from our 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 our 50%-owned Eagle Ford, which initiated flow on its natural gas gathering system on August 1, 2011; and
▪
a $6 million (2%) decrease from our 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 our Kinder Morgan Interstate Gas Transmission pipeline system and our Trailblazer pipeline system decreased $29 million (33%) and $20 million (59%), 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
__________
(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.
(b)
2012 amount also includes a $7 million gain from the sale of our ownership interest in the Claytonville oil field unit.
(c)
Includes McElmo Dome and Doe Canyon sales volumes.
(d)
Represents 100% of the production from the field. We own 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 us, after royalties and outside working interests.
(f)
Includes all of our crude oil production properties.
(g)
Includes production attributable to leasehold ownership and production attributable to our ownership in processing plants and third party processing agreements.
Our CO2 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 $9 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 $16 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:
__________
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. Our 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 we 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 our 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, our 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
__________
(a)
2013, 2012 and 2011 amounts include decreases in earnings of $182 million, $33 million and $231 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 our 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.
(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 $149 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 our Products Pipelines business segment’s EBDA in 2013 compared to 2012 were attributable to the following:
▪
a $27 million (174%) increase from our transmix processing operations-due to higher margins on processing volumes, incremental earnings from third-party sales of excess renewable identification numbers (RINS) (generated through our 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, we now directly purchase incremental transmix volumes and sell incremental volumes of refined products, resulting in both higher revenues and higher costs of sales expenses;
▪
a $25 million (34%) increase from our 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 our 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 our 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 our 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;
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incremental earnings of $3 million from our 50% interest in Double Eagle Pipeline LLC-which gathers condensate and crude oil for Eagle Ford shale producers and which we acquired as part of our Copano acquisition effective May 1, 2013;
▪
a $7 million (3%) decrease from our 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 our Products Pipelines business segment’s EBDA in 2012 compared to 2011 were attributable to the following:
▪
a $22 million (43%) increase from our 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 our Kinder Morgan Crude & Condensate Pipeline, which began transporting crude oil and condensate volumes in October 2012;
▪
a $4 million (7%) increase from our 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 our 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 our 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, we now directly purchase incremental volumes of transmix and sell incremental volumes of refined products, resulting in both higher revenues and higher costs of sales expenses;
▪
a $9 million (3%) decrease from our 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
__________
(a)
2013, 2012 and 2011 amounts include an increase of $55 million, a decrease of $43 million, and an increase of $3 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 expense reimbursements; (iii) a $59 million increase in clean-up and repair expense, all related to 2012 hurricane activity at our New York Harbor and Mid-Atlantic terminals; and (iv) a $3 million increase in expense associated with the removal of certain physical assets at our 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 our Myrtle Grove, Louisiana, ITM facility. 2011 amount consists of a $5 million decrease in expense (reflecting tax savings) related to non-cash compensation expense allocated to us from KMI (however, we do not have any obligation, nor did we pay any amounts or realize any direct benefits related to this compensation expense), and a combined $2 million decrease from other certain items.
(b)
Volumes for acquired terminals are included for all periods and include our proportionate share of joint venture tonnage.
(c)
The ratio of our actual leased capacity to our estimated potential capacity.
Our Terminals business segment includes the operations of our petroleum, chemical and other liquids terminal facilities (other than those included in our Products Pipelines segment), and all of our coal, petroleum coke, fertilizer, steel, ores and other dry-bulk material services facilities. We group our bulk and liquids terminal operations into regions based on geographic location and/or primary operating function. This structure allows our 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 $98 million increase in segment EBDA in 2013, a $46 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 our Terminals’ EBDA in 2013 versus 2012 was driven by incremental contributions from our Gulf Liquids terminals, due primarily to higher liquids revenues from our 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 our Terminals 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 our 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, our 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 our 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 our Northeast terminal operations were driven by incremental contributions from our Carteret New Jersey liquids facility and our 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). Our Perth Amboy terminal benefited from higher year-over-year revenues, due mainly to additional and restructured customer contracts at higher rates.
Earnings from our Mid-Atlantic terminals were flat across both 2013 and 2012, as higher earnings from our Fairless Hills, Pennsylvania bulk terminal were offset by lower earnings and revenues from our 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 our Terminals 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 our materials handling, wholly-owned subsidiary, Kinder Morgan Materials Services (KMMS); and (ii) higher income tax expense.
__________
The overall increase in EBDA from our Terminals business segment in 2012 compared to 2011 was driven by higher contributions from the terminal facilities included in our Gulf Liquids, Mid-Atlantic and Northeast regions. The increase from our Gulf Liquids facilities was driven by higher warehousing revenues (as a result of new and renewed customer agreements at higher rates) at our Galena Park and Pasadena, Texas facilities, higher ethanol volumes through our Deer Park, Texas rail terminal, and higher overall gasoline throughput volumes. We also benefited from both higher capitalized overhead associated with the ongoing construction of our majority-owned Battleground Oil Specialty Terminal Company LLC terminal located on the Houston Ship Channel, and higher earnings from our crude oil storage operations located in Cushing, Oklahoma.
The year-to-year earnings increase from our Mid-Atlantic region resulted primarily from higher export coal shipments from our Pier IX terminal, and higher import steel and iron ore imports from our 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, our 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 our Northeast terminal operations was driven by higher contributions from our Staten Island terminal, due mainly to new and favorable contract changes. Despite being affected heavily by Hurricane Sandy in 2012, our liquids terminal in Carteret, New Jersey increased earnings primarily due to higher transfer and storage rates, and to new and renegotiated contracts. We also benefited from incremental earnings from our Philadelphia liquids terminal, due largely to new and restructured customer contracts at higher rates, and from our 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 our additional equity investment in the short-line railroad operations of Watco Companies, LLC (acquired in December 2011) and our 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 we owned the assets in 2011.
The remaining increases and decreases in our Terminals 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 our 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
__________
(a)
2013 amount includes both a $224 million gain from the sale of our 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 us from KMI (however, we do not have any obligation, nor did we pay any amounts related to this compensation expense).
(b)
Represents Trans Mountain pipeline system volumes.
Our Kinder Morgan Canada business segment includes the operations of our Trans Mountain and Jet Fuel pipeline systems, and until March 14, 2013, the effective date of sale, our 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:
__________
(a)
Equity investment; accordingly, we recorded earnings under the equity method of accounting. However, we sold our debt and equity investments in Express effective March 14, 2013.
The period-to-period decreases in earnings before depreciation, depletion and amortization expenses from Express were primarily due to both lower equity earnings and lower interest income resulting from the sale of our 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, we 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 our 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
__________
(a)
2013, 2012 and 2011 amounts include increases in expense of $49 million, $124 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 us from KMI (however, we do not have any obligation, nor did we pay any amounts related to this expense); (iii) a $9 million increase in expense attributable to our drop-down asset groups for periods prior to our acquisition dates; and (iv) a combined $4 million decrease in expense from other certain items. 2012 amount consists of a $110 million increase in expense attributable to our drop-down asset groups for periods prior to our acquisition dates (including $67 million of severance, retention and bonus expenses), 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 us from KMI; however, we do not have any obligation, nor did we pay any amounts related to this expense, and a combined $4 million increase in expense from other certain items.
(b)
2013 and 2012 amounts include increases in expense of $10 million and $68 million, respectively, related to the combined effect from certain items. 2013 amount consists of a $15 million increase in expense attributable to our drop-down asset groups for periods prior to our acquisition dates, and a $5 million decrease in expense associated with debt fair value adjustments recorded in purchase accounting for our Copano acquisition. 2012 amount consists of a $69 million increase in expense attributable to our drop-down asset groups for periods prior to our acquisition dates, and a combined $1 million decrease in expense from other certain items.
(c)
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 our 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.”
Items not attributable to any segment include general and administrative expenses, unallocable interest income and income tax expense, interest expense, and net income attributable to noncontrolling interests. Our general and administrative expenses include such items as unallocated salaries and employee-related expenses, employee benefits, payroll taxes, insurance, office supplies and rentals, unallocated litigation and environmental expenses, and shared corporate services-including accounting, information technology, human resources and legal services.
These expenses are generally not controllable by our business segment operating managers and therefore are not included when we measure business segment operating performance. For this reason, we do not specifically allocate our general and administrative expenses to our business segments. As discussed previously, we use segment EBDA internally as a measure of
profit and loss to evaluate segment performance, and each of our segment’s EBDA includes all costs directly incurred by that segment.
Combined, the certain items described in footnote (a) to the table above decreased our general and administrative expenses by $75 million in 2013, and increased our 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 our acquisition of the drop-down asset groups from KMI (effective August 1, 2012 and March 1, 2013), and for 2013 versus 2012, our acquisition of Copano (effective May 1, 2013). We 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 interest expense to arrive at one interest amount, and after taking into effect the certain items described in footnote (b) to the table above, our 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.
Our 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 we have made since the beginning of 2011. For more information on our capital expenditures, capital contributions, and acquisition expenditures, see “-Liquidity and Capital Resources.”
The weighted average interest rate on all of our 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 our 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 we assumed as part of the drop-down transactions.
We 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, and as of December 31, 2013, approximately 29% of our consolidated debt balances (excluding debt fair value adjustments) was 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. As of December 31, 2012, approximately 37% of our consolidated debt balances (excluding debt fair value adjustments) was subject to variable interest rates. For more information on our interest rate swaps, see Note 13 to our consolidated financial statements.
Liquidity and Capital Resources
General
As of December 31, 2013, we had $404 million of “Cash and cash equivalents”, a decrease of $125 million (24%) from December 31, 2012. We also had, as of December 31, 2013, approximately $1.5 billion of borrowing capacity available under our $2.7 billion senior unsecured revolving credit facility (discussed below in “-Short-term Liquidity”). We believe our cash position and our remaining borrowing capacity is adequate to allow us to manage our day-to-day cash requirements and anticipated obligations.
Our primary cash requirements, in addition to normal operating expenses, are for debt service, sustaining capital expenditures (those capital expenditures which do not increase the capacity or throughput), expansion capital expenditures and quarterly distributions to our common unitholders, Class B unitholder and general partner.
In general, we expect to fund:
▪
cash distributions and sustaining capital expenditures with existing cash and cash flows from operating activities;
▪
expansion capital expenditures and working capital deficits with retained cash (which may result from including i-units in the determination of cash distributions per unit but paying quarterly distributions on i-units in additional i-units rather than cash), proceeds from divestitures, additional borrowings (including commercial paper issuances), and the issuance of additional common units or the proceeds from purchases of additional i-units by KMR;
▪
interest payments with cash flows from operating activities; and
▪
debt principal payments, as such debt principal payments become due, with proceeds from divestitures, additional borrowings or by the issuance of additional common units or the proceeds from purchases of additional i-units by KMR.
In addition to our results of operations, our debt and capital balances are affected by our financing activities, as discussed below in “-Financing Activities.” Cash provided from our operations is fairly stable across periods since a majority of our cash generated is fee based from a diversified portfolio of assets and is not sensitive to commodity prices. However, in our CO2 business segment, while we hedge the majority of our oil production, we do have exposure to unhedged volumes, a significant portion of which are NGL.
Credit Ratings and Capital Market Liquidity
Our credit ratings affect our ability to access the public and private debt markets (including the commercial paper market), as well as the terms and pricing of our debt (see Part I, Item 1A “Risk Factors”). Based on our credit ratings as discussed below, we expect that our respective short-term liquidity needs will be met primarily through short-term borrowings. Nevertheless, our ability to satisfy financing requirements or fund planned capital expenditures (including 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.
Our debt ratings are as follows:
Short-term Liquidity
As of December 31, 2013, our principal sources of short-term liquidity were (i) our $2.7 billion senior unsecured revolving credit facility with a diverse syndicate of banks that matures May 1, 2018; (ii) our $2.7 billion short-term commercial paper program (which is supported by our credit facility, with the amount available for borrowing under our credit facility being reduced by our outstanding commercial paper borrowings and letters of credit); and (iii) cash from operations (discussed below in “-Cash Flow-Operating Activities”). The loan commitments under our revolving credit facility can be used to fund borrowings for general partnership purposes and as a backup for our commercial paper program. As of both December 31, 2013 and 2012, we had no outstanding credit facility borrowings.
Our outstanding short-term debt as of December 31, 2013 was $1,504 million, primarily consisting of (i) $979 million of outstanding commercial paper borrowings and (ii) $500 million in principal amount of 5.125% senior notes that mature November 15, 2014. We intend to refinance our 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. As of December 31, 2012, our short-term debt totaled $1,155 million.
We had a working capital deficit of $1,909 million as of December 31, 2013, and a working capital deficit of $870 million as of December 31, 2012. The overall $1,039 million (119%) unfavorable change from year-end 2012 was primarily due to (i) higher “Accrued contingencies,” due largely to certain transportation rate case liabilities being reclassified from long-term liabilities to short-term liabilities; (ii) a higher short-term debt balance, due primarily to higher net commercial paper borrowings; and (iii) lower “Assets held for sale,” due to the sale of our investments in the Express pipeline system effective March 14, 2013. 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 cash and cash equivalent balances as a result of debt or equity issuances (discussed below in “-Long-term Financing”).
We employ a centralized cash management program for our U.S.-based bank accounts that essentially concentrates the cash assets of our operating partnerships and their subsidiaries in joint accounts for the purpose of providing financial flexibility and lowering the cost of borrowing. Our centralized cash management program provides that funds in excess of the daily needs of our operating partnerships and their subsidiaries are concentrated, consolidated, or otherwise made available for use by other entities within our consolidated group. We 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, our cash and the cash of our subsidiaries is not concentrated into accounts of KMI or any company not in our consolidated group of companies, and KMI has no rights with respect to our cash except as permitted pursuant to our partnership agreement.
Furthermore, certain of our 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
In addition to our principal sources of short-term liquidity listed above, we could meet our cash requirements (other than distributions of cash from operations to our common unitholders, Class B unitholder and general partner) through issuing long-term debt securities or additional common units, or by utilizing the proceeds from purchases of additional i-units by KMR with the proceeds from issuances of KMR shares.
Our equity offerings consist of the issuance of additional common units or the issuance of additional i-units to KMR (which KMR purchases with the proceeds from the sale of additional KMR shares). As a publicly traded limited partnership, our common units are attractive primarily to individual investors, although such investors represent a small segment of the total equity capital market. We believe that some institutional investors prefer shares of KMR over our common units due to tax and other regulatory considerations, and we are able to access this segment of the capital market through KMR’s purchases of i-units issued by us with the proceeds from the sale of KMR shares to investors. For more information about our equity issuances during 2013, see Note 10 “Partners’ Capital-Equity Issuances-2013 Issuances” to our consolidated financial statements.
From time to time we issue long-term debt securities, often referred to as our senior notes. Our senior notes issued to date, generally have very similar terms, except for interest rates, maturity dates and prepayment premiums. All of our outstanding senior notes are unsecured obligations that rank equally with all of our other senior debt obligations. Our fixed rate senior notes provide that we may redeem the notes 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. As of December 31, 2013 and 2012, the aggregate principal amount of the various series of our senior notes was $15,600 million and $13,350 million, respectively.
In addition, from time to time our subsidiaries TGP, EPNG and Copano have issued long-term debt securities, often referred to as their senior notes. Most of the debt of our operating partnerships and subsidiaries is unsecured; however a modest amount of secured debt has been incurred by some of our operating partnerships and subsidiaries. As of December 31, 2013 and 2012, the total liability balance due on the various borrowings of our operating partnerships and subsidiaries (including senior notes issued by TGP, EPNG and Copano) was $3,335 million and $3,091 million, respectively.
To date, our debt balances have not adversely affected our operations, our ability to grow or our ability to repay or refinance our indebtedness. For additional information about our debt obligations and our debt-related transactions during 2013, see Note 8 “Debt” to our consolidated financial statements. For information about our interest rate risk, see Item 7A
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 we 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.
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, we often enter into fixed price swaps and/or futures contracts to guarantee or lock-in the sale price of our crude oil or the margin from the sale and purchase of our 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 we only enter into derivative contracts 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 we 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, our 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 us increased certainty with regard to our operating cash flows and helps us undertake further capital improvement projects, attain budget results and meet distribution targets to our partners. 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 income” 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 income” (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 our natural gas and crude oil 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, (i) a hypothetical 10% movement in underlying commodity natural gas prices would affect the estimated fair value of our natural gas derivatives by $15 million and $7 million, respectively and (ii) a hypothetical 10% movement in underlying commodity crude oil prices would affect the estimated fair value of our crude oil derivatives 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 our NGL derivatives by $5 million. As discussed above, we enter into our 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 and crude oil 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, we do not have 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 our fixed rate debt until we would be required to refinance such debt.
As of December 31, 2013 and 2012, the carrying values of our fixed rate debt (including our debt fair value adjustments) were $20,060 million and $17,972 million, respectively. These amounts compare to, as of December 31, 2013 and 2012, fair values of $20,482 million and $19,651 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 $795 million and $690 million, respectively, in the fair values of these instruments.
The carrying value and fair value of our variable rate debt, excluding the value of interest rate swap agreements (discussed following), was $1,068 million as of December 31, 2013 and $788 million as of December 31, 2012. As of December 31, 2013 and 2012, we were a party to interest rate swap agreements with notional principal amounts of $4,675 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 46 basis points in 2013 and 42 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 a change of approximately $27 million in both our 2013 and 2012 annual pre-tax earnings.
We entered into our interest rate swap agreements for the purpose of transforming a portion of the underlying cash flows related to our 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 our fixed rate debt varies with changes in the market rate of interest, we enter into swap agreements 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 our fixed rate debt due to market rate changes.
We monitor our mix of fixed rate and variable rate debt obligations in light of changing market conditions and from time to time may alter that mix by, for example, refinancing balances outstanding under our 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, we attempt to maintain an overall target mix of approximately 50% fixed rate debt and 50% variable rate debt.
For more information on our interest rate risk management and on our interest rate swap agreements, see Note 13 to our consolidated financial statements.
Item 8.
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
105.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A.
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 10% of our total revenues for 2013 and 14% 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.
Item 9B. Other Information.
None.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance
Directors and Executive Officers of our General Partner and its Delegate
Set forth below is information concerning the directors and executive officers of our general partner and KMR, the delegate of our general partner. All directors of our general partner are elected annually by, and may be removed by, KMI as its sole common shareholder, and all directors of KMR are elected annually by, and may be removed by, our general partner as the sole holder of KMR’s voting shares. All officers of our general partner and all officers of KMR serve at the discretion of the board of directors of our general partner.
Richard D. Kinder is Director, Chairman and Chief Executive Officer of KMR, Kinder Morgan G.P., Inc., and KMI. Mr. Kinder has served as Director, Chairman and Chief Executive Officer of KMR since its formation in February 2001. He was elected Director, Chairman and Chief Executive Officer of the predecessor of KMI in October 1999. He was elected Director, Chairman and Chief Executive Officer of Kinder Morgan G.P., Inc. in February 1997. He also served as Chief Manager, and as a member of the Board of Managers, of Kinder Morgan Holdco LLC from May 2007 until February 2011, and continued in the role of Chairman and Chief Executive Officer of KMI upon its conversion. In May 2012, he was elected as a Director, Chairman and appointed as Chief Executive Officer of the general partner of El Paso Pipeline Partners, L.P. Mr. Kinder’s experience as Chief Executive Officer of KMI, KMR, Kinder Morgan G.P., Inc. and the general partner of El Paso Pipeline Partners, L.P., provide him with a familiarity with our strategy, operations and finances that can be matched by no one else. In addition, we believe that with Mr. Kinder’s significant direct and indirect equity ownership in us, his economic interests are aligned with those of our other equity investors.
Steven J. Kean is Director, President and Chief Operating Officer of KMR, Kinder Morgan G.P., Inc., and KMI. Mr. Kean was elected Director and President of KMR, Kinder Morgan G.P., Inc. and KMI in March 2013, and was elected Chief Operating Officer of KMR, Kinder Morgan G.P., Inc. and the predecessor of KMI in January 2006. He served as Executive Vice President of KMR and Kinder Morgan G.P., Inc. from January 2006 to March 2013. He also served as President, Natural Gas Pipelines of KMR and Kinder Morgan G.P., Inc. from July 2008 to November 2009. He also served as Chief Operating Officer, and as a member of the Board of Managers, of Kinder Morgan Holdco LLC from May 2007 until February 2011, and continued in the role of Director, Executive Vice President and Chief Operating Officer of KMI upon its conversion. He has served in various management roles for the Kinder Morgan companies since 2002. In May 2012, he was elected as a director and appointed as Executive Vice President and Chief Operating Officer of the general partner of El Paso Pipeline Partners, L.P. Mr. Kean received his Juris Doctor from the University of Iowa in May 1985 and received a Bachelor of Arts degree from Iowa State University in May 1982. Mr. Kean’s experience as one of our executives since 2002 provides him valuable management and operational expertise and a thorough understanding of our business operations and strategy.
Ted A. Gardner is a Director of KMR and Kinder Morgan G.P., Inc. Mr. Gardner was elected Director of KMR and Kinder Morgan G.P., Inc. in July 2011 to fill the vacancy left by Mr. C. Berdon Lawrence, who resigned from the KMR and Kinder Morgan G.P., Inc. boards of directors that same month. Since June 2005, Mr. Gardner has been a Managing Partner of Silverhawk Capital Partners in Charlotte, North Carolina. Formerly, he was a Director of the predecessor of KMI from 1999 to
2007, and was a Director of Encore Acquisition Company from 2001 to 2010. Mr. Gardner also served as Managing Partner of Wachovia Capital Partners and was a Senior Vice President of Wachovia Corporation from 1990 to June 2003. He is currently a Director of Summit Materials Holdings, Spartan Energy Partners and Athlon Energy Inc. We believe Mr. Gardner’s prior management, business and leadership experience, and his previous board experience with the predecessor of KMI, provides us with the perspectives and judgment necessary to guide our business strategies, thereby qualifying him to serve as a director.
Gary L. Hultquist is a Director of KMR and Kinder Morgan G.P., Inc. Mr. Hultquist was elected Director of KMR upon its formation in February 2001. He was elected Director of Kinder Morgan G.P., Inc. in October 1999. Since 1995, Mr. Hultquist has been the Managing Director of Hultquist Capital, LLC, a San Francisco-based strategic and merger advisory firm. Since 2009, Mr. Hultquist has also been Chairman of the board of directors of Prairie Bankers, LLC, a data center development company, and a Principal of NewCap Partners Inc., a FINRA-registered broker-dealer and investment bank, specializing in technology, mergers and acquisitions. In February 2014, Mr. Hultquist was appointed to the board of directors of Resolute Energy Corporation. Mr. Hultquist has over 20 years of experience as an investment banker and over 15 years’ experience practicing law. This combination of experience provides him an understanding of the business and legal risks applicable to us.
Perry M. Waughtal is a Director of KMR and Kinder Morgan G.P., Inc. Mr. Waughtal was elected Director of KMR upon its formation in February 2001. Mr. Waughtal was elected Director of Kinder Morgan G.P., Inc. in April 2000. Since 1994, Mr. Waughtal has been the Chairman of Songy High Roads, LLC (formerly Songy Partners Limited), an Atlanta, Georgia based real estate investment company. Mr. Waughtal was a Director of HealthTronics, Inc. from 2004 to 2009. Mr. Waughtal was elected as Chairman of the Board of Highland Resources, LLC, a family-owned real estate investment company, in October 2013. We believe Mr. Waughtal’s 30 years of experience with Hines Interests Limited Partnership, a privately owned, international real estate firm, including as Vice Chairman of development and operations and Chief Financial Officer, and 15 years of experience as Chairman of Songy High Roads, LLC (formerly Songy Partners Limited) provide him with planning, management, finance and accounting experience with, and an understanding of, large organizations with capital-intensive projects analogous to the types in which we typically engage, thereby qualifying him to serve as a director.
Kimberly A. Dang is Vice President and Chief Financial Officer of KMR, Kinder Morgan G.P., Inc., and KMI. Mrs. Dang was elected Chief Financial Officer of KMR, Kinder Morgan G.P., Inc. and the predecessor of KMI in May 2005. She was elected Vice President, Investor Relations of KMR, Kinder Morgan G.P., Inc. and KMI in July 2002 and served in that role until January 2009. She also served as Chief Financial Officer of Kinder Morgan Holdco LLC from May 2007 until February 2011, and continued in the role of Vice President and Chief Financial Officer of KMI upon its conversion. She has served in various management roles for the Kinder Morgan companies since 2001. She has served as Vice President of the general partner of El Paso Pipeline Partners, L.P. since May 2012, and served as Chief Financial Officer from May 2012 to March 2013. Mrs. Dang received a Masters in Business Administration degree from the J.L. Kellogg Graduate School of Management at Northwestern University and a Bachelor of Business Administration degree in accounting from Texas A&M University.
David R. DeVeau is Vice President and General Counsel of KMR, Kinder Morgan G.P., Inc. and KMI. Mr. DeVeau was elected Vice President and General Counsel of KMR, Kinder Morgan G.P., Inc. and KMI in March 2013. Mr. DeVeau joined Kinder Morgan in 2001 as an Assistant General Counsel, and he served as Deputy General Counsel of KMR, Kinder Morgan G.P., Inc. and the predecessor of KMI from 2006 to March 2013. Mr. DeVeau received a J.D. degree from The Dickinson School of Law, Pennsylvania State University, and a bachelor’s degree, cum laude, in political science from Norwich University.
Thomas A. Martin is Vice President (President, Natural Gas Pipelines) of KMR, Kinder Morgan G.P., Inc and KMI. Mr. Martin was elected Vice President (President, Natural Gas Pipelines) of KMR and Kinder Morgan G.P., Inc. in November 2009 and was elected Vice President (President, Natural Gas Pipelines) of KMI in 2012. Mr. Martin served as President, Texas Intrastate Pipeline Group from May 2005 until November 2009, and has served in various management roles for the Kinder Morgan companies since 2003. In May 2012, he was elected as a director and appointed as Vice President (President, Natural Gas Pipelines) of the general partner of El Paso Pipeline Partners, L.P. Mr. Martin received a Bachelor of Business Administration degree from Texas A&M University.
Ronald G. McClain is Vice President (President, Products Pipelines) of KMR and Kinder Morgan G.P., Inc. Mr. McClain was elected Vice President (President, Products Pipelines) of KMR and Kinder Morgan G.P., Inc. in March 2013. From 2005 to March 2013, Mr. McClain served as Vice President of operations and engineering for Kinder Morgan’s Products Pipelines business segment. Mr. McClain joined Kinder Morgan over 30 years ago and, prior to 2005, held various operations and engineering positions in Kinder Morgan’s Natural Gas Pipelines business segment. Mr. McClain holds a bachelor’s degree in computer science from Aurora University.
Dax A. Sanders is Vice President, Corporate Development of KMR, Kinder Morgan G.P., Inc. and KMI. Mr. Sanders was elected Vice President, Corporate Development of KMR and Kinder Morgan G.P., Inc. in March 2013. Mr. Sanders has served as a Vice President within Kinder Morgan’s Corporate Development group since 2009. From 2006 until 2009, Mr. Sanders was Vice President of Finance for Kinder Morgan Canada. Mr. Sanders joined Kinder Morgan in 2000, and from 2000 to 2006 served in various finance and business development roles within Corporate Development, Investor Relations, Natural Gas Pipelines business segment and Products Pipeline business segment, with the exception of a two-year period while he attended business school. Mr. Sanders holds a master’s degree in business administration from the Harvard Business School and a master’s and a bachelor’s degree in accounting from Texas A&M University. He is also a Certified Public Accountant in the State of Texas.
John W. Schlosser is Vice President (President, Terminals) of KMR and Kinder Morgan G.P., Inc. Mr. Schlosser was elected Vice President (President, Terminals) of KMR and Kinder Morgan G.P., Inc. in March 2013. Mr. Schlosser was named Senior Vice President and Chief Commercial Officer of Kinder Morgan’s Terminals group in 2010, and previously served as Vice President of Sales and Business Development for Kinder Morgan’s Terminals group since he joined Kinder Morgan in 2001 in connection with Kinder Morgan’s purchase of the U.S. pipeline and terminal assets of the GATX Corporation, where he served as Vice President of Sales. Mr. Schlosser has more than 27 years of experience in commodity transportation and logistics, business development and sales, sales management and operations. Mr. Schlosser holds a Bachelor of Science degree from Miami University, Oxford, Ohio.
Lisa M. Shorb is Vice President, Human Resources, Information Technology and Administration of KMR, Kinder Morgan G.P., Inc., and KMI. She was elected Vice President, Human Resources, Information Technology and Administration of KMR, Kinder Morgan G.P., Inc., and KMI in January 2014. Previously, Ms. Shorb served as Vice President of Procurement and Administration for the Kinder Morgan companies since June 2002. Ms. Shorb joined Kinder Morgan over 29 years ago and prior to 2002 served in various roles in the commercial and gas measurement areas. Ms. Shorb received a Master of Science degree in Geology from Duke University and a Bachelor of Science degree in Geology from the University of Dayton.
James P. Wuerth is Vice President (President, CO2) of KMR and Kinder Morgan G.P., Inc. Mr. Wuerth was elected Vice President (President, CO2) of KMR and Kinder Morgan G.P., Inc. in March 2013. Prior to March 2013, Mr. Wuerth served as Vice President of Finance and Accounting for Kinder Morgan’s CO2 business segment since joining Kinder Morgan in 2000. He has more than 30 years of oil and gas industry experience in accounting, operations, field development and business development. Prior to joining Kinder Morgan, he worked for Shell Oil Company. Mr. Wuerth holds a bachelor’s degree in accounting from the University of Washington in Seattle and is a Certified Public Accountant in the State of Texas.
Corporate Governance
We have a separately designated standing audit committee established in accordance with Section 3(a)(58)(A) of the Securities Exchange Act of 1934 comprised of Messrs. Gardner, Hultquist and Waughtal. Mr. Waughtal is the chairman of the audit committee and has been determined by the board to be an “audit committee financial expert.” The board has determined that all of the members of the audit committee are independent as described under the relevant standards.
We have not, nor has our general partner nor KMR, made, within the preceding three years, contributions to any tax-exempt organization in which any of our or KMR’s independent directors serves as an executive officer that in any single fiscal year exceeded the greater of $1.0 million or 2% of such tax-exempt organization’s consolidated gross revenues.
We make available free of charge within the “Investors” information section of our Internet website, at www.kindermorgan.com, the governance guidelines, the charters of the audit committee, compensation committee and nominating and governance committee, and our code of business conduct and ethics (which applies to senior financial and accounting officers and the chief executive officer, among others). We intend to disclose any amendments to our code of business conduct and ethics that would otherwise be disclosed on Form 8-K and any waiver from a provision of that code granted to our executive officers or directors that would otherwise be disclosed on Form 8-K on our website within four business days following such amendment or waiver. The information contained on or connected to our website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC.
Interested parties may contact our lead director (Mr. Hultquist, discussed in Item 13), the chairpersons of any of the board’s committees, the independent directors as a group or the full board by mail to Kinder Morgan Management, LLC, 1001 Louisiana Street, Suite 1000, Houston, Texas 77002, Attention: General Counsel, or by e-mail within the “Contact Us” section of our Internet website, at www.kindermorgan.com. Any communication should specify the intended recipient.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16 of the Securities Exchange Act of 1934 requires our directors and officers, and persons who own more than 10% of a registered class of our equity securities, to file initial reports of ownership and reports of changes in ownership with the SEC. Such persons are required by SEC regulation to furnish us with copies of all Section 16(a) forms they file.
Based solely on our review of the copies of such forms furnished to us and written representations from our executive officers and directors, we believe that all Section 16(a) filing requirements were met during 2013, other than an inadvertently late Form 4 filed on January 31, 2014 by Mr. Wuerth to report a purchase of KMP common units that occurred on December 13, 2013.
Item 11.
Item 11. Executive Compensation.
As is commonly the case for publicly traded limited partnerships, we have no officers. Under our limited partnership agreement, Kinder Morgan G.P., Inc., as our general partner, is to direct, control and manage all of our activities. Pursuant to a delegation of control agreement, Kinder Morgan G.P., Inc. has delegated to KMR the management and control of our business and affairs to the maximum extent permitted by our partnership agreement and Delaware law, subject to our general partner’s right to approve certain actions by KMR. The executive officers and directors of Kinder Morgan G.P., Inc. serve in the same capacities for KMR, and certain of those executive officers also serve as executive officers of KMI.
Except as indicated otherwise, all information in this report with respect to compensation of executive officers describes the total compensation received by those persons in all capacities for services rendered to us, our subsidiaries and our affiliates, including KMI. In this Item 11, “we,” “our” or “us” refers to Kinder Morgan Energy Partners, L.P. and, where appropriate, Kinder Morgan G.P., Inc., KMR, and KMI.
Compensation Discussion and Analysis
Program Objectives
We seek to attract and retain executives who will help us achieve our primary business strategy objective of growing the value of our portfolio of businesses for the benefit of our unitholders. To help accomplish this goal, we have designed an executive compensation program that rewards individuals with competitive compensation that consists of a mix of cash, benefit plans and long-term compensation, with a majority of executive compensation consisting of the “at-risk” annual cash bonus and long-term incentive compensation.
The key objectives of our executive compensation program are to attract, motivate and retain executives who will advance our overall business strategies and objectives to create and return value to our unitholders. We believe that an effective executive compensation program should link total compensation to financial performance and to the attainment of short-term and long-term strategic, operational, and financial objectives. We believe operational objectives should take into account adherence to and promotion of our Code of Business Conduct and Ethics and our Environmental Health and Safety Policy Statement. We also believe it should provide competitive total compensation opportunities at a reasonable cost. In designing our executive compensation program, we believe that our executives should have a much greater portion of their overall compensation at-risk and linked to long-term shareholder value than do our other employees. Consequently, we have tried to establish the at-risk and long-term incentive portions of our executives’ total compensation at levels that recognize their much increased level of responsibility and their ability to influence business results.
From 2007 through 2012, our executive compensation program was principally composed of the following two elements: (i) base cash salary; and (ii) possible annual cash bonus (reflected in the Summary Compensation Table below as Non-Equity Incentive Plan Compensation). In 2013, we added a long-term incentive component to our executives’ compensation, in the form of restricted KMI stock granted under KMI’s 2011 Stock Incentive Plan.
In addition, we believe that the compensation of our Chief Executive Officer, Chief Financial Officer and the other executives named in the Summary Compensation Table below (collectively referred to in this Item 11 as our named executive officers), should be directly and materially tied to the financial performance of KMI and us, and should be aligned with the interests of our unitholders. Therefore, the majority of our named executive officers’ compensation is allocated to the “at-risk” portion of our compensation program-the annual cash bonus and the long-term incentive restricted stock grants.
While we are not required to solicit an advisory vote of our unitholders on our executive compensation, KMI is required to do so. In 2012, KMI’s shareholders overwhelmingly voted to approve (with an almost 97% approval rate), on an advisory
basis, the compensation of KMI’s then named executive officers. We believe the result of that vote is an affirmation of our compensation policies and practices.
Our compensation is determined without the use of any compensation consultants. Nevertheless, we annually compare our executive compensation components with market information, consisting of third-party surveys in which we participate. The surveys we use in reviewing our executive compensation consist of the Towers Watson Executive Survey and the Aon Hewitt Executive Survey. Over 400 companies participate in each survey. The purpose of this comparison is to ensure that our total compensation package operates effectively, remains both reasonable and competitive with the energy industry, and is generally comparable to the compensation offered by companies of similar size and scope to ours. We also keep abreast of current trends, developments, and emerging issues in executive compensation, and if appropriate, will obtain advice and assistance from outside legal, compensation or other advisors.
We have endeavored to design our executive compensation program and practices with appropriate consideration of all tax, accounting, legal and regulatory requirements. Section 162(m) of the Internal Revenue Code limits the deductibility of certain compensation for executive officers to $1,000,000 of compensation per year; however, if specified conditions are met, certain compensation may be excluded from consideration of the $1,000,000 limit. Since the bonuses paid to our executive officers were paid under KMI’s Annual Incentive Plan as a result of reaching designated financial targets established by KMI’s and KMR’s compensation committees, we expect that all compensation paid to our executives would qualify for deductibility under federal income tax rules. Though we are advised that limited partnerships, such as us, are not subject to section 162(m), we have chosen to generally operate as if this code section does apply to us as a measure of appropriate governance.
Compensation Designed to Reward Performance
Our executive compensation program is designed to reward individuals for advancing our business strategies and the interests of our stakeholders, and to deter engaging in any detrimental activities, such as performing services for a competitor, disclosing confidential information or violating appropriate business conduct standards. Each executive is held accountable to uphold and comply with company guidelines, which require the individual to maintain a discrimination-free workplace, to comply with the law, and to maintain high standards of operating safety and environmental protection.
Unlike many companies, we have no executive perquisites, supplemental executive retirement, non-qualified supplemental defined benefit/contribution, deferred compensation or split-dollar life insurance programs for our executive officers. We have no executive company cars or executive car allowances nor do we pay for financial planning services. Additionally, we do not own any corporate aircraft, and we do not pay for executives to fly first class. We believe that this area of our overall compensation package is below competitive levels for comparable companies; however, we have no current plans to change our policy of not offering such executive benefits or perquisite programs.
We do not have employment agreements or special severance arrangements with our executive officers. Although one of our affiliated companies entered into severance agreements with eleven of our then executive officers in connection with KMI’s 2011 initial public offering those severance agreements with any of our current executive officers, as well as Richard D. Kinder’s 1999 employment agreement, were terminated August 1, 2013. Our executive officers are now eligible for severance under the same plan as our other non-union U.S. based employees.
At his request, Mr. Kinder receives $1 of base salary per year from KMI. Additionally, Mr. Kinder has requested that he receive no annual bonus, equity, or other compensation from us or any of our affiliates. Mr. Kinder does not have any deferred compensation, supplemental retirement or any other special benefit, compensation or perquisite arrangement with us, and each year, Mr. Kinder reimburses us for his portion of health care premiums and parking expenses.
In 2013, Mr. Kean made a similar request to Mr. Kinder to change his annual base salary to $1. Mr. Kean also requested that he receive no annual bonus from us or any of our affiliates. As a result, Mr. Kean’s total compensation consists of a restricted stock grant received in 2013 which is subject to six-year cliff vesting, dividend equivalents paid on that restricted stock, and benefits available to our U.S. employees generally (such as healthcare, life insurance and 401k plan benefits). There are no plans at this time to grant additional restricted stock to Mr. Kean until the vesting terms of his 2013 grant have been met.
Elements of Compensation
As outlined above, our 2013 executive compensation program is principally composed of three elements: (i) a base cash salary; (ii) a possible annual cash bonus and (iii) long-term incentive compensation in the form of restricted KMI stock. KMR’s compensation committee reviews and approves annually the financial goals and objectives that are relevant to the compensation of our named executive officers.
In 2013, the KMR compensation committee solicited information from Mr. Kinder and James E. Street (our then Vice President, Human Resources, Information Technology and Administration-Mr. Street retired in January 2014, and Ms. Lisa Shorb has been promoted to the Vice President, Human Resources, Information Technology and Administration position) regarding the performance of Mr. Kean as President and Chief Operating Officer. Similarly, the compensation committee solicited information from Messrs. Kinder, Kean and Street with respect to the performance of our other named executive officers. The compensation committee also obtained information from Mr. Street with respect to compensation of comparable positions of responsibility at comparable companies. All of this information was taken into account by the compensation committee, which made final determinations regarding compensation of the named executive officers. No named executive officer reviewed his or her own performance or approved his or her own compensation.
Furthermore, if any of our general partner’s or KMR’s executive officers is also an executive officer of KMI or its other subsidiaries, including EPB’s general partner, the compensation determination or recommendation may be with respect to his or her (i) compensation to be received from each of KMI, KMR, and our general partner; or alternatively (ii) the aggregate compensation to be received from and allocated among KMR and our general partner, on the one hand, and KMI and its other subsidiaries, on the other hand.
Base Salary
Base salary is paid in cash. In January 2013, the compensation committee increased the annual base salary cap for our executive officers from $300,000 to $400,000. However, the maximum base salary that any of our executives received in 2013 was $325,000. Additionally, we expect to only increase our executives’ salaries to a maximum of $350,000 for 2014, and we do not expect any of our executives’ annual base salaries to reach the cap for at least two more years. As noted above, our Chairman and Chief Executive Officer and our President and Chief Operating Officer each receive $1 of annual base salary. We continue to believe that, even at the $400,000 cap, our executive officers’ base salaries would be below annual base salaries for executives in similar positions and with similar responsibilities at companies of comparable size and scope, based upon independent salary surveys in which we participate.
Possible Annual Cash Bonus (Non-Equity Cash Incentive)
Commencing with bonus awards for the 2011 bonus year, KMI’s board of directors approved a new Annual Incentive Plan (referred to in this discussion as the Annual Incentive Plan or the Plan). The overall purpose of the Annual Incentive Plan is to increase our executive officers’ and our employees’ personal stake in the continued success of KMI, and us, by providing to them additional incentives through the possible payment of annual cash bonuses.
The plan consists of two components: the executive plan component and the non-executive plan component. All employees of KMI and its subsidiaries, including KMGP Services Company, Inc., are eligible to participate in the plan (except for employees covered by collective bargaining, agreements that do not expressly provide for eligibility). Our Chairman and Chief Executive Officer and all employees who report directly to the Chairman, including all of the named executive officers, are eligible for the executive plan component; however, as stated above, Messrs. Kinder and Kean have elected not to participate. All other U.S. and Canadian eligible employees are eligible for the non-executive plan component.
Under the plan, a pool of bonus dollars is established at the beginning of each year for annual cash bonuses that may be paid to our executive officers and other employees, depending on whether KMI and its subsidiaries (including us) meet certain financial performance objectives (as discussed below). If the financial performance objectives are met, the budgeted pool of bonus dollars is further assessed and potentially increased if the financial performance objectives are exceeded. The budgeted pool of bonus dollars also may be adjusted upward or downward based on KMI’s and its subsidiaries’ overall performance in other areas, including safety and environmental goals and regulatory compliance.
At or before the start of each calendar year (or later, to the extent allowed under Internal Revenue Code regulations), financial performance objectives based on one or more of the criteria set forth in the plan are established by KMR’s compensation committee. In addition, the compensation committee sets the bonus opportunities available to each executive officer (see table “Grants of Plan-Based Awards”). If none of the financial performance objectives were met, no bonus opportunity would be available to the named executive officers. The maximum payout to any individual under the plan for any year is $3 million. The compensation committee may reduce the amount of the bonus actually paid to any executive officer from the amount of any bonus opportunity open to such executive officer. Because payments under the plan for our executive officers are determined by comparing actual performance to the performance objectives established each year for eligible executive officers chosen to participate for that year, it is not possible to accurately predict any amounts that will actually be paid under the executive portion of the plan over the life of the plan.
Three financial performance objectives were set for 2013 under both the executive plan component and the non-executive plan component. The three financial performance objectives were:
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$5.28 in cash distributions per common unit by us;
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$1.57 in cash dividends per share by KMI; and
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$2.55 in cash distributions per unit by EPB.
A fourth objective, which could potentially decrease or increase the budgeted pool of bonus dollars for 2013, was to achieve our environmental, health, and safety performance objectives by: (i) beating industry average incident rates; (ii) improving incident rates compared to our previous three-year averages; and (iii) experiencing no significant incidents in our operations or expansions.
The compensation committee set maximum bonus opportunities under the plan for 2013 for the executive officers at dollar amounts in excess of those which were expected to actually be paid under the plan. In fact, while achievement of the financial performance objectives sets the maximum bonus opportunity for each executive officer, the compensation committee has never awarded the maximum bonus opportunity to a current named executive officer. At the end of 2013, the extent to which the financial performance objectives had been attained and the extent to which the bonus opportunity had been earned under the formula previously established by KMR’s compensation committee was determined. For 2013:
▪
we paid $5.33 in cash distributions per common unit;
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KMI paid $1.60 in cash dividends per share; and
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EPB paid $2.55 in cash distributions per unit.
Based on the above, the KMR compensation committee approved approximately 99% of the total 2013 budgeted cash bonus opportunity be earned and funded under the plan. The approved funding level includes any premium pay calculations for bonus awards paid to non-exempt employees. Payout amounts to our named executive officers for 2013 (paid in 2014) were below this level and are set forth in the Summary Compensation Table in the column entitled “Non-Equity Incentive Plan Compensation.”
The 2013 bonuses for our executive officers were overwhelmingly based on whether the established financial performance objectives were met. The compensation committee also considered, in a purely subjective manner, how well the executive officer performed his or her duties during the year. Information was solicited from relevant members of senior management regarding the performance of our named executive officers (described following), and determinations and recommendations were made at the regularly scheduled first quarter board and compensation committee meetings held in January 2014. Other factors considered by the compensation committee primarily consisted of the amount of the bonus paid to the executive officer in the prior year and market data about compensation of comparable positions of responsibility at comparable companies, consisting of the compensation surveys referred to above. With respect to using these other factors in assessing performance, KMR’s compensation committee did not find it practicable to, and did not, use a “score card” or quantify or assign relative weight to the specific criteria considered. The amount of a downward adjustment, subject to the maximum bonus opportunity that was established at the beginning of the year, was not subject to a formula. Specific aspects of an individual’s performance were not identified in advance. Rather, adjustments were based on KMR’s compensation committee’s judgment and input from Mr. Kinder and Mr. Kean, giving consideration to the totality of the record presented, including the individual’s performance and the magnitude of any other positive or negative factors.
For a discussion of effects under the plan of death, disability, termination of employment or a change in control of KMI, please read “Potential Payments upon Death, Disability, Termination or a Change in Control.”
Long-Term Incentive Compensation
The Kinder Morgan, Inc. 2011 Stock Incentive Plan was approved by KMI’s pre-IPO shareholders and was effective as of January 1, 2011. Prior to 2013, no awards were made to our executive officers under this plan because, in connection with KMI’s going-private transaction, members of our management were awarded Kinder Morgan Holdco LLC Class A-1 and Class B units and had agreed to forego any long-term executive compensation until the investment funds advised by or affiliated with Goldman Sachs & Co., Highstar Capital LP, The Carlyle Group and Riverstone Holdings LLC which owned interests in KMI at the time, collectively referred to as the “Sponsor Investors,” sold their interests in KMI or converted their Class A shares into Class P shares of KMI. In connection with KMI’s IPO, the Class B units were converted into KMI Class B shares, and the Class A-1 units were converted into KMI Class C shares. As of December 26, 2012, the Sponsor Investors had sold their
interests in KMI or converted their Class A shares into Class P shares, and as a result, all Class B shares and Class C shares had converted into Class P shares.
Accordingly, in 2013, the compensation committee granted long-term incentive compensation to our named executive officers (other than Mr. Kinder) in the form of restricted KMI stock under KMI’s 2011 Stock Incentive Plan. All awards granted are subject to multi-year cliff vesting schedules of approximately six years during which the named executive officers are not expected to receive additional equity incentive grants (see “Grants of Plan Based Awards” table for details). In connection with his 2013 grant of restricted stock, Mr. Kean forfeited participation in the 2013 Annual Incentive Plan and decreased his annual base salary to $1 per year. Mr. Kinder did not receive an award under the plan in 2013, and we do not expect that he will receive any awards under the plan in the future. There are no plans at this time to grant additional shares until the vesting terms have been met.
For a discussion of effects under the Stock Incentive Plan of death, disability, termination of employment or a change in control of KMI, please read “Potential Payments upon Death, Disability, Termination or a Change in Control.”
Other Compensation
Kinder Morgan Savings Plan. The Kinder Morgan Savings Plan is a defined contribution 401(k) plan. The Kinder Morgan savings plan permits eligible employees of KMI and those of KMGP Services Company, Inc., including the named executive officers, to contribute between 1% and 50% of base compensation, on a pre-tax or Roth 401(k) basis, into participant accounts. For more information on this plan, see Note 9 “Employee Benefits-Kinder Morgan Savings Plan” to our consolidated financial statements.
Kinder Morgan Retirement Plan. Employees of KMI and KMGP Services Company, Inc., including the named executive officers, are also eligible to participate in the Kinder Morgan Retirement Plan (Plan), a cash balance plan. Employees accrue benefits through a Personal Retirement Account (PRA) in the Plan. Prior to 2013, KMI allocated contribution credits equivalent to 3% of eligible compensation every pay period to participants’ PRA. Beginning January 1, 2013, KMI began allocating contribution credits of 4% or 5% of eligible compensation every pay period to participants’ PRA based on age and years of eligible service as of December 31 of the prior year. Interest is credited to the PRA at the 5-year U.S. Treasury bond rate published in the Internal Revenue Bulletin for the November of the prior year, plus 0.25%. Employees become 100% vested in the plan after three years and may take a lump sum distribution upon termination of employment or retirement.
The following table sets forth the estimated actuarial present value of each named executive officer’s accumulated pension benefit as of December 31, 2013, under the provisions of the Cash Balance Retirement Plan. With respect to our named executive officers, the benefits were computed using the same assumptions used for financial statement purposes, assuming current remuneration levels without any salary projection, and assuming participation until normal retirement at age 65. These benefits are subject to federal and state income taxes, where applicable, but are not subject to deduction for social security or other offset amounts.
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(a)
The present values in the Pension Benefits table are current year-end balances.
(b)
Mr. Kinder has elected to not participate under the plan.
Potential Payments upon Death, Disability, Termination or a Change in Control
Our named executive officers are entitled to certain benefits in the events of death, disability, termination of employment or a change in control of KMI. The plans or agreements and circumstances triggering such benefits are described below.
Annual Incentive Plan. The Annual Incentive Plan provides the KMI compensation committee with discretion to take action that it deems appropriate with respect to outstanding awards upon a change in control (as defined below); if, however, in connection with a change in control, Mr. Kinder is no longer our Chairman:
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each participant under the executive component of the plan will be deemed to have earned 100% of the bonus opportunity available to him or her, unless the compensation committee has previously determined that the participant should receive a lesser percentage of the bonus opportunity;
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each participant under the non-executive component of the plan will receive an award equal to the award most recently paid to such participant under the plan; and
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the awards to executive and non-executive participants will be paid in a cash lump sum within 30 days after the change in control.
“Change in control” as defined under the plan means (i) the acquisition of securities representing 50% or more of the voting power of KMI by any person other than a permitted holder (as defined below); (ii) a sale, merger or other business combination after which the voting securities of KMI outstanding immediately before such transaction represent less than 50% of the voting securities of KMI outstanding after the such transaction; (iii) the sale of all or substantially all of the assets of KMI, other than to an entity of which more than 50% of the voting power is held by permitted holders (as defined below); (iv) for reasons other than normal retirement, death or disability, changes to the majority of the KMI board of directors during any period of two consecutive years; or (v) approval by the stockholders of KMI of a liquidation or sale of KMI.
A “permitted holder” as defined under the plan means Richard D. Kinder or any of the “Sponsor Investors.”
Kinder Morgan Severance Plan. All of our executive officers, including Mr. Kinder, are eligible for severance payments under the Kinder Morgan Severance Plan (which is available to all regular full time U.S.-based employees not covered by a bargaining agreement), which caps severance payments at an amount equal to six months of annual base salary.
The following table lists the potential payments to named executive officers under the Kinder Morgan Severance Plan upon termination without cause. The table assumes the triggering event for the payments or provision of benefits occurred on December 31, 2013.
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(a)
Since the severance formula is based on the annual base salary, Mr. Kinder’s and Mr. Kean’s benefit calculates to less than $1 (the cap under the plan is 26 weeks of base pay).
(b)
Payment equals cap calculation under the plan of 26 weeks of annual base salary.
2013 Restricted Stock Grants under the Kinder Morgan, Inc. 2011 Stock Incentive Plan. Named executive officers who received 2013 restricted stock grants are entitled to accelerated vesting in certain termination or change-in-control circumstances under the award agreements governing their grants. The award agreements provide for accelerated vesting upon (a) a change in control of KMI or (b) termination of the employee’s employment by reason of (i) death, (ii) disability that results in KMI determining that the employee cannot perform the essential functions of his or her job, with or without a reasonable accommodation, or (iii) an involuntary termination by KMI due to a reorganization or reduction in force for which the employee would be eligible for pay under the Kinder Morgan Severance Plan, or (iv) the sale of KMI or the sale, transfer or discontinuation of any part of the operations or any business unit of KMI.
The definition of “change in control” in the Stock Incentive Plan is the same as that in the Annual Incentive Plan described above under “Annual Incentive Plan.”
The following table lists the potential accelerated value of our named executive officers’ 2013 restricted stock grants upon death, disability or termination without cause. The table assumes the triggering event for the payments or provision of benefits occurred on December 31, 2013.
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(a)
Mr. Kinder did not receive a 2013 restricted stock grant.
(b)
Calculation equals number of restricted shares granted multiplied by the closing price on December 31, 2013 of KMI’s common stock of $36.00.
Other Potential Post-Employment Benefits. In addition to the amounts payable under the Kinder Morgan Severance Plan and their respective 2013 restricted stock grants, each executive would receive payments for amounts of base salary and vacation time accrued through the date of termination and payment for any reimbursable business expenses incurred prior to the date of termination.
Summary Compensation Table
The following table shows compensation paid or otherwise awarded to (i) our principal executive officer; (ii) our principal financial officer; and (iii) our three most highly compensated executive officers (other than our principal executive officer and principal financial officer) serving at fiscal year end 2013 (collectively referred to as the “named executive officers”) for services rendered to us, our subsidiaries or our affiliates, including KMI (collectively referred to as the KMI affiliated entities), during fiscal years 2013, 2012 and 2011, as applicable. The amounts in the columns below represent the total compensation paid or awarded to the named executive officers by all the KMI affiliated entities, and as a result, the amounts are in excess of the compensation expense allocated to, recognized and paid by us for services rendered to us.
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(a)
Restricted stock awards granted in 2013 were intended to provide long-term incentive compensation over an approximately six-year cliff-vesting period during which named executive officers are not expected to receive additional equity incentive grants. Amounts in this column reflect the grant date fair value of stock awards granted to each named executive officer under the Kinder Morgan, Inc. 2011 Stock Incentive Plan computed in accordance with FASB Codification Topic 718, “Compensation-Stock Compensation”.
(b)
Represents amounts paid according to the provisions of the Annual Incentive Plan then in effect. Amounts were earned in the fiscal year indicated but were paid in the next fiscal year.
(c)
Represents the 2013, 2012 and 2011, as applicable, change in the actuarial present value of accumulated defined pension benefit (including unvested benefits) according to the provisions of KMI’s Cash Balance Retirement Plan.
(d)
Amounts in 2012 and 2011 include value of contributions to the KMI Savings Plan (a 401(k) plan), value of group-term life insurance exceeding $50,000 and parking subsidy. Amounts in 2012 and 2011 representing the value of contributions to the KMI Savings Plan are $12,500, and $12,250 respectively. Amounts in 2013 include value of contributions to the KMI Savings Plan (a 401(k) plan), value of group-term life insurance exceeding $50,000 and dividend equivalents paid on unvested restricted stock. 2013 amounts are detailed in the table below:
(e)
Includes long-term incentive stock awards with approximately six-year cliff-vesting period. See note (a).
(f)
Effective July 1, 2013, Mr. Kean’s salary was reduced to $1 per year.
(g)
Mr. Martin was not a named executive officer during the year 2011.
(h)
Mr. Schlosser was not a named executive officer during 2012 or 2011.
Grants of Plan-Based Awards
The following supplemental compensation table shows compensation details on the value of plan-based incentive awards granted during 2013 to our named executive officers. The table includes awards made during or for 2013. The information in the table under the caption “Estimated Future Payouts Under Non-Equity Annual Incentive Plan Awards” represents the threshold, target and maximum amounts payable under the Kinder Morgan, Inc. Annual Incentive Plan for performance in 2013. Amounts actually paid under that plan for 2013 are set forth in the Summary Compensation Table under the caption “Non-Equity Incentive Plan Compensation.” Information under the “Grant Date Fair Value of Restricted Stock” represents the July 2013 restricted stock grants to our named executive officers under KMI’s 2011 Stock Incentive Plan. These amounts are set forth in the Summary Compensation Table under the caption “Stock Awards”.
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(a)
See “-Compensation Discussion and Analysis-Elements of Compensation” and “-Possible Annual Cash Bonus (Annual Cash Incentive)” above for further discussion of these awards.
(b)
Represents the maximum bonus opportunity available to the executive officer if one of the financial performance objectives was met.
(c)
Represents the maximum bonus opportunity available to the executive officer if all of the financial performance objectives were met.
(d)
Represents the maximum bonus opportunity available to the executive officer if all of the financial performance objectives were exceeded by 10% or more.
(e)
Represents the number of shares of restricted stock granted in 2013 to the named executive officers. Ms. Dang’s and Messrs. Kean and Martin’s grants vest on July 16, 2019. Mr. Schlosser’s grant vests on March 1, 2019.
(f)
Restricted stock awards granted in 2013 were intended to provide long-term incentive compensation over an approximately six-year cliff-vesting period during which named executive officers are not expected to receive additional equity incentive grants. Represents the grant date fair value computed in accordance with FASB ASC Topic 718 of restricted stock granted to the named executive officers during 2013.
(g)
Declined to participate.
Outstanding Equity Awards at Fiscal Year-End
For each of the fiscal years 2011 and 2012, none of the named executive officers was awarded any stock options, restricted stock or similar stock-based awards, and we had no expectation of granting any such awards to the named executive officers while any of the Sponsor Investors held Class A shares. On December 26, 2012, the last of the Sponsor Investors converted its remaining Class A shares into Class P shares. As a result, in July 2013, each of the named executive officers (other than Mr. Kinder) received grants of restricted KMI stock, as detailed above.
Stock Vested
No stock awards to the named executive officers vested during 2013.
Risks Associated with Compensation Practices
KMGP Services Company, Inc., KMI and Kinder Morgan Canada Inc. employ all persons necessary for the operation of our business, and in our opinion, our compensation policies and practices for all persons necessary for the operation of our business do not create risks that are reasonably likely to have a material adverse effect on our business, financial position, results of operations or cash flows. Our belief is based on the fact that our employee compensation-primarily consisting of annual salaries and cash bonuses-is based on performance that does not reward risky behavior and is not tied to entering into transactions that pose undue risks to us.
Director Compensation
Compensation Committee Interlocks and Insider Participation
The compensation committee of KMR functions as our compensation committee. KMR’s compensation committee is comprised of Messrs. Ted A. Gardner, Gary L. Hultquist and Perry M. Waughtal. KMR’s compensation committee makes compensation decisions regarding the executive officers of our general partner and its delegate, KMR. Mr. Kinder and Mr. Kean, who are executive officers of KMR, and Mr. Street, who was an executive officer of KMR, participated in the deliberations of the KMR compensation committee concerning our executive officers’ 2013 compensation. None of the members of KMR’s compensation committee is or has been one of our officers or employees, and none of our executive officers served during 2013 on a board of directors or compensation committee of another entity which has employed any of the members of KMR’s board of directors or compensation committee.
Directors Fees
KMR’s three non-employee directors receive an annual cash fee with the option to receive KMP common units in lieu of receiving cash under our Common Unit Compensation Plan for Non-Employee Directors. This plan is described in Note 12
“-KMEP Common Unit Compensation Plan for Non-Employee Directors” to our consolidated financial statements. Directors of KMR who are also employees of KMI (Messrs. Kinder and Kean) do not receive compensation in their capacity as directors.
The following table discloses the compensation earned by each of KMR’s non-employee directors for board service during fiscal year 2013. In addition, directors are reimbursed for reasonable expenses in connection with board meetings.
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The annual fees have been increased to $200,000 for 2014.
Compensation Committee Report
Throughout fiscal 2013, the compensation committee of KMR’s board of directors was comprised of three directors (Mr. Gardner, Mr. Hultquist and Mr. Waughtal), each of whom the KMR board of directors has determined meets the criteria for independence under KMR’s governance guidelines and the NYSE rules.
The KMR compensation committee has discussed and reviewed the above Compensation Discussion and Analysis for fiscal year 2013 with management. Based on this review and discussion, the KMR compensation committee recommended to its board of directors that this Compensation Discussion and Analysis be included in this annual report on Form 10-K for the fiscal year 2013.
KMR Compensation Committee:
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Ted A. Gardner
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Gary L. Hultquist
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Perry M. Waughtal
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The following table sets forth information as of January 31, 2014, regarding (i) the beneficial ownership of our common and Class B units and KMR shares by each of the directors of our general partner and KMR, its delegate, by each of the named executive officers identified in Item 11 “Executive Compensation” and by all directors and executive officers as a group and (ii) the beneficial ownership of our common units, Class B units and KMR shares by all persons known by our general partner to own beneficially at least 5% of such units or shares. Unless otherwise noted, the address of each person below is c/o Kinder Morgan Energy Partners, L.P., 1001 Louisiana Street, Suite 1000, Houston, Texas 77002.
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* Less than 1%.
(a)
Except as noted otherwise, each beneficial owner has sole voting power and sole investment power over the units and shares listed.
(b)
As of January 31, 2014, we had 312,989,671 common units issued and outstanding.
(c)
As of January 31, 2014, we had 5,313,400 Class B units issued and outstanding.
(d)
Represent the LLC shares of KMR. As of January 31, 2014, there were 125,399,834 issued and outstanding KMR shares, including four voting shares owned by our general partner. In all cases, our i-units will be voted in proportion to the affirmative and negative votes, abstentions and non-votes of owners of KMR shares. Through the provisions in our partnership agreement and KMR’s LLC agreement, the number of outstanding KMR shares, including voting shares owned by our general partner, and the number of our i-units will at all times be equal.
(e)
Includes 7,879 common units and 1,319 KMR shares owned by Mr. Kinder’s spouse. Mr. Kinder disclaims all beneficial and pecuniary interest in these common units and KMR shares.
(f)
Includes 18,641 KMR shares held by a limited partnership, the general partner of which is owned 50% by Mr. Waughtal and 50% by his spouse and jointly controlled by Mr. Waughtal and his spouse. Mr. Waughtal disclaims 99.5% of any beneficial and pecuniary interest in these shares.
(g)
See notes (e) and (f).
(h)
Includes common units owned by KMI and its consolidated subsidiaries, including 1,724,000 common units owned by Kinder Morgan G.P., Inc.
(i)
As reported on the Schedule 13G/A filed February 5, 2014 by Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne, Kayne Anderson Capital Advisors, L.P. reported that in regard to KMR shares, it had sole voting power over 0 shares, shared voting power over 10,859,808 shares, no sole disposition power over 0 shares and shared disposition power over 10,859,808 shares. Mr. Kayne reports that in regard to KMR shares, he had sole voting power over 0 shares, shared voting power over 10,859,808 shares, sole disposition power over 0 shares and shared disposition power over 10,859,808 shares. Kayne Anderson Capital Advisors, L.P.’s and Richard A. Kayne’s address is 1800 Avenue of the Stars, Second Floor, Los Angeles, California 90067.
KMR’s board of directors and its compensation committee previously established a minimum ownership requirement for members of the board with respect to KMP units, KMR shares or a combination thereof. As of December 31, 2013, one member of the board, Mr. Hultquist, did not satisfy this minimum ownership requirement. Effective February 6, 2014, the board, by unanimous consent, determined to provide a waiver of the minimum ownership requirement in the case of Mr. Hultquist until December 31, 2014, or such later date determined by the board.
The following table sets forth information as of January 31, 2014, regarding the beneficial ownership of KMI Class P shares by each of the directors of our general partner and KMR, its delegate, by each of the named executive officers identified in Item 11 “Executive Compensation” and by all directors and executive officers as a group.
___________
* Less than 1%.
(a)
Except as noted otherwise, each beneficial owner has sole voting power and sole investment power over the shares listed.
(b)
As of January 31, 2014, KMI had 1,030,677,290 Class P shares issued and outstanding.
(c)
Includes 40,467 Class P shares owned by Mr. Kinder’s wife. Mr. Kinder disclaims any and all beneficial or pecuniary interest in the Class P shares held by his wife. Also includes 11,072,258 Class P shares held by a limited partnership of which Mr. Kinder controls the voting and disposition power. Mr. Kinder disclaims 99% of any beneficial and pecuniary interest in these shares.
(d)
Includes 230,000 Class P shares held by a limited partnership. Mr. Kean is the sole general partner of the limited partnership, and two trusts of which family members of Mr. Kean are sole beneficiaries and Mr. Kean is a trustee, each own a 49.5% limited partner interest in the limited partnership. Mr. Kean disclaims beneficial ownership of the Class P shares held by the limited partnership except to the extent of his pecuniary interest therein. Also includes 625,000 Class P shares owned by a charitable foundation of which Mr. Kean is a member of the board of directors and shares voting and investment power. Mr. Kean disclaims any beneficial ownership in these 625,000 shares.
(e)
Amount does not reflect warrants to purchase 180,000 Class P shares held by Mr. Gardner, which warrants are not currently exercisable based on current market prices for the Class P shares.
(f)
Includes 10,000 Class P shares held by a limited partnership, the general partner of which is owned 50% by Mr. Waughtal and 50% by his spouse and jointly controlled by Mr. Waughtal and his spouse. Mr. Waughtal disclaims 99.5% of any beneficial and pecuniary interest in these shares.
(g)
Includes 2,026,048 Class P shares held by a limited partnership of which Mrs. Dang controls the voting and disposition power. Mrs. Dang disclaims 10% of any beneficial and pecuniary interest in these shares. Amount does not reflect warrants to purchase 192 Class P shares held by Mrs. Dang, which warrants are not currently exercisable based on current market prices for the Class P shares.
(h)
Includes 148,950 Class P shares held by a trust for the benefit of family members of Mr. Martin with respect to which Mr. Martin shares voting and disposition power. Mr. Martin disclaims any beneficial ownership in these shares.
(i)
See notes (c) through (h) above. Also includes 174,019 Class P shares held by limited partnerships, limited liability companies or trusts with respect to which executive officers have sole or shared voting or disposition power, but in respect of which Class P shares the executive officers disclaim all or a portion of any beneficial or pecuniary interest. Amount does not reflect warrants to purchase 1,600 Class P shares held by an executive officer, which warrants are not currently exercisable based on current market prices for the Class P shares.
Equity Compensation Plan Information
The following table sets forth information regarding our equity compensation plans as of December 31, 2013. Specifically, the table provides information regarding our Common Unit Compensation Plan for Non-Employee Directors. This plan is described in Note 12 “-KMEP Common Unit Compensation Plan for Non-Employee Directors” to our consolidated financial statements.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
Related Transactions
Our policy is that (i) employees must obtain authorization from the appropriate business unit president of the relevant company or head of corporate function, and (ii) directors, business unit presidents, executive officers and heads of corporate functions must obtain authorization from the non-interested members of the audit committee of the applicable board of directors, for any business relationship or proposed business transaction in which they or an immediate family member has a direct or indirect interest, or from which they or an immediate family member may derive a personal benefit (a “related party transaction”). When deciding whether to authorize a related party transaction, our business unit presidents and the non-interested members of the audit committee of the applicable board of directors, consider, among other things, the nature of the transaction and the relationship, the dollar amount involved, and the availability of reasonable alternatives.
The maximum dollar amount of related party transactions that may be approved as described above in this paragraph in any calendar year is $1.0 million. Any related party transactions that would bring the total value of such transactions to greater than $1.0 million must be referred to the audit committee of the appropriate board of directors for approval or to determine the procedure for approval.
For further information regarding our related party transactions, see Note 11 to our consolidated financial statements.
Director Independence
Our limited partnership agreement provides for us to have a general partner rather than a board of directors. Pursuant to a delegation of control agreement, our general partner delegated to KMR, to the fullest extent permitted under Delaware law and our partnership agreement, all of its power and authority to manage and control our business and affairs, except that KMR cannot take certain specified actions without the approval of our general partner. Through the operation of that agreement and our partnership agreement, KMR manages and controls our business and affairs, and the board of directors of KMR performs the functions of and acts as our board of directors. Similarly, the standing committees of KMR’s board of directors function as standing committees of our board. KMR’s board of directors is comprised of the same persons who comprise our general
partner’s board of directors. References in this report to the board mean KMR’s board, acting as our board of directors, and references to committees mean KMR’s committees, acting as committees of our board of directors.
The board has adopted governance guidelines for the board and charters for the audit committee, nominating and governance committee and compensation committee. The governance guidelines and the rules of the NYSE require that a majority of the directors be independent, as described in those guidelines, the committee charters and rules, respectively. Copies of the guidelines and committee charters are available on our Internet website at www.kindermorgan.com.
As described above, each of Mr. Gardner, Mr. Hultquist and Mr. Waughtal is also an independent director of our general partner. Further, each has no family relationship with any of the directors or executive officers of KMR, our general partner or us, and each has no direct or indirect material interest in any transaction or proposed transaction required to be reported under Section 404(a) of Regulation S-K.
The board has affirmatively determined that Messrs. Gardner, Hultquist and Waughtal, who constitute a majority of the directors, are independent as described in our governance guidelines and the NYSE rules. In conjunction with all regular quarterly and certain special board meetings, these three non-management directors also meet in executive session without members of management. In January 2014, Mr. Hultquist was elected for a one year term to serve as lead director to develop the agendas for and preside at these executive sessions of independent directors.
The governance guidelines and our audit committee charter, as well as the rules of the NYSE and the SEC, require that members of the audit committee satisfy independence requirements in addition to those above. The board has determined that all of the members of the audit committee are independent as described under the relevant standards.
Item 14.
Item 14. Principal Accounting Fees and Services
The following sets forth fees billed for the audit and other services provided by PricewaterhouseCoopers LLP for the fiscal years ended December 31, 2013 and 2012 (in dollars):
____________
(a)
Includes fees for integrated audit of annual financial statements and internal control over financial reporting, reviews of the related quarterly financial statements, and reviews of documents filed with the SEC. 2013 and 2012 amounts also include fees of $1,292,000 and $909,000, respectively, for GAAP audits of certain stand-alone financial statements; and fees of $525,000 for 2012 audit costs related to our FTC Natural Gas Pipelines disposal group.
(b)
For 2013 and 2012, amounts include fees of $3,314,276 and $2,267,448, respectively, billed for professional services rendered for tax processing and preparation of Forms K-1 for our unitholders; and fees of $15,676 and $12,705, respectively, billed for professional services rendered for Internal Revenue Service assistance, tax function effectiveness, and for general state, local and foreign tax compliance and consulting services.
All services rendered by PricewaterhouseCoopers LLP are permissible under applicable laws and regulations, and were pre-approved by the audit committee of KMR and our general partner. Pursuant to the charter of the audit committee of KMR, the delegate of our general partner, the committee’s primary purposes include the following: (i) to select, appoint, engage, oversee, retain, evaluate and terminate our external auditors; (ii) to pre-approve all audit and non-audit services, including tax services, to be provided, consistent with all applicable laws, to us by our external auditors; and (iii) to establish the fees and other compensation to be paid to our external auditors. The audit committee has reviewed the external auditors’ fees for audit and non audit services for fiscal year 2013. The audit committee has also considered whether such non audit services are compatible with maintaining the external auditors’ independence and has concluded that they are compatible at this time.
Furthermore, the audit committee will review the external auditors’ proposed audit scope and approach as well as the performance of the external auditors. It also has direct responsibility for and sole authority to resolve any disagreements between our management and our external auditors regarding financial reporting, will regularly review with the external auditors any problems or difficulties the auditors encountered in the course of their audit work, and will, at least annually, use its reasonable efforts to obtain and review a report from the external auditors addressing the following (among other items): (i) the auditors’ internal quality-control procedures; (ii) any material issues raised by the most recent internal quality-control
review, or peer review, of the external auditors; (iii) the independence of the external auditors; and (iv) the aggregate fees billed by our external auditors for each of the previous two fiscal years.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
(a) (1) and (2) Financial Statements and Financial Statement Schedules
(3) Exhibits
_______
* 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 Partners of Kinder Morgan Energy Partners, L.P.:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of comprehensive income, of partners’ capital and of cash flows present fairly, in all material respects, the financial position of Kinder Morgan Energy Partners, L.P. and its subsidiaries (the “Partnership”) 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 Partnership 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 Partnership’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 Partnership’s 2013 Annual Report on Form 10-K. Our responsibility is to express opinions on these financial statements and on the Partnership’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 Partnership’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 14% and 10%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2013.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 18, 2014
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements
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 ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. General
Organization
Kinder Morgan Energy Partners, L.P. is a Delaware limited partnership formed in August 1992. Unless the context requires otherwise, references to “we,” “us,” “our,” “KMP,” or the “Partnership” are intended to mean Kinder Morgan Energy Partners, L.P., our operating limited partnerships and their majority-owned and controlled subsidiaries. We are a leading pipeline transportation and energy storage company in North America, managing a diversified portfolio of energy transportation and storage assets. We own an interest in or operate approximately 52,000 miles of pipelines and 180 terminals, and we conduct our business through five reportable business segments.
These segments and the activities performed to provide services to our customers and create value for our unitholders are as follows:
▪
Natural Gas Pipelines - transporting, storing, buying, selling, gathering, treating, processing and fractionating natural gas;
▪
CO2 - transporting oil, producing, transporting and selling CO2 for use in, and selling crude oil, natural gas and NGL produced from, enhanced oil recovery operations;
▪
Products Pipelines - transporting, storing and processing refined petroleum products (including gasoline, diesel fuel and jet fuel), NGL, crude oil, condensate and bio-fuels, plus operating associated product terminals and petroleum pipeline transmix facilities;
▪
Terminals - transloading, storing and delivering a wide variety of bulk, petroleum (including crude oil), petrochemical and other liquid products at terminal facilities located across the U.S. and portions of Canada; and
▪
Kinder Morgan Canada - transporting crude oil and refined petroleum products from Edmonton, Alberta, Canada to marketing terminals and refineries in British Columbia and the state of Washington.
We focus on providing fee-based services to customers, generally avoiding near-term commodity price risks and taking advantage of the tax benefits of a limited partnership structure. We trade on the NYSE under the symbol “KMP,” and we conduct our operations through five limited partnerships and one limited liability corporation, as follows: (i) Kinder Morgan Operating L.P. “A”; (ii) Kinder Morgan Operating L.P. “B”; (iii) Kinder Morgan Operating L.P. “C”; (iv) Kinder Morgan Operating L.P. “D”; (v) Kinder Morgan CO2 Company, L.P.; and (vi) Copano. Combined, the five limited partnerships are referred to as our operating partnerships, and we are the 98.9899% limited partner and our general partner is the 1.0101% general partner in each. Both we and our operating partnerships are governed by Amended and Restated Agreements of Limited Partnership, as amended, and certain other agreements that are collectively referred to in this report as the partnership agreements.
KMI and Kinder Morgan G.P., Inc.
KMI, a Delaware corporation, indirectly owns all the common stock of our general partner, Kinder Morgan G.P., Inc., a Delaware corporation; however, in July 2007, our general partner issued and sold to a third party 100,000 shares of Series A fixed-to-floating rate term cumulative preferred stock due 2057. The consent of holders of a majority of these preferred shares is required with respect to a commencement of or a filing of a voluntary bankruptcy proceeding with respect to us or two of our subsidiaries, SFPP and Calnev. KMI’s common stock trades on the NYSE under the symbol “KMI.”
As of December 31, 2013, KMI and its consolidated subsidiaries owned, through KMI’s general and limited partner interests in us and its ownership of shares issued by its subsidiary KMR (discussed following), an approximate 11.6% interest in us. In addition to the distributions it receives from its limited and general partner interests, KMI also receives an incentive distribution from us as a result of its ownership of our general partner. Including both its general and limited partner interests in us, at the 2013 distribution level, KMI received approximately 49% of all quarterly distributions of available cash from us, with approximately 43% and 6% of all quarterly distributions from us attributable to KMI’s general partner and limited partner interests, respectively. As of December 31, 2012, KMI owned an approximate 12.8% interest in us and, at the 2012 distribution level, KMI received approximately 51% of all quarterly distributions of available cash from us, with approximately 45% and 6% of all quarterly distributions from us attributable to KMI’s general partner and limited partner interests, respectively. In addition, as a result of its May 25, 2012 acquisition of all of the outstanding shares of EP, a Delaware corporation, KMI now owns a 41% limited partner interest and the 2% general partner interest in EPB.
KMR
KMR is a Delaware LLC formed in February 2001. Our general partner owns all of KMR’s voting securities and, pursuant to a delegation of control agreement, has delegated to KMR, to the fullest extent permitted under Delaware law and our partnership agreement, all of its power and authority to manage and control our business and affairs, except that KMR cannot take certain specified actions without the approval of our general partner. KMR’s shares represent LLC interests and trade on the NYSE under the symbol “KMR.”
Under the delegation of control agreement, KMR, as the delegate of our general partner, manages and controls our business and affairs and the business and affairs our operating limited partnerships, of Copano, and our operating limited partnerships and Copano’s majority-owned and controlled subsidiaries. Furthermore, in accordance with its LLC agreement, KMR’s activities are limited to being a limited partner in us, and managing and controlling the business and affairs of us, our operating limited partnerships, Copano, and our operating limited partnerships and Copano’s majority-owned and controlled subsidiaries. As of December 31, 2013 and 2012, KMR, through its sole ownership of our i-units, owned approximately 28.3% and 30.8%, respectively, of all of our outstanding limited partner units (which are in the form of i-units that are issued only to KMR).
2. Summary of Significant Accounting Policies
Basis of Presentation
General
Our reporting currency is in 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 include our accounts, and the accounts of Copano and our operating limited partnerships and Copano’s majority-owned and controlled subsidiaries. We have prepared these consolidated financial statements under the rules and regulations of the U.S. 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 financial statements are consolidated into the consolidated financial statements of KMI; however, except for the related party transactions described in Note 11 “Related Party Transactions-Asset Acquisitions and Sales,” KMI is not liable for, and its assets are not available to satisfy, the obligations of us and/or our subsidiaries and vice versa. Responsibility for payments of obligations reflected in our or KMI’s financial statements is a legal determination based on the entity that incurs the liability. Furthermore, the determination of responsibility for payment among entities in our consolidated group of subsidiaries is not impacted by the consolidation of our financial statements into the consolidated financial statements of KMI.
KMI Asset Drop-Downs
Effective August 1, 2012, we acquired a 100% ownership interest in TGP and a 50% ownership interest in EPNG from KMI for an aggregate consideration of approximately $6.2 billion (including our proportional share of assumed debt borrowings as of August 1, 2012). In this report, we refer to this acquisition of assets from KMI as the August 2012 drop-down transaction; and the combined group of assets acquired from KMI effective August 1, 2012 as the August 2012 drop-down asset group.
Effective March 1, 2013, we acquired from KMI the remaining 50% ownership interest we did not already own in both EPNG and the EP midstream assets for an aggregate consideration of approximately $1.7 billion (including our proportional share of assumed debt borrowings as of March 1, 2013). In this report, we refer to this acquisition of assets from KMI as the March 2013 drop-down transaction; the combined group of assets acquired from KMI effective March 1, 2013 as the March 2013 drop-down asset group; the EP midstream assets of Kinder Morgan Altamont LLC (formerly, El Paso Midstream Investment Company, L.L.C.) as the EP midstream assets; the combined August 2012 drop-down transaction (described above) and the March 2013 drop-down transaction as the drop-down transactions; and the combined August 2012 drop-down asset group (described above) and the March 2013 drop-down asset group as the drop-down asset groups. We acquired our initial 50% ownership interest in the EP midstream assets from an investment vehicle affiliated with Kohlberg Kravis Roberts & Co. L.P., referred to as KKR, effective June 1, 2012. Prior to the March 2013 drop-down transaction, we accounted for our initial 50% ownership interests in both EPNG and the EP midstream assets under the equity method of accounting.
KMI acquired all of the assets included in the drop-down asset groups as part of its May 25, 2012 acquisition of EP, and KMI accounted for its EP acquisition under the acquisition method of accounting. We, however, accounted for the drop-down transactions as combinations of entities under common control. Accordingly, we prepared our consolidated financial statements to reflect the transfers of the drop-down asset groups from KMI to us as if such transfers had taken place on the date when the drop-down asset groups met the accounting requirements for entities under common control-May 25, 2012 for both TGP and EPNG, and June 1, 2012 for the EP midstream assets. Specifically, we (i) consolidated our now 100% investments in the drop-down asset groups as of the effective dates of common control, recognizing the acquired assets and assumed liabilities at KMI’s carrying value (including all of KMI’s purchase accounting adjustments); (ii) recognized any difference between our purchase price and the carrying value of the net assets we acquired as an adjustment to our Partners’ Capital (specifically, as an adjustment to our general partner’s and our noncontrolling interests’ capital interests); and (iii) retrospectively adjusted our consolidated financial statements, for any date after the effective dates of common control.
Additionally, because KMI both controls us and consolidates our financial statements into its consolidated financial statements as a result of its ownership of our general partner, we fully allocated to our general partner:
▪
the earnings of the drop-down asset groups for the periods beginning on the effective dates of common control (described above) and ending August 1, 2012 for the August 2012 drop-down asset group and March 1, 2013 for the March 2013 drop-down asset group, respectively (we refer to these earnings as “pre-acquisition” earnings and we reported these earnings separately as “Pre-acquisition income from operations of drop-down asset groups allocated to General Partner” within the “Calculation of Limited Partners’ Interest in Net Income (Loss)” section of our accompanying consolidated statements of income for the years ended December 31, 2013 and 2012; and
▪
incremental severance expense related to KMI’s acquisition of EP and allocated to us from KMI (and we reported this expense separately as “Drop-down asset groups’ severance expense allocated to General Partner” within the “Calculation of Limited Partners’ Interest in Net Income (Loss)” section of our accompanying consolidated statements of income for the years ended December 31, 2013 and 2012. The severance expense allocated to us was associated with the drop-down asset groups; however, we do not have any obligation, nor did we pay any amounts related to this expense.
For all periods beginning after our acquisition dates of August 1, 2012 and March 1, 2013, respectively, we allocated our earnings (including the earnings from the drop-down asset groups) to all of our partners according to our partnership agreement. For more information about the drop-down transactions, see Note 3 “Acquisitions and Divestitures-KMI Asset Drop-Downs.” For more information on the changes to our Partners’ Capital related to the drop-down transactions, see Note 10 “Partners’ Capital-Adjustment to Partners’ Capital from KMI Asset Drop-Downs.”
FTC Natural Gas Pipelines Disposal Group - Discontinued Operations
Effective November 1, 2012, KMI sold our (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 to Tallgrass Energy Partners, LP (now known as Tallgrass Development, LP) (Tallgrass) for approximately $1.8 billion in cash (before selling costs), or $3.3 billion including our share of joint venture debt. In this report, we refer to this combined group of assets as our FTC Natural Gas Pipelines disposal group. The sale of our FTC Natural Gas Pipelines disposal group satisfied terms of a March 15, 2012 agreement between KMI and the FTC to divest certain of our assets in order to receive regulatory approval for KMI’s EP acquisition.
Following KMI’s agreement with the FTC, we accounted for our FTC Natural Gas Pipelines disposal group as discontinued operations in accordance with the provisions of the “Presentation of Financial Statements-Discontinued Operations” Topic of the Codification. Accordingly, we (i) reclassified and excluded the 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 FTC Natural Gas Pipelines disposal group” 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 FTC Natural Gas Pipelines disposal group to fair value” within the discontinued operations section of our accompanying consolidated statements of income for the years ended December 31, 2013 and 2012. We did not, however, 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 our FTC Natural Gas Pipelines disposal group, see Note 3 “Acquisitions and Divestitures-Divestitures-FTC Natural Gas Pipelines Disposal Group - Discontinued Operations.”
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.
Cash held in escrow is restricted cash, and as of December 31, 2013 and 2012, our restricted cash totaled $19 million and $7 million, respectively. We included $17 million of our restricted cash as of December 31, 2013 within “Other current assets” on our accompanying consolidated balance sheet, and we included the remaining balance within “Deferred charges and other assets.” As of December 31, 2012, we included all of our restricted cash balance within “Other current 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 December 31, 2013 and 2012, our gas imbalance receivables-including both trade and related party receivables-totaled $68 million and $15 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-including both trade and related party payables-totaled $25 million and $6 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 system sales, excluding land, are recorded to the appropriate accumulated depreciation reserve. Gains and losses for operating systems sales and land sales are booked to income or expense accounts in accordance with regulatory accounting guidelines.
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 1.1% to 14.0%, 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 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 acquired net assets, and such amounts are reported separately as on our consolidated balance sheets. As of December 31, 2013 and 2012, our total goodwill was $6,547 million and $5,417 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 our CO2 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, until they are amortized to expense.
Noncontrolling Interests
Noncontrolling interests represents the outstanding ownership interests in our five operating limited partnerships and their 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 “Partners’ Capital.”
As of December 31, 2013 our noncontrolling interests consisted of the following: (i) the 1.0101% general partner interest in each of our five operating partnerships; (ii) the 0.5% special limited partner interest in SFPP; (iii) the 33 1/3% interest in International Marine Terminals Partnership, a Louisiana partnership; (iv) the approximate 31% interest in the Pecos Carbon Dioxide Transportation Company, a Texas general partnership; (v) the 35% interest in Guilford County Terminal Company, LLC; (vi) the 45% interest in BOSTCO; (vii) the 49% interest in Deeprock Development LLC; and (viii) the 30.5% interest in Southern Dome, LLC, acquired as part of our May 1, 2013 Copano acquisition. In addition to the above, our noncontrolling interest as of December 31, 2012 included the 50% interest in Globalplex Partners, a Louisiana joint venture that was dissolved in December 2013.
Income Taxes
We are not a taxable entity for federal income tax purposes. As such, we do not directly pay federal income tax. Our taxable income or loss, which may vary substantially from the net income or net loss we report in our consolidated statement of income, is includable in the federal income tax returns of each partner. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined as we do not have access to information about each partner’s tax attributes in us.
Some of our corporate subsidiaries and corporations in which we have an equity investment do pay U.S. federal, state, and foreign income taxes. Deferred income tax assets and liabilities for certain operations conducted through corporations are recognized for temporary differences between the 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 not expected to be realized.
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 partners’ capital equity accounts are translated by using historical exchange rates. The cumulative translation adjustments balance is reported as a component of “Accumulated other comprehensive income” within “Partners’ Capital” in our consolidated balance sheets.
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.
Limited Partners’ Net Income (Loss) per Unit
We compute Limited Partners’ Net Income (Loss) per Unit by dividing our limited partners’ interest in net income (loss) by the weighted average number of units outstanding during the period. The overall computation, presentation, and disclosure requirements for our Limited Partners’ Net Income per Unit are made in accordance with the “Earnings per Share” Topic of the Codification.
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 twenty-five 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. We expect 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.
3. Acquisitions and Divestitures
Business Combinations and Acquisitions of Investments
During 2013, 2012 and 2011, we completed the following significant acquisitions, and except for our acquisition of two separate equity interests in Watco Companies, LLC and our acquisition of an initial 50% interest in the EP midstream assets (noted as (1), (5) and (6), respectively, in the table and discussion below and accounted for under the equity method), 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 goodwill are both the value of the synergies created between the acquired assets and our pre-existing assets, and our expected ability to grow the business we acquired by leveraging our pre-existing business experience. With the exception of our acquisitions of (i) KinderHawk and EagleHawk and (ii) SouthTex Treaters (noted as (3) and (4) 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) Watco Companies, LLC (1 of 2)
On January 3, 2011, we purchased 50,000 Class A preferred shares of Watco Companies, LLC for $50 million in cash in a private transaction. In connection with our purchase of these preferred shares, the most senior equity security of Watco, we entered into a limited liability company agreement with Watco that provides us certain priority and participating cash distribution and liquidation rights. Pursuant to the agreement, we receive priority, cumulative cash distributions from the preferred shares at a rate of 3.25% per quarter (13% annually), and we participate 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 us certain approval rights, including the right to appoint one of the members to Watco’s Board of Managers. On December 28, 2011, we made an additional $50 million investment in Watco, as described below in “-(5) 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. Our investment provided capital to Watco for further expansion of specific projects and complemented our existing terminal network. It also provides our customers more transportation services for many of the commodities that we currently handle, and offers us the opportunity to share in additional growth opportunities through new projects. As of December 31, 2013, our net equity investment in Watco totaled $103 million and is within “Investments” on our accompanying consolidated balance sheet. We account for our investment under the equity method of accounting, and we include it in our Terminals business segment.
(2) TGS Development, L.P. Terminal Acquisition
On June 10, 2011, we 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, we settled the $7 million liability by issuing additional common units to TGSD (we 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 our existing Gulf Coast bulk terminal facilities and expanded our pre-existing petroleum coke handling operations. All of the acquired assets are included as part of our Terminals business segment.
(3) KinderHawk and EagleHawk
Effective July 1, 2011, we 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 we 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). We then repaid the outstanding $154 million of borrowings and following this repayment, KinderHawk had no outstanding debt. We also terminated the revolving bank credit facility at the time of such repayment. All of the acquired operations are included in our Natural Gas Pipelines business segment.
Following this acquisition of the remaining ownership interest on July 1, 2011, we changed our method of accounting from the equity method to full consolidation, and due to the fact that we acquired a controlling financial interest in KinderHawk, we remeasured our previous 50% equity investment in KinderHawk to its fair value. We recognized a $167 million non-cash loss as a result of this remeasurement. The loss amount represented the excess of the carrying value of our 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 our contracts with Petrohawk.
(4) SouthTex Treaters, Inc. Asset Acquisition
On November 30, 2011, we 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 our existing natural gas treating business, and all of the acquired operations are included in our Natural Gas Pipelines business segment.
(5) Watco Companies, LLC (2 of 2)
On December 28, 2011, we 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 we acquired on January 3, 2011-we receive priority, cumulative cash distributions from the preferred shares at a rate of 3.25% per quarter (13% annually), and we participate partially in additional profit distributions at a rate equal to 0.5%.
(6) EP Midstream Assets (1 of 2)
Effective June 1, 2012, we acquired from an investment vehicle affiliated with KKR a 50% equity ownership interest in the EP midstream assets, 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. We acquired our initial 50% interest for an aggregate consideration of $289 million in common units (we
issued 3,792,461 common units and determined each unit’s value based on the $76.23 closing market price of the common units on the NYSE on the June 4, 2012 issuance date).
Effective March 1, 2013, we acquired from KMI the remaining 50% equity ownership interest in the EP midstream assets. For more information about this acquisition see “-KMI Asset Drop-Downs-March 2013 KMI Asset Drop-Down.”
(7) Copano
Effective May 1, 2013, we 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 our common units for each Copano common unit. We issued 43,371,210 of our 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 our acquisition included the remaining 50% interest in Eagle Ford Gathering LLC that we did not already own, we remeasured our existing 50% equity investment in Eagle Ford to its fair value as of the acquisition date. As a result of our remeasurement, we recognized a $558 million non-cash gain, which represented the excess of the investment’s fair value ($704 million) over our 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. Our evaluation of the assigned fair values is ongoing and subject to adjustment.
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 our Natural Gas Pipelines business segment.
(8) Goldsmith Landreth Field Unit
On June 1, 2013, we 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, we obtained a long-term supply contract for up to 150 MMcf/d of CO2. The acquisition complemented our existing oil and gas producing assets in the Permian Basin, and we included the acquired assets as part of our CO2 business segment. Our evaluation of the assigned fair values is ongoing and subject to adjustment.
KMI Asset Drop-Downs
August 2012 KMI Asset Drop-Down
As discussed above in Note 2, we acquired the August 2012 drop-down asset group from KMI effective August 1, 2012. Our consideration to KMI consisted of (i) $3.5 billion in cash; (ii) 4,667,575 common units (valued at $0.4 billion based on the $81.52 closing market price of the common units on the NYSE on the August 13, 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 acquired the August 2012 drop-down asset group in order to replace the cash flows associated with the divested FTC Natural Gas Pipelines disposal group, and the terms of the August 2012 drop-down transaction were approved on behalf of KMI by the independent members of its board of directors and on our behalf by the audit committees and the boards of directors of both our general partner and KMR, in its capacity as the delegate of our general partner, following the receipt by the independent directors of KMI and the audit
committees of our general partner and KMR of separate fairness opinions from different independent financial advisors. We included the August 2012 drop-down asset group in our Natural Gas Pipelines segment.
TGP is an 11,800 mile pipeline system with a transport design capacity of approximately 8.5 Bcf/d of natural gas. It transports natural gas from Louisiana, the Gulf of Mexico and south Texas to the northeastern U.S., including the metropolitan areas of New York City and Boston. EPNG is a 10,700 mile pipeline system with a design capacity of approximately 5.6 Bcf/d of natural gas. It transports natural gas from the San Juan, Permian and Anadarko basins to California, other western states, Texas and northern Mexico.
March 2013 KMI Asset Drop-Down
As discussed above in Note 2, we acquired the March 2013 drop-down asset group from KMI effective March 1, 2013. Our consideration to KMI consisted of (i) $994 million in cash (including $6 million paid to KMI 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 a 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). The terms of the drop-down transaction were approved on behalf of KMI by the independent members of its board of directors and on our behalf by the audit committees and the boards of directors of both our general partner and KMR, in its capacity as the delegate of our general partner, following the receipt by the independent directors of KMI and the audit committees of our general partner and KMR of separate fairness opinions from different independent financial advisors. We included the March 2013 drop-down asset group in our Natural Gas Pipelines segment.
Pro Forma Information
The following summarized unaudited pro forma consolidated income statement information for the years ended December 31, 2013 and 2012, assumes that our acquisitions of the drop-down asset groups, Copano and the Goldsmith Landreth field unit had occurred as of January 1, 2012. We prepared the following 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 we had completed our acquisitions of the drop-down asset groups, Copano and the Goldsmith Landreth field unit 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 unit amounts:
Acquisition Subsequent to December 31, 2013
Effective January 17, 2014, we 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). We funded this transaction with borrowings made under our commercial paper program, which is supported by a short-term liquidity facility dated January 17, 2014 (discussed further in Note 8 “Debt-Subsequent Event”). Additionally, our 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. We expect 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 our existing crude oil and refined products transportation business, and all of the acquired assets are included in our Terminals business segment.
Divestitures
FTC Natural Gas Pipelines Disposal Group - Discontinued Operations
As described above in Note 2, following KMI’s March 2012 agreement with the FTC, we began accounting for our FTC Natural Gas Pipelines disposal group as discontinued operations (prior to KMI’s sale announcement, we included the disposal group in our Natural Gas Pipelines business segment). Effective November 1, 2012, we then sold our FTC Natural Gas Pipelines disposal group to Tallgrass Energy Partners, LP (now known as Tallgrass Development, LP) (Tallgrass), and we 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); however, KMI contributed to us $45 million to be used as partial funding for our cash selling expenses, and we recognized this contribution as an increase to our general partner’s capital interest in us.
Additionally, during 2012, we remeasured the disposal group’s net assets to reflect our assessment of fair value as a result of the FTC mandated sale requirement, and as a result of our remeasurement of net assets to fair value and the sale of net assets, we recognized a combined $829 million loss. We reported this loss amount separately as “Loss on sale and the remeasurement of FTC Natural Gas Pipelines disposal group to fair value” within the discontinued operations section of our accompanying consolidated statement of income for the year ended December 31, 2012. We reported the proceeds we 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, we and Tallgrass trued up the final consideration for the sale of our FTC Natural Gas Pipelines disposal group and based both on this true up and certain incremental selling expenses we paid in 2013, we recognized an additional $4 million loss. We reported this loss amount separately as “Loss on sale and the remeasurement of FTC Natural Gas Pipelines disposal group to fair value” 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, we recorded no other financial results from the operations of our FTC Natural Gas Pipelines disposal group in 2013.
Summarized financial information for our 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 our FTC Natural Gas Pipelines disposal group effective November 1, 2012.
Express Pipeline System
Effective March 14, 2013, we sold both our one-third equity ownership interest in the Express pipeline system and our subordinated debenture investment in Express to Spectra Energy Corp. We 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 sale of investments in Express pipeline system” 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, our equity investment in Express totaled $67 million and our note receivable due from Express totaled $110 million. Prior to the sale, we (i) accounted for our equity investment under the equity method of accounting; (ii) accounted for our debt investment under the historical amortized cost method of accounting; and (iii) included the financial results of the Express pipeline system within our Kinder Morgan Canada business segment. As of December 31, 2012, our 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 our Class A member interest in BOSTCO, our 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 us for an aggregate consideration of $79 million, and following this acquisition, we now own a 55% Class A member interest in BOSTCO (we 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 we retained a controlling financial interest in BOSTCO, we continued to account for our investment under the full consolidation method and we accounted for this change in our ownership interest as an equity transaction; specifically, partners’ capital attributable to us decreased by $5 million and the noncontrolling interest in BOSTCO increased by $84 million.
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.
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:
Our deferred tax assets and liabilities as of December 31, 2013 and 2012 resulted from the following (in millions):
We account for uncertainty in income taxes in accordance with the “Income Taxes” Topic of the Codification. Pursuant to these provisions, we must 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 on the past administrative practices and precedents of the taxing authority. The tax benefits recognized in our 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 beginning and ending gross unrecognized tax benefits (excluding interest and penalties) for each of the years ended December 31, 2013 and 2012 is as follows (in millions):
Our continuing practice is to recognize interest and/or penalties related to income tax matters in income tax expense. During each of the years ended December 31, 2013, 2012 and 2011, we recognized interest expense of approximately $3 million, $2 million and $1 million, respectively.
As of December 31, 2013, (i) we had $7 million of accrued interest and no accrued penalties; (ii) we believe it is reasonably possible that our $57 million liability for unrecognized tax benefits will increase by approximately $8 million during the next twelve months; and (iii) we believe the full amount of $57 million of unrecognized tax benefits, if recognized, would favorably affect our effective income tax rate in future periods. As of December 31, 2012, we had $5 million of accrued interest and no accrued penalties. In addition, we have U.S. and state tax years open to examination for the periods 2007 through 2013.
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 $9,034 million and $8,954 million, respectively, within “Property, plant and equipment, net” on our accompanying consolidated balance sheets. These regulated amounts constituted 33% and 40%, 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 $1,311 million in 2013, $1,065 million in 2012 and $887 million in 2011.
Asset Retirement Obligations
As of December 31, 2013 and 2012, we recognized asset retirement obligations in the aggregate amount of $199 million and $170 million, respectively. The majority of our asset retirement obligations are associated with our CO2 business segment,
where we are required to plug and abandon oil and gas wells that have been removed from service and to remove our surface wellhead equipment and compressors. We included $25 million and $31 million, respectively, of our total asset retirement obligations as of December 31, 2013 and 2012 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 since December 31, 2012 related primarily to the increases and decreases associated with our May 1, 2013 Copano acquisition. As part of this acquisition, we 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 we did not already own (we exchanged our status as an owner of an equity investment in Eagle Ford for a full controlling financial interest, and we began accounting for our investment under the full consolidation method).
As shown in the table above, our remaining significant equity investments (excluding the three investments described above) as of December 31, 2013 consisted of the following:
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Midcontinent Express Pipeline LLC-we operate and own a 50% ownership 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.;
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BHP Billiton Petroleum (Eagle Ford Gathering) LLC, f/k/a EagleHawk Field Services LLC and referred to in this report as EagleHawk-we own a 25% ownership 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;
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Plantation Pipe Line Company-we operate and own a 51.17% ownership 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, we do not control Plantation, and we account for our investment under the equity method;
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Red Cedar Gathering Company-we own a 49% ownership interest in 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;
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Fayetteville Express Pipeline LLC-we own a 50% ownership 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;
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Parkway Pipeline LLC-we operate and own a 50% ownership interest in Parkway, the sole owner of the Parkway Pipeline refined petroleum products pipeline system. Valero Energy Corp. owns the remaining 50% interest;
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Watco Companies, LLC-we hold a preferred equity investment in Watco Companies, LLC, the largest privately held short line railroad company in the U.S. We own 100,000 Class A preferred shares and pursuant to the terms of our investment, we receive priority, cumulative cash distributions from the preferred shares at a rate of 3.25% per quarter, and we participate 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 us certain approval rights, including the right to appoint one of the members to Watco’s Board of Managers; and
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Cortez Pipeline Company-we operate and own a 50% ownership interest in Cortez Pipeline Company, the sole owner of the Cortez carbon dioxide pipeline system. A subsidiary of Exxon Mobil Corporation owns a 37% ownership interest and Cortez Vickers Pipeline Company owns the remaining 13% ownership interest.
Our earnings from equity investments were as follows (in millions):
__________
(a)
Effective May 1, 2013, we acquired the remaining 50% equity ownership interest in Eagle Ford that we did not already own and we changed our method of accounting from the equity method to full consolidation.
(b)
Effective July 1, 2011, we acquired the remaining 50% equity ownership interest in KinderHawk that we did not already own and we changed our method of accounting from the equity method to full consolidation.
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 we 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):
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(a)
2012 acquisition amount relates to acquisition of the drop-down asset groups from KMI as discussed in Note 3.
(b)
2012 disposal amount relates to the sale of our FTC Natural Gas Pipelines disposal group as discussed in Note 3. Since our 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 $1,141 million relating to our May 1, 2013 Copano acquisition as discussed in Note 3, and $5 million relating to the acquisition of the drop-down asset groups from KMI.
For more information on our accounting for goodwill, see Note 2 “Summary of Significant Accounting Policies-Goodwill.”
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 $309 million and $186 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 twenty-five 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 $2,414 million and $1,142 million, respectively, and primarily consisted of customer contracts, relationships and agreements associated with our Natural Gas Pipelines and Terminals 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 $121 million, $82 million and $61 million, respectively. Our estimated amortization expense for our intangible assets for each of the next five fiscal years (2014 - 2018) is approximately $137 million, $132 million, $129 million, $126 million and $124 million, respectively. As of December 31, 2013, the weighted average amortization period for our intangible assets was approximately twenty-one 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 as of December 31, 2013 and 2012. The table amounts exclude all debt fair value adjustments, including debt discounts and premiums (in millions):
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(a)
All of our fixed rate senior notes provide that we may redeem the notes 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)
In May 2013, in association with the increase in capacity negotiated for our senior unsecured revolving bank credit facility (see “-Credit Facility” below), we increased our commercial paper program by $500 million to provide for the issuance of up to $2.7 billion. As of December 31, 2013 and 2012, the average interest rates on our outstanding commercial paper borrowings were 0.28% and 0.45%, respectively. The borrowings under our commercial paper program were used principally to finance the acquisitions and capital expansions we made during 2013 and 2012.
(c)
See “-Credit Facility and Restrictive Covenants” below.
(d)
Consists of six separate series of fixed-rate unsecured senior notes that we assumed as part of the August 2012 drop-down transaction.
(e)
Consists of four separate series of fixed-rate unsecured senior notes that we assumed as part of the August 2012 and March 2013 drop-down transactions.
(f)
Consists of a single series of fixed-rate unsecured senior notes that we guaranteed as part of our May 1, 2013 Copano acquisition. For further information about these notes, see “-2013 Changes in Debt-Copano Debt” below; for further information about our guarantee, see Note 18 “Guarantee of Securities of Subsidiaries.”
(g)
Includes commercial paper borrowings.
(h)
Excludes debt fair value adjustments. As of December 31, 2013 and 2012, our “Debt fair value adjustments” increased our debt balances by $1,214 million and $1,698 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 “Risk Management-Debt Fair Value Adjustments.”
Credit Facility and Restrictive Covenants
On May 1, 2013, we replaced our 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 our credit facility can be used for general partnership purposes and as a backup for our commercial paper program, and borrowings under our commercial paper program reduce the borrowings allowed under our credit facility. We had no borrowings under the credit facility as of December 31, 2013, and there were no borrowings under our previous credit facility as of December 31, 2012. Our new credit facility’s financial covenants are substantially similar to those in our previous facility, and as of December 31, 2013, we were in compliance with all required financial covenants (described following). Our credit facility provides that both the margin we will pay with respect to borrowings, and the facility fee we will pay on the total commitment, will vary based on our senior debt credit rating. Interest on the credit facility accrues at our option at a floating rate equal to either:
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the administrative agent’s base rate, plus a margin, which varies depending upon the credit rating of our 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
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LIBOR for a one-month eurodollar loan, plus a margin, which varies depending upon the credit rating of our long-term senior unsecured debt.
In addition, we had, as of December 31, 2013, $1,518 million of borrowing capacity available under our credit facility. The amount available for borrowing under our credit facility was reduced by a combined amount of $1,182 million, consisting of $979 million of commercial paper borrowings and $203 million of letters of credit, consisting of (i) a $100 million letter of credit that supports certain proceedings with the CPUC involving refined petroleum products tariff charges on the intrastate common carrier operations of our Pacific operations’ pipelines in the state of California; (ii) a combined $84 million in three letters of credit that support tax-exempt bonds; and (iii) a combined $19 million in other letters of credit supporting other obligations of us and our subsidiaries.
Our credit facility included the following restrictive covenants as of December 31, 2013:
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total debt divided by earnings before interest, income taxes, depreciation and amortization for the preceding four quarters may not exceed:
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5.5, in the case of any such period ended on the last day of (i) a fiscal quarter in which we make any Specified Acquisition (as defined in the credit facility), or (ii) the first or second fiscal quarter next succeeding such a fiscal quarter; or
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5.0, in the case of any such period ended on the last day of any other fiscal quarter;
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certain limitations on entering into mergers, consolidations and sales of assets;
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limitations on granting liens; and
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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 our credit facility, the occurrence at any time of any of the following would constitute an event of default (i) our 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) our 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 us 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 our liquidation, reorganization or any other similar relief under any federal, state or foreign bankruptcy, insolvency, receivership or similar law.
Our credit facility does not contain a material adverse change clause coupled with a lockbox provision; however, the facility does provide that the margin we will pay with respect to borrowings, and the facility fee that we will pay on the total commitment, will vary based on our senior debt credit rating. None of our debt is subject to payment acceleration as a result of any change to our credit ratings.
2013 Changes in Debt
KMEP Debt
During 2013, we completed two separate public offerings of senior notes. With regard to these offerings, we received net proceeds as follows (i) $991 million from a February 28, 2013 public offering with a combined total of $1 billion in principal amount of senior notes in two separate series, consisting of $600 million of 3.50% notes due September 1, 2023 and $400 million of 5.00% notes due March 1, 2043 and (ii) $1,724 million from an August 5, 2013 public offering with a combined total of $1.75 billion in principal amount of senior notes in three separate series, consisting of $800 million of 2.65% notes due February 1, 2019, $650 million of 4.15% notes due February 1, 2024, and $300 million of 5.00% notes due March 1, 2043 (the 5.00% notes we issued in August 2013 constitute a further issuance of the $400 million aggregate principal amount of 5.00% notes we issued in February 2013 and form a single series with those notes). We used the proceeds from our February 2013 debt offering to pay a portion of the purchase price for our March 2013 drop-down transaction and to reduce the borrowings under our commercial paper program. We used the proceeds from our August 2013 debt offering to reduce the borrowings under our commercial paper program and to fund our partial redemption and retirement of Copano’s 7.125% senior notes in September 2013 (described following in “-Copano Debt).
In addition, on December 15, 2013, we paid $500 million to retire the principal amount of our 5.00% senior notes that matured on that date. We borrowed the necessary funds under our commercial paper program.
Copano Debt
As of our May 1, 2013 acquisition date, we 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 our acquisition, we repaid the outstanding $404 million of borrowings under Copano’s revolving credit facility, and we terminated the credit facility at the time of such repayment. On June 1, 2013, we 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 our May 1, 2013 purchase price allocation, we valued the 7.75% senior notes equal to the $259 million redemption value and accordingly, we recorded no gain or loss from this debt retirement. We utilized borrowings under our commercial paper program for both of these debt retirements.
On September 4, 2013, we 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 our May 1, 2013 purchase price allocation, we valued the repaid portion of the 7.125% senior notes equal to the $191 million redemption value and accordingly, we 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.
Kinder Morgan Altamont LLC (EP midstream assets) Debt
In February 2013, prior to the close of the March 2013 drop-down transaction, we and KMI each contributed $45 million to Kinder Morgan Altamont LLC to allow it to repay the outstanding $90 million of borrowings under its revolving credit facility and following this repayment, Kinder Morgan Altamont LLC had no outstanding debt. In May 2013, we terminated the credit facility.
2012 Changes in Debt
KMEP Debt
During 2012, we completed two separate public offerings of senior notes. With regard to these offerings, we received net proceeds as follows (i) $994 million from a March 14, 2012 public offering of a total of $1 billion in principal amount of 3.95% senior notes due September 1, 2022 and (ii) $1,236 million from an August 13, 2012 public offering of a total of $1,250 million in principal amount of senior notes in two separate series, consisting of $625 million of 3.45% notes due February 15, 2023, and $625 million of 5.00% notes due August 15, 2042. We used the proceeds from our March 2012 debt offering to both retire our $450 million of 7.125% senior notes that matured on March 15, 2012, and reduce the borrowings under our commercial paper program. We used the proceeds from our August 2012 debt offering to pay a portion of the purchase price for our August 2012 drop-down transaction.
On August 6, 2012, we entered into a new credit facility with us as borrower; Wells Fargo Bank, National Association, as administrative agent; Barclays Bank PLC, as syndication agent; and a syndicate of other lenders. This credit facility provided for borrowings up to $2.0 billion pursuant to a short-term bridge loan credit facility with a term of six months. The covenants of this bridge loan credit facility were substantially similar to the covenants of our then-existing $2.2 billion senior unsecured revolving credit facility that was due July 1, 2016, and borrowings under the bridge loan credit facility could be used to back our commercial paper issuances and for other general partnership purposes (including to pay a portion of the purchase price for the August 2012 drop-down transaction). In August 2012, we made borrowings of $576 million under the short-term bridge loan credit facility to pay a portion of the purchase price for the August 2012 drop-down transaction. We then repaid these credit facility borrowings in August 2012 with incremental borrowings under our commercial paper program, and we terminated the bridge loan credit facility on November 16, 2012. At that time, we also repaid the incremental commercial paper borrowings with the net proceeds we received from the disposal of our FTC Natural Gas Pipelines disposal group.
On September 15, 2012, we paid $500 million to retire the principal amount of our 5.85% senior notes that matured on that date. We borrowed the necessary funds under our commercial paper program.
KMI Asset Drop-Downs
We assumed the following debt amounts in 2012 as part of the drop-down transactions (i) $1,790 million combined principal amount of fixed-rate unsecured senior notes (TGP is the obligor); (ii) $1,115 million combined principal amount of
fixed-rate unsecured senior notes (EPNG is the obligor); and (iii) $95 million of outstanding EP midstream assets credit facility borrowings (Kinder Morgan Altamont LLC was the obligor). The interest rates on the TGP notes range from 7% per annum through 8.375% per annum, and the maturity dates range from February 2016 through April 2037. The interest rates on the EPNG notes range from 5.95% per annum through 8.625% per annum, and the maturity dates range from April 2017 through June 2032. The EP midstream assets’ revolving credit facility had a maturity date of June 10, 2016, however, as discussed above in “-2013 Debt Changes,” we repaid all outstanding borrowings and terminated the credit facility in May 2013. During 2012, we made net repayments of $17 million, and as of December 31, 2012, the outstanding balance under this credit facility was $78 million.
Maturities of Debt
The scheduled maturities of our outstanding debt, excluding the value of interest rate swaps, 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 4.62% during 2013 and 4.24% during 2012. Information on our interest rate swaps is contained in Note 13 “Risk Management-Interest Rate Risk Management.” For information about our contingent debt agreements, see Note 12 “Commitments and Contingent Liabilities-Contingent Debt.”
Subsequent Event
On January 17, 2014, we 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 our existing senior credit facility that is due May 1, 2018. In conjunction with the establishment of our liquidity facility, we increased our commercial paper program to provide for the issuance of up to $3.7 billion (up from $2.7 billion). Our liquidity facility supports our commercial paper program, and borrowings under our commercial paper program reduce the borrowings allowed under our liquidity facility. As of the date of this report, we had no borrowings under our liquidity facility.
9. Employee Benefits
Pension and Other Postretirement Benefit Plans
Two of our 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 also provide postretirement benefits other than pensions for retired employees. Our 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, we estimate our overall net periodic pension and other postretirement benefit costs for these plans for 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, we expect to contribute approximately $10 million to these benefit plans in 2014.
Our subsidiaries TGP and EPNG also provide postretirement benefits other than pensions for certain retired employees. The costs for these plans are prefunded to the extent such costs are recoverable through natural gas pipeline transportation rates. Our combined net periodic benefit costs for these two other postretirement benefit plans for 2013 was a credit (increase to income) of $10 million, recognized ratably over the year. For 2012, we recognized ratably, over the seven months we
included TGP and EPNG in our consolidated results, a postretirement benefit credit (increase to income) of $4 million for these plans. As of December 31, 2013, we estimate our combined net periodic other postretirement benefit costs for the TGP and EPNG plans for 2014 will be a credit of approximately $13 million. Furthermore, we expect to make no contributions to these two benefit plans in 2014.
Additionally, our 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.
As of December 31, 2013 and 2012, the recorded value of our benefit liabilities for all of our pension and other postretirement benefit plans (including benefit liabilities for inactive employees after employment but before retirement) was a combined $61 million and $76 million, respectively. As of these same dates, the TGP and EPNG other postretirement benefit plans for retired employees were overfunded by a combined $119 million and $76 million, respectively. We consider our overall pension and other postretirement benefit liability exposure and the fair value of our pension and other postretirement plan assets to be minimal in relation to the value of our total consolidated assets and net income.
Multi-employer Plans
As a result of acquiring several terminal operations, primarily our acquisition of Kinder Morgan Bulk Terminals, Inc. effective July 1, 1998, we participate in several multi-employer pension plans for the benefit of employees who are union members. We do not administer these plans and contribute 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 for each of the years ended December 31, 2013, 2012 and 2011 were $11 million, $11 million and $12 million, respectively. We consider our overall multi-employer pension plan liability exposure to be minimal in relation to the value of our total consolidated assets and net income.
Kinder Morgan Savings Plan
The Kinder Morgan Savings Plan is a defined contribution 401(k) plan. The Savings Plan permits all full-time employees of KMI and KMGP Services Company, Inc. to contribute between 1% and 50% of base compensation, on a pre-tax basis, into participant accounts. Currently, our general partner contributes an amount equal to 5% of base compensation per year for most plan participants. However, for certain plan participants, employee contributions and general partner contributions are based on collective bargaining agreements. Plan assets are held and distributed pursuant to a trust agreement. The total amount charged to expense for the Kinder Morgan Savings Plan was $19 million during 2013, $16 million during 2012, and $17 million during 2011.
Kinder Morgan Retirement Plan
The Kinder Morgan Retirement 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 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.
10. Partners’ Capital
Limited Partner Units
As of December 31, 2013 and 2012, our partners’ capital included the following limited partner units:
__________
(a)
As of both December 31, 2013 and December 31, 2012, all of our Class B units were held by a wholly-owned subsidiary of KMI. The Class B units are similar to our common units except that they are not eligible for trading on the NYSE
(b)
As of both December 31, 2013 and 2012, all of our i-units were held by KMR. Our i-units are a separate class of limited partner interests in us and are not publicly traded. In accordance with KMR’s LLC agreement, KMR’s activities are restricted to being a limited partner in us, and to controlling and managing our business and affairs and the business and affairs of our operating limited partnerships and their subsidiaries. Through the combined effect of the provisions in our partnership agreement and the provisions of KMR’s LLC agreement, the number of outstanding KMR shares and the number of our i-units will at all times be equal. The number of i-units we distribute to KMR is based upon the amount of cash we distribute to the owners of our common units. When cash is paid to the holders of our common units, we issue additional i-units to KMR. The fraction of an i-unit paid per i-unit owned by KMR will have a value based on the cash payment on the common units.
The total limited partner units represent our limited partners’ interest and an effective 98% interest in us, exclusive of our general partner’s right to receive incentive distributions. Our general partner has an effective 2% interest in us, excluding its right to receive incentive distributions.
Equity Issuances
2013 Issuances
On June 3, 2013, we entered into a fourth amended and restated equity distribution agreement with UBS Securities LLC, referred to as UBS, which increased the aggregate offering price of our common units to up to $2.175 billion (up from $1.9 billion), and on August 7, 2013, we replaced the amended and restated equity agreement with a new equity distribution agreement with UBS. The terms of this new equity distribution agreement are substantially similar to those in our previous agreement, and it allows us to offer and sell from time to time additional common units having an aggregate offering price of up to $1.9 billion through UBS, as sales agent. During the year ended December 31, 2013, we issued 10,814,474 of our common units pursuant to our equity distribution agreements with UBS. We received net proceeds from the issuance of these common units of $900 million, and we used the proceeds to reduce the borrowings under our commercial paper program.
Sales of common units pursuant to our equity distribution agreement are made by means of ordinary brokers’ transactions on the New York Stock Exchange at market prices, in block transactions or as otherwise agreed between us and UBS. Under the terms of this agreement, we also may sell common units to UBS as principal for its own account at a price agreed upon at the time of the sale. Any sale of common units to UBS as principal would be pursuant to the terms of a separate agreement between us and UBS.
Our equity distribution agreement provides us the right, but not the obligation, to sell common units in the future, at prices we deem appropriate. We retain at all times complete control over the amount and the timing of each sale, and we will designate the maximum number of common units to be sold through UBS, on a daily basis or otherwise as we and UBS agree. UBS will then use its reasonable efforts to sell, as our sales agent and on our behalf, all of the designated common units. We may instruct UBS not to sell common units if the sales cannot be effected at or above the price designated by us in any such instruction. Either we or UBS may suspend the offering of common units pursuant to the agreement by notifying the other party.
Additionally, during the year ended December 31, 2013, we issued 2,640,196 i-units to KMR. We received net proceeds of $210 million for the issuance of these i-units, and we used the proceeds to reduce the borrowings under our commercial paper program. KMR realized net proceeds of $210 million from the issuance of 2,640,196 of its shares pursuant to its equity distribution agreement with Credit Suisse, and KMR used the net proceeds received from the issuance of these shares to buy the additional i-units from us. KMR entered into its equity distribution agreement with Credit Suisse on May 4, 2012. The terms of this agreement are substantially similar to the terms of our equity distribution agreement with UBS, and it allows KMR to sell from time to time through Credit Suisse, as KMR’s sales agent, KMR’s shares representing limited liability company interests having an aggregate offering price of up to $500 million.
For the year ended December 31, 2013, in addition to the issuance of units described above, our significant equity issuances consisted of the following:
•
on February 26, 2013, we issued, in a public offering, 4,600,000 of our common units at a price of $86.35 per unit, less commissions and underwriting expenses. We received net proceeds of $385 million for the issuance of these 4,600,000 common units, and we used the proceeds to pay a portion of the purchase price for the March 2013 drop-down transaction;
•
on March 1, 2013, in connection with the March 2013 drop-down transaction, we issued 1,249,452 of our common units to KMI. We valued the units at $108 million, based on the $86.72 closing market price of a common unit on the NYSE on March 1, 2013; and
•
on May 1, 2013, we issued 43,371,210 common units to Copano unitholders as our purchase price for Copano. We valued the units at $3,733 million, based on the $86.08 closing market price of a common unit on the NYSE on May 1, 2013.
2012 Issuances
On February 27, 2012, we entered into a third amended and restated equity distribution agreement with UBS which increased the aggregate offering price of our common units to up to $1.9 billion (up from $1.2 billion). During the year ended December 31, 2012, we issued 6,932,576 of our common units pursuant to our equity distribution agreement with UBS. We received net proceeds of $560 million from the issuance of these common units and we used the proceeds to reduce the borrowings under our commercial paper program.
For the year ended December 31, 2012, in addition to the issuance of common units pursuant to our equity distribution agreement, our significant equity issuances consisted of the following:
•
on June 4, 2012, we issued 3,792,461 common units as our purchase price for our initial 50% equity ownership interest in the EP midstream assets we acquired from KKR. For more information about this issuance, see Note 3 “Acquisitions and Divestitures-Business Combinations and Acquisitions of Investments-(6) EP Midstream Assets (1 of 2);”
•
on August 13, 2012, in connection with the drop-down transaction, we issued 4,667,575 of our common units to KMI. We valued the units at $381 million, based on the $81.52 closing market price of the common units on the NYSE on August 13, 2012. For more information on the drop-down transaction, see Note 3 “Acquisitions and Divestitures-KMI Asset Drop-Downs-August 2012 KMI Asset Drop-Down;”
•
in the third quarter of 2012, KMR issued 10,120,000 of its shares in a public offering at a price of approximately $73.50 per share, less commissions and underwriting expenses. KMR used the net proceeds received from the issuance of these 10,120,000 shares to buy additional i-units from us, and we received net proceeds of $727 million. We used the proceeds to pay a portion of the purchase price for the August 2012 drop-down transaction; and
•
on December 14, 2012, we issued, in a public offering, 4,485,000 of our common units at a price of $78.60 per unit, less commissions and underwriting expenses. We received net proceeds, after deducting the underwriter discount, of $349 million for the issuance of these 4,485,000 common units, and we used the proceeds to reduce the borrowings under our commercial paper program.
Adjustment to Partners’ Capital from KMI Asset Drop-Downs
We accounted for the drop-down transactions as combinations of entities under common control, and accordingly, we recognized the assets we acquired and the liabilities we assumed at KMI’s carrying value (including all purchase accounting adjustments from KMI’s acquisition of the drop-down asset groups from EP effective May 25, 2012). We then recognized the difference between our purchase price and the carrying value of the assets acquired and liabilities assumed as an adjustment to our Partners’ Capital. As of December 31, 2012, the carrying value of the assets we acquired and the liabilities we assumed
from the drop-down transactions totaled $7,477 million. We paid to KMI $3,465 million in cash, issued to KMI 4,667,575 common units valued at $381 million, and recognized a non-cash increase of $3,631 million in our Partners’ Capital. The increase to Partners’ Capital consisted of (i) a $3,594 million increase in our general partner’s 1% general partner capital interest in us; (ii) a $36 million increase in our general partner’s 1.0101% general partner capital interest in our subsidiary Kinder Morgan Operating L.P. “A” (a noncontrolling interest to us); and (iii) a $1 million increase in our “Accumulated other comprehensive income” (related to a small tax adjustment on the drop-down asset group’s deferred pension gains from periods prior to our acquisition of August 1, 2012).
In 2013, we paid to KMI $994 million in cash, issued to KMI 1,249,452 common units valued at $108 million, and recognized a $35 million increase from net contributions KMI made to the March 2013 drop-down asset group in periods prior to our March 1, 2013 acquisition date. These consideration exchanges resulted in a $1,067 million decrease in our Partners’ Capital in 2013, consisting of (i) a $1,057 million decrease in our general partner’s capital interest in us and (ii) a $10 million decrease in our noncontrolling interests.
Income Allocation and Declared Distributions
For the purposes of maintaining partner capital accounts, our partnership agreement specifies that items of income and loss shall be allocated among the partners, other than owners of i-units, 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 our general partner. Incentive distributions are generally defined as all cash distributions paid to our general partner that are in excess of 2% of the aggregate value of cash and i-units being distributed, and we determine the allocation of incentive distributions to our general partner by the amount quarterly distributions to unitholders exceed certain specified target levels, according to the provisions of our partnership agreement.
The following table provides information about our distributions for each of the years ended December 31, 2013, 2012 and 2011 (in millions except per unit and i-unit distributions amounts):
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(a)
Consisting of our common and Class B unitholders, our general partner and noncontrolling interests.
(b)
The year-to-year increases in distributions paid primarily reflect the increases in amounts distributed per unit as well as the issuance of additional units.
(c)
Under the terms of our partnership agreement, we agreed that we will not, except in liquidation, make a distribution on an i-unit other than in additional i-units or a security that has in all material respects the same rights and privileges as our i-units. The number of i-units we distribute to KMR is based upon the amount of cash we distribute to the owners of our common units. When cash is paid to the holders of our common units, we will issue additional i-units to KMR. The fraction of an i-unit paid per i-unit owned by KMR will have a value based on the cash payment on the common units. If additional units are distributed to the holders of our common units, we will issue an equivalent amount of i-units to KMR based on the number of i-units it owns. Based on the preceding, the i-units we distributed were based on the $5.26, $4.85 and $4.58 per unit paid to our common unitholders during 2013, 2012 and 2011, respectively.
(d)
Incentive distribution does not include the general partner’s initial 2% distribution of available cash.
(e)
Our general partner’s incentive distributions we paid in 2013 were reduced by a waived incentive amount of $50 million related to common units issued to finance our May 2013 Copano acquisition. Beginning with our distribution payments for the quarterly period ended June 30, 2013, and ending with our distribution payments for the quarterly period ended March 31, 2038, our general partner agreed not to take certain incentive distributions related to our acquisition of Copano. For more information about our May 2013 Copano acquisition, see Note 3 “Acquisitions and Divestitures-Business Combinations and Acquisitions of Investments-(7) Copano.” In addition, our general partner’s incentive distributions we paid in 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 our May 2010 and July 2011 KinderHawk acquisitions. Beginning with our distribution payments for the quarterly period ended June 30, 2010, and ending with our distribution payments for the quarterly period ended March 31, 2013, our general partner agreed not to take certain incentive distributions related to our acquisition of KinderHawk. For more information about our July 2011 KinderHawk acquisition, see Note 3 “Acquisitions and Divestitures-Business Combinations and Acquisitions of Investments-(3) KinderHawk and EagleHawk.” In
addition, with regard to our declared distribution for the quarterly period ended December 31, 2013 (discussed below in “-Subsequent Events”), our general partner agreed not to take certain incentive distributions of $25 million for Copano.
For further information about our partnership distributions, see Note 11 “Related Party Transactions-Partnership Interests and Distributions.”
Subsequent Events
Units issued subsequent to December 31, 2013 were comprised of (i) 198,110 of our common units and (ii) 76,100 of our i-units, both of which were issued in early January 2014, for the settlement of sales made on or before December 31, 2013 pursuant to our equity distribution agreement and KMR’s equity distribution agreement, respectively. We received net proceeds of $16 million and $6 million from the issuances of these additional common units and i-units, respectively, and we used the proceeds to reduce the borrowings under our commercial paper program.
On January 15, 2014, we declared a cash distribution of $1.36 per unit for the quarterly period ended December 31, 2013. This distribution was paid on February 14, 2014, to unitholders of record as of January 31, 2014. Since this distribution was declared after the end of the quarter, no amount is shown in our December 31, 2013 balance sheet as a distribution payable. Our common unitholders and our Class B unitholder received cash. KMR, our sole i-unitholder, received a distribution in the form of additional i-units based on the $1.36 distribution per common unit. The number of i-units distributed was 2,237,258. For each outstanding i-unit that KMR held, a fraction of an i-unit (0.017841) was issued. The fraction was determined by dividing:
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$1.36, the cash amount distributed per common unit
by
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$76.230, the average of KMR’s limited liability shares’ closing market prices from January 14-28, 2014, the ten consecutive trading days preceding the date on which the shares began to trade ex-dividend under the rules of the NYSE.
This February 14, 2014 distribution included an incentive distribution to our general partner in the amount of $445 million. This incentive distribution was affected by a waived incentive distribution amount equal to $25 million related to common units issued to finance our May 2013 Copano acquisition.
11. Related Party Transactions
General and Administrative Expenses
KMGP Services Company, Inc., a subsidiary of our general partner, provides employees and Kinder Morgan Services LLC, a wholly owned subsidiary of KMR, provides centralized payroll and employee benefits services to (i) us; (ii) our operating partnerships and subsidiaries; (iii) our general partner; and (iv) KMR (collectively referred to in this note as the Group). Employees of KMGP Services Company, Inc. are assigned to work for one or more members of the Group. The direct costs of all compensation, benefits expenses, employer taxes and other employer expenses for these employees are allocated and charged by Kinder Morgan Services LLC to the appropriate members of the Group, and the members of the Group reimburse Kinder Morgan Services LLC for their allocated shares of these direct costs. There is no profit or margin charged by Kinder Morgan Services LLC to the members of the Group. The administrative support necessary to implement these payroll and benefits services is provided by the human resource department of KMI, and the related administrative costs are allocated to members of the Group in accordance with existing expense allocation procedures.
The effect of these arrangements is that each member of the Group bears the direct compensation and employee benefits costs of its assigned or partially assigned employees, as the case may be, while also bearing its allocable share of administrative costs. Pursuant to our limited partnership agreement, we provide reimbursement for our share of these administrative costs and such reimbursements will be accounted for as described above. Additionally, we reimburse KMR with respect to costs incurred or allocated to KMR in accordance with our limited partnership agreement, the delegation of control agreement among our general partner, KMR, us and others, and KMR’s LLC agreement.
The named executive officers of our general partner and KMR and other employees that provide management or services to both KMI and the Group are employed by KMI. Additionally, other KMI employees assist in the operation of certain of our assets (discussed below in “-Operations”). These employees’ expenses are allocated without a profit component between KMI on the one hand, and the appropriate members of the Group, on the other hand.
Non-Cash Compensation and Severance Expenses
In 2013 and 2012, KMI paid and then allocated to us employee severance expense amounts of $11 million and $9 million, respectively. KMI’s severance expense was associated with its acquisition of EP on May 25, 2012, and the severance expense allocated to us was associated with the drop-down asset groups we acquired from KMI effective August 1, 2012 and March 1, 2013. However, we do not have any obligation, nor did we pay any amounts related to this allocated severance expense. We recognized $10 million of the amount allocated to us in 2013 and $7 million of the amount allocated to us in 2012 as both an expense on our income statement and a contribution to “Total Partners’ Capital” on our balance sheet. The remaining amounts of allocated severance expense for both years was included within (i) the earnings of our subsidiary EPNG in periods prior to the acquisition of our remaining 50% ownership interest in EPNG on March 1, 2013 (because we have included the historical results of EPNG as though 100% of the net assets had been transferred to us May 25, 2012) and (ii) our proportionate share of the equity earnings from our 50% ownership interest in Bear Creek (a 50%-owned equity investee of our subsidiary TGP).
In addition, for accounting purposes, KMI was required to allocate to us a portion of the compensation expense incurred from (i) a one-time special cash bonus payment that was paid to non-senior management employees in May 2011 and (ii) a May 2007 merger of its then wholly-owned subsidiary Kinder Morgan Kansas, Inc. and a wholly-owned subsidiary of Kinder Morgan Kansas, Inc.’s then parent, Knight Holdco LLC (Knight Holdco LLC was a private company owned by investors led by Richard D. Kinder, Chairman and Chief Executive Officer of our general partner and KMR, and this merger is referred to as the going-private transaction). As a subsidiary of KMI, we were then required to recognize the allocated amounts as expense on our income statements, and accordingly in 2011, we recognized non-cash compensation expense of (i) $87 million associated with the special bonus payment to non-senior management employees and (ii) $3 million associated with certain going-private transaction expenses. However, we did not have any obligation, nor did we pay any amounts related to this allocated compensation expense, and since we were not responsible for paying this expense, we recognized the amounts allocated to us as both an expense on our income statement and a contribution to “Total Partners’ Capital” on our balance sheet.
Partnership Interests and Distributions
General
Our partnership agreement requires that we distribute 100% of “Available Cash,” as defined in our partnership agreement, to our partners within 45 days following the end of each calendar quarter. Available Cash consists generally of all of our cash receipts, including cash received by our operating partnerships and net reductions in reserves, less cash disbursements and net additions to reserves and amounts payable to noncontrolling interests.
Our general partner is granted discretion by our partnership agreement, which discretion has been delegated to KMR, subject to the approval of our general partner in certain cases, to establish, maintain and adjust reserves for the proper conduct of our 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 our quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level.
Our general partner and owners of our common units and Class B units receive distributions in cash, while KMR, the sole owner of our i-units, receives distributions in additional i-units. We do not distribute cash to i-unit owners (KMR) but instead retain the cash for use in our business. However, the cash equivalent of distributions of i-units is treated as if it had actually been distributed for purposes of determining the distributions to our general partner. Each time we make a distribution, the number of i-units owned by KMR and the percentage of our total units owned by KMR increase automatically under the provisions of our partnership agreement.
Pursuant to our partnership agreement, distributions to 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 to our general partner.
Cash from Operations. Cash from operations generally refers to our cash balance on the date we commenced operations, plus all cash generated by the operation of our 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 us 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 we 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 we retain this cash and use it in our business. To date, all of our 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 us of available cash that would constitute cash from interim capital transactions would be distributed effectively as follows:
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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
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2% to our general partner, until we have distributed cash from this source in respect of a common unit outstanding since our 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 our general partner. With respect to the portion of our distribution of available cash for 2010 that was from interim capital transactions, our general partner waived this resetting of the distribution target levels.
Kinder Morgan G.P., Inc.
Kinder Morgan G.P., Inc. serves as our sole general partner. Pursuant to our partnership agreement, our general partner’s interests represent a 1% ownership interest in us, and a direct 1.0101% ownership interest in each of our five operating partnerships. Collectively, our general partner owns an effective 2% interest in our operating partnerships, excluding incentive distributions rights as follows:
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its 1.0101% direct general partner ownership interest (accounted for as a noncontrolling interest in our consolidated financial statements); and
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its 0.9899% ownership interest indirectly owned via its 1% ownership interest in us.
As of December 31, 2013, our general partner owned 1,724,000 common units, representing approximately 0.39% of our outstanding limited partner units. For information on distributions paid to our general partner, see Note 10 “Partners’ Capital-Income Allocation and Declared Distributions.”
KMI
KMI remains the sole indirect common stockholder of our general partner. Also, as of December 31, 2013, KMI directly owned 18,169,815 common units, indirectly owned 5,313,400 Class B units and 4,117,640 common units through its consolidated affiliates (including our general partner), and owned 15,934,516 KMR shares, representing an indirect ownership interest of 15,934,516 i-units. Together, these units represented approximately 9.8% of our outstanding limited partner units.
Including both its general and limited partner interests in us, at the 2013 distribution level, KMI received approximately 49% of all quarterly distributions of available cash from us, with approximately 43% attributable to its general partner interest and the remaining 6% attributable to its limited partner interest. These percentages were impacted slightly due to the general partner’s waiver of certain incentive distribution amounts, as described in Note 10 “Partners’ Capital-Income Allocation and Declared Distributions.”
KMR
As of December 31, 2013, KMR, our general partner’s delegate, remained the sole owner of our 125,323,734 i-units.
Asset Acquisitions and Sales
From time to time in the ordinary course of business, we buy and sell assets and related services from KMI and its subsidiaries. Such transactions are conducted in accordance with all applicable laws and regulations and on an arms’ length basis consistent with our policies governing such transactions. In conjunction with our acquisition of (i) certain Natural Gas Pipelines assets and partnership interests from KMI in December 1999 and December 2000; (ii) TransColorado Gas Transmission Company LLC from KMI in November 2004; (iii) TGP and 50% of EPNG from KMI in August 2012; and (iv) the remaining 50% ownership interest in EPNG and the EP midstream assets from KMI in March 2013, KMI has agreed to indemnify us and our general partner with respect to approximately $5.9 billion of our debt as of December 31, 2013. KMI would be obligated to perform under this indemnity only if we are unable, and/or our assets were insufficient, to satisfy our obligations.
Mr. C. Berdon Lawrence, a non-management director on the boards of our general partner and KMR until July 20, 2011, is also Chairman Emeritus of the Board of Kirby Corporation. On February 9, 2011, we sold a marine vessel to Kirby Corporation’s subsidiary Kirby Inland Marine, L.P., and additionally, we and Kirby Inland Marine L.P. formed a joint venture named Greens Bayou Fleeting, LLC. Pursuant to the joint venture agreement, we sold our ownership interest in the boat fleeting business we acquired from Megafleet Towing Co., Inc. in April 2009 to the joint venture for $4 million in cash and a 49% ownership interest in the joint venture. Kirby then made cash contributions to the joint venture in exchange for the remaining 51% ownership interest. In the first quarter of 2011, after final reconciliation and measurement of all of the net assets sold, we recognized a combined $2 million increase in income from the sale of these net assets, and additionally, the sale of our ownership interest resulted in an $11 million non-cash reduction in our goodwill.
Operations
Natural Gas Pipelines and Products Pipelines Business Segments
KMI (or its subsidiaries) operates and maintain for us the assets comprising our Natural Gas Pipelines business segment, as well as our Products Pipelines business segment’s 50%-owned Cypress Pipeline. Pursuant to the applicable underlying agreements, we pay (reimburse) KMI for the actual corporate general and administrative expenses incurred in connection with the operation of these assets. The combined amounts paid to KMI for corporate general and administrative costs incurred were$213 million for 2013, $198 million for 2012 and $71 million for 2011. We believe the amounts paid to KMI for the services it provided each year fairly reflect the value of the services performed; however, due to the nature of the allocations, these reimbursements may not exactly match the actual time and overhead spent. We also reimburse KMI for operating and maintenance costs and capital expenditures incurred with respect to our assets.
We sold our ownership interest in Kinder Morgan NatGas Operator LLC as part of our divestiture of the FTC Natural Gas Pipelines disposal group effective November 1, 2012. Prior to its divestiture, Kinder Morgan NatGas Operator LLC operated the Rockies Express natural gas pipeline system pursuant to an operating agreement. Under this agreement, it was reimbursed for its costs and received a management fee of 1%, based on Rockies Express’ operating income, less all depreciation and amortization expenses. In the first ten months of 2012, and the full year of 2011, it received management fees of $5 million and $6 million, respectively. Prior to its divestiture, Kinder Morgan NatGas Operator LLC also operated the Midcontinent Express pipeline system. The Midcontinent Express pipeline system is operated by one of our affiliates.
In addition, we purchase natural gas transportation and storage services from NGPL and certain affiliates, collectively. KMI owns a 20% ownership interest in NGPL and accounts for its investment under the equity method of accounting. Pursuant to the provisions of a 15-year operating agreement that was entered into in 2008, KMI continues to operate NGPL’s assets. For each of the years 2013, 2012 and 2011, expenses related to NGPL totaled $1 million, $5 million and $8 million, respectively, and we included these expense amounts within the caption “Gas purchases and other costs of sales” in our accompanying consolidated statements of income.
Terminals Business Segment
For services in the ordinary course of Kirby Corporation’s and our Terminals segment’s businesses, Kirby Corporation received payments from our subsidiaries totaling $38,729 in 2011. In turn, Kirby made payments of $44,615 to our subsidiaries in 2011.
Risk Management
Certain of our business activities expose us to risks associated with 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 fixed rate debt obligations. Pursuant to our management’s approved risk management policy, we use derivative contracts to hedge or reduce our exposure to these risks and protect our profit margins.
Our commodity-related risk management activities are monitored by our risk management committee, which is a separately designated standing committee whose job responsibilities involve operations exposed to commodity market risk and other external risks in the ordinary course of business. Our risk management committee is charged with the review and enforcement of our management’s risk management policy. The committee is comprised of 14 executive-level employees of KMI or KMGP Services Company, Inc. whose job responsibilities involve operations exposed to commodity market risk and other external risks in the ordinary course of our businesses. The committee is chaired by our Chief Financial Officer and is charged with the following three responsibilities: (i) establish and review risk limits consistent with our risk tolerance philosophy; (ii) recommend to the audit committee of our general partner’s delegate any changes, modifications, or amendments to our risk management policy; and (iii) address and resolve any other high-level risk management issues.
For more information on our risk management activities see Note 13.
KM Insurance, Ltd.
KM Insurance, Ltd. is a Class 2 Bermuda insurance company and wholly-owned subsidiary of KMI. The sole business of KM Insurance is to issue policies for KMI, EPB and us to secure the deductible portion of our workers compensation, automobile liability, and general liability policies placed in the commercial insurance market. We accrue for the cost of insurance and include these costs within our related party general and administrative expenses. For each of the years 2013, 2012 and 2011, these expenses totaled $9 million.
Notes Receivable
Plantation
We and ExxonMobil have a term loan agreement covering a note receivable due from Plantation. We own a 51.17% equity interest in Plantation and our 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 our portion of the note) due on July 20, 2016. We included $1 million of our 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,” we sold both our 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. Our 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 we had entered into a definitive agreement to sell our 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.
KMI and EP
At the time of KMI’s acquisition of EP on May 25, 2012 (discussed in Note 1), TGP and EPNG each had a note receivable from EP, and during the second quarter of 2012, TGP and EPNG received principal note repayments of approximately $44 million and $21 million, respectively. Upon our acquisition of TGP and EPNG from KMI as part of the drop-down transactions discussed in Note 2, we and KMI agreed that both the remaining $466 million amount due on TGP’s note receivable and the remaining $858 million amount due on EPNG’s note receivable would not be repaid. Accordingly, the amounts were treated as a decrease in KMI’s investment in TGP, EPNG and us, and as a result, neither TGP nor EPNG any longer has a related party note receivable with either KMI or EP. However, because we have included the historical results of TGP and EPNG as though the net assets had been transferred to us on May 25, 2012, the combined principal note repayments of $65 million are now included within “Repayments from related party” on our consolidated statement of cash flows for the year ended December 31, 2012.
Subsequent Event
On February 4, 2014, we entered into a loan agreement with Midcontinent Express Pipeline LLC, our 50%-owned equity investee. The loan agreement allows us, at our 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, we made loans totaling $4 million pursuant to this loan agreement.
Other Receivables and Payables
As of December 31, 2013 and December 31, 2012, our related party receivables (other than the notes receivable discussed above in “-Notes Receivable”) totaled $7 million and $14 million, respectively. The receivable amounts consisted of (i) $6 million and $12 million, respectively, included within “Accounts receivable, net” on our accompanying consolidated balance sheets and (ii) $1 million and $2 million, respectively, of natural gas imbalance receivables included within “Other current assets.”
The $6 million accounts receivable amount as of December 31, 2013 primarily consisted of amounts due from NGPL and Plantation, and the $1 million natural gas imbalance receivable consisted of amounts due from NGPL. The $12 million accounts receivable amount as of December 31, 2012 primarily consisted of amounts due from the Express pipeline system, and the $2 million natural gas imbalance receivable consisted of amounts due from NGPL.
As of December 31, 2013 and December 31, 2012, our related party payables totaled $13 million and $10 million, respectively. The 2013 amount consisted of (i) $12 million for amounts payable to both KMI and certain of our equity investees and included within “Accounts payable” on our accompanying consolidated balance sheet and (ii) $1 million for natural gas imbalance payables due to EPB and included within “Other current liabilities.” Our 2012 related party payable amount consisted primarily of amounts due to KMI, and we included this amount within “Accounts payable.”
Additionally, we have agreed to guarantee certain KMI lease payments from 2014 through 2035. For more information about this guarantee, see “Note 12 Commitments and Contingent Liabilities-Contingent Lease Liabilities.”
Other
Generally, KMR makes all decisions relating to the management and control of our business, and in general, KMR has a fiduciary duty to manage us in a manner beneficial to our unitholders. Our general partner owns all of KMR’s voting securities and elects all of KMR’s directors. KMI, through its wholly owned and controlled subsidiary Kinder Morgan (Delaware), Inc., owns all the common stock of our general partner, and the officers of KMI have fiduciary duties to manage KMI, including selection and management of its investments in its subsidiaries and affiliates, in a manner beneficial to the owners of KMI. Accordingly, certain conflicts of interest could arise as a result of the relationships among KMR, our general partner, KMI and us.
The partnership agreements for us and our operating partnerships contain provisions that allow KMR to take into account the interests of parties in addition to us in resolving conflicts of interest, thereby limiting its fiduciary duty to our unitholders, as well as provisions that may restrict the remedies available to our unitholders for actions taken that might, without such limitations, constitute breaches of fiduciary duty. The partnership agreements also provide that in the absence of bad faith by KMR, the resolution of a conflict by KMR will not be a breach of any duties. The duty of the officers of KMI may, therefore, come into conflict with the duties of KMR and its directors and officers to our unitholders. The audit committee of KMR’s board of directors will, at the request of KMR, review (and is one of the means for resolving) conflicts of interest that may arise between KMI or its subsidiaries, on the one hand, and us, on the other hand.
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 35 years. Total lease and rental expenses for each of the years ended December 31, 2013, 2012 and 2011 were $112 million, $92 million and $140 million, 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 our 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.
KMEP Common Unit Compensation Plan for Non-Employee Directors
On January 18, 2005, KMR’s compensation committee established the Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan. 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 our interests and the interests of our unitholders by aligning the compensation of the non-employee members of the board of directors of KMR with unitholders’ interests. Further, since KMR’s success is dependent on its operation and management of our business and our 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 plan 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.
The elections under this plan for 2013, 2012 and 2011 were made effective January 15, 2013, January 17, 2012 and January 18, 2011, respectively (the elections for 2014 were made effective January 15, 2014). Each annual election is evidenced by an agreement, the Common Unit Compensation Agreement, between us and each non-employee director, and this agreement contains the terms and conditions of each award. Pursuant to this agreement, all common units issued under this plan are subject to forfeiture restrictions that expires six months from the date of issuance. Until the forfeiture restrictions lapse, common units issued under the plan may not be sold, assigned, transferred, exchanged, or pledged by a non-employee director. In the event the director’s service as a director of KMR is terminated prior to the lapse of the forfeiture restriction either for cause, or voluntary resignation, each director will, for no consideration, forfeit to us all common units to the extent then subject to the forfeiture restrictions. Common units with respect to which forfeiture restrictions have lapsed cease to be subject to any forfeiture restrictions, and we will provide each director a certificate representing the units as to which the forfeiture restrictions have lapsed. In addition, each non-employee director has the right to receive distributions with respect to the common units awarded to him under the plan, to vote such common units and to enjoy all other unitholder rights, including during the period prior to the lapse of the forfeiture restrictions.
The number of common units to be issued to a non-employee director electing to receive the cash compensation in the form of common units will equal the amount of such cash compensation awarded, divided by the closing price of the common units on the NYSE on the day the cash compensation is awarded (such price, the fair market value), rounded down to the nearest 50 common units. The common units will be issuable as specified in the Common Unit Compensation Agreement. A non-employee director electing to receive the cash compensation in the form of common units will receive cash equal to the difference between (i) the cash compensation awarded to such non-employee director and (ii) the number of common units to be issued to such non-employee director multiplied by the fair market value of a common unit. This cash payment is payable in four equal installments generally around March 31, June 30, September 30 and December 31 of the calendar year in which such cash compensation is awarded.
On January 18, 2011, each of KMR’s then three non-employee directors was awarded cash compensation of $180,000 for board service during 2011. Effective January 18, 2011, Mr. Hultquist and Mr. Waughtal elected to receive the full amount of their compensation in the form of cash only. Mr. Lawrence elected to receive compensation of $176,964 in the form of our common units and was issued 2,450 common units. On July 20, 2011, Mr. Lawrence resigned from the KMR and Kinder Morgan G.P., Inc. boards of directors and was replaced by Mr. Ted A. Gardner. Mr. Lawrence received remaining compensation of $1,518 paid in cash during the first half of 2011 (amount equal to one-half of the difference between (i) his total cash compensation award and (ii) the value of cash compensation received in the form of our common units according to the provisions of our Common Unit Compensation Plan for Non-Employee Directors). Mr. Gardner was awarded cash compensation of $90,000 for board service during 2011, and his compensation was paid in cash as described above. No other compensation was paid to the non-employee directors during 2011.
On January 17, 2012, each of KMR’s three non-employee directors was awarded cash compensation of $180,000 for board service during 2012. Each of the non-employee directors elected to receive the full amount of their compensation in the form of cash only. No other compensation was paid to the non-employee directors during 2012.
On January 15, 2013, each of KMR’s three non-employee directors was awarded cash compensation of $180,000 for board service during 2013. Each of the non-employee directors elected to receive the full amount of their compensation in the form of cash only. No other compensation will be paid to the non-employee directors during 2013.
On January 15, 2014, each of KMR’s three non-employee directors was awarded cash compensation of $200,000 for board service during 2014. Each of the non-employee directors elected to receive the full amount of their compensation in the form of cash only. No other compensation will be paid to the non-employee directors during 2014.
Contingent Debt
Our contingent debt disclosures pertain to certain types of guarantees or indemnifications we have made and cover certain types of guarantees included within debt agreements, even if the likelihood of requiring our performance under such guarantee is remote. As of December 31, 2013 and 2012, our contingent debt obligations, as well as our obligations with respect to related letters of credit, totaled $74 million and $86 million, respectively. This amount primarily related to the debt obligations of our 50%-owned investee Cortez Pipeline Company (we are severally liable for our percentage ownership share (50%) of the Cortez Pipeline Company debt).
For additional information regarding our debt facilities see Note 8 “Debt.”
Contingent Lease Liabilities
We have agreed to guarantee certain lease payments from 2014 through 2035 made by KMI to EPC Building, LLC, a wholly-owned subsidiary of KMI, related to KMP’s principal executive offices located at 1001 Louisiana Street in Houston, Texas. We would be required to perform under this guarantee only if KMI was unable to perform. During the term of this lease, the payments we guarantee increase from $27 million in 2014 to $38 million in 2035.
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. Additionally, as part of our May 1, 2013 Copano acquisition, we 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, we had entered into the following outstanding commodity forward contracts to hedge our 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, we had a combined notional principal amount of $4,675 million of fixed-to-variable interest rate swap agreements, effectively converting the interest expense associated with certain series of our senior notes from fixed rates to variable rates based on an interest rate of LIBOR plus a spread. All of our 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, we terminated three of our existing fixed-to-variable interest rate swap agreements in separate transactions. These swap agreements had a combined notional principal amount of $975 million, and we received combined proceeds of $96 million from the early termination of these swap agreements. In August 2013, we 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 our 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 our 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 principal amount of $375 million and effectively converting a portion of the interest expense associated with our 5.00% senior notes terminated upon the maturing of the associated notes.
As of December 31, 2012, we had a combined notional principal amount of $5,525 million 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 December 31, 2013 and 2012 (in millions):
___________
(a)
Cash margin deposits held by us associated with our energy commodity contract positions and OTC swap agreements and reported within “Other current liabilities” on our accompanying consolidated balance sheets.
(b)
Cash margin deposits posted by us associated with our energy commodity contract positions and OTC swap agreements and reported within “Other current assets” on 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) $645 million and $638 million, respectively, associated with fair value adjustments to our debt previously recorded in purchase accounting; (ii) $101 million and $602 million, respectively, associated with the offsetting entry for hedged debt; (iii) $517 million and $488 million, respectively, associated with unamortized premium from the termination of interest rate swap agreements; and offset by (iv) $49 million and $30 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 $6 million loss associated with energy commodity price risk management activities and included in our Partners’ Capital 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 year ended December 31, 2013, we recognized losses of $9 million from derivative contracts not designated as accounting hedges. We included this loss amount within “Revenues-Product sales and other” on our accompanying consolidated statement of income. For the years ended December 31, 2012 and 2011, we recognized no material gain or loss in income from derivative contracts not designated as accounting hedges.
Credit Risks
We have counterparty credit risk as a result of our use of financial derivative contracts. Our counterparties consist primarily of financial institutions, major energy companies 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, we had no outstanding letters of credit supporting our hedging of energy commodity price risks associated with the sale of natural gas, NGL and crude oil.
We also have agreements with certain counterparties to our derivative contracts that contain provisions requiring us to post additional collateral upon a decrease in our credit rating. As of December 31, 2013, we estimate that if our credit rating was downgraded one notch, we would be required to post no additional collateral to our counterparties. If we were downgraded two notches (that is, below investment grade), we would be required to post $8 million of additional collateral.
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 income” within “Partners’ Capital” in our consolidated balance sheets. Changes in the components of our “Accumulated other comprehensive income” 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:
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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;
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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
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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 and NGL options.
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):
____________
(a)
2013 purchases include a net asset of $18 million of Level 3 energy commodity derivative contracts assumed in conjunction with our May 1, 2013 Copano acquisition.
As of December 31, 2013, our Level 3 derivative assets and liabilities consisted primarily of WTI options and NGL options, 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 our management’s best estimate of fair value.
Fair Value of Financial Instruments
The estimated fair value of our outstanding debt balance as of December 31, 2013 and 2012 (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 operate in five reportable business segments. These segments and their principal sources of revenues are as follows:
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Natural Gas Pipelines-the sale, transport, processing, treating, fractionation, storage and gathering of natural gas and NGL;
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CO2-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;
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Products Pipelines-the transportation and terminaling of refined petroleum products (including gasoline, diesel fuel and jet fuel), NGL, crude oil and condensate, and bio-fuels;
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Terminals-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; and
▪
Kinder Morgan Canada-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.
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.
Financial information by segment follows (in millions):
____________
(a)
Includes natural gas purchases and other costs of sales, operations and maintenance expenses, and taxes, other than income taxes.
(b)
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 our previously held 50% equity interest in KinderHawk to fair value (discussed further in Note 3).
(c)
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).
(d)
2013 amount includes an $84 million increase in expense related to the pre-tax gain amount described in footnote (c).
(e)
Includes revenues, earnings from equity investments, allocable interest income, and other, net, less operating expenses, allocable income taxes, and other expense (income).
(f)
The increases in the 2013 and 2012 amounts versus the respective prior year amounts reflect our acquisition of the drop-down asset groups from KMI, and for 2013 versus 2012 only, our acquisition of Copano. For further information about these acquisitions, see Note 3.
(g)
Represents amounts from our FTC Natural Gas Pipelines disposal group. For further information, see Note 3.
(h)
Includes cash and cash equivalents; margin and restricted deposits; unallocable interest receivable, prepaid assets and deferred charges; and risk management assets related to debt fair value adjustments.
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 $862 million, $713 million and $534 million, respectively.
Our revenue is derived from a wide customer base. For each of the years ended December 31, 2013, 2012 and 2011, no revenues from transactions with a single external customer amounted to 10% or more of our total consolidated revenues.
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 (i) goodwill; (ii) other intangibles, net; and (iii) long-term note receivables from related parties.
16. Litigation, Environmental and Other Contingencies
We are party to various legal, regulatory and other matters arising from the day-to-day operations of our businesses that may result in claims against the Partnership. 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 distributions to limited partners. We believe we have meritorious defenses to the matters to which we are a party and intend to vigorously defend the Partnership. 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 2 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 we may include in our 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 our distributions to our limited partners.
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
We have 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 we believe 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 our review of these CPUC proceedings and the shipper comments thereon, we estimate 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 our business, financial position or results of operations. Furthermore, we do not expect any reparations that we would pay in this matter to impact the per unit cash distributions we expect to pay to our limited partners for 2014.
Copano Shareholders’ Litigation
Three putative class action lawsuits were filed in connection with our 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, we have increased our 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. We believe 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 our 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.
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 $611 million and $404 million, respectively. The reserve primarily relates to various claims from regulatory proceedings arising from our 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 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 distributions to limited partners.
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 forty 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. We are participating in the allocation process on behalf of both KMLT and KMBT. Each entity has two facilities located in Portland Harbor. We expect 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, we 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 us 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, we 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 our permit request to increase the discharge of water from our 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 and approximately one hundred 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 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 $168 million and $166 million, respectively.
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. Guarantee of Securities of Subsidiaries
KMEP has guaranteed the payment of Copano’s outstanding series of senior notes that mature on April 1, 2021 (referred to in this report as the “Guaranteed Notes”). Copano Energy Finance Corporation (Copano Finance Corp), a direct subsidiary of Copano, is the co-issuer of the Guaranteed Notes. Excluding fair value adjustments, as of December 31, 2013, Copano had $332 million of Guaranteed Notes outstanding. Copano Finance Corp’s obligations as a co-issuer and primary obligor are the same as and joint and several with the obligations of Copano as issuer, however, it has no subsidiaries and no independent assets or operations. Subject to the limitations set forth in the applicable supplemental indentures, KMEP’s guarantee is full and unconditional and guarantees the Guaranteed Notes through their maturity date.
A significant amount of KMEP’s income and cash flow is generated by its respective subsidiaries. As a result, the funds necessary to meet its debt service and/or guarantee obligations are provided in large part by distributions or advances it receives from its respective subsidiaries. For purposes of the condensed consolidating financial information, distributions from our wholly owned subsidiaries have been presented as operating cash flows whether or not distributions exceeded cumulative earnings. In addition, we utilize a centralized cash pooling program among our majority-owned and consolidated subsidiaries, including the subsidiary issuers and non-guarantor subsidiaries. The following Condensed Consolidating Statements of Cash Flows present the intercompany loan and distribution activity, as well as cash collection and payments made on behalf of our subsidiaries, as cash activities.
Included among the non-guarantor subsidiaries are KMEP’s five operating limited partnerships and their majority-owned and controlled subsidiaries, along with Copano’s remaining majority-owned and controlled subsidiaries. In the following condensed consolidating financial information, KMEP is “Parent Guarantor,” and Copano and Copano Finance Corp are the “Subsidiary Issuers.” The Subsidiary Issuers are 100% owned by KMEP.
Supplemental Selected Quarterly Financial Data (Unaudited)
____________
(a)
First quarter 2013 includes a $225 million non-operating gain from the sale of our equity and debt investments in the Express pipeline system.
(b)
Second quarter 2013 includes (i) a $558 million non-operating gain from the remeasurement of our previously held 50% equity interest in Eagle Ford to fair value; and (ii) reflects our acquisition of Copano effective May 1, 2013.
(c)
Third quarter 2013 includes a $1 million non-operating loss from the sale of our equity and debt investments in the Express pipeline system.
(d)
First quarter 2012 includes a $322 million discontinued operations loss from the remeasurement of our FTC Natural Gas Pipelines disposal group to fair value.
(e)
Second quarter 2012 includes a $327 million discontinued operations loss from the remeasurement of our FTC Natural Gas Pipelines disposal group to fair value.
(f)
Third quarter 2012 includes a $178 million discontinued operations loss from both costs to sell and the remeasurement of our FTC Natural Gas Pipelines disposal group to fair value.
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 our 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 us.
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 us. 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, our CO2 business segment managers and our Vice President (President, CO2) review all significant reserves changes and all new proved developed and undeveloped reserves additions; and
▪
our CO2 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 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 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.
Our 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 ENERGY PARTNERS, L.P.
Registrant (a Delaware Limited Partnership)
By: KINDER MORGAN G.P., INC.,
Its sole General Partner
By: KINDER MORGAN MANAGEMENT, LLC, the Delegate of Kinder Morgan G.P., Inc.
By: /s/ KIMBERLY A. DANG
Kimberly A. Dang,
Vice President and Chief Financial Officer
(principal financial and accounting officer)
Date: February 18, 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 of Kinder Morgan Management, LLC, Delegate of Kinder Morgan G.P., Inc. (principal financial and accounting officer)
February 18, 2014
Kimberly A. Dang
/s/ RICHARD D. KINDER
Chairman of the Board and Chief Executive Officer of Kinder Morgan Management, LLC, Delegate of Kinder Morgan G.P., Inc. (principal executive officer)
February 18, 2014
Richard D. Kinder
/s/ TED A. GARDNER
Director of Kinder Morgan Management, LLC, Delegate of Kinder Morgan G.P., Inc.
February 18, 2014
Ted A. Gardner
/s/ GARY L. HULTQUIST
Director of Kinder Morgan Management, LLC, Delegate of Kinder Morgan G.P., Inc.
February 18, 2014
Gary L. Hultquist
/s/ PERRY M. WAUGHTAL
Director of Kinder Morgan Management, LLC, Delegate of Kinder Morgan G.P., Inc.
February 18, 2014
Perry M. Waughtal
/s/ STEVEN J. KEAN
Director, President and Chief Operating Officer of Kinder Morgan Management, LLC, Delegate of Kinder Morgan G.P., Inc.
February 18, 2014
Steven J. Kean