ITEM 1. BUSINESS
Overview and Strategy
We are a Delaware master limited partnership (MLP) formed in 2007 to own and operate interstate natural gas transportation and terminaling facilities. As of December 31, 2011, we own Wyoming Interstate Company, L.L.C. (WIC), Southern LNG Company, L.L.C. (SLNG), Elba Express Company, L.L.C. (Elba Express), Southern Natural Gas Company, L.L.C. (SNG) and an 86 percent interest in Colorado Interstate Gas Company, L.L.C. (CIG). In March 2011, we acquired an additional 25 percent interest in SNG from El Paso Corporation (El Paso). In June 2011, we acquired the remaining 15 percent interest in SNG and an additional 28 percent interest in CIG from El Paso. WIC and CIG are interstate pipeline systems serving the Rocky Mountain region, SLNG owns the Elba Island LNG storage and regasification terminal near Savannah, Georgia, and both Elba Express and SNG are interstate pipeline systems serving the southeastern region of the United States (U.S.). We are controlled by our general partner, El Paso Pipeline GP Company, L.L.C., a wholly-owned subsidiary of El Paso.
On October 16, 2011, El Paso announced a definitive agreement (the “Merger Agreement”) with Kinder Morgan, Inc. (KMI) whereby KMI will acquire El Paso in a transaction that valued El Paso at approximately $38 billion (based on the KMI stock price at that date), including the assumption of debt. The transaction has been approved by each company’s board of directors but remains subject to the approvals of El Paso’s shareholders, the Federal Trade Commission and other customary regulatory and other approvals. The approval of KMI shareholders will also be required, but a voting agreement has been executed by the majority of the shareholders of KMI to support the transaction. We will conduct our business in the ordinary course, in all material respects, in substantially the same manner as conducted prior to the date of the Merger Agreement, subject to certain conditions and restrictions. The most substantial of which are a limitation on the size of quarterly distribution increases and approval from KMI of asset drop downs from El Paso to us.
Our pipeline systems, storage facilities and LNG receiving terminal operate under tariffs approved by the FERC that establish rates, cost recovery mechanisms and other terms and conditions of services to our customers. The fees or rates established under our tariff are a function of our cost of providing services to our customers, including a reasonable return on our invested capital.
Our primary business objectives are to generate stable cash flows sufficient to make distributions to our unitholders and to grow our business through the construction, development and acquisition of additional energy infrastructure assets. We intend to increase our cash distributions over time by enhancing the value of our transportation, storage and terminaling assets by:
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focusing on customer service;
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successfully executing our committed expansion projects on time and on budget;
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developing growth projects in our market and supply area;
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focusing on the integrity and the safety of our pipeline systems and other assets;
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optimizing our contract portfolio;
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focusing on increasing utilization, efficiency and cost control in our operations; and
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pursuing strategic asset acquisitions from El Paso and third parties to grow our business.
Our Assets
The table below and discussion that follows provide detail of our pipeline systems as of December 31, 2011:
(1) The WIC throughput includes 179 BBtu/d, 183 BBtu/d and 131 BBtu/d transported by WIC on behalf of CIG for the years ended December 31, 2011, 2010 and 2009.
(2) Volumes reflected are 100 percent of the volumes transported on the CIG system.
(3) CIG’s storage capacity includes 7 Bcf of storage capacity from the Totem Gas Storage facility (Totem), which is owned by WYCO Development LLC (WYCO), CIG’s 50 percent equity investee.
(4) SNG’s storage capacity includes 29 Bcf of storage capacity associated with its 50 percent ownership interest in Bear Creek Storage Company, LLC (Bear Creek), a joint venture with Tennessee Gas Pipeline Company, L.L.C. (TGP), our affiliate.
(5) This system was placed in service in March 2010 and although capacity is under contract, the average volumes transported during 2011 and 2010 were not material.
WIC. WIC is comprised of a mainline system that extends from western Wyoming to northeast Colorado (the Cheyenne Hub) and several lateral pipeline systems that extend from various interconnections along the WIC mainline into western Colorado, northeast Wyoming and eastern Utah. WIC owns interstate natural gas transportation systems providing takeaway capacity from the mature Overthrust, Piceance, Uinta, Powder River and Green River Basins. The WIC system is operated by CIG Pipeline Services Company, L.L.C. (CIGSC) pursuant to a service agreement.
CIG. CIG is comprised of pipelines that deliver natural gas from production areas in the Rocky Mountains and the Anadarko Basin directly to customers in Colorado, Wyoming and indirectly to the midwest, southwest, California and Pacific northwest. CIG also owns interests in five storage facilities located in Colorado and Kansas and one natural gas processing plant located in Wyoming.
CIG owns a 50 percent ownership interest in WYCO, a joint venture with an affiliate of Public Service Company of Colorado (PSCo). WYCO owns Totem and the 164-mile High Plains pipeline (High Plains) both of which are in northeast Colorado and are operated by CIG. Totem has a peak withdrawal capacity of 200 MMcf/d and a maximum injection rate of 100 MMcf/d. Totem services and interconnects with High Plains. WYCO also owns a state regulated intrastate gas pipeline that extends from the Cheyenne Hub in northeast Colorado to Public Service Company of Colorado’s Fort St. Vrain’s electric generation plant, which CIG does not operate, and a compressor station in Wyoming leased by WIC.
SNG. SNG is comprised of pipelines extending from natural gas supply basins in Texas, Louisiana, Mississippi, Alabama and the Gulf of Mexico to market areas in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina and Tennessee, including the metropolitan areas of Atlanta and Birmingham. SNG owns pipeline facilities serving southeastern markets in Alabama, Georgia and South Carolina. SNG owns 100 percent of the Muldon storage facility and a 50 percent interest in Bear Creek. The storage facilities have a combined peak withdrawal capacity of 1.2 Bcf/d. The SNG system is also connected to SLNG’s Elba Island LNG terminal.
Elba Express. Elba Express owns the Elba Express pipeline which transports natural gas supplies from the Elba Island LNG terminal to markets in the southeastern and eastern U.S. Under a firm transportation service agreement, the entire capacity of Elba Express is contracted to Shell NA LNG, LLC (Shell LNG) for 30 years at a fixed rate that will be reduced beginning on December 31, 2013 and remains flat thereafter. The firm transportation service agreement is supported by a step-down parent guarantee from Shell Oil Company (Shell) that secures the timely performance of the obligations of the agreement.
SLNG. SLNG owns the Elba Island LNG receiving terminal, located near Savannah, Georgia. The Elba Island LNG terminal is one of nine land based terminal facilities in the U.S. capable of providing domestic storage and vaporization services to international producers of LNG. The Elba Island LNG terminal has approximately 11.5 Bcf equivalent of LNG storage capacity and approximately
1.8 Bcf/d of peak send-out capacity. The capacity of the Elba Island LNG terminal is fully contracted with BG LNG Services, LLC under a conventional recourse rate contract and Shell LNG under a long-term step-down fixed rate contract (that will be reduced beginning on December 31, 2013 and remain flat thereafter). The firm SLNG service agreements are supported by parent guarantees from BG Energy Holdings Limited (BG) and Shell that secure the timely performance of the obligations of those agreements. The Elba Island LNG terminal is directly connected to three interstate pipelines, indirectly connected to two others, and also connected by commercial arrangements to a major local distribution company; thus, is readily accessible to the southeast and mid-Atlantic markets. SNG Pipeline Services Company, L.L.C (SNGSC) operates the Elba Island LNG terminal pursuant to a service agreement.
Markets and Competition
Our customers consist of natural gas distribution and industrial companies, electric generation companies, natural gas producers, other natural gas pipelines and natural gas marketing and trading companies. We provide transportation and storage services in both our natural gas supply and market areas, and in doing so, we compete with other pipeline service providers as well as alternative energy sources such as coal, nuclear energy, wind, hydroelectric power, solar and fuel oil.
The natural gas industry has experienced a major shift in supply sources, from conventional to unconventional, such as shales. The source shift will affect the supply patterns, the flows and the rates that can be charged on pipeline systems. The impacts will vary among pipelines according to the location and the number of competitors attached to these new supply sources. Our SNG system is directly connected to the Haynesville Shale formation in northern Louisiana and indirectly connected, through new interconnecting pipelines, to the Barnett Shale, Bossier Sands, Woodford Shale and Fayetteville Shale. The divergence of oil prices above natural gas prices has also led to an increase in production from associated gas, or natural gas found in association with oil.
Another change in the supply patterns is the reduction in imports from Canada. The decreases in imported supplies from Canada have been the result of declining conventional production and increasing demand in Canada. On the Southern border, exports to Mexico are increasing and may increase further over time as demand growth exceeds production growth in that country. In addition to these trends in Canada and Mexico, imports of LNG to the U.S. have been declining over the last several years in response to increased U.S. shale gas production which has resulted in a decline in U.S. natural gas prices relative to gas prices in Europe and Asia. The projected gas price disparity between U.S. and European/Asian markets suggests that North America could change from a net importer of LNG to a net exporter of LNG before the end of this decade. All of the aforementioned factors have led to increased demand for domestic U.S. supplies and related transportation services over the last several years, a trend which is likely to continue.
Electric power generation has been the source of most of the demand growth for natural gas over the last 10 years, and this trend is expected to continue. The growth of natural gas in this sector is influenced by competition with coal and economic growth. Short-term market shifts have been driven by relative electricity generation costs of coal-fired plants versus gas-fired plants. A long-term market shift in the use of coal in power generation could be driven by environmental regulations. The future demand for natural gas could be increased by regulations limiting or discouraging coal use. However, natural gas demand could potentially be adversely affected by laws mandating or encouraging renewable power sources. Industrial demand has also grown recently with the economic recovery and low natural gas price environment, and this sector offers an opportunity for continued growth. In addition, a potential new and significant demand market for North American natural gas production is for LNG exports to Europe and Asia. Several Gulf Coast projects have received Department of Energy approval to export LNG to global markets beginning in the second half of this decade.
For a further discussion of factors impacting our markets and competition, See Item 1A.
ITEM 1A. RISK FACTORS
CAUTIONARY STATEMENT REGARDING FORWARD LOOKING STATEMENTS
This report contains forward-looking statements that are based on assumptions or beliefs that we believe to be reasonable; however, assumed facts almost always vary from the actual results and such variances can be material. Where we express an expectation or belief as to future results, that expectation or belief is expressed in good faith and is believed to have a reasonable basis. We cannot assure you, however, that the stated expectation or belief will occur. The words “believe,” “expect,” “estimate,” “anticipate” and similar expressions will generally identify forward-looking statements. All of our forward-looking statements, whether written or oral, are expressly qualified by these and other cautionary statements. We disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date provided. With this in mind, you should consider the risks discussed elsewhere in this report and other documents we file with the SEC from time to time and the following important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements.
Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. If any of the following risks were to occur, our business, results of operations and financial condition could be materially, adversely affected. In that case, we may not be able to pay distributions on our common units and the trading price of our common units could decline materially. The risks referred to herein refer to risks inherent to our wholly-owned operations through WIC, SNG, SLNG and Elba Express and our majority-owned interest in CIG.
Risks Inherent in Our Business
The supply and demand for natural gas could be adversely affected by many factors outside of our control which could negatively affect us.
Our success depends on the supply and demand for natural gas. The degree to which our business is impacted by changes in supply or demand varies. Our business can be negatively impacted by sustained downturns in supply and demand for natural gas, including reductions in our ability to renew pipeline transportation contracts on favorable terms and to construct new pipeline infrastructure. One of the major factors that will impact natural gas demand will be the potential growth of the demand for natural gas in the power generation market, particularly driven by the speed and level of existing coal-fired power generation that is replaced with natural gas-fired power generation. One of the major factors impacting natural gas supplies has been the significant growth in unconventional sources such as shale plays. In addition, the supply and demand for natural gas for our business will depend on many other factors outside of our control, which include, among others:
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adverse changes in general global economic conditions. The level and speed of the recovery from the recent recession remains uncertain and could impact the supply and demand for natural gas and our future rate of growth in our business;
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adverse changes in geopolitical factors, including the establishment of production levels by the Organization of the Petroleum Exporting Countries (OPEC), political unrest and changes in foreign governments in production regions of the world and unexpected wars, terrorist activities and others acts of aggression;
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adverse changes in domestic regulations that could impact the supply or demand for natural gas;
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technological advancements that may drive further increases in production and reduction in costs of developing natural gas shales;
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competition from imported LNG and Canadian supplies and alternate fuels;
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increased prices of natural gas or NGLs that could negatively impact demand for these products;
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increased costs to explore for, develop, produce, gather, process and transport natural gas or NGLs;
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adoption of various energy efficiency and conservation measures; and
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perceptions of customers on the availability and price volatility of our services, particularly customers’ perceptions on the volatility of natural gas prices over the longer-term.
The prices for natural gas and NGLs could be adversely affected by many factors outside of our control which could negatively affect us.
Natural gas and NGL prices historically have been volatile and are likely to continue to be volatile in the future, especially given current global geopolitical and economic conditions. There is a risk that commodity prices, which are at relatively low levels at this time, will remain depressed for sustained periods. Our business can be negatively impacted in the long-term by sustained depression in commodity prices for natural gas and NGLs including reductions in differentials between receipt and delivery points on our systems and in our ability to enter into or renew pipeline transportation contracts on favorable terms and to construct new pipeline infrastructure. The prices for natural gas and NGLs are subject to a variety of additional factors that are outside of our control, which include, among others:
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changes in regional, domestic and international supply and demand;
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volatile trading patterns in commodity-futures markets;
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changes in basis differentials among different supply basins that can negatively impact the ability of our business to compete with supplies from other basins, including our ability to maintain pipeline transportation revenues and to enter into or renew transportation contracts in any supply basins that are not as competitive with other alternatives;
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changes in the costs of exploring for, developing, producing, transporting, processing and marketing natural gas;
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increased federal and state taxes, if any, on the sale or transportation of natural gas and NGLs; and
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the price and availability of supplies of alternative energy sources.
Our business is subject to competition from third parties which could negatively affect us.
The natural gas pipeline business is highly competitive. We compete with other interstate and intrastate pipeline companies as well as gatherers and storage companies for the transportation and storage of natural gas. We also compete with suppliers of alternate energy sources such as coal and fuel oil. We frequently have one or more competitors in the supply basins and markets that we are connected to. This includes new pipeline systems that have recently been constructed from supply basins in which one or more of our pipelines are located and growing competition in many of the markets we serve. This competition could result in our inability to renew contracts and to maintain rates and transportation volumes, any of which could have a material adverse effect on our business.
The success of our pipeline business depends on many factors beyond our control.
The results of our pipeline business are impacted in the long term by the volumes of natural gas we transport or store and the prices we are able to charge for these services. The volumes of natural gas we are able to transport and store depend on the actions of third parties that are beyond our control. Such factors include events that negatively impact our customers’ demand for natural gas and could expose our pipelines to the risk that we will not be able to renew contracts at expiration or that will require us to discount our rates significantly upon renewal. We are also highly dependent on our customers and downstream pipelines to attach new and increased loads on their systems in order to grow our pipeline business. Further, state agencies that regulate our pipelines’ local distribution company customers could impose requirements that could impact demand for our pipelines’ services.
The volume of gas that we are able to transport and store also depends on the availability of natural gas supplies that are accessible to our pipeline systems, including the need for producers to continue to develop additional natural gas supplies to offset the natural decline from existing wells connected to our systems. This requires the development of additional natural gas reserves, obtaining additional supplies from interconnecting pipelines, and the development of LNG facilities on or near our systems. There have been major shifts in supply basins over the last few years, especially with regard to the development of new natural gas shale plays and declining production from conventional sources of supplies as well as declining deliveries from Canada. A prolonged decline in energy prices could cause a decrease in these development activities and could cause a decrease in the volume of reserves available for transportation and storage through our systems.
With the recent rapid growth of shale gas production in the U.S. and the subsequent drop in U.S. natural gas prices, the need and incentive to import LNG to U.S. regasification terminals has greatly diminished. Actual U.S. LNG imports are now at their lowest levels in several years. If shale gas production continues to grow as expected, imports of LNG to the U.S. will remain at minimal levels. Although our existing LNG import terminal is fully subscribed under long term fixed revenue contracts, extended periods of reduced levels of physical LNG imports could necessitate changes in how our LNG facility is operated to accommodate these potential low flow conditions.
Furthermore, our ability to deliver natural gas to our shippers is dependent upon their ability to purchase and deliver gas at various receipt points into our system. On occasion, particularly during extreme weather conditions, the gas delivered by our shippers at the receipt points into our system is less than the gas that they take at delivery points from our system. This can cause operational problems and can negatively impact our ability to meet our shippers’ demand.
Our operations are subject to operational hazards and uninsured risks which could negatively affect us.
Our operations are subject to a number of inherent operational hazards and uninsured risks such as:
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Adverse weather conditions, natural disasters, and/or other climate related matters - including extreme cold or heat, lightning and flooding, fires, earthquakes, hurricanes, tornadoes and other natural disasters. Although the potential effects of climate change on our operations (such as hurricanes, flooding, etc.) are uncertain at this time, changes in climate patterns as a result of global emissions of greenhouse gas (GHG) could also have a negative impact on our operations in the future, particularly with regard to any of our facilities that are located in or near the Gulf of Mexico and other coastal regions.
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Acts of aggression on critical energy infrastructure-including terrorist activity or “cyber security” events. We are subject to the ongoing risk that one of these incidents may occur which could significantly impact our business operations and/or financial results. Should one of these events occur in the future, it could impact our ability to operate or control our pipeline assets, our operations could be disrupted, property could be damaged and/or customer information could be stolen resulting in substantial loss of revenues, increased costs to respond or other financial loss, damage to reputation, increased regulation and litigation and/or inaccurate information reported from our operations to our financial applications, to our customers and to regulatory entities.
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Other hazards-including the collision of third-party equipment with our infrastructure (such as damage caused to our underground pipelines by third party excavation); explosions, pipeline failures, mechanical and process safety failures, events causing our facilities to operate below expected levels of capacity or efficiency; uncontrollable flows of natural gas, release of pollution or contaminants into the environment (including discharges of toxic gases or substances) and other environmental hazards.
Each of these risks could result in (a) damage or destruction of our facilities, (b) damages and injuries to persons and property or (c) business interruptions while damaged energy and/or technology infrastructure is repaired or replaced, each of which could cause us to suffer substantial losses. While we maintain insurance against some of these risks in amounts that we believe are reasonable, our insurance coverages have material deductibles, self-insurance levels, limits on our maximum recovery and do not cover all risks. For example, from time to time we may not carry, or may be unable to obtain on terms that we find acceptable, insurance coverage for certain exposures including, but not limited to, certain environmental exposures (including potential environmental fines and penalties), business interruption and named windstorm / hurricane exposures. The premiums and deductibles we pay for certain insurance policies are also subject to the risk of substantial increases over time that could negatively impact our financial results. In addition, we may not be able to renew existing insurance policies or procure desirable insurance on commercially reasonable terms. There is also a risk that our insurers may default on their coverage obligations or that amounts for which we are insured, or that the proceeds of such insurance will not compensate us fully for our losses. As a result, we could be adversely affected if a significant event occurs that is not fully covered by insurance.
Certain of our pipeline systems’ transportation services are subject to “negotiated rate” contracts that may not allow us to recover our costs of providing the services.
Under FERC policy, interstate pipelines and their customers may execute contracts at a negotiated rate which may be above or below the FERC-regulated recourse rate for that service. These negotiated rate contracts are generally not subject to adjustment for increased costs which could occur due to inflation, increase in cost of capital, taxes or other factors relating to the specific facilities being used to perform the services. It is possible that costs to perform services under negotiated rate contracts will exceed the negotiated rates. Any shortfall of revenue, representing the difference between recourse rates and negotiated rates could result in either losses or lower rates of return in providing such services.
The revenues of our pipeline business are generated under contracts that must be renegotiated periodically.
Substantially all of our pipeline revenues are generated under transportation and storage contracts which expire periodically and must be renegotiated, extended or replaced. If we are unable to extend or replace these contracts when they expire or renegotiate contract terms as favorable as the existing contracts, we could suffer a material reduction in our revenues, earnings and cash flows. For example, basis differentials between receipt and delivery points on our pipeline systems could decrease over time and thereby negatively impact our ability to renew contracts at rates that were previously in place. Our ability to extend and replace contracts could be adversely affected by factors we cannot control. In addition, changes in state regulation of local distribution companies may cause them to negotiate short-term contracts or turn back their capacity when their contracts expire.
The expansion of our pipeline systems by constructing new facilities subjects us to construction and other risks that may adversely affect us.
We frequently expand the capacity of our existing pipeline, storage or LNG facilities by constructing additional facilities. Construction of these facilities is subject to various regulatory, development and operational risks, including:
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our ability to obtain necessary approvals and permits from the FERC and other regulatory agencies on a timely basis that are on terms that are acceptable to us, including the potential negative impact of delays and increased costs caused by general opposition to energy infrastructure development, especially in environmentally and culturally sensitive areas and more heavily populated areas;
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the ability to access sufficient capital at reasonable rates to fund expansion projects, especially in periods of prolonged economic decline when we may be unable to access the capital markets;
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the availability of skilled labor, equipment, and materials to complete expansion projects;
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potential changes in federal, state and local statutes, regulations, and orders;
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impediments on our ability to acquire rights-of-way or land rights on terms that are acceptable to us;
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our ability to construct projects within anticipated costs, including the risk that we may incur cost overruns resulting from weather conditions, geologic conditions, inflation or increased costs of equipment, materials (such as steel and nickel) and labor, contractor productivity, delays in construction due to various factors including delays in obtaining regulatory approvals or other factors beyond our control. These cost overruns could be material and we may not be able to recover such excess costs from our customers which could negatively impact our return on our investments;
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our ability to construct projects within anticipated time frames that would likely delay our collection of transportation charges under our contracts;
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the failure of suppliers and contractors to meet their performance and warranty obligations; and
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the lack of transportation, storage or throughput commitments.
Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated costs. There is also the risk that a downturn in the economy and its negative impact upon natural gas demand may result in either slower development in the potential for future expansion projects or adjustments in the contractual commitments supporting such projects. As a result, new facilities may be delayed or may not achieve our expected investment return.
We are subject to a complex set of laws and regulations from various agencies that regulate the energy industry. Such laws and regulations result in us incurring substantial compliance and remediation costs which impact the profitability of our pipeline business and our customers.
Our pipeline businesses are extensively regulated by the FERC, the U.S. Department of Transportation, the U.S. Department of Interior, the U.S. Coast Guard, the U.S. Department of Homeland Security and various state and local regulatory agencies who have the ability to issue regulations or enforcement orders that may adversely affect our profitability.
Our operations are subject to a complex set of federal, state and local laws and regulations that tend to change from time to time and generally are becoming more stringent. In addition to laws and regulations affecting our business, there are various laws and regulations that regulate various market practices in the industry, including antitrust laws and laws that prohibit fraud and manipulation in the markets in which we operate. The authority of the Federal Trade Commission (FTC), FERC and U.S. Commodity Futures Trading Commission to impose penalties for violations in these areas has generally increased over the last few years.
In addition, our business is subject to laws and regulations that govern environmental, health and safety matters. These regulations include compliance obligations for air emissions, water quality, wastewater discharges and solid and hazardous waste disposal, as well as regulations designed for the protection of human health and safety and threatened or endangered species. Compliance obligations can result in significant costs to install and maintain pollution controls and to maintain measures to address personal and process safety and protection of the environment and animal habitat near our operations.
We are often obligated to obtain permits or approvals in our operations from various federal, state and local authorities, which permits and approvals (including renewals thereof) can be denied or delayed. In addition, we are exposed to fines and penalties to the extent that we fail to comply with the applicable laws and regulations, as well as the potential for limitations to be imposed on our operations. These regulations often impose remediation obligations associated with the investigation or clean-up of contaminated properties, as well as damage claims arising out of the contamination of properties or impact on natural resources. Many of our assets are located and operate on federal, state, local or tribal lands and are typically regulated by one or more federal, state or local agencies. For example, we operate pipeline facilities that are located on federal lands located both onshore and offshore, which are regulated by the Department of the Interior, particularly by the Bureau of Land Management and the Bureau of Ocean Energy Management, Regulation, and Enforcement. In addition, we also have pipeline operations on Native American tribal lands, which are regulated by the Department of the Interior, particularly by the Bureau of Indian Affairs, as well as local tribal authorities. Operations on these properties are often subject to additional regulations and compliance obligations, which can delay our access to such lands and impose additional compliance costs.
In addition, the FERC regulates most aspects of our business, including the terms and conditions of services offered, our relationships with affiliates, construction and abandonment of facilities and the rates charged by our pipelines (including establishing authorized rates of return). Many of our pipelines periodically file to adjust the rates charged to their customers. There is a risk that the FERC may establish rates that are not acceptable to us and have a negative impact on us. In addition, the profitability of our pipeline systems 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 such costs increase in an amount greater than what we are permitted to recover in our rates or to the extent that there is a lag before the pipeline can file and obtain rate increases, such events can have a negative impact on our operating results. Our existing rates may also be challenged by complaint. The FERC commenced several proceedings against pipeline systems and storage facilities to reduce the rates they were charging their customers. There is a risk that the FERC or our customers could file similar complaints on one or more of our pipeline systems and that a successful complaint against our pipeline rates could have an adverse impact on us. For example, the FERC recently initiated an investigation concerning the rates of our affiliate, Bear Creek. The FERC currently allows publicly traded partnerships to include in their cost-of-service an income tax allowance. Any changes to FERC’s treatment of income tax allowances in cost of service could result in lower recourse rates that could negatively impact our unitholders’ investment in us.
The laws and regulations (and the interpretations thereof) that are applicable to our business could materially change in the future and increase the cost of our operations or otherwise negatively impact us.
The regulatory framework affecting our business is frequently subject to change, with the risk that either new laws or regulations may be enacted or existing laws and regulations may be amended. Such new or amended laws and regulations can materially affect our operations and our financial results. In this regard, there have been proposals to adopt or amend federal, state, local and tribal laws and regulations that could negatively impact our business, which includes among others:
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Climate Change and other Emissions. The Environmental Protection Agency (EPA) and several state environmental agencies have adopted regulations to regulate GHG emissions. It is uncertain at this time what impact the existing and proposed regulations will have on the demand for natural gas and on our operations. This will largely depend on what regulations are ultimately adopted, how the requirements of these regulations are implemented and incentives and subsidies provided to other fossil fuels, nuclear power and renewable energy sources. Although the EPA has adopted a tailoring rule to regulate GHG emissions, it is not expected to materially impact our existing operations until 2016. However, the tailoring rule is subject to judicial reviews and such reviews could result in the EPA being required to regulate GHG emissions at lower levels that could subject many of our larger facilities to regulation prior to 2016. There have also been various legislative and regulatory proposals and final rules at the federal and state levels to address air emissions from power plants and industrial boilers. Although such rules and proposals will generally favor the use of natural gas over other
fossil fuels such as coal, it remains uncertain what regulations will ultimately be adopted and when they will be adopted. Finally, there have been other various environmental regulatory proposals that could increase the cost of our environmental liabilities as well as increase our future compliance costs. For example, the EPA has proposed more stringent emission standards with regard to oil and gas operations that will affect our operations. In addition, any regulations would likely increase our costs of compliance by potentially delaying the receipt of permits and other regulatory approvals, requiring us to monitor emissions, install additional equipment or modification facilities to reduce GHG and other emissions, to purchase emission credits, and utilize electric-driven compression at facilities to obtain regulatory permits and approvals in a timely manner. While we may be able to include some or all of the costs associated with our environmental liabilities and environmental compliance in the rates charged by our pipelines, our ability to recover such costs is uncertain and may depend on events beyond our control including the outcome of future rate proceedings before the FERC and the provisions of any final regulations and legislation.
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Renewable / Conservation Legislation. There have been various legislative and regulatory proposals at the federal and state levels to provide incentives and subsidies to (a) shift more power generation to renewable energy sources and (b) support technological advances to drive less energy consumption. These incentives and subsidies could have a negative impact on natural gas consumption and thus have negative impacts on our operations and financial results.
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Pipeline Safety. New federal legislation was enacted in December 2011 associated with pipeline safety and integrity issues including changes that require installation of additional valves and other equipment on our pipelines and potential expansion of high consequence areas. The legislation requires the U.S. Department of Transportation Pipeline and Hazardous Material Safety Administration to conduct various studies, which may ultimately result in additional regulations which could negatively impact our operations.
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Tax Policies. Various federal legislation has been proposed to materially revise the tax provisions associated with the energy industry. For example, previous proposed changes have included changes to the taxation of carried interests, which could potentially change the taxation of sales or exchange of partnership interests such as ours. There have also been proposals to simplify the tax code by generally eliminating deductions and reducing the effective corporate and individual tax rates, which could negatively impact the tax allowance in our FERC-approved pipeline rates and impact the return and yield expectations of our investors. It is unclear whether these or other changes will be enacted and if enacted when they will become effective. Any such changes could negatively impact us.
Our pipeline systems depend on certain key customers for a significant portion of their revenues and the loss of any of these key customers could result in a decline in our revenues. In addition, we are exposed to the credit risk of our counterparties and our credit risk management may not be adequate to protect against such risk.
We are subject to the risk of our counterparties failing to make payments to us, which may include payments not being received within the time required under our contracts. Our current largest exposures are associated with shippers under long-term transportation contracts on our pipeline systems. Our systems rely on a limited number of customers for a significant portion of our systems’ revenues. For the year ended December 31, 2011, the four largest customers for each of WIC, CIG, SNG, SLNG and Elba Express accounted for approximately 72 percent, 64 percent, 61 percent, 100 percent and 100 percent of their respective operating revenues. The creditworthiness of our customers may be adversely impacted by negative effects in the economy, including low natural gas prices which can reduce liquidity and cash flows for some of our customers that produce natural gas. The loss of all or a portion of the contracted volumes of these customers, as a result of competition, creditworthiness, inability to negotiate extensions, or replacements of contracts, could have a material adverse effect on us. Our credit procedures and policies that are governed by the FERC may not be adequate to fully eliminate counterparty credit risk. In addition, in certain situations, we may assume certain additional credit risks for competitive reasons or otherwise. If our existing or future counterparties fail to pay and/or perform, we could be adversely affected. For example, we may not be able to effectively remarket capacity during and after insolvency proceedings involving a customer.
We are exposed to the credit and performance risk of our key contractors and suppliers.
As an owner of large energy infrastructure facilities with significant capital expenditures in our business, we rely on contractors for certain construction and on suppliers for key materials, supplies and services, including steel mills, pipe and other manufacturers. There is a risk that such contractors and suppliers may experience credit and performance issues that could adversely impact their ability to perform their contractual obligations with us, including their performance and warranty obligations. This could result in delays or defaults in performing such contractual obligations and increased costs to seek replacement contractors, each of which could adversely impact us.
The costs to maintain, repair and replace our pipeline systems may exceed our expected levels.
Much of our pipeline infrastructure was constructed many years ago. The age of these assets may result in them being more costly to maintain and repair. We may also be required to replace certain facilities over time. In addition, our pipeline assets may be subject to the risk of failures or other incidents due to factors outside of our control (including third party excavation near our pipelines, unexpected degradation of our pipelines, unexpected erosion of soil as well as design, construction or manufacturing defects) that could result in personal injury or property damages. Much of our pipeline system is located in populated areas which increases the level of such risks. Such incidents could also result in unscheduled outages or periods of reduced operating flows which could result in a loss of our ability to serve our customers and a loss of revenues. Although we are targeted to complete our pipeline integrity program which includes the development and use of in-line inspection tools in high consequence areas by its required completion date at the end of 2012, we will continue to incur substantial expenditures beyond 2012 relating to the integrity and safety of our pipelines. In addition, there is a risk that new regulations or other regulatory actions associated with pipeline safety and integrity issues will be adopted that could require us to incur additional material expenditures in the future. We are also subject to inherent risk associated with operating storage facilities, including potential risk of gas losses and field degradation.
We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.
We do not own all of the land on which our pipelines and facilities are located. We are subject to the risk that we do not have valid rights-of-way, that such rights-of-way may lapse or terminate or our facilities may not be properly located within the boundaries of such rights-of-way. Our loss of or interference with these rights could have a material adverse effect on us.
There are accounting principles that are unique to regulated interstate pipeline assets that could materially impact our recorded earnings.
Accounting policies for FERC regulated pipelines are in certain instances different from U.S. GAAP for nonregulated entities. For example, we are permitted to record certain regulatory assets on our balance sheet that would not be recorded for nonregulated entities. In determining whether to account for regulatory assets on each of our pipelines, we consider various factors including regulatory changes and the impact of competition to determine the probability of recovery of these assets. Currently, all of our pipeline systems have regulatory assets recorded on their balance sheets. If we determine that future recovery is no longer probable for any of our pipeline systems, then we could be required to write off the regulatory assets in the future. In addition, we capitalize a carrying cost (AFUDC) on equity funds related to our construction of long-lived assets. Equity amounts capitalized are included as other income on our income statement. We periodically evaluate the applicability of accounting standards related to regulated operations, and consider factors such as regulatory changes and the impact of competition. If cost-based regulation ends or competition increases, we may have to evaluate our assets for impairment and write-off the associated regulatory assets and our future earnings could be impacted.
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.
We are managed and operated by El Paso and its affiliates. Such operations and management require the retention and recruitment of a skilled workforce including engineers, technical personnel and other professionals. El Paso competes with other companies in the energy industry for this skilled workforce. In addition, many of El Paso’s current employees are retirement eligible,
which have significant institutional knowledge that must be transferred to other employees. If El Paso is unable to (a) retain their 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. See Risks Related to Proposed KMI Purchase of El Paso.
We have certain contingent liabilities that could exceed our estimates.
We have certain contingent liabilities associated with litigation, regulatory and environmental matters. We are involved in various lawsuits in which we or our subsidiaries have been sued (see Part II, Item 8. Financial Statements and Supplementary Data, Note 9). Although we believe that we have established appropriate reserves for these litigation, regulatory and environmental liabilities, we could be required to accrue additional amounts in the future and these amounts could be material.
Risks Related to Our Liquidity
We depend on distributions from our subsidiaries to meet our needs.
We have no significant assets other than our ownership interests in our operating subsidiaries. We are dependent on the earnings and cash flows, dividends, loans or other distributions from our subsidiaries to generate the funds necessary to meet our obligations. Applicable law and contractual restrictions (including restrictions in certain of our subsidiaries’ credit facilities and the rights of certain creditors of our subsidiaries that would often be superior to our interests) may negatively impact our ability to obtain such distributions from our subsidiaries.
The amount of cash we have available for distribution depends primarily upon our cash flow, including cash flow from working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may increase cash distributions during periods when we experience reductions in net income for financial accounting purposes and may reduce cash distributions during periods when we experience increases in net income for financial accounting purposes.
We have significant existing debt which requires us to dedicate a substantial portion of our cash flows to service our debt payment obligations, as well as reduces our flexibility to respond to changing circumstances.
We have significant debt, debt service and debt maturity obligations. This requires us to dedicate a material portion of our cash flow from operations to debt service payments, thereby reducing the availability of cash for working capital, capital expenditures, acquisitions or general partnership purposes, as well as distributions to our unitholders. In addition, these debt levels expose us to liquidity and default risks, especially during times of financial volatility and reduced commodity prices.
We have significant capital programs in our business that require us to access capital markets frequently and any inability to do so in the future at competitive rates could have a negative impact on us.
We have extensive capital programs in our business, which requires us to frequently access the capital markets. Although the markets have become less volatile than they were in recent years, volatility in the financial market remains. Our cost of capital could be negatively impacted in the future if we are unable to successfully raise capital in the capital markets. This could require us to forego capital opportunities, make those opportunities less attractive to us or make us less competitive in our pursuit of growth opportunities.
Our current and future debt and associated borrowing costs can be negatively impacted by the ratings assigned to our debt facilities and securities, the credit and risk profile of our general partner and its owner, El Paso, which could have a negative impact upon us.
Our credit ratings may be adversely affected by the leverage of our general partner or El Paso, as credit rating agencies may consider the leverage and credit profile of El Paso and its affiliates because of their ownership interest in and control of us and the strong operational links between El Paso and us.
(1) Investment grade.
(2) Below investment grade.
These ratings have increased our cost of capital and our operating costs in comparison to some of our peers. There is a risk that these credit ratings may be adversely affected in the future as the credit rating agencies review their general credit requirements as well as review our leverage, liquidity, credit profile, and potential transactions. Following the announcement of El Paso’s proposed merger with KMI, Moody’s and Fitch adjusted their view of El Paso to a negative outlook, and Moody’s adjusted their view of EPB, EPPOC, CIG and SNG to a negative outlook. Any reduction in our credit rating could also impact our cost of capital. Any reduction in our credit rating could also negatively impact the credit rating of our subsidiaries, which could also increase their cost of capital. It could also impact our ability, as well as the ability of our subsidiaries, to access the capital markets. 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 units.
A breach of the covenants applicable to our debt and other financing obligations could affect our ability to borrow funds, could accelerate our debt and other financing obligations and those of our subsidiaries and reduce our cash available for distribution to our unitholders.
Our debt and other financing obligations contain restrictive covenants and require us to maintain certain financial ratios, including debt to earnings before interest, income taxes, depreciation and amortization (EBITDA) and EBITDA to interest expense in our note purchase agreements and contain cross default provisions. Volatility in the financial markets and a reduction in access to capital could cause these covenants to become more restrictive over time. A breach of any of these covenants could preclude us or our subsidiaries from issuing letters of credit, from borrowing under our credit agreements and could accelerate our debt and other financing obligations and those of our subsidiaries. If this were to occur, we might not be able to repay such debt and other financing obligations.
Restrictions in our credit facility and note purchase agreement could limit our ability to make distributions to our unitholders.
Our credit facility and the note purchase agreement related to our issuance of senior unsecured notes contain covenants limiting our ability to make distributions to our unitholders and equity repurchases. Our ability to comply with any restrictions and covenants may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If we are unable to comply with these restrictions and covenants, a significant portion of indebtedness outstanding under our credit facility or the note purchase agreement may become immediately due and payable, and our lenders’ commitment to make further loans to us under our credit facility may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. Our payment of principal and interest on any future indebtedness will reduce our cash available for distribution to our unitholders. Further, our credit facility limits our ability to pay distributions to our unitholders during an event of default or if an event of default would result from the distribution.
We are subject to interest rate risks.
Although a substantial portion of our debt capital structure has fixed interest rates, changes in market conditions, including potential increases in the deficits of foreign, federal and state governments, could have a negative impact on interest rates that could cause our financing costs to increase. Since interest rates are at historically low levels, it is anticipated that they will increase in the future. Rising interest rates could also negatively impact our unitholders’ investment in us, as changes in interest rates may affect the yield requirements of investors in our units. It may also negatively impact our ability to issue additional equity to make acquisitions, to incur debt or for other purposes.
Risks Inherent in Our Structure and Relationship with El Paso
Our ability to continue to acquire interests in interstate pipelines from El Paso could be negatively impacted by various factors that would reduce our growth opportunities.
An important source of our growth in the past and potentially in the future is the purchase of interests in interstate pipelines from El Paso. As the owner of our general partner, El Paso is entitled to incentive distribution rights (IDRs). El Paso is currently entitled to receive the maximum level of IDRs. Our ability to purchase additional interests on an accretive basis to the limited partner unitholders may be negatively impacted by such IDRs unless El Paso elects to reduce the level of the IDRs as provided for in the partnership agreement. In addition, as the owner of the general partner of the partnership, El Paso could also be subject to claims associated with conflicts of interest and breach of fiduciary duties. Although the partnership agreements expressly define and limit its obligations as the general partner, if any conflicts of interest or breach of fiduciary duties are found, then our ability to purchase additional interests in interstate pipeline assets from El Paso could be negatively impacted.
We do not have the same flexibility as other types of organizations to accumulate cash, which may limit cash available to service the notes or to repay them at maturity.
Unlike a corporation, EPB’s partnership agreement requires EPB to distribute, on a quarterly basis, 100 percent of its available cash to its unitholders of record and its general partner. Available cash is generally defined as all of EPB’s cash-on-hand as of the end of a fiscal quarter, adjusted for cash distributions and net changes to reserves. EPB’s general partner will determine the amount and timing of such distributions and has broad discretion to establish and make additions to its reserves or the reserves of EPB’s operating subsidiaries in amounts it determines in its reasonable discretion to be necessary or appropriate:
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to provide for the proper conduct of our business and the businesses of EPB’s operating subsidiaries (including reserves for future capital expenditures and for EPB’s anticipated future credit needs);
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to reimburse EPB’s general partner for all expenses it has incurred on EPB’s behalf;
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to provide funds for distributions to EPB’s unitholders and its general partner for any one or more of the next four calendar quarters; or
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to comply with applicable law or any of EPB’s loan or other agreements.
El Paso controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates, including El Paso, have conflicts of interest with us and limited fiduciary duties, and they may favor their own interests to the detriment of our unitholders.
El Paso owns and controls our general partner, and appoints all of the directors of our general partner. Some of our general partner’s directors, and some of its executive officers, are directors or officers of El Paso or its affiliates. Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to El Paso. Therefore, conflicts of interest may arise between El Paso and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders.
Affiliates of our general partner, including El Paso and its other subsidiaries, are not limited in their ability to compete with us and are not obligated to offer us the opportunity to pursue additional assets or businesses, which could limit our commercial activities or our ability to acquire additional assets or businesses.
Neither our partnership agreement nor the omnibus agreement among us, El Paso and others will prohibit affiliates of our general partner, including El Paso, El Paso Natural Gas Company (EPNG), Cheyenne Plains Gas Pipeline Company, L.L.C. (Cheyenne Plains), Bear Creek, Ruby Pipeline, L.L.C. and TGP, from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, El Paso and its affiliates may acquire, construct or dispose of additional transportation or other assets in the future, without any obligation to offer us the opportunity to purchase or construct any of those assets. Each of these entities is a large, established participant in the interstate pipeline and/or storage business, and each may have greater resources than we have, which factors may make it more difficult for us to compete with these entities with respect to commercial activities as well as for acquisition candidates. As a result, competition from these entities could adversely impact us.
Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which the common units will trade.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will not elect our general partner or its board of directors, and will have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner, including the independent directors, will be chosen entirely by its owners and not by the unitholders. Unlike publicly traded corporations, we will not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at such annual meetings of stockholders. Furthermore, if the unitholders were dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
Cost reimbursements to our general partner and its affiliates for services provided, which will be determined by our general partner, will be substantial and will reduce our cash available for distribution.
Pursuant to an omnibus agreement we entered into with El Paso, our general partner and certain of its affiliates, El Paso and its affiliates will receive reimbursement for the payment of operating and capital expenses related to our operations and for the provision of various general and administrative services for our benefit, including costs for rendering administrative staff and support services to us, and overhead allocated to us, including pension and health care costs which amounts will be determined by the general partner in good faith. Payments for these services will be substantial and will reduce the amount of cash available for distribution to unitholders. In addition, WIC reimburses CIG for the costs incurred to operate and maintain the WIC system pursuant to an operating agreement. CIG also reimburses certain of its affiliates for costs incurred and services it receives (primarily from EPNG and TGP) and receives reimbursements for costs incurred and services it provides to other affiliates (primarily Cheyenne Plains and Young Gas Storage Company Ltd.). In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash otherwise available for distribution to our unitholders.
Our partnership agreement limits our general partner’s fiduciary duties to holders of our common units and restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty laws. The limitation and definition of these duties is permitted by the Delaware law governing limited partnerships. In addition, the limited liability company agreement of CIG contains similar provisions that define the fiduciary standards of each member (a subsidiary of El Paso owns a 14 percent interest in CIG and we own an 86 percent interest in CIG) to the other. In addition, the limited liability agreement includes provisions that define the fiduciary standards that the members of the management committee of CIG appointed by a member owe to the member that did not designate such person. The defined fiduciary standards are more limited than those that would apply under Delaware law in the absence of such definition.
Limited unitholders cannot remove our general partner without its consent.
The vote of the holders of at least 66 2/3 percent of all outstanding common units voting together as a single class is required to remove our general partner. Our unitholders are currently unable to remove our general partner without its consent because affiliates of our general partner own sufficient units to be able to prevent the general partner’s removal. In addition, under certain circumstances the successor general partner may be required to purchase the combined general partner interest and incentive distribution rights of the removed general partner, or alternatively, such interests will be converted into common units.
Our general partner may elect to cause us to issue Class B common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of our general partner or holders of our common units. This may result in lower distributions to holders of our common units in certain situations.
Our general partner has the right, at a time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48 percent) for each of the prior four consecutive fiscal quarters, to reset the initial cash target distribution levels at higher levels based on the distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution amount.
In connection with resetting these target distribution levels, our general partner will be entitled to receive a number of Class B common units. The Class B common units will be entitled to the same cash distributions per unit as our common units and will be convertible into an equal number of common units. The number of Class B common units to be issued will be equal to that number of common units whose aggregate quarterly cash distributions equaled the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when it is experiencing, or may be expected to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued our Class B common units, which are entitled to receive cash distributions from us on the same priority as our common units, rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued new Class B common units to our general partner in connection with resetting the target distribution levels related to our general partner incentive distribution rights.
The control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the members of our general partner from transferring their member interest in our general partner to a third party. The new owners of our general partner would then be in a position to replace the board of directors and officers of the general partner with their own choices and to control the decisions taken by the board of directors and officers of the general partner. This effectively permits a change of control of the partnership without unitholders’ vote or consent. In addition, pursuant to the omnibus agreement with El Paso, any new owner of the general partner would be required to change our name so that there would be no further reference to El Paso.
If we are deemed an “investment company” under the Investment Company Act of 1940, it would adversely affect the price of our common units and could have a material adverse effect on our business.
Our assets consist of a 100 percent ownership interest in WIC, SNG, SLNG and Elba Express and an 86 percent interest in CIG. If a sufficient amount of our assets acquired in the future, are deemed to be “investment securities” within the meaning of the
Investment Company Act of 1940, we would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the SEC or modify our organizational structure or our contract rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates. The occurrence of some or all of these events would adversely affect the price of our common units and could have a material adverse effect on our business.
Moreover, treatment of us as an investment company would prevent our qualification as a partnership for federal income tax purposes in which case we would be treated as a corporation. As a result, we would pay federal income tax on our taxable income at the corporate tax rate, distributions would generally be taxed again as corporate distributions and none of our income, gains, losses or deductions would flow through. Because a tax would be imposed upon us as a corporation, our cash available for distribution would be substantially reduced. Therefore, treatment of us as an investment company would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.
We may issue additional units without approval which would dilute existing ownership interests.
Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
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each unitholder’s proportionate ownership interest in us will decrease;
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the amount of cash available for distribution on each unit may decrease;
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the ratio of taxable income to distributions may increase;
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new classes of securities could be issued that provide preferences to the new class in relation to existing unitholders, including preferences on distributions of available cash, distributions upon our liquidation and voting rights;
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the relative voting strength of each previously outstanding unit may be diminished; and
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the market price of the common units may decline.
Our general partner has a limited call right that may require unitholders to sell common units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 75 percent of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders would be required to sell common units at an undesirable time or price and may not receive any return on investment. Unitholders might also incur a tax liability upon a sale of such units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934. Our general partner and its affiliates own approximately 42 percent of our outstanding common units at December 31, 2011.
Our partnership agreement restricts the voting rights of unitholders owning 20 percent or more of our common units.
Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person that owns 20 percent or more of any class of units then outstanding, other than our general partner and its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. The partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders ability to influence the manner or direction of management.
Unitholder liability may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. Unitholders could be liable for any and all of our obligations as if they were a general partner if a court or government agency determined that:
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we were conducting business in a state but had not complied with that particular state’s partnership statute; or
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unitholders’ right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.
The market price of our common units could be adversely affected by sales of substantial amounts of our common units in the public or private markets, including sales by affiliates of our general partner.
As of February 20, 2012, we had 205,698,750 common units outstanding, which includes 88,400,059 common units held by affiliates of our general partner. Sales by any of our existing unitholders, including affiliates of our general partner, of a substantial number of our common units in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. Under our partnership agreement, our general partner and its affiliates have registration rights relating to the offer and sale of any units that they hold, subject to certain limitations.
Risks Related to our Senior Unsecured Notes
The notes are unsecured obligations of EPPOC and not guaranteed by any of its subsidiaries. As such, the notes are effectively junior to EPPOC’s existing and future secured debt and to all debt and other liabilities of its subsidiaries.
The notes are EPPOC’s unsecured obligations and rank equally in right of payment with all of its other existing and future unsubordinated debt. All of EPPOC’s operating assets are in subsidiaries of EPPOC, and none of these subsidiaries guarantee EPPOC’s obligations with respect to the notes. Creditors of EPPOC’s subsidiaries have claims with respect to the assets of those subsidiaries that rank effectively senior to the notes. In the event of any distribution or payment of assets of such subsidiaries in any dissolution, winding up, liquidation, reorganization or other bankruptcy proceeding, the claims of those creditors would be satisfied prior to making any such distribution or payment to EPPOC in respect of its direct or indirect equity interests in such subsidiaries. Consequently, after satisfaction of the claims of such creditors, there may be little or no amounts left available to make payments in respect of the notes. As of December 31, 2011, the notes were effectively subordinated to approximately $2.0 billion of outstanding indebtedness of EPPOC’s subsidiaries. Furthermore, such subsidiaries are not prohibited under the indenture from incurring additional indebtedness.
In addition, because the notes and the guarantee of the notes by EPB are unsecured, holders of any secured indebtedness of EPPOC or EPB would have claims with respect to the assets constituting collateral for such indebtedness that are senior to the claims of the holders of the notes. Currently, neither EPPOC nor EPB have any secured indebtedness. Although the indenture governing the notes places some limitations on the ability of EPPOC to create liens securing debt, there are significant exceptions to these limitations, which allow us to secure significant amounts of indebtedness without equally and ratably securing the notes. If EPPOC or EPB incur secured indebtedness and such indebtedness is either accelerated or becomes subject to a bankruptcy, liquidation or reorganization, the assets of EPPOC or EPB would be used to satisfy obligations with respect to the indebtedness secured thereby before any payment could be made on the notes. Consequently, any such secured indebtedness would effectively be senior to the notes and the guarantee of the notes by EPB, to the extent of the value of the collateral securing the secured indebtedness. In that event, the noteholders may not be able to recover all the principal or interest that is due under the notes.
We may not be able to repurchase the notes upon a change of control.
Upon the occurrence of a change of control trigger event, we will be required to offer to repurchase all outstanding notes at 101 percent of their principal amount plus accrued and unpaid interest. We may not be able to repurchase the notes upon a change of control trigger event because we may not have sufficient funds. Further, we may be contractually restricted under the terms of our revolving credit facility or other future senior indebtedness from repurchasing all of the notes tendered by holders upon a change of control. Accordingly, we may not be able to satisfy our obligations to purchase the notes unless we are able to refinance or obtain waivers under our credit facilities. Our failure to repurchase the notes upon a change of control would cause a default under the indenture and a cross-default under our revolving credit facility. Our revolving credit facility provides that a change of control, as defined in such agreement, will be a default that permits lenders to accelerate the maturity of borrowings thereunder and limiting our ability to purchase the notes, and reducing the practical benefit of the offer to purchase provisions to the holders of the notes. Any of our future debt agreements may contain similar provisions. In addition, the change of control provisions in the indenture may not protect the noteholders from certain important corporate events, such as a leveraged recapitalization (which would increase the level of our indebtedness), reorganization, restructuring, merger or other similar transaction.
We may not be able to generate sufficient cash to service all of our indebtedness, including the notes and our indebtedness under our revolving credit facility, and we may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful.
Our ability to make scheduled payments on or to refinance our debt obligations depends on our financial and operating performance, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond our control. We cannot assure the noteholders that we will maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness. If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay capital expenditures, sell assets or operations, seek additional capital or restructure or refinance our indebtedness, including the notes. We cannot assure the noteholders that we would be able to take any of these actions, that these actions would be successful and would permit us to meet our scheduled debt service obligations or that these actions would be permitted under the terms of our existing or future debt agreements, including our credit agreement and the indenture that will govern the notes. In the absence of such cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. Our revolving credit facility contains restrictions on our ability to dispose of assets. We may not be able to consummate those dispositions or to obtain the proceeds that we could realize from them, and any proceeds may not be adequate to meet any debt service obligations when due.
Risks Related to Proposed KMI Purchase of El Paso
Our General Partner is owned by El Paso, which recently announced an agreement to merge with KMI, which owns the general partner of KMP. KMI’s ownership of us and KMP may result in conflicts of interest.
El Paso entered into definitive agreements with KMI, which provide for a series of transactions whereby KMI will acquire El Paso. The closing of the merger is subject to various conditions precedent. As a result, there is a risk that the acquisition may not be completed. In addition, prior to closing, various restrictions are imposed in the definitive agreements on the sale of assets owned by El Paso, which could restrict the ability of El Paso to sell its interests in pipeline assets to us prior to the closing of the merger. Our ability to purchase interests in El Paso’s pipeline assets after the closing of the merger is also uncertain. KMI owns the general partner of KMP, which also owns other interstate natural gas pipelines. KMI has indicated its intention to sell certain of the interstate pipelines owned by El Paso to KMP and to EPB. As a result, we may compete with KMP for the dropdown of interstate pipeline assets owned by El Paso following the acquisition of El Paso by KMI.
Following the completion of the merger of KMI and El Paso, the directors and officers of our general partner and its affiliates will have duties to manage our general partner in a manner that is beneficial to KMI who would be the sole owner of our general partner. At the same time, our general partner will have duties to manage us in a manner that is beneficial to our unitholders. Therefore, following the completion of the merger, our general partner’s duties to us may conflict with the duties of its officers and directors to KMI. As a result of these conflicts of interest following the merger, our general partner may favor its own interest or the interests of KMI or KMP, or their owners or affiliates over the interest of our unitholders. Additional conflicts may also arise in the future following the merger associated with (1) the allocation of capital and the allocation of costs among KMP and us, (2) the
amount of time devoted by the officers and directors of KMI to the business of KMP in relation to us and (3) the future business opportunities that are pursued in KMP and us. Specifically, certain conflicts may arise as a result of KMI pursuing acquisitions or development opportunities in KMP that may also be advantageous to us. If we are limited in our ability to pursue such opportunities, we may not realize all or any of the commercial value of such opportunities.
The recently announced merger of El Paso and Kinder Morgan is subject to regulatory approvals which could require us to divest certain of our assets.
The merger of El Paso and Kinder Morgan is subject to various regulatory approvals, including approvals from the Federal Trade Commission. The FTC may impose certain restrictions or obligations on our businesses as conditions for their approval of the merger, which could include requiring the divestiture of certain of our assets or businesses in order to obtain such approvals. Any required divestiture of assets could have a material impact on our business, including our ability to grow our business and distributions.
Pending the completion of the merger, our business and operations could be materially adversely affected.
Uncertainty about the effect of the merger on El Paso’s employees may have an adverse effect on us. This uncertainty may impair El Paso’s ability to attract, retain and motivate personnel until the merger is completed. Employee retention may be particularly challenging during the pendency of the merger, as employees may feel uncertain about their future roles with the combined company. If El Paso’s employees depart because of issues relating to the uncertainty and difficulty of integration or a desire not to become employees of the combined company, it could negatively impact our business, operations and financial results. In connection with the pending merger, it is possible that some customers, suppliers and other persons with whom we have a business relationship may delay or defer certain business decisions or might decide to seek to terminate, change or renegotiate their relationship with us as a result of the merger, which could negatively affect our revenues, earnings and cash flows, as well as the market price of our common units, regardless of whether the merger is completed.
Failure to successfully combine and integrate the organizations and processes of El Paso and KMI may adversely affect us.
KMI has announced that it expects to realize certain anticipated benefits and synergies as part of its acquisition of El Paso. However, if KMI and El Paso do not successfully integrate their operations, we may not realize any such benefits. Furthermore, the integration of two organizations and their processes and systems inherently involve risks, including ensuring maintaining effective compliance with laws and regulations as well as effective internal controls over financial reporting.
Following consummation of the El Paso and KMI merger, our credit ratings could be adversely affected, which may increase our borrowing costs.
KMI will have considerably higher aggregate levels of indebtedness due to the debt incurred to finance the transaction. There can be no assurance that the credit ratings of KMI will not be subject to downgrade. Our credit ratings may be adversely affected in the event of any downgrade of KMI’s ratings in the light of the ownership interest and operational control of us following the merger. Any reduction in our credit ratings could also negatively impact the credit rating of our subsidiaries. Any of such actions by the credit rating agencies could increase our cost of capital and that of our subsidiaries, as well as negatively impact our ability to access the capital markets. It could also have a negative impact on the market value of our units.
Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of additional entity-level taxation by states. If the Internal Revenue Service (IRS) were to treat us as a corporation or if we become subject to a material amount of additional entity-level taxation for state tax purposes, then it would substantially reduce the amount of cash available for distribution to our unitholders.
The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS, on this or any other tax matter affecting us. If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35 percent, and would likely pay state income tax at varying rates. Distributions would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through. Because a tax would be imposed upon us as a corporation, our cash available to pay distributions would be substantially reduced. Thus, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.
Current law may change, causing us to be treated as a corporation for federal income tax purposes or otherwise subjecting us to entity-level taxation. Because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state was to impose a tax upon us as an entity, the cash available to pay distributions would be reduced.
Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
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 interpretation at any time. Recently, members of the U.S. Congress considered substantive changes to the existing U.S. federal income tax laws that would have affected the tax treatment of certain publicly traded partnerships. Any modification to the U.S. federal income tax laws or interpretations thereof may or may not be applied retroactively. Although we are unable to predict whether any of these changes or any other proposals will ultimately be enacted, any changes could negatively impact the value of an investment in our common units.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular 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 between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. 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 unitholders.
An IRS challenge of the federal income tax positions we take may adversely affect the market for our common units, and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.
We have not requested any ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all the positions we take. Any challenge by the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, the costs of any contest with the IRS will result in a reduction in cash available to pay distributions to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner.
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 will be treated as partners to whom we will allocate taxable income which could be different in amount than cash we distribute, they will be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not cash is distributed from us. Cash distributions may not equal a unitholder’s share of our taxable income or even equal the actual tax liability that results from the unitholder’s share of our taxable income.
The tax gain or loss on the disposition of our common units could be different than expected.
If our unitholders sell units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Prior distributions to them in excess of the total net taxable income they were allocated for a common unit, which decreased their tax basis in that common unit, will, in effect, become taxable income to them if the common unit is sold at a price greater than their tax basis in that common unit, even if the price they receive is less than their original cost. A substantial portion of the amount realized, regardless of whether such amount represents gain, may be taxed as ordinary income to our unitholders due to potential recapture items, including depreciation recapture. In addition, if they sell their units, they may incur a tax liability in excess of the amount of cash they receive from the sale.
Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs) and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from 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 or foreign persons should consult their tax advisor regarding their investment in our common units.
We will treat each purchaser of 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 will 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 our unitholders. It also could affect the timing of these tax benefits or the amount of gain from their sale of our common units and could have a negative impact on the value of our common units or result in audit adjustments to their tax returns.
We may adopt certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.
When we issue additional units or engage in certain other transactions, we will 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 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 the general partner, which may be unfavorable to such unitholders. Moreover, under our methodologies subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the 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 unitholders. It also could affect the amount of gain from our 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 unitholders’ tax returns without the benefit of additional deductions.
The sale or exchange of 50 percent or more of our capital and profits interests during any 12-month period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50 percent or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income.
Unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of their investment in our common units.
In addition to federal income taxes, unitholders will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if they do not live in any of those jurisdictions. Unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose an income tax. It is the unitholder’s responsibility to file all federal, state and local tax returns.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2. PROPERTIES
A description of our properties is included in Part I, Item 1. Business, and is incorporated herein by reference.
We believe that we have satisfactory title to the properties owned and used in our businesses, subject to liens for taxes not yet payable, liens incident to minor encumbrances, liens for credit arrangements and easements and restrictions that do not materially detract from the value of these properties, our interests in these properties, or the use of these properties in our businesses. We believe that our properties are adequate and suitable for the conduct of our business in the future.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
A description of our legal proceedings is included in Part II, Item 8. Financial Statements and Supplementary Data, Note 9, and is incorporated herein by reference.
ITEM 4.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common units are traded on the New York Stock Exchange under the symbol EPB. As of February 20, 2012, we had 38 unitholders of record, which does not include beneficial owners whose shares are held by a clearing agency, such as a broker or bank.
The following table reflects the quarterly high and low sales prices for our common units based on the daily composite listing of stock transactions for the New York Stock Exchange and the cash distributions per unit we declared in each quarter:
Cash Distribution Policy. We will distribute to the holders of common and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.2875 per common unit ($1.15 per common unit on an annualized basis) to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. Our ability to pay cash distributions at this minimum quarterly distribution rate is subject to various restrictions and other factors. On February 14, 2012, we paid a distribution of $0.50 per unit to all unitholders of record at the close of business on January 31, 2012. Our partnership agreement requires us to distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner. We refer to this cash as “available cash.” Our partnership agreement also requires that we distribute all of our available cash from operating surplus each quarter in the following manner: first, 98 percent to the holders of common units and 2 percent to our general partner, until each common unit has received a minimum quarterly distribution of $0.2875 plus any arrearages from prior quarters; second, 98 percent to the holders of subordinated units and 2 percent to our general partner, until each subordinated unit has received a minimum quarterly distribution of $0.2875; and third, 98 percent to all unitholders, pro rata, and 2 percent to our general partner, until each unit has received a distribution of $0.33063. If cash distributions to our unitholders exceed $0.33063 per unit in any quarter, our general partner will receive, in addition to distributions on its 2 percent general partner interest, increasing percentages, up to 48 percent, of the cash we distribute in excess of that amount. We refer to these distributions as incentive distributions. Our general partner received incentive distributions of $8 million and $49 million in 2010 and 2011, respectively. On February 14, 2012 our general partner received incentive distributions of $19 million.
Incentive Distribution Rights. Our general partner, as the holder of our incentive distribution rights, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial cash target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and cash target distribution levels upon which the incentive distribution payments to our general partner would be set. In connection with this election, our general partner will be entitled to receive a number of newly issued Class B common units and general partner units based on a predetermined formula. Our general partner’s right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions payable to our general partner is based, may be exercised, without approval of our unitholders or the conflicts committee of our general partner, at any time when there are no subordinated units outstanding and we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for each of the prior four consecutive fiscal quarters. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount and the target distribution levels prior to the reset such that our general partner will not receive any incentive distributions under the reset target distribution levels until cash distributions per unit following this event increase.
The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under Marginal Percentage Interest in Distribution are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Unit Target Amount”, until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2 percent general partner interest and assume our general partner has contributed any additional capital necessary to maintain its two percent general partner interest and has not transferred its incentive distribution rights.
Subordination Period. Our partnership agreement provided that, during the subordination period, the common units had the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.2875 per common unit, which is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. Furthermore, no arrearages would be paid on the subordinated units. The practical effect of the subordinated units was to increase the likelihood that during the subordination period there would be available cash to be distributed on the common units. The subordination period ended upon payment of the quarterly cash distribution payment for the fourth quarter of 2010 as the financial tests required for the conversion of all subordinated units into common units were satisfied. As a result, the 27,727,411 subordinated units held by affiliates of El Paso were converted on February 15, 2011 on a one-for-one basis into common units effective January 3, 2011. The conversion did not impact the amount of cash distribution paid or the total number of the Partnership’s outstanding units.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following selected historical financial data as of and for the years ended December 31, 2009 to 2011 and results of operations for the period ended December 31, 2008 is derived from the audited consolidated financial statements for EPB and its subsidiaries. We derived the operating results data for 2007 and the financial position data for 2008 and 2007 from our accounting records. The selected financial data is not necessarily indicative of results to be expected in future periods and should be read together with Item 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview
Our Management’s Discussion and Analysis (MD&A) should be read in conjunction with our consolidated financial statements and the accompanying footnotes. MD&A includes forward-looking statements that are subject to risks and uncertainties that may result in actual results differing from the statements we make. These risks and uncertainties are discussed further in Part 1, Item 1A. Risk Factors.
We completed our initial public offering in November 2007. As of January 2009, we owned WIC, 40 percent general partner interest in CIG and 25 percent general partner interest in SNG. In 2009, we acquired an additional 18 percent general partner interest in CIG from El Paso for $214 million. In 2010 we acquired a 100 percent member interest in each of SLNG and Elba Express and a 35 percent general partner interest in SNG from El Paso for an aggregate $2.4 billion. In 2011, we acquired the remaining 40 percent general partner interest in SNG and an additional 28 percent general partner interest in CIG from El Paso for an aggregate $1.4 billion, and as a result, currently own an aggregate 100 percent interest in WIC, SLNG , Elba Express and SNG and an 86 percent interest in CIG. For a further discussion of each of these acquisitions see Item 8. Financial Statements and Supplementary Data, Note 2.
Listed below is a general outline of our MD&A:
Our Business - includes a summary of our business purpose and description, factors influencing profitability, types of revenue and the contract portfolio, a summary of our 2011 performance, an outlook for 2012 and our growth projects;
Results of Operations - includes a year-over-year analysis of the results of our business and other income statement items, including trends that may impact our business in the future;
Distributable Cash Flow (DCF) - includes our calculation of cash distribution capability, which is a non-GAAP measure (see Distributable Cash Flow section for definition of DCF) and the reconciliation to net income and net cash provided by operating activities;
Liquidity and Capital Resources - includes a general discussion of our sources and uses of cash, available liquidity, our liquidity outlook for 2012, an overview of cash flow activity for 2011 and additional factors that could impact our liquidity;
Off Balance Sheet Arrangements and Contractual Obligations - includes a discussion of our off balance sheet arrangements, including letters of credit and other contractual obligations; and
Critical Accounting Estimates - includes a discussion of accounting estimates that involve the use of significant assumptions and/or judgments in the preparation of our financial statements.
Our Business
We are a Delaware master limited partnership formed in 2007 by El Paso (our general partner) to own and operate interstate natural gas transportation and terminaling facilities. We own WIC, SLNG, Elba Express and SNG and an 86 percent interest in CIG. Our primary business consists of interstate transportation and storage of natural gas. Our pipeline operations are rate-regulated and accordingly we generate profit based on our ability to earn a return in excess of our costs through the rates we charge our customers.
Factors influencing profitability. Our long-term profitability will be influenced primarily by the following factors:
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Executing successfully on our expansion projects and developing growth projects in our market and supply areas;
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Contracting and recontracting pipeline capacity with our customers;
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Maintaining or obtaining approval by the FERC of acceptable rates, terms of service and expansion projects;
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Improving operating efficiency; and
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Pursuing strategic asset acquisitions from El Paso and third parties to grow our business.
Types of Revenue and the Contract Portfolio. Each of our subsidiaries faces varying degrees of competition from other existing and proposed pipelines and LNG facilities, as well as from alternative energy sources used to generate electricity, such as hydroelectric power, coal and fuel oil. Our revenues from transportation and storage services consist of the following types:
(1) This system was placed in service in March 2010 and although capacity is under contract, the average volumes transported during the year ended December 31, 2011 were not material.
(2) Excludes liquids transportation revenue and fuel sales. In the case of CIG, liquids revenue associated with CIG’s processing plants are also excluded. For SLNG, the revenue recorded for BG’s option cancellation payment was excluded (see Results of Operations for further discussion). The revenues described in this table constitute approximately 97 percent of EPB’s, 93 percent of CIG’s, 91 percent of SLNG’s and 100 percent of WIC’s, Elba Express’ and SNG’s total revenues.
The FERC regulates the rates we can charge our customers. These rates are generally a function of the cost of providing services to our customers, including a reasonable return on our invested capital. Because of our regulated nature and the high percentage of our revenues attributable to reservation charges, our revenues have historically been relatively stable. However, our financial results can be subject to volatility due to factors such as changes in natural gas prices, changes in supply and demand, regulatory actions, competition, declines in the creditworthiness of our customers and weather.
Our subsidiaries continue to manage the process of renewing expiring contracts to limit the risk of significant impacts on revenues. The contracts of our subsidiaries mature at various times and in varying amounts of throughput capacity. The ability to extend existing customer contracts or remarket expiring contracted capacity is dependent on competitive alternatives, the regulatory environment at the federal, state and local levels and the market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of new or renegotiated contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility. Our subsidiaries attempt to recontract or remarket capacity at the maximum rates allowed under their respective tariffs, although at times, they enter into firm transportation contracts at amounts that are less than these maximum allowable rates to remain competitive. The extent that these amounts are less than the maximum rates varies for each of our pipeline systems. The weighted average remaining contract term for our active contracts is approximately eight years as of December 31, 2011.
Below is the contract expiration portfolio and the associated revenue expirations for our firm transportation contracts on our wholly and majority owned systems as of December 31, 2011, including those with terms beginning in 2011 or later:
(1) Includes SNG contracts of 1,551 BBtu/d for $188 million that were extended in conjunction with SNG’s rate case settlement approved by the FERC in January 2010.
Summary of 2011 Performance. During 2011, we continued to deliver solid operational performance. We acquired the remaining 40 percent interest in SNG and an additional 28 percent interest in CIG from El Paso for an aggregate $1.4 billion.
During 2011, we generated significant earnings and continued to focus on delivering our expansion projects. SNG placed into service Phases I and II of the South System III Expansion project and Phase II of the Southeast Supply Header (SESH) project, on time and under budget.
Earnings before interest expense and income taxes (EBIT) for 2011 was up 29 percent over the same period in 2010 primarily driven by the acquisitions from El Paso and the completion of organic growth projects in 2010 and 2011. See Results of Operations section for definition of EBIT. Approximately 93 percent of our revenues are collected in the form of demand or reservation charges, which are not dependent upon commodity prices or throughput levels.
We also settled the CIG rate case and refinanced our revolving credit facility extending its maturity to 2016. As of December 31, 2011, we had approximately $1.1 billion of liquidity. During 2011, we met our obligations with our available liquidity and generated strong earnings.
El Paso’s Proposed Merger with Kinder Morgan, Inc. (KMI). On October 16, 2011, El Paso announced a definitive agreement (the “Merger Agreement”) with KMI whereby KMI will acquire El Paso in a transaction that valued El Paso at approximately $38 billion (based on the KMI stock price at that date), including the assumption of debt. The transaction has been approved by each company’s board of directors but remains subject to the approvals of El Paso’s shareholders, the Federal Trade Commission and other customary regulatory and other approvals. The approval of KMI’s shareholders will also be required, but a voting agreement has been executed by the majority of KMI’s shareholders to support the transaction. We will conduct our business in the ordinary course, in all material respects, in substantially the same manner as conducted prior to the date of the Merger Agreement, subject to certain conditions and restrictions. The most substantial of which are a limitation on the size of quarterly distribution increases and approval from KMI of asset drop downs from El Paso to us.
Outlook for 2012. For 2012, we expect that our operations will continue to provide a strong base of earnings and operating cash flow as a result of our long-term and stable fee based revenue stream. However, our subsidiaries continue to focus on renewing expiring contracts to mitigate the impact on future revenue, particularly on our Rocky Mountain assets where we face recontracting risk due, in part, to competition with other pipelines which transport natural gas from the same supply basins that we do, and due to potential declines in production in certain supply basins. However, our subsidiaries have predominantly fixed-fee contracts with a weighted average remaining contract life of approximately eight years; therefore, we are not significantly impacted by short term changes in the demand and supply of natural gas. Our ability to increase distributions to our unitholders will be driven by organic growth and accretive acquisitions. We believe we will have opportunities for organic expansion in multiple markets but our near-term prospects are likely limited. Our ability to make accretive acquisitions, in particular from El Paso, includes factors that are out of our control, including the number, size, and timing of such opportunities. In addition, as a result of El Paso’s announced merger with KMI, there are restrictions placed upon potential acquisitions including the prior approval of KMI. KMI has stated an intention to sell El Paso assets in the future to us once the merger is complete. For a further discussion, see Liquidity and Capital Resources.
Growth Projects. During 2011, we continued to focus on our expansion projects. We spent approximately $163 million during the year, the majority of which relate to projects that have been placed into service.
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South System III. The ongoing South System III project expands the SNG pipeline system in Mississippi, Alabama and Georgia by adding approximately 81 miles of pipeline looping and replacement on SNG’s south system and 17,310 horsepower of compression to serve an existing power generation facility owned by Southern Company in the Atlanta, Georgia area that is being converted from coal fired to cleaner burning natural gas. This expansion project is comprised of three phases, with each phase expected to add an additional 122 MMcf/d of capacity. Phases I and II of the project were placed in service in January 2011 and June 2011, respectively, on time and under budget. The estimated in-service date for Phase III is June 2012.
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SESH. Phase II of the SESH project was placed in service in June 2011. Phase II expanded the jointly-owned segment of the existing SESH pipeline in order to increase SNG’s capacity in that segment from 140,000 Dth/d to 500,000 Dth/d.
We continue to evaluate additional expansion opportunities around our well-positioned assets. We have other prospective projects that are in various phases of commercial development. Many of these potential projects involve expansion capacity to serve increased natural gas-fired generation loads or to adapt to changing supply profiles resulting from burgeoning shale gas development and declines in LNG imports, and would have in-service dates from 2014 and beyond. If we are successful in contracting for these new loads, the capital requirements could be substantial and would be incremental to our contracted organic growth projects. Although we pursue the development of these potential projects from time to time, there can be no assurance that we will be successful in negotiating the definitive binding contracts necessary for such projects to be included in our contracted organic growth projects.
Results of Operations
Our management uses EBIT as a measure to assess the operating results and effectiveness of our business, which consists of both consolidated operations and investments in unconsolidated affiliates. We believe EBIT is useful to our investors to provide them with the same measure used by management to evaluate our performance so that investors may evaluate our operating results without regard to our financing methods or capital structure. We define EBIT as net income adjusted for items such as (i) interest and debt expense, net, (ii) affiliated interest income and expense, net, (iii) income tax expense and (iv) net income attributable to noncontrolling interest. EBIT may not be comparable to measures used by other companies. Additionally, EBIT should be considered in conjunction with net income, income before income taxes and other performance measures such as operating income or operating cash flows.
Below is a reconciliation of our EBIT to net income, our throughput volumes and an analysis and discussion of our operating results for each of the three years ended December 31, 2011.
Operating Results:
(1) Throughput volumes are presented for WIC, CIG and SNG only and exclude intrasegment volumes. Elba Express was placed in service in March 2010 and although capacity is under contract, the average volumes transported during the years ended December 31, 2011 and 2010 were not material.
Below is a discussion of factors impacting EBIT in 2011 as compared to 2010 and 2010 as compared to 2009.
(1) Consists of individually insignificant items.
Expansions. Our EBIT increased during the years ended December 31, 2011 and 2010 primarily due to expansion projects placed into service during 2009, 2010 and 2011. This increase was driven by higher revenues partially offset by an increase in operating expenses and lower non-cash allowance for equity funds used during construction (AFUDC equity) from expansion projects, as follows:
Transportation Revenues and Expenses. During 2011, we experienced an $18 million decrease in reservation revenue primarily driven by nonrenewal of expiring contracts on CIG, WIC and SNG and increased competition in the Rockies region. We also experienced lower usage and interruptible revenues of $8 million when compared to 2010 primarily due to record cold weather conditions in the southeast U.S. during the first quarter of 2010.
During 2010, our SNG system experienced higher revenues of $54 million when compared to 2009 as a result of higher tariff rates which became effective September 1, 2009 pursuant to its rate case settlement as discussed in Other Regulatory Matters below. Additionally, our revenues increased during 2010 when compared to 2009 due to higher reservation revenue of $16 million on WIC’s mainline system which was offset by $16 million in higher expenses as a result of increased third party capacity commitments. During 2009, our EBIT was negatively impacted by a $4 million transportation contract buy-out cost on CIG and an $8 million decrease in usage revenues on CIG and WIC.
Throughput decreased from 2010 to 2011 primarily due to lower demand for volumes driven by lower regional exports from the Rockies which negatively impacted our WIC system and a return of normal weather in the southeast U.S. following extremely cold temperatures in 2010, which negatively impacted our SNG system. Overall throughput also decreased from 2009 to 2010 primarily due to lower demand for volumes on WIC and CIG as a result of milder weather and increased competition from pipelines taking gas out of the Rockies region. This decrease was partially offset by an increase in SNG as a result of extreme weather during 2010, increased gas-fired power generation and recovering industrial demand. However, these decreases in throughput do not have a significant impact on EBIT as a material portion of our revenue is derived from firm reservation contracts.
Operational Gas, Revaluations and Processing Revenues. During 2011, we experienced $3 million unfavorable gas balance revaluations on our SNG system due to lower prices and higher retained volumes in 2011 when compared to 2010. During 2010, we experienced $9 million favorable gas balance revaluations on CIG and WIC when compared to 2009. We also benefited from the implementation of SNG’s fuel volumetric tracker by $5 million in 2010 as part of SNG’s rate case settlement which was offset by a $7 million unfavorable impact due to the elimination of SNG’s fuel sharing mechanism. During 2009, WIC recorded a $10 million unfavorable fuel tracker adjustment which was partially offset by CIG’s $7 million favorable fuel tracker adjustment pursuant to the 2009 FERC orders. On July 31, 2009 and October 1, 2009, the FERC issued orders to CIG and WIC, respectively, which retroactively unwound the non-volumetric provisions of the fuel and gas cost recovery mechanisms, which exposes us to both positive and negative fluctuations in gas prices related to gas balance items. The price volatility impacts our earnings on the CIG, WIC and SNG systems through the monthly non-cash revaluation of our gas balances. We continue to seek options with the FERC and shippers to minimize the price volatility associated with these operational activities.
In addition, our processing revenue at CIG is largely offset by expenses associated with the gas consumed in processing the liquids. CIG experienced $5 million lower processing revenues in 2011 compared to 2010 due to decreased demand partially offset by favorable prices of natural gas liquids. This decrease was largely offset by lower gas processing expenses in 2011 due to lower gas prices. CIG experienced $8 million higher processing revenues in 2010 compared to 2009 due to increased demand and favorable prices of natural gas liquids partially offset by $7 million higher gas processing expenses as a result of unfavorable gas prices.
Operating, General and Administrative Expenses. During 2011, our operating expenses related to contractor and maintenance costs increased by $10 million due to increased activity and expansions placed in service. There was also an increase of $5 million due to higher costs related to our pipeline integrity program. Additionally, our EBIT was unfavorably impacted during 2011 by $9 million primarily due to higher payroll and benefit costs. During 2010, we experienced lower general and administrative expenses when compared to 2009 primarily due to severance costs recorded in 2009.
Non-cash Asset Write Down/Gain on Sale of Assets. In November 2009, CIG sold the Natural Buttes compressor station and gas processing plant to a third party and recorded a gain of approximately $8 million related to the sale. In September 2010, CIG recorded a $21 million non-cash write down as an increase to operation and maintenance expense based on a FERC order related to the 2009 sale of the Natural Buttes facilities. In October 2010, CIG filed a request for rehearing and clarification of the FERC order and in October 2011, the FERC denied the request. For a further discussion of Natural Buttes, see Item 8. Financial Statements and Supplementary Data, Note 2.
Project Cancellation Payment. In June 2011, SLNG recognized $17 million of operating revenue, consisting of a $9 million payment received in 2009 which granted BG LNG Services, LLC (BG LNG) a cancellation option related to their commitment on Phase B of SLNG’s Elba III Expansion and $8 million received as a result of BG LNG exercising their cancellation option in June 2011. In addition, SLNG wrote off $3 million for certain project development costs incurred in conjunction with this expansion project.
Net Income Attributable to Noncontrolling Interests. The decrease in net income attributable to noncontrolling interest for 2011 as compared to 2010 is primarily due to the acquisition of the remaining 49 percent member interest in each of SLNG and Elba Express in November 2010, the acquisition of an additional 28 percent interest in CIG in June 2011 and the acquisition of the aggregate remaining 40 percent interest in SNG in March and June 2011.
The increase in net income attributable to noncontrolling interest for 2010 as compared to 2009 was primarily driven by the increase in net income due to an increase in CIG’s net income primarily related to additional revenue generated by CIG from its Totem Gas Storage expansion project, an increase in SLNG’s net income from its Elba III Phase A Expansion project which was placed in service in March and July 2010, an increase in Elba Express’ net income from placing the Elba Express Pipeline in service in March 2010 and an increase in SNG’s net income primarily from its higher tariff rates effective September 1, 2009 pursuant to their rate case settlement.
Other Regulatory Matters. Our pipeline systems periodically file for changes in their rates, which are subject to approval by the FERC. Changes in rates and other tariff provisions resulting from these regulatory proceedings have the potential to positively or negatively impact our profitability.
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SNG Rate Case. In January 2010, the FERC approved SNG’s rate case settlement in which SNG (i) increased its base tariff rates effective September 1, 2009, (ii) implemented a volume tracker for gas used in operations, (iii) agreed to file its next general rate case to be effective after August 31, 2012 but no later than September 1, 2013 and (iv) extended the majority of SNG’s firm transportation contracts until August 31, 2013. As part of the proposed asset sale entered into in September 2011 (see Item 8. Financial Statements and Supplementary Data, Note 2), SNG agreed with its customers to file its next general rate case to be effective September 1, 2013.
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CIG Rate Case. In August 2011, the FERC approved an uncontested pre-filing settlement of a rate case required under the terms of a previous settlement. The settlement generally provides for (i) CIG’s current tariff rates to continue until the next general rate case which will be effective no earlier than October 1, 2014 but no later than October 1, 2016; (ii) contract extensions to March 2016; (iii) a revenue sharing mechanism with certain of our customers for certain revenues above annual threshold amounts; and (iv) a revenue surcharge mechanism with certain of our customers to charge for certain shortfalls of revenue less than an annual threshold amount.
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Bear Creek Cost and Revenue Study. In November 2011, Bear Creek, along with other unaffiliated storage companies, received an order from the FERC related to an investigation into the rates charged to customers. The FERC ordered Bear Creek to file a full cost and revenue study within 75 days of the order. Bear Creek filed the cost and revenue study in January 2012 and the outcome of this proceeding is not expected to be material to our results of operations.
Interest and Debt Expense
For the periods ended December 31, 2011 and 2010, interest and debt expense increased by $68 million and $58 million as compared to same periods in 2010 and 2009, respectively. The increases in 2011 and 2010 were primarily due to higher average debt outstanding used to partially fund acquisitions and organic expansion projects and lower allowance for funds used during construction debt as a result of expansion projects placed in service during 2010 and 2011. The increase in our average debt outstanding for 2011 was attributable to the debt issuance of $500 million by EPPOC and $300 million by SNG and the 2010 increase was attributable to EPPOC’s issuance of $1.3 billion. Also contributing to the 2011 increase in interest expense was an increase in interest rates primarily as a result of refinancing our revolving credit facility in May 2011. For a further discussion of our long-term financing obligations, see Item 8. Financial Statements and Supplementary Data, Note 7.
The following table shows the average balance outstanding and the average interest rates under our credit facility for the years ended December 31, 2011, 2010 and 2009:
Income Taxes
Effective February 4, 2010, SLNG converted into a limited liability company and is no longer subject to income taxes. Our effective tax rates of less than one percent for the year ended December 31, 2010 and 4 percent for the year ended December 31, 2009 were lower than the statutory rate of 35 percent due to income associated with non-taxpaying entities, partially offset by the effect of state income taxes. For a reconciliation of the statutory rate to the effective tax rates, see Item 8. Financial Statements and Supplementary Data, Note 14.
Distributable Cash Flow
We use the non-GAAP financial measure “Distributable Cash Flow” as it provides important information relating our financial operating performance to our cash distribution capability. Additionally, we use Distributable Cash Flow in setting forward expectations and in communications with the board of directors of our general partner. We define Distributable Cash Flow as Adjusted EBITDA less cash interest expense, net, maintenance capital expenditures, pre-acquisition undistributed earnings from consolidated subsidiaries and adjusted for other income and expenses, net, which primarily includes deferred revenue, AFUDC equity and other non-cash items. Adjusted EBITDA, which is also a non-GAAP financial measure, is defined as net income adjusted for (i) income tax expense (ii) interest and debt expense, net of interest income, (iii) affiliated interest income, net of affiliated interest expense, (iv) depreciation and amortization expense, (v) the partnership’s share of distributions declared by unconsolidated affiliates for the applicable period, (vi) earnings from unconsolidated affiliates and (vii) distributions declared by majority owned subsidiaries to El Paso for the applicable period.
We believe that the non-GAAP financial measures described above are useful to investors because these measures are used by many companies in the industry as measures of operating and financial performance and are commonly employed by financial analysts and others to evaluate the operating and financial performance of the partnership and to compare it with the performance of other publicly traded partnerships within the industry.
Neither Distributable Cash Flow nor Adjusted EBITDA should be considered an alternative to net income, earnings per unit, operating income, cash flow from operating activities or any other measure of financial performance presented in accordance with U.S. GAAP. These non-GAAP measures exclude some, but not all items that affect net income and operating income and these measures may vary among other companies; therefore, Distributable Cash Flow and Adjusted EBITDA may not be comparable to similarly titled measures of other companies. Furthermore, these non-GAAP measures should not be viewed as indicative of the actual amount of cash we have available for distributions or that we plan to distribute for a given period, nor do they equate to Available Cash as defined in our partnership agreement.
Our Distributable Cash Flows were $574 million and $390 million for the years ended December 31, 2011 and 2010. The increase in distributable cash flow in 2011 was primarily due to higher expansion revenues and our increased ownership interest in SLNG, Elba Express, CIG and SNG. The tables below provide our reconciliations of Distributable Cash Flow and Adjusted EBITDA for the years ended December 31, 2011 and 2010.
Reconciliation of Distributable Cash Flow to Net Income
(1) For a further discussion of our use of EBIT, see Results of Operations.
(2) In 2011, declared distributions include $35 million from CIG and $12 million from SNG. In 2010, declared distributions include $72 million from CIG, $128 million from SNG, $36 million from SLNG and $12 million from Elba Express.
(3) The amount represents SNG’s undistributed earnings prior to the November 2010 acquisition by EPB. For further discussion, see Note 2.
(4) Includes deferred revenue and certain non-cash items such as AFUDC equity, $6 million non-cash earnings related to BG LNG’s cancellation option and related write-off in 2011, $21 million asset write down in 2010 based on FERC order related to the sale of the Natural Buttes facilities and other items.
Reconciliation of Distributable Cash Flow to Net Cash Provided by Operating Activities
(1) In 2011, declared distributions include $35 million from CIG and $12 million from SNG. In 2010, declared distributions include $72 million from CIG, $128 million from SNG, $36 million from SLNG and $12 million from Elba Express.
(2) The amount represents SNG’s undistributed earnings prior to the November 2010 acquisition by EPB. For further discussion , see Note 2.
(3) Includes deferred revenue and certain non-cash items such as AFUDC equity, $6 million non-cash earnings related to BG LNG’s cancellation option and related write-off in 2011, $21 million asset write down in 2010 based on FERC order related to the sale of the Natural Buttes facilities and other items.
Liquidity and Capital Resources
Our ability to finance our operations, including our ability to make cash distributions, fund capital expenditures, make acquisitions and satisfy any indebtedness obligations will depend on our ability to generate cash in the future and our ability to access the capital markets. Our ability to generate cash and our ability to access the capital markets is subject to a number of factors, some of which are beyond our control as discussed below.
Our sources of liquidity include cash generated from our operations and available borrowing capacity under our $1.0 billion new revolving credit facility. This facility is expandable to $1.5 billion for certain expansion projects and acquisitions. We may also generate additional sources of cash through future issuances of additional partnership units and/or future debt offerings. As of December 31, 2011, we had approximately $1.1 billion of liquidity, consisting of $1.0 billion of availability under our new credit facility and $105 million of cash on hand.
We are primarily relying on cash flows from operating activities and availability under our new credit facility to meet our operating needs, our anticipated cash distributions to our partners and our planned capital expenditure requirements for the foreseeable future. Our exposure to changes in our operating cash flows as the result of changes in natural gas consumption and demand is largely mitigated by a revenue base that is significantly comprised of long term contracts that are based on firm demand charges and are less affected by a potential reduction in the actual usage or consumption of natural gas. In addition, we believe the current equity and debt capital markets will support potential acquisition opportunities.
Our total cash capital expenditures for the year ended December 31, 2011 were $264 million, including $101 million for maintenance and $163 million for expansion. We expect our current liquidity and operating cash flow to be sufficient to fund our estimated 2012 capital program of approximately $141 million, including $91 million for maintenance and $50 million for expansion. Our expansion capital is primarily for Phase III of SNG’s South System III expansion and is expected to be place in service in June 2012. We continue to evaluate additional expansion opportunities around our well-positioned assets. While we expect to fund maintenance capital expenditures through internally generated funds, we intend to fund our expansion capital expenditures through cash on hand and borrowings under our new credit facility. We have $65 million of current debt maturities consisting of $55 million of senior notes and other financing obligations and a $10 million affiliate note payable to El Paso which we anticipate to refinance primarily through revolver borrowings. As a result of our current available liquidity, we believe we are well positioned to meet our obligations. We will continue to assess and take further actions where prudent to meet our long-term objectives and capital requirements as well as address further changes in the financial and commodity markets.
However, there are a number of factors that could impact our future plans, including the completion of El Paso’s announced merger with KMI, and our ability to increase our distributions, to make strategic acquisitions from El Paso and third parties, to recontract our expiring contracts and to access the financial markets if these markets are restricted. If these events occur, or fail to occur, additional adjustments to our plan may be required. For further detail of risk factors which could impact our business and liquidity, see Part 1, Item 1A. Risk Factors.
Overview of Cash Flow Activities. Our cash flows for the years ended December 31, 2011 and 2010 are summarized as follows:
For the year ended December 31, 2011, we generated cash flow from operations of $748 million compared to $672 million in the same period in 2010. Our operating cash flow in 2011 increased as compared to 2010 primarily due to higher revenue from our WIC System Expansion, Raton 2010 Expansion, Elba III Phase A Expansion and Elba Express pipeline which were placed in service in 2010. Phases I and II of the South System III expansion project, which were placed in service in 2011 also contributed to the increase. Those increases were partially offset by lower transportation revenue driven by nonrenewal of expiring contracts in both the southeast U.S. and Rockies regions and increased competition in the Rockies. In addition, higher operating, general and administrative expenses driven by increased contractor and material costs from field repairs and higher payroll and benefit costs also offset the cash flow from expansion projects placed in service. Our 2010 operating cash flows were burdened primarily due to SLNG’s conversion into a limited liability company and the related pre-acquisition settlement of its current and deferred tax balances. During 2011 we received $968 million in net proceeds from the issuance of additional common and general partner units, $789 million of net proceeds from SNG’s and EPPOC’s debt offerings and approximately $1.0 billion in borrowings under our new revolving credit facility. In addition, El Paso contributed $30 million to us to fund their share of expansion capital expenditures for SNG and CIG.
During 2011, we utilized our cash inflows to pay distributions, including the CIG and SNG distributions to El Paso for its share of available cash (see Item 8. Financial Statements, Note 13), to fund maintenance and growth projects and to acquire additional interests in SNG and CIG. We made cash distributions to our unitholders of $422 million during the year ended December 31, 2011 compared to $244 million in the same period in 2010, reflecting a greater number of partnership units outstanding, an increase in our cash distribution per unit and increased incentive distributions to our general partner.
Off-Balance Sheet Arrangements
We have no off-balance sheet financing entities or structures with third parties other than our equity investments in WYCO and Bear Creek, our accounts receivable sales program and a letter of credit associated with construction costs for SNG. For a further discussion of our off-balance sheet arrangements, see Item 8. Financial Statements and Supplementary Data, Note 13, 12 and 9.
Contractual Obligations
We are party to various contractual obligations, a portion of which are reflected in our financial statements, such as long-term debt and our capital lease. Other obligations, such as capital commitments and demand charges under transportation commitments, are not reflected on our balance sheet. The following table and discussion that follows summarizes our contractual cash obligations as of December 31, 2011 for each of the periods presented:
Long-Term Financing Obligations (Principal and Interest). Long-term financing obligations represent stated maturities. Interest payments are shown through the stated maturity date of the related debt based on (i) the contractual interest rates for fixed rate debt and (ii) current market interest rates and the contractual credit spread for our variable rate debt. Included in these amounts are payments related to the financing obligations of CIG for the construction of WYCO’s High Plains pipeline and Totem gas storage facility. CIG makes monthly interest payments on these obligations that are based on 50 percent of the operating results of High Plains pipeline and Totem storage facility. Also included in these amounts is a compressor station under a capital lease from CIG’s unconsolidated investment in WYCO. The compressor station lease expires in November 2029. For a further discussion of our long-term financing and capital lease obligations see Item 8. Financial Statements and Supplementary Data, Note 7.
Other contractual liabilities. Included in this amount are environmental liabilities related to sites that we own or have a contractual or legal obligation with a regulatory agency or property owner upon which we perform remediation activities. These liabilities are included in other current and non-current liabilities in our balance sheet.
Operating Leases. For a further discussion of these obligations, see Item 8. Financial Statements and Supplementary Data, Note 9.
Capital Commitments. Included in this amount are capital commitments related to our expansion projects. We have other planned capital and investment projects that are discretionary in nature, with no substantial contractual capital commitments made in advance of the actual expenditures. For a further discussion of these obligations, see Item 8. Financial Statements and Supplementary Data, Note 9.
Other Contractual Commitments and Purchase Obligations. Other contractual commitments and purchase obligations are defined as legally enforceable agreements to purchase goods or services that have fixed or minimum quantities and fixed or minimum variable price provisions, and that detail approximate timing of the underlying obligations. Included are the following:
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Transportation and Storage Commitments. Included in these commitments are agreements for capacity on third party pipeline systems and storage capacity from an affiliate.
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Other Commitments. Included in these amounts are commitments for purchase obligations. We exclude asset retirement obligations and reserves for litigation and environmental remediation, other than those disclosed above, when these liabilities are not contractually fixed as to timing and amount.
Critical Accounting Estimates
Our significant accounting policies are described in Note 1 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K. The preparation of financial statements in conformity with GAAP requires management to select appropriate accounting estimates and to make estimates and assumptions that affect the reported amount of assets, liabilities, revenues, expenses and the disclosures of contingent assets and liabilities. We consider our critical accounting estimates to be those that require difficult, complex, or subjective judgment necessary in accounting for inherently uncertain matters and those that could significantly influence our financial results based on changes in those judgments. Changes in facts and circumstances may result in revised estimates and actual results may differ materially from those estimates. We have discussed the development and selection of the following critical accounting estimates and related disclosures with the Audit Committee of our Board of Directors.
Cost-Based Regulation. We account for our regulated operations in accordance with current Financial Accounting Standards Board accounting standards for rate-regulated operations. The economic effects of regulation can result in a regulated company recording assets for costs that have been or are expected to be approved for recovery from customers or recording liabilities for amounts that are expected to be returned to customers in the rate-setting process in a period different from the period in which the amounts would be recorded by a non-regulated enterprise. Accordingly, we record assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. Management regularly assesses whether regulatory assets are probable of future recovery or if regulatory liabilities are probable of being refunded to our customers by considering factors such as applicable regulatory changes and recent rate orders applicable to other regulated entities. Based on this continual assessment, management believes the existing regulatory assets are probable of recovery. We periodically evaluate the applicability of accounting standards related to regulated operations, and consider factors such as regulatory changes and the impact of competition. If cost-based regulation ends or competition increases, we may have to reduce certain of our asset balances to reflect a market basis lower than cost and write-off the associated regulatory assets.
Accounting for Environmental and Legal Reserves. We accrue environmental and legal reserves when our assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. Estimates of our liabilities are based on an evaluation of potential outcomes, currently available facts, and in the case of environmental reserves, existing technology and presently enacted laws and regulations taking into consideration the likely effects of societal and economic factors, estimates of associated onsite, offsite and groundwater technical studies and legal costs. Actual results may differ from our estimates, and our estimates can be, and often are, revised in the future, either negatively or positively, depending upon actual outcomes or changes in expectations based on the facts surrounding each matter.
Accounting for Other Postretirement Benefits. We reflect an asset or liability for our subsidiaries’ postretirement benefit plans based on their over funded or underfunded status. As of December 31, 2011, our postretirement benefit plans were over funded by $17 million. Our postretirement benefit obligations and net benefit costs are primarily based on actuarial calculations. We use various assumptions in performing these calculations, including those related to the return that we expect to earn on our plan assets, the estimated cost of health care when benefits are provided under our plans and other factors. A significant assumption we utilize is the discount rates used in calculating the benefit obligations. We select our discount rate by matching the timing and amount of our expected future benefit payments for our postretirement benefit obligation to the average yields of various high-quality bonds with corresponding maturities.
Actual results may differ from the assumptions included in these calculations, and as a result, our estimates associated with the postretirement benefits can be, and often are, revised in the future. The income statement impact of the changes in the assumptions on our related benefit obligations, along with changes to the plans and other items, are deferred and recorded as either accumulated other comprehensive income or a regulatory asset or liability depending on whether these costs are recoverable through rates. A one-percentage point change in the primary assumptions would not have had a significant effect on net postretirement benefit cost. The following table shows the impact of a one percent change to the funded status for the year ended December 31, 2011 (in millions):
Asset and Investment Impairments. The accounting rules on asset and investment impairments require us to continually monitor our businesses, the business environment and the performance of our investments to determine if an event has occurred that indicates that a long-lived asset or investment may be impaired. Such events include market declines that are believed to be other than temporary, changes in the manner in which we intend to use a long-lived asset, decisions to sell an asset or investment and adverse changes in the legal or business environment such as adverse actions by regulators. If an event occurs, which is a determination that involves judgment, we evaluate the recoverability of our carrying values based on either (i) the long-lived asset’s ability to generate future cash flows on an undiscounted basis or (ii) the fair value of the investment in an unconsolidated affiliate. The assessment of project level cash flows requires significant judgment to make projections and assumptions for many years into the future for pricing, demand, competition, operating costs, legal and regulatory issues and other factors that are often outside of our control. Due to the imprecise nature of these projections and assumptions, actual results can, and often do, differ from our estimates. If an impairment is indicated, or if we decide to sell a long-lived asset or group of assets, we adjust the carrying value of the asset downward, if necessary, to its estimated fair value.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our primary market risk is exposure to changing interest rates. The table below shows the maturity of the carrying amounts and related weighted-average interest rates on our long-term interest-bearing securities by expected maturity date as well as the total fair value of those securities. The fair value on our fixed and variable rate obligations have been estimated based on quoted market prices for the same or similar issues.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index
Below is an index to the items contained in Part II, Item 8. Financial Statements and Supplementary Data.
MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined by Securities and Exchange Commission (SEC) rules adopted under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is 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. It consists of policies and procedures that:
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Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;
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Provide reasonable assurance that transactions are recorded as necessary to permit preparation of the financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and
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Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.
Under the supervision and with the participation of management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), we made an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2011. In making this assessment, we used the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our evaluation, we concluded that our internal control over financial reporting was effective as of December 31, 2011. The effectiveness of our internal control over financial reporting as of December 31, 2011 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report included herein.
Report of Independent Registered Public Accounting Firm
The Board of Directors of El Paso Pipeline GP Company, L.L.C.
as General Partner of El Paso Pipeline Partners, L.P.,
and the Partners of El Paso Pipeline Partners, L.P.:
We have audited the accompanying consolidated balance sheets of El Paso Pipeline Partners, L.P. (the Partnership) as of December 31, 2011 and 2010, and the related consolidated statements of income, comprehensive income, partners’ capital and cash flows for each of the three years in the period ended December 31, 2011. Our audits also included the financial statement schedule listed in the Index at Item 15(a) for each of the three years in the period ended December 31, 2011. These financial statements and schedule are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of El Paso Pipeline Partners, L.P. at December 31, 2011 and 2010, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole presents fairly in all material respects the information set forth therein.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), El Paso Pipeline Partners, L.P.’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2012 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Houston, Texas
February 27, 2012
Report of Independent Registered Public Accounting Firm
The Board of Directors of El Paso Pipeline GP Company, L.L.C.
as General Partner of El Paso Pipeline Partners, L.P.,
and the Partners of El Paso Pipeline Partners, L.P.:
We have audited El Paso Pipeline Partners, L.P.’s (the Partnership) internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). El Paso Pipeline Partners, L.P.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of 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.
In our opinion, El Paso Pipeline Partners, L.P. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of El Paso Pipeline Partners, L.P. as of December 31, 2011 and 2010, and the related consolidated statements of income, comprehensive income, partners’ capital and cash flows for each of the three years in the period ended December 31, 2011 of El Paso Pipeline Partners, L.P. and our report dated February 27, 2012 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Houston, Texas
February 27, 2012
El PASO PIPELINE PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per unit amounts)
(1) All subordinated units were converted to common units on a one-for-one basis effective January 3, 2011. See Note 4 for further discussion.
See accompanying notes.
EL PASO PIPELINE PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In millions)
See accompanying notes.
El PASO PIPELINE PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(In millions, except units)
See accompanying notes.
El PASO PIPELINE PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
See accompanying notes.
El PASO PIPELINE PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(In millions)
See accompanying notes.
El PASO PIPELINE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Basis of Presentation and Significant Accounting Policies
Organization
We are a Delaware master limited partnership formed in 2007 to own and operate interstate natural gas transportation and terminaling facilities. We own Wyoming Interstate Company, L.L.C. (WIC), Southern LNG Company, L.L.C. (SLNG), Elba Express Company, L.L.C. (Elba Express), Southern Natural Gas Company, L.L.C. (SNG) and an 86 percent interest in Colorado Interstate Gas Company, L.L.C. (CIG). WIC and CIG are interstate pipeline systems serving the Rocky Mountain region, SLNG owns the Elba Island LNG storage and regasification terminal near Savannah, Georgia, and both Elba Express and SNG are interstate pipeline systems serving the southeastern region of the United States (U.S.). We are controlled by our general partner, El Paso Pipeline GP Company, L.L.C., a wholly-owned subsidiary of El Paso Corporation (El Paso).
Effective August 2011, CIG and SNG converted their legal structures to limited liability companies and changed their names to Colorado Interstate Gas Company, L.L.C. and Southern Natural Gas Company, L.L.C.
On October 16, 2011, El Paso announced a definitive agreement (the “Merger Agreement”) with Kinder Morgan, Inc. (KMI) whereby KMI will acquire El Paso in a transaction that valued El Paso at approximately $38 billion (based on the KMI stock price at that date), including the assumption of debt. The transaction has been approved by each company’s board of directors but remains subject to the approvals of El Paso’s shareholders, the Federal Trade Commission and other customary regulatory and other approvals. The approval of KMI shareholders will also be required, but a voting agreement has been executed by the majority of the shareholders of KMI to support the transaction. We will conduct our business in the ordinary course, in all material respects, in substantially the same manner as conducted prior to the date of the Merger Agreement, subject to certain conditions and restrictions. The most substantial of which are a limitation on the size of quarterly distribution increases and approval from KMI of asset drop downs from El Paso to us.
Basis of Presentation and Principles of Consolidation
Our consolidated financial statements are prepared in accordance with U.S. generally accepted accounting principles (GAAP) and include the accounts of all consolidated subsidiaries after the elimination of all significant intercompany accounts and transactions. Our financial statements for prior periods also include reclassifications that were made to conform to the current year presentation, none of which impacted our reported net income, partners’ capital or cash flows from operating activities. We consolidate entities when we have the ability to control or direct the operating and financial decisions of the entity or when we have a significant interest in the entity that gives us the ability to direct the activities that are significant to that entity. The determination of our ability to control, direct or exert significant influence over an entity involves the use of judgment. We apply the equity method of accounting where we can exert significant influence over, but do not control or direct the policies, decisions or activities of an entity.
Use of Estimates
The preparation of our financial statements requires the use of estimates and assumptions that affect the amounts reported as assets, liabilities, revenues, expenses and disclosures in these financial statements. Actual results can, and often do, differ from those estimates.
Regulated Operations
Our interstate natural gas pipelines, storage operations and liquefied natural gas (LNG) receiving terminal are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC) and follow the Financial Accounting Standards Board’s (FASB) accounting standards for regulated operations. Under these standards, we record regulatory assets and liabilities that would not be recorded for non-regulated entities. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges or credits that are expected to be recovered from or refunded to customers through the rate making process. Items to
which we apply regulatory accounting requirements include certain postretirement benefit plan costs, losses on reacquired debt, taxes related to an equity return component on regulated capital projects in periods prior to our subsidiaries’ change in legal structure to non taxable entities, certain costs related to gas not used in operations and other costs included in, or expected to be included in, future rates.
Cash and Cash Equivalents
We consider short-term investments with an original maturity of less than three months to be cash equivalents.
Allowance for Doubtful Accounts
We establish provisions for losses on accounts receivable and for natural gas imbalances due from shippers and operators if we determine that we will not collect all or part of the outstanding balance. We regularly review collectability and establish or adjust our allowance as necessary using the specific identification method.
Materials and Supplies
We value our materials and supplies at the lower of cost or market value with cost determined using the average cost method.
Natural Gas Imbalances
Natural gas imbalances occur when the amount of natural gas delivered from or received by a pipeline system differs from the scheduled amount of gas delivered or received. We value these imbalances due to or from shippers and operators at current index prices. Imbalances are settled in cash or made up in-kind, subject to the terms of the tariff. Imbalances due from others are reported in the balance sheet as either accounts receivable from customers or accounts receivable from affiliates. Imbalances owed to others are reported in the balance sheet as either trade accounts payable or accounts payable to affiliates. We classify all imbalances as current as we expect them to be settled within a year.
Property, Plant and Equipment
Our property, plant and equipment is recorded at its original cost of construction or, upon acquisition, at either the fair value of the assets acquired or the cost to the entity that first placed the asset in service. For constructed assets, direct costs, such as labor and materials, and indirect costs, such as overhead, interest and an equity return component are capitalized, as allowed by the FERC. Major units of property replacements or improvements are capitalized and minor items are expensed.
We use the composite (group) method to depreciate property, plant and equipment. Under this method, assets with similar lives and characteristics are grouped and depreciated as one asset. The FERC-accepted depreciation rate is applied to the total cost of the group until the net book value equals the salvage value. For certain general plant, the asset is depreciated to zero. We re-evaluate depreciation rates each time we redevelop our transportation and storage rates to file with the FERC for an increase or decrease in rates. When property, plant and equipment is retired, accumulated depreciation and amortization is charged for the original cost of the assets in addition to the cost to remove, sell or dispose of the assets, less salvage value. We do not recognize gains or losses unless we sell or retire an entire operating unit, as determined by the FERC. We include gains or losses on dispositions of operating units in operations and maintenance expense in our income statements.
Included in our property balances are base gas and working gas at our storage facilities. We periodically evaluate natural gas volumes at our storage facilities for gas losses. When events or circumstances indicate a loss has occurred, we recognize a loss in our income statement or defer the loss as a regulatory asset on our balance sheet if deemed probable of recovery through future rates charged to customers.
We capitalize a carrying cost (an allowance for funds used during construction or AFUDC) on debt and equity funds related to the construction of long-lived assets. This carrying cost consists of a return on the investment financed by debt and a return on the investment financed by equity. The debt portion is calculated based on the average cost of debt. Interest costs capitalized are included as a reduction to interest and debt expense on our income statement. The equity portion is calculated based on the most recent FERC approved rate of return. Equity amounts capitalized are included in other income on our income statements.
Asset and Investment Divestitures/Impairments
We evaluate our assets and investments for impairment when events or circumstances indicate that their carrying values may not be recovered. These events include market declines that are believed to be other than temporary, changes in the manner in which we intend to use a long-lived asset, decisions to sell an asset or investment and adverse changes in the legal or business environment such as adverse actions by regulators. If an event occurs, which is a determination that involves judgment, we evaluate the recoverability of our carrying values based on either (i) the long-lived asset’s ability to generate future cash flows on an undiscounted basis or (ii) the fair value of the investment in an unconsolidated affiliate. If an impairment is indicated, or if we decide to sell a long-lived asset or group of assets, we adjust the carrying value of the asset downward, if necessary, to its estimated fair value. Our fair value estimates are generally based on assumptions market participants would use, including market data obtained through the sales process or an analysis of expected discounted cash flows.
We classify assets (or groups of assets) to be disposed of as held for sale when specific criteria have been met. The lower of the carrying value or the estimated fair value less cost to sell of those assets is considered to determine if recognition of an impairment is required. We cease depreciation and amortization of the assets in the period they are considered held for sale.
Revenue Recognition
Our revenues are primarily generated from natural gas transportation, storage and processing services as well as from LNG storage services and terminal operations and include estimates of amounts earned but unbilled. We estimate these unbilled revenues based on contract data, regulatory information, and preliminary throughput and allocation measurements, among other items. Revenues for all services are based on the thermal quantity of gas delivered or subscribed at a price specified in the contract. For our transportation services and storage services, we recognize reservation revenues on firm contracted capacity ratably over the contract period regardless of the amount of natural gas that is transported or stored. For interruptible or volumetric-based services, we record revenues when physical deliveries of natural gas are made at the agreed upon delivery point or when gas is injected or withdrawn from the storage facility. For contracts with step-up or step-down rate provisions that are not related to changes in levels of service, we recognize reservation revenues ratably over the contract life. Gas not used in operations is based on the volumes we are allowed to retain relative to the amounts of gas we use for operating purposes. We recognize revenue from gas not used in operations from our shippers when the FERC allows us to retain the volumes at the market prices required under our tariffs. We are subject to FERC regulations and, as a result, revenues we collect may be subject to refund in a rate proceeding. We establish reserves for these potential refunds.
Environmental Costs and Other Contingencies
Environmental Costs. We record environmental liabilities at their undiscounted amounts on our balance sheet as other current or long-term liabilities when environmental assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of our liabilities are based on currently available facts, existing technology and presently enacted laws and regulations, taking into consideration the likely effects of other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by the Environmental Protection Agency (EPA) or other organizations. Our estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and we recognize a current period charge in operation and maintenance expense when clean-up efforts do not benefit future periods.
We evaluate any amounts paid directly or reimbursed by government sponsored programs and potential recoveries or reimbursements of remediation costs from third parties including insurance coverage separately from our liability. Recovery is evaluated based on the creditworthiness or solvency of the third party, among other factors. When recovery is assured, we record and report an asset separately from the associated liability on our balance sheet.
Other Contingencies. We recognize liabilities for other contingencies when we have an exposure that indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the low end of the range is accrued.
Income Taxes
Effective February 2010, SLNG converted into a limited liability company and is no longer subject to income taxes. As a result of the conversion, SLNG settled its current and deferred tax balances with recoveries of notes receivable from El Paso under the cash management program pursuant to the tax sharing agreement with El Paso (see Note 14). Prior to the conversion date, SLNG recorded current income taxes based on taxable income and provided for deferred income taxes to reflect estimated future tax payments and receipts. Deferred taxes represented the income tax impacts of differences between the financial statement and tax basis of assets and liabilities and carryovers at each year end.
We are a partnership for income tax purposes and are not subject to either federal income taxes or generally to state income taxes. Our partners are responsible for income taxes on their allocated share of taxable income which may differ from income for financial statement purposes due to differences in the tax basis and financial reporting basis of assets and liabilities. We are unable to readily determine the net difference in the bases of our assets and liabilities for financial and tax reporting purposes because information regarding each partner’s tax attributes in us is not available to us.
Accounting for Asset Retirement Obligations
We record a liability for legal obligations associated with the replacement, removal and retirement of our long-lived assets in the period the obligation is incurred and estimable. Our asset retirement liabilities are initially recorded at their estimated fair value with a corresponding increase to property, plant and equipment. This increase in property, plant and equipment is then depreciated over the useful life of the asset to which that liability relates. An ongoing expense is recognized for changes in the value of the liability as a result of the passage of time, which we record as depreciation and amortization in our income statement. If we have the ability to recover certain of these costs from our customers, we record an asset (rather than expense) associated with the initial recognition and subsequent accretion of the liabilities described above.
We have legal obligations associated with the retirement of our natural gas pipeline, related transmission facilities, storage wells and LNG facilities. We have obligations to plug storage wells when we no longer plan to use them and when we abandon them. Our legal obligations associated with our natural gas transmission facilities primarily involve purging, sealing and possibly removing the facilities if they are abandoned. We also have obligations to remove hazardous materials associated with our natural gas transmission facilities if they are replaced. We accrue a liability for legal obligations based on an estimate of the timing and amount of their settlement.
We are required to operate and maintain our natural gas pipelines, storage systems and LNG facilities, and intend to do so as long as supply and demand for natural gas exists, which we expect for the foreseeable future. Therefore, we believe that we cannot reasonably estimate the asset retirement obligation for the substantial majority of our natural gas pipeline system assets and LNG facility assets because these assets have indeterminate lives. We continue to evaluate our asset retirement obligations and future developments could impact the amounts we record.
Partners’ Capital
We allocate our net income to the capital accounts of our general partner and limited partner unitholders based on the terms of the partnership agreement. The agreement requires these allocations to be made based on the relative percentage of their ownership interests, adjusted for any replenishment of previously allocated aggregate net losses and/or special allocations, each as defined in our partnership agreement. As a result of the retrospective consolidation of CIG, SLNG, Elba Express and SNG, earnings prior to the acquisitions of the incremental interests in CIG, SLNG, Elba Express and SNG (pre-acquisition earnings) have been allocated solely to our general partner.
Our partnership agreement authorizes us to issue an unlimited number of additional partnership securities on the terms and conditions determined by our general partner without the approval of our unitholders. Accordingly, all of our issued units are authorized and outstanding, and there are an unlimited number of units that are authorized beyond those currently issued.
Postretirement Benefits
CIG and SNG, our consolidated subsidiaries, maintain postretirement benefit plans covering certain of their former employees. These plans require them to make contributions to fund the benefits to be paid out under the plans. These contributions are invested until the benefits are paid out to plan participants. The net benefit cost of these plans is recorded in our income statement and is a function of many factors including benefits earned during the year by plan participants (which is a function of factors such as the level of benefits provided under the plans, actuarial assumptions and the passage of time), expected returns on plan assets and amortization of certain deferred gains and losses. For a further discussion of our policies with respect to CIG’s and SNG’s postretirement benefit plans, see Note 10.
In accounting for CIG’s and SNG’s postretirement benefit plans, we record an asset or liability based on the over funded or underfunded status. Any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions are recorded as either a regulatory asset or liability or recorded as other comprehensive income until those gains or losses are recognized on the income statement.
2. Acquisitions and Divestitures
2009 Acquisition from El Paso. As of January 2009, we owned WIC, 40 percent general partner interest in CIG and 25 percent general partner interest in SNG. In July 2009, we acquired an additional 18 percent general partner interest in CIG from El Paso for $214 million in cash. We recorded the additional interest in CIG at its historical cost of $143 million and the excess cash paid to El Paso of $71 million over contributed book value as a decrease to general partner’s capital. Subsequent to the acquisition, we had the ability to control CIG’s operating and financial decisions and policies and as a result have consolidated CIG in our financial statements. We have retrospectively adjusted our historical financial statements in all periods to reflect the reorganization of entities under common control and the change in reporting entity. We have reflected El Paso’s 42 percent interest in CIG as a noncontrolling interest in our financial statements until the acquisition of an additional 28 percent general partner interest in June 2011. As a result of the retrospective consolidation of CIG, earnings prior to the acquisition of the incremental interest in CIG, pre-acquisition earnings, have been allocated solely to our general partner. The retrospective consolidation of CIG increased net income attributable to EPB by $15 million for the year ended December 31, 2009.
2010 Acquisitions. Prior to our acquisition of SLNG and Elba Express, Elba Express purchased pipeline assets from SNG, its affiliate, for $8 million and sold pipeline assets to SNG for $18 million. We recorded both the purchase and sale at their historical cost and accordingly, recognized no gain or loss on these transactions.
In March 2010, we acquired a 51 percent member interest in each of SLNG and Elba Express from El Paso for $810 million. The consideration paid to El Paso consisted of $658 million in cash and the issuance of common units and general partner units (see Note 3). We financed the cash payment through (i) net proceeds of $420 million from the issuance of public debt in March 2010, (ii) $236 million of cash on hand from the proceeds of our January 2010 public offering of common units and related issuance of general partner units to El Paso (see Note 3) and (iii) $2 million borrowed under our revolving credit facility. We recorded the additional interests in SLNG and Elba Express at their historical cost of $468 million and the excess cash paid to El Paso of $190 million over contributed book value as a decrease to general partner’s capital. Subsequent to the acquisition, we had the ability to control SLNG’s and Elba Express’ operating and financial decisions and policies and as a result consolidated SLNG and Elba Express in our financial statements. We retrospectively adjusted our historical financial statements in all periods to reflect the reorganization of entities under common control and the change in reporting entity. We reflected El Paso’s 49 percent member interest in each of SLNG and Elba Express as noncontrolling interests in our financial statements until the acquisition of the remaining 49 percent interest in each of SLNG and Elba Express in November 2010. As a result of the retrospective consolidation, SLNG’s and Elba Express’ earnings prior to the March 2010 acquisition date were allocated solely to our general partner. The retrospective consolidation of SLNG and Elba Express increased net income attributable to EPB by $16 million and $32 million for the years ended December 31, 2010 and 2009.
In June 2010, we acquired an additional 20 percent general partner interest in SNG from El Paso for $493 million in cash. We financed the cash payment through (i) net proceeds of $325 million from our June 2010 public offering of common units and the related issuance of general partner units to El Paso (see Note 3), (ii) $110 million from the issuance of public debt, (iii) $21 million from El Paso’s repayment of our demand notes receivable and (iv) $37 million borrowed under our revolving credit facility. We recorded the additional interest in SNG at its historical cost of $319 million and the excess cash paid to El Paso of $174 million over contributed book value as a decrease to general partner’s capital.
In November 2010, we acquired the remaining 49 percent member interest in each of SLNG and Elba Express and an additional 15 percent general partner interest in SNG from El Paso for an aggregate consideration of $1,133 million in cash. We financed the cash payment through (i) net proceeds of $415 million from the September 2010 public offering of common units and related issuance of general partner units to El Paso, (see Note 3) (ii) net proceeds of $347 million from the November 2010 public offering of common units and related issuance of general partner units to El Paso (iii) and $371 million from the proceeds of the November 2010 debt offering (see Note 7). Of the aggregate consideration, $758 million was related to the acquisition of the remaining 49 percent member interest in each of SLNG and Elba Express. Such transaction was for the acquisition of additional interests in already consolidated entities, and as a result was accounted for on a prospective basis. Accordingly, we decreased our historical noncontrolling interest by $443 million associated with SLNG and Elba Express and reflected the amount as an increase to general partner’s capital.
We recorded the additional interest in SNG at its historical cost of $238 million and the excess cash paid to El Paso of $137 million over contributed book value as a decrease to general partner’s capital. Subsequent to the SNG acquisition, we had the ability to control SNG’s operating and financial decisions and policies and therefore consolidated SNG in our financial statements. We retrospectively adjusted our historical financial statements in all periods to reflect the reorganization of entities under common control and the change in reporting entity. We reflected El Paso’s 40 percent interest in SNG as a noncontrolling interest in our financial statements until the acquisition of incremental interests in March and June 2011. As a result of the retrospective consolidation of SNG, pre-acquisition earnings of the incremental interests in SNG, in historical periods are allocated solely to our general partner. The retrospective consolidation of SNG increased net income attributable to EPB by $61 million and $72 million for the year ended December 31, 2010 and 2009.
2011 Acquisitions. In March 2011, we acquired an additional 25 percent general partner interest in SNG from El Paso for $667 million in cash. We financed the acquisition through (i) net proceeds of $467 million from our March 2011 public offering of common units and related issuance of general partner units to El Paso (see Note 3) and (ii) $200 million borrowings under our revolving credit facility. This transaction was for the acquisition of an additional interest in an already consolidated entity, thus was accounted for on a prospective basis.
In June 2011, we acquired the remaining 15 percent general partner interest in SNG and an additional 28 percent general partner interest in CIG from El Paso for $745 million in cash. We financed the acquisition through (i) net proceeds of $501 million from our May 2011 public offering of common units and related issuance of general partner units to El Paso, including the underwriters’ June 2011 exercise of the overallotment option (see Note 3) and (ii) $244 million borrowings under our revolving credit facility. This transaction was for the acquisition of additional interests in already consolidated entities, thus was accounted for on a prospective basis.
We have decreased our historical noncontrolling interests in SNG and CIG for both the March and June 2011 acquisitions by $896 million and reflected that amount as an increase to general partner’s capital. We reflected El Paso’s general partner interest in SNG and CIG as noncontrolling interest in our financial statements. El Paso’s general partner interest in SNG was 40 percent from January 1, 2011 to March 13, 2011 and 15 percent until the June 29, 2011 acquisition of the remaining general partner interest. Subsequent to the June 2011 acquisition, SNG became a wholly owned subsidiary of EPB. We reflected El Paso’s 42 percent general partner interest in CIG as noncontrolling interest in our financial statements for the period from January 1, 2011 to June 29, 2011 and 14 percent thereafter.
Divestitures
Divestiture of Natural Buttes. In November 2009, CIG sold the Natural Buttes compressor station and gas processing plant to a third party for $9 million and recorded a gain of approximately $8 million related to the sale, which was included in the income statement as a reduction of operation and maintenance expense. Pursuant to the 2009 FERC order approving the sale of the compressor station and gas processing plant, CIG filed for FERC approval of the proposed accounting entries associated with the sale which utilized a technical obsolescence valuation methodology for determining the portion of the composite accumulated depreciation attributable to the plant. In September 2010, the FERC issued an order that utilized a different depreciation allocation methodology to estimate the net book value of the facilities. Based on the order, CIG recorded a non-cash adjustment as an increase to operation and maintenance expense of approximately $21 million to write down the net property, plant and equipment associated with the sale since it was no longer probable of recovery. In October 2010, CIG filed a request for rehearing and clarification of the FERC order and in October 2011, the FERC denied the request.
Assets Held for Sale. In September 2011, SNG entered into an agreement to sell certain offshore and onshore assets (including pipeline, platforms and other related assets located in the Gulf of Mexico and Louisiana) for approximately $50 million. At December 31, 2011, SNG classified these assets as held for sale at fair value which approximates the sales price. The fair value is based on observable market data which is a Level 2 measurement. SNG deferred the estimated loss of approximately $38 million as a regulatory asset. The sale is contingent upon receiving an acceptable FERC approval of the abandonment application including the ability to recover the regulatory asset in future rates, which we believe is probable based on the general support of our customer group and the underlying facts supporting the abandonment by sale.
3. Partners’ Capital
We issued common units to the public and issued general partner units to El Paso. The net proceeds from the offerings were used as partial consideration to fund acquisitions from El Paso and general partnership purposes. The table below shows the units issued, the net proceeds for the issuances and the ultimate use of the proceeds.
(1) Includes the underwriters’ exercise of their option to purchase additional common units of $28 million in July 2009, $45 million in December 2010 and a partial exercise of $25 million in June 2011, respectively.
In addition, in March 2010, we issued 5,346,251 common units and 109,107 general partner units to El Paso in conjunction with our acquisition of interests in SLNG and Elba Express.
El Paso owns a 42 percent limited partner interest in us and retains its 2 percent general partner interest in us and all of our incentive distribution rights (IDRs). The table below provides a reconciliation of our limited and general partner units.
(1) Amount is net of 4,575 forfeited unvested restricted common units.
(2) All subordinated units were converted to common units on a one-for-one basis effective January 3, 2011. See Note 4 for further discussion.
4. Earnings Per Unit and Cash Distributions
Earnings per unit. Earnings per unit is calculated based on distributions declared to our unitholders, including distributions related to the IDRs for the related reporting period. To the extent net income attributable to EPB exceeds cash distributions, the excess is allocated to unitholders and the holder of IDRs based on their contractual participation rights to share in those earnings. If cash distributions exceed net income attributable to EPB, the excess distributions are allocated proportionately to all participating units outstanding based on their respective ownership percentages. Additionally, the calculation of earnings per unit does not reflect an allocation of undistributed earnings to the IDR holders beyond amounts distributable under the terms of the partnership agreement. Payments made to our unitholders are determined in relation to actual declared distributions and are not based on the net income allocations used in the calculation of earnings per unit.
As discussed in Note 2, we have retrospectively adjusted our historical financial statements for the consolidations of CIG, SLNG, Elba Express and SNG following the acquisitions of controlling interest in each entity. As a result of the retrospective consolidations, earnings prior to the acquisition of the incremental interests (pre-acquisition earnings) in CIG, SLNG, Elba Express and SNG have been allocated solely to our general partner in all periods presented.
Net income attributable to EPB per limited partner unit is computed by dividing the limited partners’ interest in net income attributable to EPB by the weighted average number of limited partner units outstanding. Diluted earnings per limited partner unit reflects the potential dilution that could occur if securities or other agreements to issue common units were exercised, settled or converted into common units. As of December 31, 2011 and 2010, the dilutive, restricted units outstanding were immaterial.
The tables below show the (i) allocation of net income attributable to EPB and the (ii) net income attributable to EPB per limited partner unit based on the number of basic and diluted limited partner units outstanding for the years ended December 31, 2011, 2010 and 2009.
Allocation of Net Income Attributable to El Paso Pipeline Partners, L.P.
Net Income Attributable to El Paso Pipeline Partners, L.P. per Limited Partner Unit
(1) Reflects distributions declared to our common and subordinated unitholders of $1.93 per unit, $1.63 per unit and $1.365 per unit for the years ended December 31, 2011, 2010 and 2009.
Subordinated units. All of the subordinated units were held by a wholly owned subsidiary of El Paso. Our partnership agreement provided that, during the subordination period, the common units would have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.2875 per common unit, which is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units.
Upon payment of the quarterly cash distribution payment for the fourth quarter of 2010, the financial tests required for the conversion of all subordinated units into common units were satisfied. As a result, the 27,727,411 subordinated units held by affiliates of El Paso were converted on February 15, 2011 on a one-for-one basis into common units effective January 3, 2011. The conversion did not impact the amount of cash distribution paid or the total number of the Partnership’s outstanding units.
Incentive distribution rights. The general partner holds IDRs in accordance with the partnership agreement. These rights pay an increasing percentage interest in quarterly distributions of cash based on the level of distribution to all unitholders. Additionally, our general partner, as the holder of our IDRs, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial cash target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and cash target distribution levels upon which the incentive distribution payments to our general partner would be set. In February 2012, our general partner received incentive distributions of $19 million.
Cash Distributions to Unitholders. Our common unitholders and general partner are entitled to receive quarterly distributions of available cash as defined in our partnership agreement. The partnership has declared the quarterly distributions to our unitholders and general partner, including IDRs (in millions, except for per unit amounts) as follows:
The distribution for the quarter ended December 31, 2011 was paid to all outstanding common and general partner units and IDRs on February 14, 2012 to unitholders of record at the close of business on January 31, 2012.
5. Regulatory Assets and Liabilities
Our regulatory asset and liability balances are recoverable or reimbursable over various periods. Below are the details of our regulatory assets and liabilities as of December 31:
Our significant regulatory assets and liabilities include:
Difference between gas retained and gas consumed in operations: These amounts reflect the value of volumetric differences between gas retained and consumed in our operations. These amounts are not included in the rate base, but given our tariffs, are expected to be recovered from our customers or returned to our customers in subsequent fuel filing periods.
Taxes on capitalized funds used during construction: These regulatory asset balances were established to offset the deferred tax for the equity component of the allowance for funds used during the construction of long-lived assets. Taxes on capitalized funds used during construction and the offsetting deferred income taxes are included in the rate base and are recovered over the depreciable lives of the long lived asset to which they relate. These balances were established on our pipelines prior to their conversion to non-taxable entities.
Unamortized loss on reacquired debt: Amount represents the deferred and unamortized portion of losses on reacquired debt which are recovered through the cost of service over the original life of the debt issue, or in the case of refinanced debt, over the life of the new debt issue.
Unamortized loss on assets held for sale: Amount represents the deferred and unamortized portion of losses on our assets held for sale. The recovery is expected to occur at a fixed monthly rate until SNG’s next rate case which is expected to be effective September 2013 with the final recovery period dependent upon the outcome of the rate case.
Postretirement benefits: Represents unrecognized gains or losses related to SNG’s postretirement benefit plan. It also includes the differences between the postretirement benefit amounts expensed and the amounts previously recovered in rates for CIG. Prior to CIG’s rate case settlement, the balances also included unrecognized gains and losses or changes in actuarial assumptions related to their postretirement benefit plan. As part of the CIG rate case settlement, CIG no longer includes these costs in its rates and during 2011 reclassified these balances to accumulated other comprehensive income.
Property and plant retirements: Amount represents the deferral of customer-funded amounts for costs of future asset retirements.
6. Property, Plant and Equipment
Depreciable lives. We depreciate our assets using the composite (group) method. The table below presents the annual depreciation rates on our property, plant and equipment:
Capitalized costs during construction. The allowance for debt amounts capitalized during the years ended December 31, 2011, 2010 and 2009 were $2 million, $11 million and $24 million. The allowance for equity amounts capitalized during each of the years ended December 31, 2011, 2010 and 2009 were $7 million, $28 million and $44 million.
Construction work-in progress. At December 31, 2011 and 2010, we had approximately $105 million and $238 million of construction work in progress included in our property, plant and equipment.
Asset retirement obligations. Where we can reasonably estimate the asset retirement obligation, we accrue a liability based on an estimate of the timing and amount of settlement. In estimating our asset retirement obligations, we utilize several assumptions, including a projected inflation rate of 2.5 percent and credit-adjusted discount rates that currently range from 5 to 12 percent based on when the liabilities were recorded. We record changes in these estimates based on changes in the expected amount and timing of payments to settle our obligations.
The net asset retirement obligations on our balance sheet in other current and non-current liabilities and the changes in the net liability for the years ended December 31 were as follows:
(1) For the years ended December 31, 2011 and 2010, approximately $13 million and $1 million, respectively, of this amount are reflected as other current liabilities on our balance sheets.
7. Long-Term Debt and Other Financing Obligations
Our long-term debt and other financing obligations are as follows:
(1) LIBOR plus 3.9 percent for 2011 and LIBOR plus 3.6 percent for 2010.
Debt Maturities. Aggregate maturities of the principal amounts of long-term debt and other financing obligations as of December 31, 2011 for the next 5 years and in total thereafter are as follows (In millions):
Credit Facilities. In May 2011, El Paso Pipeline Partners Operating Company, L.L.C. (EPPOC) and WIC refinanced their previous credit facility which extended the maturity to 2016 and increased the borrowing capacity from $750 million to $1.0 billion (new credit facility), expandable to $1.5 billion for certain expansion projects and acquisitions. The previous credit facility was entered into in November 2007 and was expandable to $1.25 billion for certain expansion projects and acquisitions. Borrowings under the new credit facility are guaranteed by EPPOC and us, as they were in the previous credit facility. As of December 31, 2010, we had $270 million outstanding under our previous revolving credit facility. As of December 31, 2011, our remaining availability under the new credit facility was $1.0 billion.
The interest rate for our borrowings under the new credit facility has increased to LIBOR plus two percent based on a credit ratings based pricing grid. The commitment fees paid are 0.4 percent for the unutilized commitments. The previous credit facility had two pricing grids, one based on credit ratings and the other based on leverage. In March 2010, our senior debt was rated by the rating agencies and our pricing shifted from a leverage pricing grid to a ratings based pricing grid. The borrowings from our previous credit facility had an interest rate of LIBOR plus 0.575 percent based on a ratings pricing grid, a utilization fee of 0.05 percent if the utilization of the facility exceeded 50 percent and commitment fees of 0.125 percent on the facility amount regardless of usage. At December 31, 2010 the all-in borrowing rate on our previous credit facility was 1.0 percent.
The new credit facility contains covenants and provisions that affect us, the borrowers and our other restricted subsidiaries, including, without limitation, customary covenants and provisions:
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prohibiting the borrowers from creating or incurring indebtedness (except for certain specified permitted indebtedness) if such incurrence would cause a breach of the leverage ratio described below;
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limiting our ability and that of the borrowers and our other restricted subsidiaries from creating or incurring certain liens on our respective properties (subject to enumerated exceptions);
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limiting our ability to make distributions and equity repurchases (which shall be permitted if no insolvency default or event of default exists); and
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prohibiting consolidations, mergers and asset transfers by us, the borrowers and our other restricted subsidiaries (subject to enumerated exceptions).
Under the terms of the new credit facility, certain restrictive covenants will be removed in the event EPPOC receives an investment grade rating for its senior unsecured debt from at least two of three specified ratings agencies. At December 31, 2011, EPPOC was rated investment grade (BBB-) by Fitch and below investment grade by Moody’s Investor Services (Ba1) and Standard & Poor’s (BB).
The new credit facility requires that EPB and WIC maintain a consolidated leverage ratio (consolidated indebtedness to consolidated EBITDA) as defined in the credit agreement as of the end of each quarter of less than 5.0 to 1.0 for any trailing four consecutive quarter period; and 5.5 to 1.0 for any such four quarter period during the three full fiscal quarters subsequent to the consummation of specified permitted acquisitions having a value greater than $25 million. We also added additional flexibility to our covenants for growth projects. In case of a capital construction or expansion project in excess of $20 million, pro forma adjustments to consolidated EBITDA, approved by the lenders, may be made based on the percentage of capital costs expended and projected cash flows for the project. Such adjustments shall be limited to 25 percent of actual consolidated EBITDA.
The new credit facility contains certain customary events of default that affect us, the borrowers and our other restricted subsidiaries, including, without limitation, (i) nonpayment of principal when due or nonpayment of interest or other amounts within five business days of when due; (ii) bankruptcy or insolvency with respect to us, our general partner, the borrowers or any of our other restricted subsidiaries; (iii) judgment defaults against us, our general partner, the borrowers or any of our other restricted subsidiaries in excess of $50 million; or (iv) the failure of El Paso to directly or indirectly own a majority of the voting equity of our general partner and a failure by us to directly or indirectly own 100 percent of the equity of EPPOC. For the year ended December 31, 2011, we were in compliance with our debt-related covenants.
EPB Other Debt Obligations. EPPOC’s senior notes are guaranteed fully and unconditionally by its parent, EPB. EPPOC is a wholly owned subsidiary of EPB. EPB’s only operating asset is its investment in EPPOC, and EPPOC’s only operating assets are its investments in WIC, CIG, SLNG, Elba Express and SNG (collectively, the non-guarantor operating companies). EPB’s and EPPOC’s independent assets and operations, other than those related to these investments and EPPOC’s debt are less than three percent of the
total assets and operations of EPB, and thus substantially all of the operations and assets exist within these non-guarantor operating companies. Furthermore, there are no significant restrictions on EPPOC’s or EPB’s ability to access the net assets or cash flows related to its controlling interests in the operating companies either through dividend or loan. The restrictive covenants under these debt obligations are no more restrictive than the restrictive covenants under our new credit facility. For the year ended December 31, 2011, EPPOC was in compliance with all debt related covenants.
In March 2010, EPPOC issued $425 million of 6.5 percent senior notes due in 2020. EPPOC received net proceeds of $420 million which were used to provide partial funding for the acquisition of a 51 percent member interest in each of SLNG and Elba Express. For a further discussion, see Note 2.
In June 2010, EPPOC issued an additional $110 million of 6.5 percent senior notes due in 2020 and received net proceeds of $110 million (including accrued interest) which were used to provide partial funding for the acquisition of an additional 20 percent interest in SNG. For a further discussion, see Note 2.
In November 2010, EPPOC issued $375 million of 4.1 percent senior notes due 2015 and $375 million of 7.5 percent senior notes due 2040. The proceeds were used to provide partial funding for the remaining 49 percent member interest in each of SLNG and Elba Express and an additional 15 percent general partner interest in SNG, to repay in full the outstanding borrowings under Elba Express’ project financing term loan and to reduce the outstanding borrowings under our previous revolving credit facility.
In September 2011, EPPOC issued $500 million of 5.0 percent senior notes due in 2021. The proceeds of $492 million were used to reduce outstanding indebtedness under EPB’s new revolving credit facility and for general partnership purposes.
CIG Debt. In March 2009, CIG, Colorado Interstate Issuing Corporation (CIIC), El Paso and certain other El Paso subsidiaries filed a registration statement on Form S-3 under which CIG and CIIC may co-issue debt securities in the future. CIIC is a wholly owned finance subsidiary of CIG and is the co-issuer of CIG’s outstanding debt securities. CIIC has no material assets, operations, revenues or cash flows other than those related to its service as a co-issuer of CIG’s debt securities. Accordingly, it has no ability to service obligations on CIG’s debt securities. Under CIG’s various financing documents they are subject to a number of restrictions and covenants. The most restrictive of these include limitations on the incurrence of liens and limitations on sale-leaseback transactions. For the year ended December 31, 2011, CIG was in compliance with its debt-related covenants.
SLNG Debt. The SLNG notes impose certain limitations on the ability of SLNG to, among other things, incur additional indebtedness, make certain restricted payments, enter into transactions with affiliates, and merge or consolidate with any other person, sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of its assets. SLNG is required to comply with certain financial covenants, including a leverage ratio of no more than 5.0 to 1.0 and an interest coverage ratio of no less than 2.0 to 1.0.
The SLNG notes are unsecured and are redeemable at SLNG’s option at 100 percent of the principal amount plus a specified make-whole premium. The SLNG notes are also subject to a change of control prepayment offer in the event of a ratings downgrade within a 120-day period from and including the date on which a change of control with respect to SLNG occurs (as defined in the note purchase agreement). If a sufficient number of the rating agencies downgrade the ratings of the SLNG notes below investment grade within the 120-day period from and including the date of any such change of control, then SLNG is required to offer to prepay the entire unpaid principal amount of the notes held by each holder at 101 percent of the principal amount of such SLNG notes (without any make-whole amount or other penalty), together with interest accrued thereon to the date for such prepayment.
SNG Debt. In March 2009, SNG, Southern Natural Issuing Corporation (SNIC), El Paso and certain other El Paso subsidiaries filed a registration statement on Form S-3 under which SNG and SNIC may co-issue debt securities in the future. SNIC is a wholly owned finance subsidiary of SNG and is the co-issuer of certain of SNG’s outstanding debt securities. SNIC has no material assets, operations, revenues or cash flows other than those related to its service as a co-issuer of the debt securities. Accordingly, it has no ability to service obligations on the debt securities.
In June 2011, SNG and SNIC, issued $300 million aggregate principal amount of 4.4 percent senior unsecured notes due in 2021. The net proceeds of $297 million from this offering were advanced to EPB under its cash management program and will be subsequently utilized to fund SNG growth capital expenditures and for general corporate purposes. The indenture governing these notes contains restrictions and covenants, none of which are more restrictive than those of existing debt covenants.
Under the indentures, SNG is subject to a number of restrictions and covenants. The most restrictive of these include limitations on the incurrence of liens. The long-term debt contains cross-acceleration provisions, the most restrictive of which is a $10 million cross-acceleration clause. If triggered, repayment of the long-term debt that contains these provisions could be accelerated. For the year ended December 31, 2011, SNG was in compliance with debt-related covenants.
Other Financing Obligations. In conjunction with the construction of the Totem Gas Storage facility (Totem) and the High Plains pipeline (High Plains), CIG’s joint venture partner in WYCO Development L.L.C. (WYCO) funded 50 percent of the construction costs. CIG reflected the payments made by their joint venture partner as other long-term liabilities on the balance sheet during construction and upon project completion, the advances were converted into a financing obligation to WYCO. Upon placing these projects in service, we transferred our title in the projects to WYCO. Although we transferred the title in these projects to WYCO, we continue to reflect the Totem Gas Storage facility and the High Plains pipeline as property, plant and equipment in our financial statements as of December 31, 2011 due to our continuing involvement with the projects through WYCO.
As of December 31, 2011, the principal amounts of Totem and High Plains were $77 million and $100 million, respectively, which will be paid in monthly installments through 2039, and extended for the term of related firm service agreements until 2060 and 2043, respectively. Interest payments on these obligations are based on 50 percent of the operating results of the facilities and are estimated at a 15.5 percent interest rate as of December 31, 2011.
Lease. Effective December 1, 1999, WIC leased a compressor station under a capital lease from WYCO. The compressor station lease expires in November 2029. The total original capitalized cost of the lease was $12 million. As of December 31, 2011, we had a net book value of approximately $6 million related to this capital lease. Minimum future lease payments under the capital lease together with the present value of the net minimum lease payments as of December 31, 2011 are as follows:
8. Fair Value of Financial Instruments
As of December 31, 2011 and 2010, the carrying amounts of cash and cash equivalents, short-term borrowings, and current receivables and payables represent fair value because of the short-term nature of these instruments. The fair values of our long term debt and other financing obligations are primarily based on quoted market prices for the same or similar issues, a Level 2 fair value measurement.
9. Commitments and Contingencies
Legal Proceedings
Brinckerhoff Lawsuit. In December 2011, a derivative lawsuit was filed against El Paso, El Paso Pipeline GP Company, L.L.C., the general partner of EPB; certain directors of the general partner and the audit committee of the general partner. The lawsuit arises from the March 2010 drop down transaction involving EPB’s purchase of SLNG and Elba Express. The complaint generally alleges that the consideration paid by EPB was excessive and that the sales process was flawed with various conflicts of interest and mistakes. Our general partner believes this action to be without merit and intends to defend it vigorously.
We and our subsidiaries and affiliates are named defendants in numerous lawsuits and governmental proceedings and claims that arise in the ordinary course of our business. For each of these matters, we evaluate the merits of the case or claim, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we establish the necessary accruals. While the outcome of these matters cannot be predicted with certainty, and there are still uncertainties related to the costs we may incur, based upon our evaluation and experience to date, we believe we have established appropriate reserves for these matters. It is possible, however, that new information or future developments could require us to reassess our potential exposure related to these matters and adjust our accruals accordingly, and these adjustments could be material. At December 31, 2011, we had approximately $2 million accrued for our outstanding legal proceedings.
Environmental Matters
We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect of the disposal or release of specified substances at current and former operating sites. At December 31, 2011, our accrual was approximately $10 million for environmental matters. Our accrual includes amounts for expected remediation costs and associated onsite, offsite and groundwater technical studies and related environmental legal costs. Our accrual includes $6 million for environmental contingencies related to properties CIG previously owned.
Our estimates of potential liability range from approximately $10 million to approximately $34 million. Our recorded environmental liabilities reflect our current estimates of amounts we will expend on remediation projects in various stages of completion. However, depending on the stage of completion or assessment, the ultimate extent of contamination or remediation required may not be known. As additional assessments occur or remediation efforts continue, we may incur additional liabilities.
Superfund Matters. Included in our recorded environmental liabilities are projects where we have received notice that we have been designated or could be designated, as a Potentially Responsible Party (PRP) under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), commonly known as Superfund, or state equivalents for one active site. Liability under the federal CERCLA statute may be joint and several, meaning that we could be required to pay in excess of our pro rata share of remediation costs. We consider the financial strength of other PRPs in estimating our liabilities.
For 2012, we estimate that our total remediation expenditures will be approximately $4 million, most of which will be expended under government directed clean-up plans. In addition, we expect to make capital expenditures for environmental matters of approximately $4 million in the aggregate for the years of 2012 through 2016, including capital expenditures associated with the impact of the EPA rule on emissions of hazardous air pollutants from reciprocating internal combustion engines which are subject to regulations with which we have to be in compliance by October 2013.
It is possible that new information or future developments could require us to reassess our potential exposure related to environmental matters. We may incur significant costs and liabilities in order to comply with existing environmental laws and regulations. It is also possible that other developments, such as increasingly strict environmental laws, regulations and orders of regulatory agencies, as well as claims for damages to property and the environment or injuries to employees and other persons resulting from our current or past operations, could result in substantial costs and liabilities in the future. As this information becomes available, or other relevant developments occur, we will adjust our accrual amounts accordingly. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we believe our reserves are adequate.
Rates and Regulatory Matters
CIG Rate Case. In August 2011, the FERC approved an uncontested pre-filing settlement of a rate case required under the terms of a previous settlement. The settlement generally provides for (i) CIG’s current tariff rates to continue until the next general rate case which will be effective no earlier than October 1, 2014 but no later than October 1, 2016; (ii) contract extensions to March 2016; (iii) a revenue sharing mechanism with certain customers for certain revenues above annual threshold amounts; and (iv) a revenue surcharge mechanism with certain customers to charge for certain shortfalls of revenue less than an annual threshold amount.
SNG Rate Case. In January 2010, the FERC approved SNG’s rate case settlement in which SNG (i) increased its base tariff rates effective September 1, 2009, (ii) implemented a volume tracker for gas used in operations, (iii) agreed to file its next general rate case to be effective after August 31, 2012 but no later than September 1, 2013 and (iv) extended the majority of SNG’s firm transportation contracts until August 31, 2013. As part of the proposed asset sale entered into in September 2011 (see Note 2), SNG agreed with its customers to file its next general rate case to be effective September 1, 2013.
Other Commitments
Capital Commitments. At December 31, 2011, we have capital commitments of approximately $5 million related to Phase III of South System III and Southeast Supply Header (SESH), all of which will be spent in 2012. During 2009, we entered into an approximately $57 million letter of credit associated with our estimated construction costs related to our SESH Expansion project. As invoices are paid under the contract, we are able to reduce the value of the letter of credit. At December 31, 2011, the letter of credit has been reduced to approximately $8 million. We have other planned capital and investment projects that are discretionary in nature, with no substantial contractual capital commitments made in advance of the actual expenditures.
Purchase Obligations. We have entered into unconditional purchase obligations primarily for electric services, totaling approximately $2 million to be spent during 2012.
Other Commercial Commitments. We hold cancelable easement or rights-of-way arrangements from landowners permitting the use of land for the construction and operation of our pipeline systems. Currently, our obligations under these easements are not material to the results of our operations.
Transportation and Storage Commitments. We have entered into transportation commitments and storage capacity contracts totaling $318 million at December 31, 2011, of which $93 million and $8 million are related to storage capacity contracts with our affiliates, Young Gas Storage Company, Ltd. and Bear Creek Storage Company, LLC (Bear Creek), respectively. Our annual commitments under these agreements are $44 million in 2012, $33 million in 2013, $32 million in 2014, $33 million in 2015, $33 million in 2016 and $143 million in total thereafter.
Operating Leases. We lease property, facilities and equipment under various operating leases. Our minimum future annual rental commitments under our operating leases at December 31, 2011, are as follows:
Rental expense on our operating leases for each of the three years ended December 31, 2011, 2010 and 2009 was $6 million and is reflected in operation and maintenance expense on our income statements. These amounts include our share of rent allocated to us from El Paso.
10. Retirement Benefits
Pension and Retirement Savings Plans. El Paso maintains a pension plan (El Paso Corporation Pension Plan) and a retirement savings plan covering substantially all of its U.S. employees, including CIG’s and SNG’s former employees. The benefits under the pension plan are determined under a cash balance formula. Under its retirement savings plan, El Paso matches 75 percent of participant basic contributions up to six percent of eligible compensation and can make additional discretionary matching contributions depending on El Paso’s operating performance relative to its peers. El Paso is responsible for benefits accrued under its plans and allocates the related costs to its affiliates.
Postretirement Benefit Plans. CIG and SNG provide postretirement medical benefits for a closed group of retirees under the El Paso Corporation Retiree Benefits Plan. These benefits may be subject to deductibles, co-payment provisions, and other limitations and dollar caps on the amount of employer costs and El Paso reserves the right to change these benefits. In addition, certain former employees continue to receive limited postretirement life insurance benefits. Postretirement benefit plan costs are prefunded to the extent these costs are recoverable through rates. To the extent actual costs differ from the amounts recovered in rates, either accumulated other comprehensive income or a regulatory asset or liability is recorded. We expect to contribute $1 million to our postretirement benefit plan in 2012. Contributions of approximately $1 million were made for each year ended December 31, 2011 and December 31, 2010, and approximately $4 million for the year ended December 31, 2009.
Accumulated Postretirement Benefit Obligation, Plan Assets and Funded Status. In accounting for the postretirement benefit plans, we record an asset or liability based on the over funded or under funded status. Any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions are recorded as either accumulated other comprehensive income or a regulatory asset or liability. As part of the rate case settlement as discussed in Note 9, CIG will no longer include these costs in their rates and as a result, during 2011, CIG reclassified $9 million from a regulatory liability to accumulated other comprehensive income.
The table below provides information about the postretirement benefit plans.
(1) Amounts shown net of a subsidy of less than $1 million for each of the years ended December 31, 2011 and 2010 related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003.
Components of Accumulated Other Comprehensive Income. The amount recognized in accumulated other comprehensive income for CIG at December 31, 2011 of $9 million related to unrecognized gains. We anticipate that approximately $1 million of accumulated other comprehensive income will be recognized as part of net periodic benefit income in 2012.
Plan Assets. The primary investment objective of the plans’ is to ensure that, over the long-term life of the plans an adequate pool of sufficiently liquid assets exists to meet the benefit obligations to retirees and beneficiaries. Investment objectives are long-term in nature covering typical market cycles. Any shortfall of investment performance compared to investment objectives is generally the result of economic and capital market conditions. Although actual allocations vary from time to time from the targeted allocations, the target allocations of the plans’ assets are 65 percent equity and 35 percent fixed income securities. The plans’ assets may be invested in a manner that replicates, to the extent feasible, the Russell 3000 Index and the Barclays Capital Aggregate Bond Index to achieve equity and fixed income diversification, respectively.
We use various methods to determine the fair values of the assets in the other postretirement benefit plans, which are impacted by a number of factors, including the availability of observable market data over the contractual term of the underlying assets. We separate the plans’ assets into three levels (Level 1, 2 and 3) based on our assessment of the availability of market data and the significance of non-observable data used to determine the fair value of these assets. As of December 31, 2011, assets were comprised of an exchange-traded mutual fund with a fair value of $4 million and common/collective trust funds with a fair value of $68 million. As of December 31, 2010, assets were comprised of an exchange-traded mutual fund with a fair value of $4 million and common/collective trust funds with a fair value of $66 million. The exchange-traded mutual fund invests primarily in dollar-denominated securities, and its fair value (which is considered a Level 1 measurement) is determined based on the price quoted for the fund in actively traded markets. The common/collective trust funds are invested in approximately 65 percent equity and 35 percent fixed income securities, and their fair values (which are considered Level 2 measurements) are determined primarily based on the net asset value reported by the issuer, which is based on similar assets in active markets. Certain restrictions on withdrawals exist for these common/collective trust funds where the issuer reserves the right to temporarily delay withdrawals in certain situations such as market conditions or at the issuer’s discretion. The plans do not have any assets that are considered Level 3 measurements. The methods described above may produce a fair value that may not be indicative of net realizable value or reflective of future fair values, and there have been no changes in the methodologies used at December 31, 2011 and 2010.
Expected Payment of Future Benefits. As of December 31, 2011, we expect the following benefit payments under the plans (In millions):
(1) Includes a reduction of approximately $1 million in each of the years 2012 - 2016 and approximately $5 million in aggregate for 2017 - 2021 for an expected subsidy related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003.
Actuarial Assumptions and Sensitivity Analysis. Accumulated postretirement benefit obligations and net benefit costs are based on actuarial estimates and assumptions. The following table details the weighted average actuarial assumptions used in determining the postretirement plans’ obligations and net benefit costs.
(1) The expected return on plan assets listed in the table above is a pre-tax rate of return based on our targeted portfolio of investments. We utilize an after-tax expected return on plan assets to determine our benefit costs, which is based on unrelated business income taxes at a rate of 35 percent.
Actuarial estimates for the plans assumed a weighted average annual rate of increase in the per capita costs of covered health care benefits of 7.3 percent, gradually decreasing to 5.0 percent by the year 2019. A one-percentage point change would not have a significant effect on interest costs in 2011 and 2010. A one-percentage point change in assumed health care trends would have the following affect as of December 31, 2011 and 2010:
Components of Net Benefit Cost (Income). For each of the years ended December 31, the components of net benefit cost (income) are as follows:
11. Transactions with Major Customers
The following table shows revenues from major customers for each of the three years ended December 31:
* Less than 10 percent of operating revenues
At December 31, 2011, we have transportation and storage agreements with PSCo for capacity on High Plains through 2029 and Totem through 2040 with annual firm revenue of $41 million and $38 million, respectively.
12. Accounts Receivable Sales Program
We participate in accounts receivable sales programs where we sell receivables in their entirety to a third party financial institution (through wholly-owned special purpose entities). The sale of these accounts receivable (which are short-term assets that generally settle within 60 days) qualify for sale accounting. The third party financial institution involved in these accounts receivable sales programs acquires interests in various financial assets and issues commercial paper to fund those acquisitions. We do not consolidate the third party financial institution because we do not have the power to control, direct or exert significant influence over its overall activities since our receivables do not comprise a significant portion of its operations.
In connection with our accounts receivable sales, we receive a portion of the sales proceeds up front and receive an additional amount upon the collection of the underlying receivables (which we refer to as a deferred purchase price). Our ability to recover the deferred purchase price is based solely on the collection of the underlying receivables. The table below contains information related to our accounts receivable sales programs.
(1) During the period ended December 31, 2011, 2010 and 2009, losses recognized on the sale of accounts receivable were immaterial.
(2) In January 2010, we terminated our previous accounts receivable sales programs and paid $50 million to acquire the related senior interest in certain receivables under those programs. During 2009, we sold approximately $913 million of accounts receivable under that program and our fees and losses related to the program were not material.
(1) Initially recorded at an amount which approximates its fair value using observable inputs other than quoted prices in active markets, a Level 2 fair value measurement.
The deferred purchase price related to the accounts receivable sold is reflected as other accounts receivable on our balance sheet. Because the cash received up front and the deferred purchase price relate to the sale or ultimate collection of the underlying receivables, and are not subject to significant other risks given their short term nature, we reflect all cash flows under the new accounts receivable sales programs as operating cash flows on our statement of cash flows. Under the accounts receivable sales programs, we service the underlying receivables for a fee. The fair value of these servicing agreements, as well as the fees earned, were not material to our financial statements for the year ended December 31, 2011, 2010 and 2009.
13. Investments in Unconsolidated Affiliates and Transactions with Affiliates
Investments in Unconsolidated Affiliates
WYCO. CIG has a 50 percent investment in WYCO which we account for using the equity method of accounting. WYCO owns the High Plains pipeline (a FERC-regulated pipeline), the Totem Gas Storage facility (a FERC-regulated storage facility), a state regulated intrastate pipeline and a compressor station. WYCO paid cash distributions of $2 million for the year ended December 31, 2011. CIG has other financing obligations payable to WYCO totaling $177 million and $178 million as of December 31, 2011 and 2010, which are described further in Note 7.
Bear Creek. SNG owns a 50 percent ownership interest in Bear Creek, a joint venture with Tennessee Gas Pipeline Company L.L.C. (TGP), an affiliate. We account for our investment in Bear Creek using the equity method of accounting. During 2011, 2010 and 2009, Bear Creek paid distributions to SNG of $13 million, $14 million and $13 million, respectively. Also, during 2010, Bear Creek utilized its note receivable balance under the cash management program with El Paso to pay a cash distribution to its partners, including $23 million to SNG.
In November 2011, Bear Creek, along with other unaffiliated storage companies, received an order from the FERC related to an investigation into the rates charged to customers. The FERC ordered Bear Creek to file a full cost and revenue study within 75 days of the order. Bear Creek filed the cost and revenue study in January 2012 and the outcome of this proceeding is not expected to be material to our results of operations.
The information below related to our unconsolidated affiliates reflects our net investment and earnings recorded from these investments.
Net Investment and Earnings
Transactions with Affiliates
CIG Cash Distributions to El Paso. CIG makes quarterly distributions to its owners. Due to the retrospective consolidation of CIG, the distributions made prior to consolidation in July 2009, excluding distributions paid to its noncontrolling interest holder, were allocated solely to our general partner and were reflected as distributions of pre-acquisition earnings. We have reflected 42 percent of CIG’s distributions paid to El Paso through June 2011 and 14 percent thereafter as distributions to its noncontrolling interest holder.
SLNG and Elba Express Distributions to El Paso. As a result of the March 2010 acquisition, SLNG and Elba Express were required to make quarterly distributions to its owners of available cash to its members, including us. Since we consolidate SLNG and Elba Express, we have reflected 49 percent of SLNG’s and Elba Express’ distributions paid to El Paso as distributions to its noncontrolling interest holder in our financial statements from March 30, 2010 to November 19, 2010. Subsequent to the November 2010 acquisition, as described in Note 2, SLNG and Elba Express became wholly owned subsidiaries of EPB.
SNG Cash Distributions to El Paso. SNG makes quarterly distributions to its owners. Due to the retrospective consolidation of SNG, the distributions made prior to consolidation in November 2010, excluding distributions paid to its noncontrolling interest holder, were allocated solely to our general partner and were reflected as distributions of pre-acquisition earnings. We have reflected 40 percent of SNG’s distributions paid to El Paso through 2010 and 15 percent through the first quarter of 2011 as distributions to its noncontrolling interest holder. Subsequent to the June 2011 acquisition as described in Note 2, SNG became a wholly owned subsidiary of EPB.
The following table summarizes the cash distributions paid to El Paso.
(1) The 2009 distribution was made by Elba Express to El Paso to comply with certain restrictions in its project financing agreement.
Other Distributions/Contributions. During 2009, Elba Express received cash contributions from El Paso of $138 million related to their note payable under the cash management program. In addition, Elba Express received cash contributions from El Paso of $170 million for the construction of Elba Express during the year ended December 31, 2009.
In March 2010, in conjunction with our acquisition of SLNG and Elba Express, El Paso made a non-cash contribution of $64 million to Elba Express to eliminate its non-interest bearing advance from El Paso. Prior to our acquisition of a 51 percent member interest in each of SLNG and Elba Express, El Paso made a cash contribution to Elba Express of $13 million. During 2010, El Paso made capital contributions of $6 million to SLNG to fund their share of expansion project expenditures for 2010. During 2011, El Paso made capital contributions of $15 million and $15 million to CIG and SNG, respectively, to fund their share of expansion project expenditures.
Cash Management Program. Prior to consolidation into EPB, CIG, SLNG, Elba Express and SNG each participated in El Paso’s cash management program, which matched short-term cash surpluses and needs of participating affiliates, thus minimizing total borrowings from outside sources. El Paso used the cash management program to settle intercompany transactions between participating affiliates. After we acquired additional interests in each of CIG, SLNG, Elba Express and SNG which required consolidation, their participation in El Paso’s cash management program was terminated. CIG converted its note receivable with El Paso under its cash management program into a demand note receivable. In December 2010, El Paso repaid the demand note. Elba Express’ participation in El Paso’s cash management program was terminated in May 2009 due to restrictions in its project financing agreement. In 2010, SLNG and SNG received $8 million and $5 million, respectively, in cash from El Paso in settlement of their note receivable balances related to the termination of their participation in El Paso’s cash management program.
Notes Receivable and Payable with Affiliates. In June 2010, in conjunction with our acquisition of an additional 20 percent general partner interest in SNG (see Note 2), El Paso repaid $21 million of our demand notes receivable. Also, as partial funding for the September 2008 CIG acquisition, we issued a note payable to El Paso. The note payable balance was $10 million at December 31, 2011 and 2010. This note payable is expected to mature in September 2012, and is currently recorded as short-term financing obligations, including current maturities on our balance sheet.
Income Taxes. Effective February 4, 2010, SLNG converted to a limited liability company and, prior to the conversion, settled its current and deferred tax balances of approximately $72 million with recoveries of its note receivable from El Paso under the cash management program.
Other Affiliate Balances. As of December 31, 2011 and 2010, we had accounts receivable with affiliates arising in the ordinary course of business of $7 million and $6 million. In addition, as of December 31, 2011 and 2010, we had net contractual gas imbalance and trade payables, as well as other liabilities with our affiliates arising in the ordinary course of business of approximately $44 million and $39 million. We also had contractual deposits from affiliates of $9 million and $8 million included in contractual deposits on our balance sheets as of December 31, 2011 and 2010.
Affiliate Revenues and Expenses. We enter into transactions with our affiliates within the ordinary course of business and the services are based on the same terms as non-affiliates, including natural gas transportation services to and from affiliates under long-term contracts and various operating agreements. CIG also contracts with an affiliate to process natural gas and sell extracted natural gas liquids.
We do not have employees. We are managed and operated by the directors and officers of our general partner, El Paso Pipeline GP Company, L.L.C., a subsidiary of El Paso. We have an omnibus agreement with El Paso and its affiliates under which we reimburse El Paso for the provision of various general and administrative services for our benefit and for direct expenses incurred by El Paso on our behalf. El Paso bills us directly for certain general and administrative costs and allocates a portion of its general and administrative costs to us. In addition to allocations from El Paso, we are allocated costs from El Paso Natural Gas Company (EPNG) and TGP, our affiliates, associated with our pipeline services. We also allocate costs to Cheyenne Plains Gas Pipeline, our affiliate, for their share of our pipeline services. The allocations from TGP, EPNG and El Paso are based on the estimated level of effort devoted to our operations and the relative size of our earnings before interest expense and income taxes, gross property and payroll.
The table below shows overall revenues, expenses and reimbursements from our affiliates for the years ended December 31, 2011, 2010 and 2009.
14. Income Taxes
Effective February 4, 2010, SLNG, our wholly owned subsidiary, converted into a limited liability company and is no longer subject to income taxes. Effective November 1, 2007, CIG and SNG, our consolidated subsidiaries, converted into general partnerships in conjunction with our initial public offering and accordingly, are no longer subject to income taxes. As a result of the conversion of CIG, SLNG, and SNG into non-taxpaying entities, they settled their existing current and deferred tax balances with recoveries of notes receivable from El Paso under the cash management program pursuant to the tax sharing agreement with El Paso. Prior to their respective conversion dates, CIG, SLNG and SNG recorded current income taxes based on taxable income and provided for deferred income taxes to reflect estimated future tax payments and receipts.
Components of Income Taxes. There are no current or deferred federal and state income taxes for the year ended December 31, 2011. The following table reflects the components of income taxes for SLNG included in income for the years ended December 31, 2010 and 2009:
Effective Tax Rate Reconciliation. There are no income taxes included in net income for the year ended December 31, 2011. Income taxes included in income for SLNG differ from the amounts computed by applying the statutory federal income tax rate of 35 percent for the following reasons for the years ended December 31, 2010 and 2009:
15. Other
During June 2011, SLNG recognized $17 million of operating revenue, consisting of a $9 million payment received in 2009 which granted BG LNG Services, LLC (BG LNG) a cancellation option related to their commitment on Phase B of SLNG’s Elba III Expansion and $8 million received as a result of BG LNG exercising their cancellation option in June 2011. In addition, SLNG wrote off $3 million for certain project development costs incurred in conjunction with this expansion project.
Supplemental Selected Quarterly Financial Information (Unaudited)
Our financial information by quarter is summarized below. Due to the seasonal nature of our business, information for interim periods may not be indicative of our results of operations for the entire year.
(1) The quarter ended September 30, 2010 includes a non-cash asset write down of $21 million related to the sale of the Natural Buttes compressor station and gas processing plant. See Item 8. Financial Statements and Supplementary Data, Note 2 for further discussion.
(2) All subordinated units were converted to common units on a one-for-one basis effective January 3, 2011. See Item 8. Financial Statements and Supplementary Data, Note 4 for further discussion.
SCHEDULE II SCHEDULE II
EL PASO PIPELINE PARTNERS, L.P.
VALUATION AND QUALIFYING ACCOUNTS VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2011, 2010 and 2009
(In millions)
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
As of December 31, 2011, we carried out an evaluation under the supervision and with the participation of our management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO) of our general partner, as to the effectiveness, design and operation of our disclosure controls and procedures. This evaluation considered the various processes carried out under the direction of El Paso’s disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports we file or submit under the Exchange Act is accurate, complete and timely. Our management, including the CEO and CFO of our general partner, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and the CEO and CFO of our general partner have concluded that our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) were effective as of December 31, 2011. See Item 8. Financial Statements and Supplementary Data under Management’s Annual Report on Internal Control Over Financial Reporting.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting during the fourth quarter of 2011 that have materially affected or are 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
Partnership Management
El Paso Pipeline GP Company, L.L.C., our general partner, manages our operations and activities. Our general partner and its board of directors are not elected by our unitholders and are not subject to re-election on a regular basis. Unitholders are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operation. Our general partner owes a fiduciary duty to our unitholders. Our general partner will be liable, as a general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made expressly non-recourse to it. Our general partner therefore may cause us to incur indebtedness or other obligations that are non-recourse to it.
The directors of our general partner oversee our operations. We presently have seven directors, three of whom are independent as defined under the independence standards established by the New York Stock Exchange and under our corporate governance guidelines. El Paso appoints all members to the board of directors of our general partner. The New York Stock Exchange does not require a listed limited partnership like us to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating and governance committee. However, the board of our general partner has a standing audit committee, described below.
The independent board members comprise all of the members of the audit committee. The audit committee assists the board in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. The audit committee has the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to the audit committee. The members of the audit committee also serve as a conflicts committee to review specific matters that the board believes may involve conflicts of interest. The conflicts committee determines if the resolution of the conflict of interest is fair and reasonable to us. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders.
We do not directly employ any of the persons responsible for our management or operation. Rather, personnel of El Paso and its affiliates manage and operate our business. Officers of our general partner, who are also officers of El Paso or its affiliates, manage the day-to-day affairs of our business and conduct our operations. We also utilize a significant number of employees of El Paso to operate our business and provide us with general and administrative services. We reimburse El Paso for allocated expenses of operational personnel who perform services for our benefit and we reimburse El Paso for allocated general and administrative expenses.
In order to maximize operational flexibility, we conduct our operations through subsidiaries. We have one direct operating subsidiary, EPPOC, a limited liability company that conducts business through itself and its subsidiaries.
Directors and Executive Officers of Our General Partner
The following table sets forth information with respect to the directors of our general partner, including the experience, qualifications, attributes or skills that led to the conclusion that such individuals should serve as directors of our general partner, as well as information regarding executive officers of our general partner, as of February 20, 2012. The directors of our general partner hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified. Officers serve at the discretion of the board of directors. There are no family relationships among any of the directors or executive officers.
Name
Age
Position with El Paso Pipeline GP Company, L.L.C.
Ronald L. Kuehn, Jr.
Chairman of the Board
James C. Yardley
Director, President and Chief Executive Officer
John R. Sult
Director, Executive Vice President & Chief Financial Officer
Robert W. Baker
Executive Vice President and General Counsel
Susan B. Ortenstone
Executive Vice President
James J. Cleary
Senior Vice President
Daniel B. Martin
Senior Vice President
Norman G. Holmes
Senior Vice President
Douglas L. Foshee
Director
D. Mark Leland
Director
Arthur C. Reichstetter
Director
William A. Smith
Director
Ronald L. Kuehn, Jr. Mr. Kuehn has been Chairman of the Board of El Paso Pipeline GP Company, L.L.C. since August 2007. Mr. Kuehn previously served as Chairman of the Board of Directors for El Paso Corporation from March 2003 to May 2009 and Interim Chief Executive Officer from March 2003 to September 2003. From September 2002 to March 2003, Mr. Kuehn served as Lead Director of El Paso. From January 2001 to March 2003, he was a business consultant. Mr. Kuehn served as non-executive Chairman of the Board of El Paso from October 1999 to December 2000. Mr. Kuehn previously served as Chairman of the Board of Sonat Inc. from April 1986 and President and Chief Executive Officer from June 1984 until his retirement in October 1999. Mr. Kuehn formerly served on the Boards of Directors of Praxair, Inc. until 2008, Dun & Bradstreet Corporation until 2007 and Regions Financial Corporation until 2007.
Mr. Kuehn is an experienced business leader with the skills necessary to be the Chairman of the Board of El Paso Pipeline GP Company, L.L.C. As a former chairman and chief executive officer of a Fortune 500 energy company, Mr. Kuehn has extensive industry, operations and financial expertise. His knowledge and understanding of our industry provides the board of our general partner with valuable strategic insight. Mr. Kuehn’s prior service on the boards of other publicly-traded companies in our industry, including his service as Chairman of El Paso Corporation and as its interim CEO, provides valuable experience from which he can draw as a member of the board of our general partner.
James C. Yardley. Mr. Yardley has been Director, President and Chief Executive Officer of El Paso Pipeline GP Company, L.L.C. since August 2007. He has been Executive Vice President of El Paso Corporation with responsibility for the regulated pipeline business unit since August 2006. Mr. Yardley has been Chairman of the Board of El Paso Natural Gas Company since 2006. He previously served as President and Chairman of the Board of Tennessee Gas Pipeline Company from February 2007 to August 2010, and served as Chairman of the Board from August 2010 until its conversion to a limited liability company in October 2011. Mr. Yardley served as President of Southern Natural Gas Company from May 1998 to August 2010. He was a member of the Management Committees of both Colorado Interstate Gas Company and Southern Natural Gas Company until their conversion to limited liability companies in August 2011. Upon a change in management structure in February 2012, he was again named as a member of the Management Committees of both Colorado Interstate Gas Company, L.L.C. and Southern Natural Gas Company, L.L.C. Mr. Yardley serves on the board of Interstate Natural Gas Association of America and previously served as its Chairman.
Mr. Yardley’s day-to-day leadership as President and Chief Executive Officer of El Paso Pipeline GP Company, L.L.C. and his role in forming the partnership provide him with an intimate knowledge of the partnership, including its strategies, operations and markets. In addition, as Executive Vice President of El Paso Corporation’s Pipeline Group, Mr. Yardley brings an in-depth operating experience of our assets coupled with an extensive understanding of the pipeline industry overall.
John R. Sult. Mr. Sult has been a Director of El Paso Pipeline GP Company, L.L.C. since June 2009. He has served as Executive Vice President and Chief Financial Officer of El Paso Pipeline GP Company, L.L.C. since July 2010, Senior Vice President and Chief Financial Officer from November 2009 to July 2010 and Senior Vice President, Chief Financial Officer and Controller from August 2007 to November 2009. Mr. Sult has been Executive Vice President and Chief Financial Officer of El Paso Corporation since March 2010 and Senior Vice President and Chief Financial Officer from November 2009 to March 2010. Mr. Sult previously served as Senior Vice President and Controller from November 2005 to November 2009. He served as Senior Vice President, Chief Financial Officer and Controller of El Paso’s Pipeline Group from November 2005 to November 2009. Mr. Sult was Vice President and Controller for Halliburton Energy Services from August 2004 to October 2005.
Through his role as Chief Financial Officer of our general partner, as well as Chief Financial Officer of El Paso Corporation, Mr. Sult brings significant knowledge of our partnership, including its capital structure and financing requirements. Mr. Sult has an extensive knowledge of the energy industry, as well as financing and accounting skills, and brings significant operations and financial experience to the board of our general partner.
Robert W. Baker. Mr. Baker has been Executive Vice President and General Counsel of El Paso Pipeline GP Company, L.L.C. since August 2007. He has been Executive Vice President and General Counsel of El Paso Corporation since January 2004. From February 2003 to December 2003, he served as Executive Vice President of El Paso and President of El Paso Merchant Energy. Mr. Baker previously served as Senior Vice President and Deputy General Counsel of El Paso from January 2002 to February 2003. Prior to that time, he held various legal positions with El Paso and its subsidiaries, including managing the legal matters associated with telecommunication services, domestic power plant development, and the international energy infrastructure projects.
Susan B. Ortenstone. Ms. Ortenstone has been Executive Vice President of El Paso Pipeline GP Company, L.L.C. since July 2010 and Senior Vice President from August 2007 to July 2010. She has been Executive Vice President and Chief Administrative Officer of El Paso Corporation since March 2010 and Senior Vice President and Chief Administrative Officer from October 2007 to March 2010. Ms. Ortenstone previously served as Senior Vice President of El Paso from October 2003 to October 2009. Ms. Ortenstone was Chief Executive Officer for Epic Energy Pty Ltd. from January 2001 to June 2003.
James J. Cleary. Mr. Cleary has been Senior Vice President of El Paso Pipeline GP Company, L.L.C. since August 2007. He has been a director and President of El Paso Natural Gas Company since January 2004 and has also served as President of Colorado Interstate Gas Company, L.L.C. since January 2004. Mr. Cleary also serves as a member of the Management Committee of Ruby Pipeline Holding Company, L.L.C. Mr. Cleary was a member of the Management Committee of Colorado Interstate Gas Company until its conversion to a limited liability company in August 2011. He previously served as Chairman of the Board of both El Paso Natural Gas Company and Colorado Interstate Gas Company from May 2005 to August 2006. From January 2001 to December 2003, he served as President of ANR Pipeline Company. Upon a change in management structure in February 2012, Mr. Cleary was again named as a member of the Management Committee of Colorado Interstate Gas Company, L.L.C.
Daniel B. Martin. Mr. Martin has been Senior Vice President of El Paso Pipeline GP Company, L.L.C. since August 2007. He has been a director of El Paso Natural Gas Company since May 2005. Mr. Martin serves as a member of the Management Committees of both Colorado Interstate Gas Company L.L.C. and Southern Natural Gas Company L.L.C. and also as a director of Tennessee Gas Pipeline Company, L.L.C. He has been Senior Vice President of Colorado Interstate Gas Company, L.L.C. since January 2001, Senior Vice President of Southern Natural Gas Company, L.L.C. and Tennessee Gas Pipeline Company, L.L.C. since June 2000 and Senior Vice President of El Paso Natural Gas Company since February 2000. Mr. Martin served as a director of ANR Pipeline Company from May 2005 to February 2007 and Senior Vice President of ANR Pipeline Company from January 2001 to February 2007. He is currently a member of the board of directors of Citrus Corp., a joint venture between El Paso Citrus Holdings, Inc. and CrossCountry Citrus, LLC.
Norman G. Holmes. Mr. Holmes has been Senior Vice President of El Paso Pipeline GP Company, L.L.C. since August 2007. Mr. Holmes has served as President of Tennessee Gas Pipeline Company, L.L.C. since August 2010 and serves as a member of its board of directors. He has also served as President of Southern Natural Gas Company, L.L.C. since August 2010 and was a member of its Management Committee until its conversion to a limited liability company in August 2011. Upon a change in management
structure in February 2012, Mr. Holmes was again named as a member of the Management Committee of Southern Natural Gas Company. L.L.C. Mr. Holmes previously served as Senior Vice President and Chief Commercial Officer of Southern Natural Gas Company from August 2006 to August 2010. He previously served as a director of Southern Natural Gas Company from November 2005 to November 2007. Mr. Holmes served as Vice President, Business Development of Southern Natural Gas Company from 1999 to 2006.
Douglas L. Foshee. Mr. Foshee has been a Director of El Paso Pipeline GP Company, L.L.C. since August 2007. He has been Chairman of the Board of El Paso Corporation since May 2009 and President, Chief Executive Officer and a director of El Paso since September 2003. Prior to joining El Paso, Mr. Foshee served as Executive Vice President and Chief Operating Officer of Halliburton Company having joined that company in 2001 as Executive Vice President and Chief Financial Officer. Several subsidiaries of Halliburton, including DII Industries and Kellogg Brown & Root, commenced prepackaged Chapter 11 proceedings to discharge current and future asbestos and silica personal injury claims in December 2003 and an order confirming a plan of reorganization became final effective December 31, 2004. Prior to assuming his position at Halliburton, Mr. Foshee served as President, Chief Executive Officer and Chairman of the Board of Nuevo Energy Company and Chief Executive Officer and Chief Operating Officer of Torch Energy Advisors Inc. Mr. Foshee presently serves as a director of Cameron International Corporation, and from January 2009 until February 2010 served as a trustee of AIG Credit Facility Trust. Mr. Foshee also serves on the Board of Trustees of Rice University and serves as a member of the Council of Overseers for the Jesse H. Jones Graduate School of Management. He is a member of various civic and community organizations.
As Chairman, President and Chief Executive Officer of El Paso Corporation, and with over 29 years of energy industry experience, Mr. Foshee brings a comprehensive knowledge and understanding of our business. Mr. Foshee’s management experience and leadership skills are highly valuable in assessing our business strategies and in the growth and development of the partnership.
D. Mark Leland. Mr. Leland has been a Director of El Paso Pipeline GP Company, L.L.C. since August 2007. He has been Executive Vice President of El Paso Corporation and President of El Paso’s Midstream business unit since October 2009. Mr. Leland previously served as Executive Vice President and Chief Financial Officer of El Paso from August 2005 to November 2009. Mr. Leland served as Executive Vice President of El Paso Exploration & Production Company from January 2004 to August 2005, and as Chief Financial Officer and a director from April 2004 to August 2005. He served as Senior Vice President and Chief Operating Officer of GulfTerra Energy Partners, L.P. and its general partner from January 2003 to December 2003 and as Senior Vice President and Controller from July 2000 to January 2003.
With his years of experience as an executive officer of El Paso Corporation, Mr. Leland brings significant operations and financial expertise to the board of our general partner. Mr. Leland has extensive knowledge of the energy industry, financial risk management and an understanding of capital markets. Mr. Leland also provides the board of our general partner with valuable public company management experience.
Arthur C. Reichstetter. Mr. Reichstetter has been a Director of El Paso Pipeline GP Company, L.L.C. since November 2007. He has been a private investment manager since 2007. Mr. Reichstetter served as Managing Director of Lazard Freres from April 2002 until his retirement in June 2007. From February 1998 to January 2002, Mr. Reichstetter was a Managing Director with Dresdner Kleinwort Wasserstein, formerly Wasserstein Parella & Co. Mr. Reichstetter was a Managing Director with Merrill Lynch from March 1993 until his retirement in February 1996. Prior to that time, Mr. Reichstetter worked as an investment banker at The First Boston Corporation from 1974 until 1993, in various positions becoming a managing director with that company in 1982.
Mr. Reichstetter brings to the board of our general partner extensive experience in investment management and capital markets, as highlighted by his years of service at Lazard Freres, Dresdner Klienwort Wasserstein and Merrill Lynch. His leadership, together with technical expertise and extensive financial acumen provide the board with the strategic insight and experience necessary to effectuate the growth objectives of the partnership.
William A. Smith. Mr. Smith has been a Director of El Paso Pipeline GP Company, L.L.C. since May 2008. Mr. Smith is Managing Director and partner in Galway Group, L.P., an investment banking/energy advisory firm headquartered in Houston, Texas. In 2002, Mr. Smith retired from El Paso Corporation, where he was an Executive Vice President and Chairman of El Paso Merchant Energy’s Global Gas Group. Mr. Smith had a 29 year career with Sonat Inc. prior to its merger with El Paso in 1999. At the time of
the merger, Mr. Smith was Executive Vice President and General Counsel. He previously served as Chairman and President of Southern Natural Gas Company and as Vice Chairman of Sonat Exploration Company. Mr. Smith is currently a director of Eagle Rock Energy G&P LLC, a midstream/upstream master limited partnership and serves on that company’s audit committee. Mr. Smith previously served on the Board of Directors of Maritrans Inc. until 2006.
With over 40 years of experience in the energy industry, Mr. Smith brings to the board of our general partner a wealth of knowledge and understanding of our industry, including valuable legal and business expertise. His experience as an executive and attorney provides the board with an important skill set and perspective. In addition, his experience on the board of directors of other domestic and international energy companies further augments his knowledge and experience.
Board Leadership Structure
Mr. Ronald L. Kuehn Jr. serves as the Chairman of the board of our general partner in a non-executive capacity and Mr. James C. Yardley serves as President and CEO of our general partner. As a publicly-traded partnership, we believe this is the most effective board leadership structure at the present time, due to the nature of our business and the continued related party activity between El Paso and our partnership.
As stated in our Corporate Governance Guidelines, the board of our general partner does not have a policy as to whether the role of the CEO and the Chairman should be separate, or whether the Chairman should be a management or non-management director. Thus, while the board of our general partner has determined that the role of Chairman and CEO should currently be separate, the board has the right to combine those roles if in the future it determines that such action would be in the best interest of the Partnership and its unitholders.
Board’s Role in Risk Oversight
The board of directors of our general partner has oversight responsibility with regard to assessment of the major risks inherent in the business of our partnership and measures to address and mitigate such risks. The board is actively involved in overseeing risk management and reviews periodically our partnership’s system of enterprise risk management.
While the board is ultimately responsible for risk oversight, the audit committee of the board assists the board in fulfilling its oversight responsibilities by considering the risks within its area of expertise. For example, the audit committee assists the board in fulfilling its risk oversight responsibilities relating to the partnership’s risk management policies and procedures. As part of this process, the audit committee meets periodically with management to review, discuss and provide oversight with respect to the processes and controls established by the partnership to assess, monitor, manage and mitigate the partnership’s significant risk exposures (whether financial, operating or otherwise). In providing such oversight, the audit committee may also discuss such processes and controls with the partnership’s internal and independent auditors.
As mentioned above, the board’s role in risk management is one of oversight. Management is responsible for day-to-day management of risks our partnership faces. Pursuant to an omnibus agreement we entered into with El Paso, our general partner and certain affiliates, El Paso provides us with general and administrative services, including risk management services, and we reimburse El Paso for the provision of these services.
Audit Committee
The board of directors of our general partner has a standing audit committee. All of the members are independent as defined under the independence standards established by the New York Stock Exchange. The audit committee is presently comprised of Messrs. Kuehn, Reichstetter and Smith. The audit committee plays an important role in promoting effective accounting, financial reporting, risk management and compliance procedures and controls. Each member of the audit committee meets the financial literacy standard required by the New York Stock Exchange rules and at least one member qualifies as having accounting or related financial management expertise. The board of directors of our general partner has affirmatively determined that Mr. Reichstetter satisfies the definition of “audit committee financial expert,” as defined by SEC rules, and has designated him as an “audit committee financial expert.”
Corporate Governance Guidelines and Code of Ethics
Our Corporate Governance Guidelines, provide the framework for the effective governance of our partnership. We adopted the Corporate Governance Guidelines, which apply to the board of directors of our general partner, as well as to persons performing services to us, to address matters including qualifications for directors, standards for independence of directors, responsibilities of directors, limitation on serving on other boards/committees, the composition and responsibility of committees, conduct and minimum frequency of board and committee meetings, management succession, director access to management and outside advisors, director compensation, equity ownership guidelines, director orientation and continuing education, and annual self-evaluation of the board, its committees and directors. The board of directors of our general partner recognizes that effective corporate governance is an on-going process, and the board will review and revise as necessary our Corporate Governance Guidelines annually, or more frequently if deemed necessary. Our Corporate Governance Guidelines may be found on our website at www.eppipelinepartners.com.
We also adopted a code of business conduct and ethics, referred to as our “Code of Conduct,” that applies to all directors and employees of our general partner, including its Chief Executive Officer, Chief Financial Officer and senior financial and accounting officers, as well as all El Paso employees working on behalf of us or our general partner. The Code of Conduct is a value-based code that is built on five core values: stewardship, integrity, safety, accountability and excellence. In addition to other matters, the Code of Conduct establishes policies to deter wrongdoing and to promote honest and ethical conduct, including ethical handling of actual or apparent conflicts of interest, compliance with applicable laws, rules and regulations, full, fair, accurate, timely and understandable disclosure in public communications and prompt internal reporting of violations of the Code of Conduct. A copy of the Code of Conduct is available on our website at www.eppipelinepartners.com. We will post on our internet website all waivers to or amendments of the Code of Conduct, which are required to be disclosed by applicable law and the New York Stock Exchange listing standards. Currently, we do not have nor do we anticipate any waivers of or amendments to the Code of Conduct. We believe the Code of Conduct exceeds the requirements set forth in the applicable SEC regulations and the corporate governance rules of the New York Stock Exchange.
Executive Sessions of the Board and Communications by Interested Parties
As set forth in our Corporate Governance Guidelines and in accordance with NYSE listing standards, the board of directors of our general partner holds executive sessions on a regular basis without management present. Mr. Ronald L. Kuehn, Jr., our independent chairman of the board, presides over all executive sessions of the board.
The board of directors of our general partner has established a process for interested parties to communicate with the board or any individual member thereof. Such communications should be in writing, addressed to the board or an individual director, c/o Ms. Marguerite Woung-Chapman, Corporate Secretary, P.O. Box 2511, Houston, TX 77252. The corporate secretary will forward such correspondence to the addressee.
Web Access
We provide access through our website to current information related to corporate governance, including a copy of the charter of the audit committee of the board, our Corporate Governance Guidelines, our Code of Conduct, biographical information concerning each director, and other matters regarding our corporate governance principles. We also provide access through our website to all filing submitted by EPB to the SEC. Our website is www.eppipelinepartners.com, and access to this information is free of charge to the user (except for any internet provider or telephone charges).
Reimbursement of Expenses of Our General Partner
Our general partner does not receive any management fee or other compensation for its management of our partnership under the omnibus agreement with El Paso or otherwise. Under the terms of the omnibus agreement, we reimburse El Paso for the provision of various general and administrative services for our benefit. We also reimburse El Paso for direct expenses incurred on our behalf and expenses allocated to us as a result of our becoming a public entity. The partnership agreement provides that our general partner determines the expenses that are allocable to us.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934, as amended, requires executive officers and directors of our general partner and persons who beneficially own more than 10 percent of a registered class of our equity securities to file reports of ownership and changes in ownership with the Securities and Exchange Commission and to furnish us with copies of all such reports. Based solely upon a review of the copies of the reports received by us, we believe that all such filing requirements were satisfied during 2011.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The executive officers of our general partner are also executive officers of El Paso or one of its pipeline subsidiaries. The compensation of the executive officers of our general partner is set by El Paso, and we have no control over the compensation determination process. The officers and employees of our general partner participate in employee benefit plans and arrangements sponsored by El Paso. Other than the Long-Term Incentive Plan described below, neither we nor our general partner have established any employee benefit plans and our general partner has not entered into employment agreements with any of its officers.
Compensation Discussion and Analysis
We do not directly employ any of the persons responsible for managing or operating our business. Instead, we are managed by our general partner, El Paso Pipeline GP Company, L.L.C., the executive officers of which are employees of El Paso. El Paso Pipeline GP Company, L.L.C. entered into the omnibus agreement with El Paso, pursuant to which, among other matters:
•
El Paso makes available to El Paso Pipeline GP Company, L.L.C. the services of the El Paso employees who serve as the executive officers of El Paso Pipeline GP Company, L.L.C.; and
•
El Paso Pipeline GP Company, L.L.C. is obligated to reimburse El Paso for any allocated portion of the costs that El Paso incurs in providing compensation and benefits to such El Paso employees.
Although we bear an allocated portion of El Paso’s costs of providing compensation and benefits to the El Paso employees who serve as the executive officers of our general partner, we have no control over such costs and cannot establish or direct the compensation policies or practices of El Paso. Each of these executive officers performs services for our general partner, as well as El Paso and its affiliates.
We bore substantially less than a majority of El Paso’s costs of providing compensation and benefits to the Chief Executive Officer of our general partner (the principal executive officer) and the Chief Financial Officer of our general partner (the principal financial officer) during 2011.
Our general partner has adopted the El Paso Pipeline GP Company, L.L.C. Long-Term Incentive Plan, or LTIP, under which equity awards of our partnership may be granted. At this point in time, we do not anticipate that the officers and employees of our general partner (including those that also serve as directors of the general partner) will receive any grants under the LTIP. As indicated above, the compensation of such officers and employees is made pursuant to El Paso’s incentive plans and reimbursed by us pursuant to the omnibus agreement. Non-employee directors of our general partner receive equity grants under the LTIP, as described below.
Long-Term Incentive Plan
The LTIP was designed to promote the interests of our partnership by providing to employees, consultants, and directors of our general partner and employees and consultants of its affiliates who perform services for us or on our behalf incentive compensation awards for superior performance that are based on our common units. Employees, directors, and consultants of our general partner or an affiliate who perform services for us and who are selected from time to time by the board of our general partner may be granted awards under the LTIP.
The LTIP is administered by the board of our general partner or a committee thereof. The board of our general partner, subject to the terms of the LTIP, has authority to (i) select the persons to whom awards are to be granted; (ii) determine the size and type of awards; (iii) determine the terms and conditions of any award, including any performance conditions; (iv) determine whether, to what extent, and under what circumstances awards may be settled, exercised, canceled, or forfeited; (vi) interpret and administer the LTIP and any instrument or agreement relating to an award made under the LTIP; (vii) establish, amend, suspend, or waive such rules and regulations and appoint such agents as it shall deem appropriate for the proper administration of the LTIP; and (viii) make any other determination and take any other action that the board of our general partner deems necessary or desirable for the administration of the LTIP. All decisions, interpretations and other actions of the board of our general partner are final and binding.
The LTIP authorizes the granting of unit options, restricted common units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The maximum number of our common units that may at any time be delivered or reserved for delivery under the LTIP is 1,250,000 common units. If any award expires, is canceled, exercised, paid or otherwise terminates without the delivery of common units, then the units covered by such award shall again be units with respect to which awards may be granted.
The board of our general partner may terminate or amend the LTIP at any time with respect to any units for which a grant has not yet been made. The board of our general partner also has the right to alter or amend the LTIP or any part thereof from time to time, including increasing the number of units that may be granted subject to the requirements of the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the rights or benefits of the participant without the consent of the participant. The LTIP will expire on the earliest of (i) the date common units are no longer available under the LTIP for grants, (ii) termination of the LTIP by the board of our general partner or (iii) the date 10 years following its date of adoption.
Compensation of Directors
Officers or employees of our general partner or its affiliates who also serve as directors of our general partner do not receive additional compensation for their service as a director of our general partner. Directors who are not officers or employees of our general partner or its affiliates are compensated for their services on the board, as described below. In addition, each non-employee director is reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director is fully indemnified by us for his actions associated with being a director to the fullest extent permitted under Delaware law pursuant to a director indemnification agreement and our partnership agreement.
Cash Retainer. Each non-employee director of our general partner receives an annual cash retainer paid in quarterly installments. For 2011, the Board approved an increase of $15,000 in the annual cash retainer from $50,000 to $65,000. In addition, the chairman of the audit committee receives an additional retainer of $8,000 per year.
Initial Equity Grant. Each non-employee director, upon joining the board, receives an initial long-term equity grant of restricted common units. Commencing in 2011, the Board approved an increase of $10,000 in the value of the initial long-term equity grant from $50,000 to $60,000. The restricted common units are granted pursuant to the terms and conditions of the LTIP and vest in three (3) equal installments commencing on the last day of the calendar year of the year in which the grant was made and each of the following two anniversaries thereof. As no non-employee directors joined the board during 2011, no initial equity grants were made in 2011.
Annual Equity Grant. Each non-employee director who is serving on the board on December 1st will receive an annual grant of restricted common units with a value of $60,000. Commencing in 2011, the value of the annual grant was increased by $10,000 (from $50,000 to $60,000). This annual award is granted pursuant to the terms and conditions of the LTIP and vests in full on the last day of the calendar year following the year in which the grant was made. Annual equity grants for Messrs. Kuehn, Reichstetter and Smith were made on December 1, 2011.
Director Compensation Table
The following table sets forth the aggregate dollar amount of all fees paid to each of the non-employee directors of our general partner during 2011 for their services on the board. The non-employee directors do not receive stock options or pension benefits.
Director Compensation
for the Year Ended December 31, 2011 (1)
(1) Employee directors do not receive any additional compensation for serving on the board of directors of our general partner; therefore no amounts are shown for Messrs. Foshee, Sult, Leland and Yardley. Amounts paid as reimbursable business expenses to each director for attending board functions are not reflected in this table. Our general partner does not consider the directors’ reimbursable business expenses for attending board functions and other business expenses required to perform board duties to have a personal benefit and thus be considered a perquisite.
(2) This column reflects the value of a director’s annual retainer, as well as the additional retainer for the chairman of the audit committee.
(3) The amount in this column represents the aggregate grant date fair value of restricted units granted in the fiscal year calculated in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 718, “Compensation - Stock Compensation”. Each of Messrs. Kuehn, Reichstetter and Smith received a grant of 1,827 restricted common units on December 1, 2011, with each unit having a grant date fair value of $32.85.
(4) As of December 31, 2011, each of Messrs. Kuehn, Reichstetter and Smith had 1,827 restricted common units outstanding.
(5) The amount reflected in this column for Mr. Kuehn includes $580 for an airline ticket for an occasion when the director’s spouse accompanied him on a business-related flight using a commercial carrier, as well as $2,839 in cash distributions received on unvested restricted common units. The amount in this column for Messrs. Reichstetter and Smith represent cash distributions received on unvested restricted common units.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
The following table sets forth the beneficial ownership of units of our partnership owned as of February 10, 2012 by:
•
each person known by us to be a beneficial owner of more than 5 percent of the units;
•
each of the directors of our general partner;
•
each of the named executive officers of our general partner; and
•
all directors and executive officers of our general partner as a group.
The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.
The percentage of total units to be beneficially owned is based on 205,698,750 common units outstanding as of February 10, 2012.
* Less than 1 percent.
(1) Unless otherwise indicated, the address for all beneficial owners in this table is El Paso Building, 1001 Louisiana Street, Houston, Texas 77002.
(2) El Paso Corporation is the ultimate parent company of El Paso Pipeline Holding Company, L.L.C., the sole owner of the member interests of our general partner and El Paso Pipeline LP Holdings, L.L.C., the owner of 88,400,059 common units. El Paso Corporation may, therefore, be deemed to beneficially own the units held by El Paso Pipeline LP Holdings, L.L.C.
(3) According to a Schedule 13G/A filed on February 10, 2012, as of December 31, 2011, Tortoise Capital Advisors, L.L.C., was deemed to beneficially own 11,825,091 shares of common stock. The address is 11550 Ash Street, Suite 300, Leawood, KS 66211.
The following table sets forth, as of February 10, 2012, the number of shares of common stock of El Paso owned by each of the executive officers and directors of our general partner and all directors and executive officers of our general partner as a group.
* Less than 1 percent.
(1) The shares indicated represent stock options granted under El Paso’s current or previous stock option plans, which are currently exercisable or which will become exercisable within 60 days of February 10, 2012. Shares subject to options cannot be voted.
(2) Based on 772,743,059 shares outstanding as of February 10, 2012.
(3) Excludes 28,720 shares owned by Mr. Kuehn’s wife or children. Mr. Kuehn disclaims any beneficial ownership in these 28,720 shares.
(4) Excludes 8,562 shares owned by Mr. Smith’s wife. Mr. Smith disclaims any beneficial ownership in these 8,562 shares.
EQUITY COMPENSATION PLAN INFORMATION TABLE
The following table provides information concerning securities that may be issued under the El Paso Pipeline GP Company, L.L.C. Long-Term Incentive Plan as of December 31, 2011. For more information regarding this plan, which did not require approval by our limited partners, please read “Executive Compensation - Long-Term Incentive Plan.”
(1) Please read “Executive Compensation - Long-Term Incentive Plan” for a description of the material features of the plan, including the awards that may be granted under the plan.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
El Paso owns 88,400,059 common units, a 42 percent limited partner interest in us. In addition, our general partner owns a two percent general partner interest in us and the incentive distribution rights.
Distributions and Payments to Our General Partner and Its Affiliates
The following table summarizes the distributions and payments made or to be made by us to our general partner and its affiliates in connection with ongoing operation and liquidation of EPB. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.
Operational Stage
Distributions of available cash to
our general partner and its affiliates
We will generally make cash distributions 98 percent to unitholders, including our general partner and its affiliates as holders of an aggregate of 88,400,059 common units and the remaining two percent to our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target levels, our general partner will be entitled to increasing percentages of the distributions, up to 50 percent of the distributions above the highest target level.
Payments to our general partner
and its affiliates
Our general partner does not receive a management fee or other compensation for the management of our partnership. Our general partner and its affiliates are reimbursed, however, for all direct and indirect expenses incurred on our behalf. Our general partner determines the amount of these expenses. In addition we will reimburse El Paso and its affiliates for the payment of certain operating expenses and for the provision of various general and administrative services for our benefit.
Withdrawal or removal of our
general partner
If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.
Liquidation Stage
Liquidation
Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.
Omnibus Agreement
We and certain of our subsidiary companies are parties to an omnibus agreement with El Paso and our general partner that governs our relationship with them regarding the following matters:
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reimbursement of certain operating and general and administrative expenses;
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indemnification for certain environmental contingencies, tax contingencies and right-of-way defects;
•
reimbursement for certain expenditures; and
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the guaranty by El Paso of certain expenses under intercompany agreements related to the Elba Island LNG terminal expansion.
Reimbursement of Operating and General and Administrative Expense
Under the omnibus agreement we reimburse El Paso and its affiliates for the payment of certain operating expenses and for the provision of various operating expenses and general and administrative services for our benefit with respect to the assets contributed to us. The agreements further provide that we reimburse El Paso for our allocable portion of the premiums on insurance policies covering our assets.
Pursuant to these arrangements, El Paso performs centralized corporate functions for us, such as legal, accounting, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes and engineering. We reimburse El Paso and its affiliates for the expenses to provide these services as well as other expenses it incurs on our behalf, such as salaries of operational personnel performing services for our benefit and the cost of their employee benefits, including 401(k), pension and health insurance benefits.
We also reimburse El Paso for any additional state income, franchise or similar taxes paid by El Paso resulting from the inclusion of us (and our subsidiaries) in a combined state income, franchise or similar tax report with El Paso as required by applicable law. The amount of any such reimbursement will be limited to the tax that we (and our subsidiaries) would have paid had we not been included in a combined group with El Paso.
Additional services agreements with affiliates are discussed under Operating and Services Agreements.
Competition
Neither El Paso nor any of its affiliates are restricted, under either our partnership agreement or the omnibus agreement, from competing with us. El Paso and any of its affiliates may acquire, construct or dispose of additional transportation and storage or other assets in the future without any obligation to offer us the opportunity to purchase or construct those assets.
Contracts with Affiliates
Contribution Agreements
On March 4, 2011, we entered into a contribution agreement with our operating company and El Paso and certain of its subsidiaries to acquire an additional 22 percent general partner interest in SNG, with a 45 day option to purchase an additional three percent general partner interest in SNG in one percent increments. Pursuant to the contribution agreement, on March 14, 2011 we acquired the additional 25 percent general partner interest in SNG in exchange for consideration of $667 million.
On June 29, 2011, we entered into a contribution agreement with our operating company and El Paso and certain of its subsidiaries to acquire the remaining 15 percent general partner interest in SNG and an additional 28 percent interest in CIG. Pursuant to the contribution agreement, on June 29, 2011 we acquired the remaining 15 percent general partner interest in SNG and an additional 28 percent interest in CIG for aggregate consideration of $745 million.
The conflicts committee of the board of directors of the General Partner unanimously recommended approval of the terms of each of the acquisitions discussed above. With respect to each transaction, the conflicts committee of the board of directors of our general partner retained independent legal and financial advisors to assist it in evaluating and negotiating the transaction. In recommending approval of the transaction, the conflicts committee based its decision in part on an opinion from the committee’s independent financial advisor that the consideration to be paid by us pursuant to each of the contribution agreements is fair, from a financial point of view, to the holders of our common units, other than our general partner and its affiliates. The board of directors of the general partner unanimously approved the terms of each acquisition.
Note Payable
On September 30, 2008, in connection with our acquisition of additional ownership interests in CIG and SNG, we, as guarantor, and our operating company, as issuer, entered into a Note Purchase Agreement with El Paso. Under the Note Purchase Agreement, our operating company issued a $10 million senior unsecured note to El Paso bearing interest at LIBOR plus 3.9 percent due September 2012. This note may be prepaid without premium or penalty.
Our operating company’s obligations under the Note Purchase Agreement are guaranteed by us. The Note Purchase Agreement requires that we maintain, as of the end of each fiscal quarter, (i) a consolidated leverage ratio (consolidated indebtedness to consolidated EBITDA (as defined in the Note Purchase Agreement)) of less than or equal to 5.50 to 1.00 for any four consecutive fiscal quarters and (ii) an interest coverage ratio (consolidated EBITDA to interest expense) of greater than or equal to 1.50 to 1.00 for any four consecutive fiscal quarters. In case of a capital construction or expansion project costing more than $20 million, pro forma adjustments to consolidated EBITDA may be made based on the percentage of capital costs expended and projected cash flows for the project. Such adjustments shall be limited to 25 percent of actual consolidated EBITDA.
The Note Purchase Agreement also contains certain customary events of default that affect us, our operating company and our other restricted subsidiaries, including, without limitation, (i) nonpayment of principal when due or nonpayment of interest or other amounts within five business days of when due; (ii) bankruptcy or insolvency with respect to us, our general partner, our operating company or any of our other restricted subsidiaries; or (iii) judgment defaults against us, our general partner, our operating company or any of our other restricted subsidiaries in excess of $50 million.
CIG Limited Liability Company Agreement
Prior to the closing of our initial public offering in November 2007, CIG converted to a general partnership. In connection with the closing of our initial public offering, El Paso contributed to us a 10 percent general partner interest in CIG. In September 2008, we acquired from El Paso an additional 30 percent interest in CIG. In July 2009, we acquired from El Paso an additional 18 percent interest in CIG. In June 2011, we acquired an additional 28 percent general partner interest in CIG. After these transactions, we owned indirectly an 86 percent general partner interest in CIG, and an El Paso subsidiary owned indirectly a 14 percent general partner interest in CIG. In August 2011, CIG converted from a general partnership to a limited liability company (“LLC”). The conversion did not impact the respective ownership interests in CIG. The CIG LLC agreement governs the ownership and management of CIG.
CIG is a Delaware limited liability company, one member of which is a wholly owned subsidiary of the partnership (the “Partnership Member”) owning an 86 percent membership interest in CIG, and the other member is a wholly owned subsidiary of El Paso (the “El Paso Member”) owning the remaining 14 percent membership interest. The CIG LLC agreement provides that the business and affairs of CIG are fully vested in, and managed by, a management committee. The management committee is composed of five representatives, with four representatives being designated by the Partnership Member and one representative being designated by the El Paso Member. Each member of the management committee is entitled to one vote on each matter submitted for a vote of the management committee, and the vote of a majority of the members of the management committee constitutes action of the management committee. The CIG LLC agreement provides that if at any time the members shall determine that additional funds or property are necessary or desirable to meet the obligations or needs of CIG, the members may make additional capital contributions to CIG and that the members may determine the timing and amount of cash and other distributions from CIG to the members. Additionally, the CIG LLC agreement provides for indemnification of the members and officers of CIG under certain circumstances.
WYCO Development LLC Agreements
CIG has a 50 percent membership interest in WYCO Development LLC (WYCO), a limited liability company organized under the laws of the State of Colorado. The remaining membership interests in WYCO are owned by a subsidiary of Xcel Energy, the indirect corporate parent of Public Service Company of Colorado (PSCo). CIG provides administrative services to WYCO pursuant to an Administrative Services Agreement dated January 1, 2009.
WYCO is a party to a Facilities Lease Agreement with WIC, dated December 1, 1999, pursuant to which WYCO leases certain compressor facilities (the Douglas Compressor Station Facilities) to WIC. The lease agreement provides for lease payments based on the cost-of-service formula used in setting recourse rates at FERC ratemaking proceedings. The term of the lease is 30 years.
WYCO is also a party to a Lease Agreement with CIG, dated November 1, 2008, pursuant to which WYCO leases the High Plains Pipeline facilities and the Totem Storage Field facilities to CIG. The lease agreement provides for lease payments based on the cost-of-service formula used in setting recourse rates at FERC ratemaking proceedings, adjusted for certain under or over cost recoveries experienced by CIG on these facilities. The primary term of the lease is 30 years, with certain automatic renewal provisions based on the continuance of service agreements between CIG and PSCo for service on the facilities.
Operating and Services Agreements
CIG entered into a Construction and Operating Agreement with WIC, on March 12, 1982. This agreement was amended in 1984 and 1988. Under this agreement, CIG agreed to design and construct the WIC system and to operate WIC (including conducting WIC’s marketing and administering WIC’s service agreements) using the same practices that CIG adopts in the operation and administration of its own facilities. On September 1, 2011, the Construction and Operating Agreement between CIG and WIC was superseded by a more generic CIG Pipeline Services Co, L.L.C. Master Services Agreement between CIG Pipeline Services Company, L.L.C., CIG and WIC. Under this agreement, CIG Pipeline Services Company, L.L.C. (CIGSC) employees provide services to CIG and WIC, and CIG provides additional services to WIC. Direct and/or allocated costs can be billed either by CIGSC or CIG.
CIG entered into a Construction and Operating Agreement with Young Gas Storage Company, Ltd. (Young) on June 30, 1992. This agreement was amended in 1994 and 1997. Under this agreement, CIG agreed to design and construct the Young storage facilities and to operate the facilities (including conducting Young’s marketing and administering Young’s service agreements) using the same practices that CIG adopts in the operation and administration of its own facilities. CIG is entitled to reimbursement of all costs incurred in the performance of the services, including both direct costs and allocations of general and administrative costs based on direct field labor charges (including any costs charged or allocated to CIG from other affiliates). The agreement is subject to termination only in the event of the dissolution or bankruptcy of CIG, or a material default by CIG that is not cured within certain permissible time periods. Otherwise the agreement continues until the termination of the Young partnership agreement.
CIG entered into a Construction and Operating Agreement with Cheyenne Plains Gas Pipeline Company, L.L.C. (Cheyenne Plains) on November 14, 2003. Under this agreement, CIG agreed to design and construct the facilities and to operate the Cheyenne Plains facilities (including conducting marketing and administering the service agreements) using the same practices that CIG adopts in the operation and administration of its own facilities. CIG is entitled to reimbursement by Cheyenne Plains for all costs incurred in the performance of the services, including both direct field labor charges and allocations of general and administrative costs (including any costs charged or allocated to CIG from other affiliates) using a modified Massachusetts allocation methodology, a time and motion analysis or other appropriate allocation methodology. The agreement is subject to termination by Cheyenne Plains on 12 months’ prior notice and is subject to termination by CIG on 12 months’ prior notice given no earlier than 48 months following the commencement of service by Cheyenne Plains in December 2004.
CIG entered into an Administrative Services Agreement with WYCO on January 1, 2009. Under this agreement, CIG performs the general administrative functions of WYCO, including accounting, budgeting, tax and treasury functions. The contract has a one-year term, renewed automatically in the absence of notice. For these services CIG receives a fee of $2,000 per month.
CIG, WIC, SNG, SLNG and Elba Express are parties to Master Services Agreements with Tennessee Pipeline Services Company, L.L.C. (TGPSC), El Paso Natural Gas Company and CIG Pipeline Services Company, L.L.C or SNG Pipeline Services Company, L.L.C. (together the “Services Companies”). Under these agreements, CIG, WIC, SNG, SLNG and Elba Express reimburse the Services Companies for supervisory, administrative and financial services in connection with their operations.
CIG, WIC, SLNG, Elba Express and SNG reimburse TGP for technical services such as control, metallurgical, pipeline integrity, rates, tariffs, certificates, engineering and rehabilitation, operational training, government affairs and measurement. TGPSC provides these services to all El Paso pipeline operating companies. The specific allocations are based on the estimated level of effort devoted to their operations (time and motion studies).
CIG and WIC reimburse EPNG for supervisory, administrative, financial and technical services such as gas scheduling, gas control, market analysis, and executives. The specific allocations are based on estimated level of effort devoted to their operations.
Transportation Agreements
CIG is a party to four transportation service agreements with WIC for transportation on the WIC system at maximum recourse rates. The total volume subject to these contracts is 176,971 Dth/d. These contracts extend for various terms with 57,950 Dth/d expiring on December 31, 2012; and the balance expiring thereafter. Under the service agreements, we are required to make minimum annual payments of $3 million in 2012 and thereafter. In response to a solicitation of offers to turn back capacity in a WIC open season, CIG relinquished 70,000 Dth/d of capacity effective January 1, 2008. WIC has remarketed this capacity along with off-system capacity acquired by WIC on a third party pipeline and other capacity on its pipeline to another affiliate, Cheyenne Plains, under a Firm Transportation Service Agreement for 125,000 Dth/d from the Opal Hub in western Wyoming to the Cheyenne Hub at maximum recourse rates for a term extending to 2020.
WIC is also a party to a transportation service agreement with CIG for 75,600 Dth/d of firm transportation capacity on WIC from a Primary Point of Receipt at the Cheyenne Hub to a Primary Point of Delivery into El Paso’s Ruby Pipeline at Opal, Wyoming. The rate that CIG pays for this service is WIC’s maximum recourse rates plus the cost of any off-system capacity on a third party pipeline that is acquired by WIC to provide this service. The term for the transportation service agreement extends through December 31, 2020.
CIG is a party to a capacity release agreement with PSCo, whereby PSCo has released storage capacity in our affiliate, Young, to us for a term expiring on April 30, 2025. PSCo simultaneously contracted for a corresponding quantity of transportation and storage balancing service (which utilizes the storage capacity acquired through the capacity release).
In order to provide “jumper” compression service between the CIG system and the Cheyenne Plains pipeline system, CIG added compression at CIG’s existing compressor station in Weld County, Colorado. Cheyenne Plains entered into a 25-year contract that expires in 2030 for the full capacity of the additional compression pursuant to which CIG’s full cost of service is covered. The contract is for 119,500 Dth/d.
Interconnection and Operational Balancing Agreements and Other Inter-Affiliate Agreements
Each of WIC and CIG is a party to an operational balancing agreement with each other and independently with Cheyenne Plains. In addition, CIG is a party to interconnection and operational balancing agreements with Ruby Pipeline, L.L.C. (Ruby). These agreements require the interconnecting parties to use their respective reasonable efforts to cause the quantities of gas that are tendered/accepted at each point of interconnection to equal the quantities scheduled at those points. The agreements provide for the treatment and resolution of imbalances. The agreements are terminable by either party on 30 days advance notice.
CIG and WIC are parties to a capacity lease agreement dated November 1, 1997. In 1998, WIC installed a compressor unit at WIC’s Laramie compressor station. The installation of this compressor unit allowed the interconnection of CIG’s Powder River lateral and WIC’s mainline transmission system and resulted in an increase of approximately 49 MDth/d of capacity on CIG’s Powder River lateral (the original capacity on the Powder River lateral was approximately 46 MDth/d). In connection with the installation of the compression by WIC, CIG leased the additional 49 MDth/d of capacity in the Powder River lateral to WIC. WIC, in turn, leased to CIG 46 MDth/d of capacity through the new WIC compressor unit. The initial term of the lease of the Powder River lateral capacity from CIG to WIC was 10 years from the November 15, 1998 in-service date of the additional compression. In November 2008, the term of the lease was extended for 10 years. The term of the lease of the compression unit capacity from WIC to CIG continues for as long as CIG has shipper agreements for service using the compressor unit capacity. The parties to this agreement have agreed that the reciprocal leases provide adequate compensation to each other so there is no rental fee for either lease other than an agreement by WIC to reimburse CIG for any increase in operating expense incurred by CIG (including increased taxes, insurance or other expenses).
WIC is a party to an “Upstream Pipeline Capacity Agreement” with Ruby, an indirect partially-owned subsidiary of El Paso. Pursuant to this agreement WIC agreed to offer gas transportation services to shippers desiring to move gas volumes to the inlet of the proposed Ruby pipeline at Opal, Wyoming. Ruby has agreed to reimburse WIC for any unrecovered costs associated with 200 MDth/d of off-system capacity that was acquired by WIC to provide the upstream transportation services (either through a direct payment or through the acquisition of capacity on WIC). The off-system capacity was acquired by WIC on the expansions of the Rockies Express Pipeline from the Piceance Basin to Wamsutter, and the expansion of the Overthrust Pipeline from Wamsutter to Opal.
Other Agreements
In addition, each of WIC, CIG, SLNG, Elba Express and SNG currently have or will have in the future other routine agreements with El Paso or one of its subsidiaries that arise in the ordinary course of business, including revised and updated agreements for services and other transportation and exchange agreements and interconnection and balancing agreements with other El Paso pipelines.
For a description of certain additional affiliate transactions, see Part II, Item 8. Financial Statements and Supplementary Data, Note 13.
Review, Approval or Ratification of Transactions with Related Persons
Our partnership agreement contains specific provisions that address potential conflicts of interest between our general partner and its affiliates, including El Paso, on one hand, and us and our limited partners, on the other hand. Whenever such a conflict of interest arises, our general partner will resolve the conflict. Our general partner may, but is not required to, seek the approval of such resolution from the conflicts committee of the board of directors of our general partner, which, is required to be comprised of independent directors. The partnership agreement provides that our general partner will not be in breach its obligations under the partnership agreement or its duties to us or to our unitholders if the resolution of the conflict is:
•
approved by the conflicts committee;
•
approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;
•
on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
•
fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.
If our general partner does not seek approval from the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or its conflicts committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to reasonably believe that he is acting in the best interests of the partnership, unless the context otherwise requires.
Director Independence
The board of directors of our general partner has affirmatively determined that Ronald L. Kuehn, Jr., Arthur C. Reichstetter and William A. Smith each satisfy the independence requirements under the New York Stock Exchange listing standards. In making this determination, the board reviewed information from each of these directors regarding all of their respective relationships with us and analyzed the materiality of those relationships. The audit committee of our general partner’s board of directors is also composed entirely of independent directors.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Audit Fees
We paid audit fees of approximately $2,692,000 for the year ended December 31, 2011 and $2,897,000 for the year ended December 31, 2010. These fees were for professional services rendered by Ernst & Young LLP for the audit of the consolidated financial statements of EPB and its subsidiaries, the review of documents filed with the Securities and Exchange Commission, consents, the issuance of comfort letters, and certain financial accounting and reporting consultations.
Tax Fees
For the years ended December 31, 2011 and 2010, fees of $226,000 and $199,000 were paid to Ernst & Young LLP for professional services related to tax compliance and tax planning.
Audit-Related Fees
No audit-related services were provided by our independent registered public accounting firm for the years ended December 31, 2011 and 2010.
All Other Fees
No other fees were paid for the years ended December 31, 2011 and 2010.
During 2011, the Audit Committee approved all the types of audit and permitted non-audit services which our independent auditors were to perform during the year, as required under applicable law and the cap on fees for each of these categories. The Audit Committee’s current practice is to consider for pre-approval annually all categories of audit and permitted non-audit services proposed to be provided by our independent auditors for a fiscal year. Pre-approval of tax services requires that the principal independent auditor provide the Audit Committee with written documentation of the scope and fee structure of the proposed tax services and discuss with the Audit Committee the potential effects, if any, of providing such services on the independent auditor’s independence. The Audit Committee will also consider for pre-approval annually the maximum amount of fees and the manner in which the fees are determined for each type of pre-approved audit and non-audit services proposed to be provided by our independent auditors for the fiscal year. The Audit Committee must separately pre-approve any service that is not included in the approved list of services or any proposed services exceeding pre-approved cost levels. The Audit Committee has delegated pre-approval authority to the Chairman of the Audit Committee for services that need to be addressed between Audit Committee meetings. The Audit Committee is then informed of these pre-approval decisions, if any, at the next meeting of the Audit Committee.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) The following consolidated financial statements are included in Part II, Item 8 of this report:
The Exhibit Index, which follows the signature page to this report and is hereby incorporated herein by reference, sets forth a list of those exhibits filed herewith, and includes and identifies management contracts or compensatory plans or arrangements required to be filed as exhibits to this Form 10-K by Item 601 (b)(10)(iii) of Regulation S-K.
The agreements included as exhibits to this report are intended to provide information regarding their terms and not to provide any other factual or disclosure information about us or the other parties to the agreements. The agreements may contain representations and warranties by the parties to the agreements, including us, solely for the benefit of the other parties to the applicable agreement and:
•
should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;
•
may have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;
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may apply standards of materiality in a way that is different from what may be viewed as material to certain investors; and
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were made only as of the date of the applicable agreement or such other date or dates as maybe specified in the agreement and are subject to more recent developments.
Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, El Paso Pipeline Partners, L.P. has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the 27th day of February 2012.
EL PASO PIPELINE PARTNERS, L.P.
By:
El Paso Pipeline GP Company, L.L.C.,
its General Partner
By:
/s/ James C. Yardley
James C. Yardley
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of El Paso Pipeline Partners, L.P. and in the capacities with El Paso Pipeline GP Company, L.L.C., its General Partner, and on the dates indicated:
EL PASO PIPELINE PARTNERS, L.P.
EXHIBIT INDEX
December 31, 2011
Each exhibit identified below is filed as part of this report. Exhibits filed with this Report are designated by “*”. All exhibits not so designated are incorporated herein by reference to a prior filing as indicated. Exhibits designated with a “+” constitute a management contract or compensatory plan or arrangement.
EXHIBIT LIST
# Pursuant to Item 601(b)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted exhibit or schedule to the Securities and Exchange Commission upon request.
^ Confidential information has been omitted from this exhibit and filed separately with the Securities and Exchange Commission pursuant to a confidential treatment request.